<PAGE>
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 9, 2000
REGISTRATION NO. 333-84609
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
------------------------
AMENDMENT NO. 2 TO
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
------------------------
LSP ENERGY LIMITED PARTNERSHIP
LSP BATESVILLE FUNDING CORPORATION
(Exact name of registrants as specified in their charters)
<TABLE>
<S> <C> <C>
DELAWARE 4911 22-3422042
DELAWARE 6799 22-3615403
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)
</TABLE>
------------------------
TWO TOWER CENTER
20TH FLOOR
EAST BRUNSWICK, N.J. 08816
(732) 249-6750
FRANK HARDENBERGH
GENERAL COUNSEL
304 BOSTON POST ROAD
WAYLAND, MASSACHUSETTS 01778
(508) 358-2570
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
------------------------------
COPY TO:
DAVID A. GORDON, ESQ.
LATHAM & WATKINS
885 THIRD AVENUE.
NEW YORK, NEW YORK 10022
(212) 906-1251
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.
If any of the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance with
General Instruction G, check the following box. / /
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. / /
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. / /
------------------------------
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
TITLE OF EACH PROPOSED PROPOSED AMOUNT OF
CLASS OF SECURITIES AMOUNT TO BE OFFERING PRICE AGGREGATE REGISTRATION
TO BE REGISTERED REGISTERED PER BONDS (1) OFFERING PRICE(1) FEE(2)
<S> <C> <C> <C> <C>
7.164% series C senior secured bonds due
2014....................................... $150,000,000 100% $150,000,000 $41,700
8.160% series D senior secured bonds due
2025....................................... $176,000,000 100% $176,000,000 $48,928
</TABLE>
(1) Estimated solely for purposes of calculating the registration fee pursuant
to Rule 457.
(2) Paid with the initial filing of the Registration Statement.
------------------------------
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.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
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>
SUBJECT TO COMPLETION, DATED FEBRUARY 9, 2000
PROSPECTUS
LSP ENERGY LIMITED PARTNERSHIP
LSP BATESVILLE FUNDING CORPORATION
EXCHANGE OFFER FOR
7.164% SERIES A SENIOR SECURED BONDS DUE 2014
8.160% SERIES B SENIOR SECURED BONDS DUE 2025
This is an offer to exchange our outstanding 7.164% series A senior secured
bonds due 2014 and 8.160% series B senior secured bonds due 2025 you now hold
for new, substantially identical 7.164% series C senior secured bonds due 2014
and 8.160% series D senior secured bonds due 2025 that will be free of the
transfer restrictions that apply to the private bonds. This offer will expire at
5:00 p.m., New York City time, on , 2000, unless we extend it. You must
tender your private bonds by the deadline to obtain exchange bonds and the
liquidity benefits they offer.
We agreed with the initial purchasers of the private bonds to make this
offer and register the issuance of the exchange bonds following the closing for
the private bonds. This offer applies to any and all private bonds tendered
before the expiration of the exchange offer.
The exchange bonds will not trade on any established exchange. The exchange
bonds have the same financial terms and covenants as the private bonds, and have
the same business and financial risks.
A DESCRIPTION OF THOSE RISKS BEGINS ON PAGE 20.
---------------------
The terms of the exchange offer will include the following:
- We will exchange all outstanding private bonds that are validly tendered
and not validly withdrawn.
- You may withdraw tenders of private bonds at any time prior to the
expiration of the exchange offer.
- We believe that the exchange of the private bonds will not be a taxable
event for U.S. federal income tax purposes.
- We will not receive any proceeds from the exchange offer.
- The terms of the exchange bonds are substantially identical to the terms
of the outstanding private bonds, except that the exchange bonds will be
registered under the Securities Act and freely tradeable.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
The date of this prospectus is February , 2000
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
--------
<S> <C>
Prospectus Summary.......................................... 1
Risk Factors................................................ 20
The Exchange Offer.......................................... 33
Use of Proceeds............................................. 42
Estimated Sources and Uses of Funds......................... 42
Capitalization.............................................. 44
Selected Financial Data..................................... 45
Management's Discussion and Analysis of Financial
Condition................................................. 46
Business.................................................... 56
Ownership and Management.................................... 67
Reports of Independent Consultants.......................... 71
Relationships and Related Transactions...................... 84
Description of the Principal Project Documents.............. 85
Description of the Exchange Bonds........................... 138
Description of the Principal Financing Documents............ 148
Federal Income Tax Considerations........................... 169
Plan of Distribution........................................ 174
Validity of the Exchange Bonds.............................. 175
Experts..................................................... 175
Independent Engineer........................................ 175
Independent Electricity Market and Fuel Consultant.......... 175
Available Information....................................... 175
Index to the Financial Statements........................... F-1
Annex-A Definitions......................................... A-1
Annex-B Independent Engineer's Report....................... B-1
Annex-C Independent Electricity Market and Fuel Consultant's
Report.................................................... C-1
Annex-D Form of Request for Information from the Trustee.... D-1
</TABLE>
------------------------
i
<PAGE>
PROSPECTUS SUMMARY
OUR NAME IS LSP ENERGY LIMITED PARTNERSHIP AND WE, AND OUR SISTER COMPANY,
LSP BATESVILLE FUNDING CORPORATION, WILL BE THE CO-ISSUERS OF THE EXCHANGE BONDS
BEING OFFERED IN THIS PROSPECTUS. THE FOLLOWING SUMMARY CONTAINS BASIC
INFORMATION ABOUT US AND ABOUT OUR AND THE FUNDING CORPORATION'S OFFERING OF THE
EXCHANGE BONDS. IT DOES NOT CONTAIN ALL OF THE INFORMATION THAT IS IMPORTANT TO
YOU. FOR A MORE COMPLETE UNDERSTANDING OF OUR BUSINESS AND FINANCIAL STATUS AND
THE EXCHANGE BONDS THAT WE AND THE FUNDING CORPORATION ARE OFFERING, YOU SHOULD
READ CAREFULLY THIS ENTIRE PROSPECTUS AND THE OTHER DOCUMENTS THAT WE WILL REFER
YOU TO. TERMS THAT ARE NOT DEFINED IN THE BODY OF THIS PROSPECTUS ARE DEFINED IN
ANNEX A.
THE EXCHANGE OFFER
<TABLE>
<S> <C>
Private Bonds........................ $150,000,000 7.164% series A senior secured bonds due
January 15, 2014 and $176,000,000 8.160% series B senior
secured bonds due July 15, 2025 that we and the Funding
Corporation issued together in May 1999.
Exchange Bonds....................... $150,000,000 7.164% series C senior secured bonds due
January 15, 2014, which we and the Funding Corporation will
offer in exchange for the series A bonds described above,
and $176,000,000 8.160% series D senior secured bonds due
July 15, 2025, which we and the Funding Corporation will
offer in exchange for the series B bonds described above.
The Exchange Offer................... We and the Funding Corporation are offering to exchange
$1,000 principal amount of 7.164% series C bonds and 8.160%
series D bonds for each $1,000 principal amount of 7.164%
series A bonds and 8.160% series B bonds, respectively, that
are properly tendered and accepted. We and the Funding
Corporation will issue the exchange bonds on or promptly
after the expiration date for the exchange offer. As of the
date of this prospectus, there is $326,000,000 aggregate
principal amount of private bonds outstanding.
Based on an interpretation by the staff of the Securities
and Exchange Commission set forth in no-action letters
issued to third parties, we believe that the exchange bonds
issued in the exchange offer may be offered for resale,
resold and otherwise transferred by a holder without
compliance with the registration and prospectus delivery
provisions of the Securities Act, if the holder is acquiring
exchange bonds in the ordinary course of its business and is
not participating, and had no arrangement or understanding
with any person to participate, in the distribution of the
exchange bonds.
Holders who tender their private bonds in the exchange offer
with the intention of participating in a distribution of the
exchange bonds will not be able to rely on the no-action
letters described above or similar no-action letters. Each
broker-dealer that receives exchange bonds for its own
account in exchange for private bonds, where the private
bonds were acquired by the broker-dealer as a result of
market-making activities or other trading activities, must
acknowledge that it will deliver a prospectus for any resale
of those exchange bonds.
Registration Rights
Agreement.......................... We and the Funding Corporation entered into a registration
rights
</TABLE>
1
<PAGE>
<TABLE>
<S> <C>
agreement dated as of May 21, 1999, which grants the holders
of the private bonds exchange and registration rights. The
exchange offer is intended to satisfy those rights, which
will terminate upon the consummation of the exchange offer.
The holders of the exchange bonds will not be entitled to
any exchange or registration rights with respect to the
exchange bonds.
Expiration Date...................... The exchange offer will expire at 5:00 p.m., New York City
time, on [ ], 2000, unless we, in our sole discretion,
extend the exchange offer, in which case the expiration date
for the exchange offer will be the latest date and time to
which we extend the exchange offer.
Accrued Interest on the Exchange
Bonds and the Private Bonds........ The exchange bonds will bear interest from and including the
date of issuance of the private bonds, which was May 21,
1999. The holders of the exchange bonds whose private bonds
are accepted for exchange will be deemed to have waived the
right to receive any interest accrued on the private bonds,
other than interest accrued from the date of initial
issuance of the exchange bonds and interest accrued on the
private bonds from the date of initial delivery to the date
of their exchange for exchange bonds.
Conditions to the Exchange Offer..... The exchange offer contains customary conditions that may be
waived by us. The exchange offer is not conditioned upon any
minimum aggregate principal amount of private bonds being
tendered for exchange.
Exchange Agent....................... The Bank of New York
Procedures for Tendering
Private Bonds...................... Each holder of private bonds wishing to accept the exchange
offer must complete, sign and date the letter of
transmittal, or a facsimile of the letter of transmittal, in
accordance with the instructions contained in this
prospectus and in the accompanying letter of transmittal,
and mail or otherwise deliver the letter of transmittal, or
the facsimile, together with their private bonds and any
other required documentation to the exchange agent at the
address set forth in this prospectus. By executing the
letter of transmittal, the holder will represent to and
agree with us and the Funding Corporation that, among other
things:
(1) the exchange bonds to be acquired by that holder of
private bonds in the exchange offer are being acquired by
that holder in the ordinary course of its business;
(2) if that holder is not a broker-dealer, that holder is
not participating in and has no arrangement or understanding
with any person to participate in a distribution of the
exchange bonds;
(3) if that holder is a broker-dealer registered under the
Exchange Act or is participating in the exchange offer for
the purposes of distributing the exchange bonds, that
holder will comply
</TABLE>
2
<PAGE>
<TABLE>
<S> <C>
with the registration and prospectus delivery
requirements of the Securities Act for a secondary
resale transaction of the exchange bonds acquired by
that person and cannot rely on the position of the
staff of the Securities and Exchange Commission set
forth in the no-action letters described above;
(4) that holder understands that a secondary resale
transaction described in clause (3) above and any resales of
exchange bonds obtained by that holder in exchange for
private bonds acquired by that holder directly from us
and the Funding Corporation should be covered by an
effective registration statement containing the selling
securityholder information required by Item 507 or Item
508, as applicable, of Regulation S-K of the Securities
and Exchange Commission; and
(5) that holder is not an "affiliate," as defined in Rule
405 under the Securities Act, of us or the Funding
Corporation.
Holders who tender their private bonds in the exchange offer
with the intention of participating in a distribution of the
exchange bonds will not be able to rely on the no-action
letters described above or similar no-action letters. If the
holder is a broker-dealer that will receive exchange bonds
for its own account in exchange for private bonds that were
acquired as a result of market-making activities or other
trading activities, that holder will be required to
acknowledge in the letter of transmittal that that holder
will deliver a prospectus for any resale of the exchange
bonds; however, by so acknowledging and by delivering a
prospectus, that holder will not be deemed to admit that it
is an "underwriter" within the meaning of the Securities
Act.
We will make this prospectus available to any participating
broker-dealer for any resale referred to in clause (3) above
for a period of 30 days after the expiration of the exchange
offer.
Special Procedures for Beneficial
Owners............................. Any beneficial owner whose private bonds are registered in
the name of a broker, dealer, commercial bank, trust company
or other nominee and who wishes to tender its private bonds
in the exchange offer should contact the registered holder
promptly and instruct the registered holder to tender on the
beneficial owner's behalf. If the beneficial owner wishes to
tender on its own behalf, it must, prior to completing and
executing the letter of transmittal and delivering its
private bonds, either make appropriate arrangements to
register ownership of the private bonds in the beneficial
owner's name or obtain a properly completed bond power from
the registered holder. The transfer of registered ownership
may take considerable time and may not be able to be
completed prior to the expiration date for the exchange
offer.
</TABLE>
3
<PAGE>
<TABLE>
<S> <C>
Guaranteed Delivery
Procedures......................... Holders of private bonds who wish to tender their private
bonds and whose private bonds are not immediately available
or who cannot deliver their private bonds, the letter of
transmittal or any other documentation required by the
letter of transmittal to the exchange agent prior to the
expiration date for the exchange offer must tender their
private bonds according to the guaranteed delivery
procedures described later in this prospectus.
Acceptance of the Private
Bonds and Delivery of the
Exchange Bonds..................... Subject to the satisfaction or waiver of the conditions to
the exchange offer, we will accept for exchange any and all
private bonds that are properly tendered in the exchange
offer prior to the expiration date for the exchange offer.
The exchange bonds issued in the exchange offer will be
delivered on the earliest practicable date following the
expiration date.
Withdrawal Rights.................... Tenders of private bonds may be withdrawn at any time prior
to the expiration date for the exchange offer.
Federal Income Tax Considerations.... The exchange of private bonds for exchange bonds in the
exchange offer will not constitute a sale or an exchange for
federal income tax purposes. Accordingly, this exchange will
have no federal income tax consequences to you.
</TABLE>
4
<PAGE>
THE EXCHANGE BONDS
The exchange offer described in this prospectus applies to $326,000,000 in
aggregate principal amount of our and the Funding Corporation's private bonds.
The form and terms of the exchange bonds are the same as the form and terms of
the private bonds except that:
(1) the exchange bonds will have been registered under the Securities
Act and, therefore, the exchange bonds will not bear legends restricting the
transfer of the exchange bonds; and
(2) holders of the exchange bonds will not be entitled to rights
governing the exchange offer under the registration rights agreement that we
and the Funding Corporation entered into with the initial purchasers of the
private bonds, which rights will terminate upon consummation of the exchange
offer.
The exchange bonds will evidence the same indebtedness as the private bonds,
which they replace, and will be issued under, and be entitled to the benefits
of, the indenture which governs both the private bonds and the exchange bonds.
References to the bonds are to both the private bonds and the exchange bonds.
<TABLE>
<S> <C>
The Bonds Offered............................ $150,000,000 principal amount of 7.164% series C
senior secured bonds due 2014.
$176,000,000 principal amount of 8.160% series D
senior secured bonds due 2025.
Maturity Date................................ Series C bonds: January 15, 2014.
Series D bonds: July 15, 2025.
Interest Payment Dates....................... January 15 and July 15, beginning on January 15,
2000. Interest due and payable during the
construction phase of our project will be paid with
proceeds from our offering of the private bonds,
which we deposited in the construction account. The
bondholders have a security interest in the
construction account.
Scheduled Principal Payments................. We will be required to pay principal of the series C
bonds on each January 15 and July 15, commencing on
July 15, 2001, as follows:
</TABLE>
<TABLE>
<CAPTION>
PERCENTAGE OF
PRINCIPAL
PAYMENT DATE AMOUNT PAYABLE
--------------------------------------- --------------
<S> <C> <C>
July 15, 2001.......................... 2.75%
January 15, 2002....................... 2.75%
July 15, 2002.......................... 2.30%
January 15, 2003....................... 2.30%
July 15, 2003.......................... 2.45%
January 15, 2004....................... 2.45%
July 15, 2004.......................... 2.60%
January 15, 2005....................... 2.60%
July 15, 2005.......................... 3.80%
January 15, 2006....................... 3.80%
July 15, 2006.......................... 4.15%
January 15, 2007....................... 4.15%
</TABLE>
5
<PAGE>
<TABLE>
<CAPTION>
PERCENTAGE OF
PRINCIPAL
PAYMENT DATE AMOUNT PAYABLE
--------------------------------------- --------------
<S> <C> <C>
July 15, 2007.......................... 4.20%
January 15, 2008....................... 4.20%
July 15, 2008.......................... 4.35%
January 15, 2009....................... 4.35%
July 15, 2009.......................... 4.50%
January 15, 2010....................... 4.50%
July 15, 2010.......................... 4.70%
January 15, 2011....................... 4.70%
July 15, 2011.......................... 5.10%
January 15, 2012....................... 5.10%
July 15, 2012.......................... 5.10%
January 15, 2013....................... 5.10%
July 15, 2013.......................... 4.00%
January 15, 2014....................... 4.00%
We will be required to pay principal of the series D
bonds on each January 15 and July 15, commencing on
July 15, 2014, as follows:
<CAPTION>
PERCENTAGE OF
PRINCIPAL
PAYMENT DATE AMOUNT PAYABLE
--------------------------------------- --------------
July 15, 2014. 2.65%
<S> <C> <C>
January 15, 2015....................... 2.65%
July 15, 2015.......................... 2.85%
January 15, 2016....................... 2.85%
July 15, 2016.......................... 2.85%
January 15, 2017....................... 2.85%
July 15, 2017.......................... 3.00%
January 15, 2018....................... 3.00%
July 15, 2018.......................... 2.90%
January 15, 2019....................... 2.90%
July 15, 2019.......................... 3.45%
January 15, 2020....................... 3.45%
July 15, 2020.......................... 2.15%
January 15, 2021....................... 2.15%
July 15, 2021.......................... 5.25%
January 15, 2022....................... 5.25%
July 15, 2022.......................... 5.35%
January 15, 2023....................... 5.35%
July 15, 2023.......................... 5.40%
January 15, 2024....................... 5.40%
July 15, 2024.......................... 6.90%
January 15, 2025....................... 6.90%
July 15, 2025.......................... 14.50%
Initial Average Life......................... Series C bonds: approximately 9.2 years.
Series D bonds: approximately 22.1 years.
Ratings...................................... "Baa3" by Moody's Investors Service, Inc. and "BBB-" by
Standard & Poor's Ratings Group.
</TABLE>
6
<PAGE>
<TABLE>
<S> <C> <C>
Denomination................................. We will issue the exchange bonds in minimum
denominations of $1,000.
Ranking of the Bonds......................... The bonds:
- are senior secured indebtedness;
- are equivalent in right of payment to all of our
existing and future senior indebtedness; and
- rank senior to all of our subordinated
indebtedness.
Credit Suisse First Boston has agreed to issue letters
of credit for our account under a letter of credit and
reimbursement agreement. We currently, and will
continue to, use these letters of credit to provide
credit suppport in favor of one of our power
purchasers. Currently, there is one letter of credit
outstanding under this agreement, which runs in favor
of Virginia Power and is in the amount of $5,660,000.
To date, no drawings have been made under this letter
of credit. The letter of credit and reimbursement
agreement also provides for the issuance of two
additional letters of credit, each in the amount of
$5,660,000. Our obligation to reimburse Credit Suisse
First Boston for drawings on the letters of credit, and
our other obligations under the letter of credit and
reimbursement agreement, rank equally in right of
payment with the bonds and share equally in the
collateral with the bonds. Other than these
obligations, we have no existing senior secured debt
that ranks equally with the bonds.
The obligations to pay principal of, premium, if any,
Nonrecourse Obligations...................... and interest on the bonds will be solely our
obligations and those of the Funding Corporation.
Neither our partners nor the Funding Corporation's
shareholder, nor any of our or the Funding
Corporation's affiliates, employees, officers or
directors, or any other person or entity, will
guarantee the bonds or have any obligation to make any
payments on the bonds.
Collateral................................... The bonds are secured by:
- a mortgage on the site of our power facility and
the related easements;
- a security interest in all of our personal
property, including our power purchase agreements,
our other contracts and the assets comprising our
power facility, but excluding the accounts that
we may establish for the benefit of
Aquila/UtiliCorp, one of our power purchasers;
- a pledge of all of our limited and general
partnership interests; and
- a pledge of all of the capital stock of our
general partner and the Funding Corporation.
</TABLE>
7
<PAGE>
<TABLE>
<S> <C> <C>
Redemption at Our Option..................... We may redeem any or all of the series C bonds and/or
the series D bonds at a redemption price equal to:
- 100% of the principal amount of the bonds being
redeemed, PLUS
- accrued and unpaid interest on the bonds being
redeemed, PLUS
- a make-whole premium which is based on the
rates of treasury securities with average lives
comparable to the remaining average lives of
the applicable bonds plus 30 basis points in
the case of the series C bonds or 50 basis
points in the case of the series D bonds.
Mandatory Redemption......................... If our project is damaged or destroyed or taken by
eminent domain, or if there is a defect in our title
to the site of our project, and
- we receive more than $5,000,000 of insurance or
other proceeds because of the damage,
destruction, taking or defect and we decide not
to, or cannot, restore our project or fix the
title defect to make our project operate on a
commercially feasible basis, then we must use
the proceeds we received to redeem bonds and
prepay any of our other senior secured
obligations that require prepayment upon the
receipt of these proceeds; or
- we receive insurance or other proceeds because
of the damage, destruction, taking or defect and
more than $5,000,000 of the proceeds are left
over after we have restored our project or
fixed the title defect to make our project
operate on a commercially feasible basis, then
we must use the proceeds in excess of
$5,000,000 that remain after we have restored
our project to redeem bonds and prepay any of
our other senior secured obligations that
require prepayment upon receipt of these
proceeds, unless we receive a confirmation of
the then current ratings of the bonds.
If we are required to redeem bonds as described
above, the redemption price will be 100% of the
principal amount of the bonds being redeemed plus
accrued and unpaid interest on the bonds being
redeemed.
If we receive more than $10,000,000 of performance
liquidated damages under the main construction
contract for our project, then we must use these
proceeds to redeem bonds and prepay any of our other
senior secured obligations that require prepayment
upon the receipt of performance liquidated damages,
unless we receive a confirmation of the then current
ratings of the bonds. If we
</TABLE>
8
<PAGE>
<TABLE>
<S> <C> <C>
are required to redeem bonds with performance
liquidated damages, the redemption price will be 100%
of the principal amount of the bonds being redeemed
plus accrued and unpaid interest on the bonds being
redeemed.
If we receive more than $10,000,000 of proceeds from
buy-outs of our power purchase agreements, then we
must use these proceeds to redeem bonds and prepay
any of our other senior secured obligations that
require prepayment upon the receipt of buy-out
proceeds, unless we receive a confirmation of the
then current ratings of the bonds. If we are required
to redeem bonds with the proceeds of power contract
buy-outs, then the redemption price will be 100% of
the principal amount of the bonds being redeemed plus
accrued and unpaid interest on the bonds being
redeemed.
At the time we receive loss proceeds, performance
liquidated damages or buy-out proceeds, we may have
senior secured obligations in addition to the bonds
which by their terms require us to use these proceeds
or damage payments to prepay all or a portion of the
obligations. If so, the proceeds or damage payments
will be allocated among the bonds and the other
senior secured obligations that require prepayment on
a pro rata basis according to the principal amount of
the obligation to be redeemed or prepaid which is
outstanding at the time we receive the proceeds or
damage payments.
Redemption at the Option of the
Bondholders................................ If:
- funds remain on deposit in the distribution
suspense account for at least 12 months in a row,
and
- we cause the holders of the bonds to vote on
whether we should use those funds to redeem
bonds, and
- holders of at least 66 2/3% of the outstanding
bonds vote to require us to use those funds to
redeem bonds,
then we will have to use the funds which have
remained on deposit in the distribution suspense
account for at least 12 months in a row to redeem
bonds and prepay any of our other senior secured
obligations that require prepayment under those
circumstances. If we are required to redeem bonds
with those funds, then the redemption price will be
100% of the principal amount of the bonds being
redeemed plus accrued and unpaid interest on the
bonds being redeemed. If we are not required to
redeem bonds with those funds following the vote of
the holders of the bonds, and if none of our other
senior secured obligations requires us to apply these
funds to their prepayment, then we will
</TABLE>
9
<PAGE>
<TABLE>
<S> <C> <C>
be permitted to distribute those funds to our
partners without regard to the satisfaction of the
debt service coverage ratio tests contained in the
indenture.
Change of Control............................ If:
- LS Power, LLC, Cogentrix Energy, Inc. and/or
any qualified third party experienced in owning
and operating power generation facilities
collectively cease to own, directly or
indirectly, at least 51% of the capital stock
of our general partner (unless any or all of
them maintain management control of us), or
- LS Power, LLC, Cogentrix Energy, Inc. and/or
any qualified and experienced third party of the
type described above collectively cease to own,
directly or indirectly, at least 10% of the
ownership and economic interest in us,
then we must offer to purchase all of the bonds at a
purchase price equal to 101% of the outstanding
principal amount of the bonds plus accrued and unpaid
interest unless we receive a confirmation of the then
current ratings of the bonds or at least 66 2/3% of
the holders of the outstanding bonds approve the
change in ownership.
Operating Flow of Funds...................... After completion of our project, we will deposit all
of our revenues into the revenue account and disburse
these revenues each month to pay operating and
maintenance expenses, management fees and expenses
and debt service, and to fund reserve accounts which
the indenture requires us to maintain. Funds
remaining in the revenue account after making these
disbursements will be transferred to the distribution
suspense account.
We use the funds on deposit in the distribution
suspense account to make distributions to our limited
partner, LSP Batesville Holding, LLC and our general
partner, LSP Energy, Inc. We are permitted to make
these distributions once each month if we satisfy the
following conditions:
- we have made all required disbursements from
the revenue account to pay operating and
maintenance expenses, management fees and
expenses and debt service;
- we have set aside sufficient reserves to pay
principal and interest payments on the bonds and
our other senior secured debt;
- no default or event of default under the
indenture for the bonds has occurred and is
continuing;
- our historical and projected debt service
coverage ratios equal or exceed the required
levels;
</TABLE>
10
<PAGE>
<TABLE>
<S> <C> <C>
- we have sufficient funds in our accounts to
meet our ongoing working capital needs;
- our power facility is complete; and
- we make the distributions on or after the last
business day of September 2000.
Reserves Required for Distributions.......... We will not be allowed to make distributions unless
the total amount of funds in our debt service payment
account, debt service reserve account and
distribution suspense account is equal to or greater
than the sum of:
(1) a debt service reserve equal to:
- if the distribution is being made on a
scheduled payment date for the bonds, the
principal and interest payments due on all of
our senior secured debt on that date;
- if the distribution is being made on any other
date, the principal and interest payments due on
all of our senior secured debt on the next
scheduled payment date for the bonds; plus
(2) the aggregate of the principal, interest and
other payments which will be due on all of our senior
debt on the next semiannual payment date; plus
(3) the aggregate of the principal, interest and
other payments we will be required to make on our
senior debt between the distribution date and the
next semiannual payment date.
Additional Indebtedness...................... The indenture permits us to incur indebtedness in
addition to the bonds. For example, we are allowed to
incur additional indebtedness in order to:
- finance modifications or improvements to our
project which are necessary (1) to comply with
applicable law or (2) to complete our project
after all other funds available for this
purpose have been depleted, if:
- after giving effect to the financing, our
minimum projected senior debt service
coverage ratio for each fiscal year for the
remaining term of the bonds will be greater
than or equal to
(1) 1.20/1.00 during any period in which
all of the then current capacity of our
power facility is sold under our
existing power purchase agreements or
other power purchase agreements which
satisfy the criteria set forth in the
indenture,
(2) 1.35/1.00 during any period in which at
least 66 2/3% but less than 100% of the
then
</TABLE>
11
<PAGE>
<TABLE>
<S> <C> <C>
current capacity of our power facility
is sold under our existing power
purchase agreements or other power
purchase agreements which satisfy the
criteria set forth in the indenture and
(3) 1.50:1.00 during any other period, or
- we receive a confirmation of the then
current ratings of the bonds.
- finance improvements to our project which are
not necessary to comply with applicable law, if
either:
(A) after giving effect to the financing:
- our minimum projected senior debt service
coverage ratio for each fiscal year for the
remaining term of the bonds will be greater
than or equal to
(1) 1.45/1.00 during any period in which
all of the then current capacity of our
power facility is sold under our
existing power purchase agreements or
other power purchase agreements which
satisfy the criteria set forth in the
indenture,
(2) 1.70/1.00 during any period in which at
least 66 2/3% but less than 100% of the
then current capacity of our power
facility is sold under our existing
power purchase agreements or other
power purchase agreements which satisfy
the criteria set forth in the indenture
and
(3) 2.00/1.00 during any other period, and
- our average annual projected senior debt
service coverage ratio for the remaining term
of the bonds will be greater than or equal
to
(1)1.45/1.00 during any period in which all
of the then current capacity of our power
facility is sold under our existing
power purchase agreements or other power
purchase agreements which satisfy the
criteria set forth in the indenture,
(2) 1.75/1.00 during any period in which at
least 66 2/3% but less than 100% of the
then current capacity of our power
facility is sold under our existing
power purchase agreements or other
power purchase agreements which satisfy
the criteria set forth in the indenture
and
(3) 2.25/1.00 during any other period, or
</TABLE>
12
<PAGE>
<TABLE>
<S> <C> <C>
(B) we receive a confirmation of the then current
ratings of the bonds.
- finance an expansion of our project, if we
receive a confirmation of the then current
ratings of the bonds.
Covenants.................................... We have agreed to, among other things:
- maintain our existence,
- obtain and comply with applicable governmental
approvals,
- comply with applicable laws,
- maintain insurance for our power facility,
- provide financial statements, default notices
and other notices to the trustee,
- prepare a major maintenance plan,
- maintain our status as an exempt wholesale
generator, and
- pay our taxes.
We have agreed not to, among other things:
- create any lien on our properties other than
permitted liens,
- make any distributions other than as permitted
under the indenture,
- engage in any business other than the
development, financing, construction, operation
and expansion of our project,
- make any investment other than permitted
investments, or
- enter into non-arm's length transactions with
our affiliates.
These affirmative and negative covenants are affected
by a number of important qualifications and
exceptions.
Trustee, Administrative Agent and Collateral
Agent...................................... The Bank of New York.
Independent Engineer......................... The independent engineer for our project will be
responsible for, among other things, providing
confirmations and reports to the trustee and the
administrative agent with respect to:
- construction drawdowns and concurrence with
certifications made by us under the indenture
which relate to technical matters;
</TABLE>
13
<PAGE>
<TABLE>
<S> <C> <C>
- material change order requests under the main
construction contract;
- the occurrence of completion of our project;
- review of the annual operating budget; and
- upon our receipt of insurance and other loss
proceeds:
(1) whether it is commercially feasible to
repair, rebuild, restore or replace our power
facility; or
(2) whether the insurance or other proceeds
will not be sufficient to repair, rebuild,
restore or replace our project.
Independent Electricity Market and Fuel The independent electricity market and fuel
Consultant................................. consultant for our project will be responsible for
providing projections of market prices for
electricity which we will use to confirm
certifications that we will make with respect to
projections of debt service coverage ratios during
periods in which less than all of the capacity of our
power facility is being disposed of under long term
power purchase agreements.
</TABLE>
OUR COMPANY
We were formed to develop, construct, own, operate and finance our gas-fired
power plant facility in Batesville, Mississippi that will include three
combined-cycle electric generation units. Our power facility also includes an
electrical substation on our site and the transmission lines that connect the
substation with two utility transmission systems. The project described in this
prospectus includes our power facility and all its associated contracts. Our
power facility is already under construction. Though we may expand our power
facility after the offering of the exchange bonds by constructing additional
electric generation capacity at the project site, we do not intend to engage in
any business activities other than those related to our project.
Our sister company, LSP Batesville Funding Corporation, will be the
co-issuer of the exchange bonds that we are offering in this prospectus. The
Funding Corporation was formed for the sole purpose of issuing the bonds and
incurring other debt to finance our project. The Funding Corporation has nominal
assets and will not conduct any operations.
Our principal executive offices are located at Two Tower Center, 20th Floor,
East Brunswick, New Jersey 08816. Our telephone number is (732) 249-6750.
We are indirectly owned primarily by LS Power, LLC and Cogentrix
Energy, Inc. For a more detailed description of our ownership structure, please
see the chart on the next page.
14
<PAGE>
[CHART]
(*) This percentage could be adjusted based on the limited liability company
operating agreement of LSP Batesville Holding, LLC. which is described later
in this prospectus.
15
<PAGE>
OUR PROJECT
GENERAL DESCRIPTION. Our power facility, which is in the process of being
constructed, will be an approximately 837 megawatt natural gas-fired, three
combined-cycle unit electric generation facility. Natural gas-fired facilities
are those which use natural gas as a fuel source. Combined-cycle facilities are
those which use the exhaust heat produced by a combustion turbine to generate
steam, which is in turn used to make electricity in a steam turbine. Each of the
three combined-cycle "units" of our power facility will therefore contain three
main pieces of equipment: (1) a gas-fired combustion turbine; (2) a heat
recovery steam generator; and (3) a steam turbine, plus auxiliary equipment.
KEY PROJECT DOCUMENTS. The chart below depicts some of the key contracts
for our project.
[CHART]
16
<PAGE>
CONSTRUCTION OF OUR POWER FACILITY. The main contractor for most of our
power facility, BVZ Power Partners-Batesville, is a joint venture between
Black & Veatch Construction, Inc. and H.B. Zachry Company. BVZ Power Partners
has agreed to design, engineer, procure equipment for, construct, test and
start-up our power facility, other than the electric substation and transmission
lines. We have agreed to pay BVZ Power Partners a fixed price of approximately
$240,174,000 for doing this work in accordance with the construction contract
that we have entered into with BVZ Power Partners. We gave BVZ Power Partners a
notice to proceed with the work on our power facility on August 28, 1998. Since
that time, we have agreed on change orders under this construction contract
which have increased the contract price by about $176,000. These change orders
are covered by the contingency funds provided for in our budget. Engineering and
procurement under the facility construction contract is complete and overall
construction is about 90% complete. BVZ Power Partners has invoiced us for 93%
of the fixed price of the construction contract. We currently expect that BVZ
Power Partners' work on our power facility will be completed during the second
quarter of 2000.
We have also entered into construction and supply contracts with Lauren
Constructors, Inc., North American Transformer, Inc. and Siemens Power
Transmission and Distribution, LLC for the design, engineering, procurement,
testing and start-up of our electrical substation and transmission lines that
will interconnect our substation with the utility transmission systems described
below. We have agreed to pay these contractors and suppliers approximately
$9,130,000 in the aggregate. The work on these facilities is complete.
SALE OF POWER FROM OUR POWER FACILITY. We have entered into two long-term
power purchase agreements for the sale of the capacity of and electric energy
from our power facility. One of those agreements is with Virginia Electric and
Power Company and covers the sale of the capacity of and electric energy from
two of our power facility's generating units for an initial term of 13 years,
which Virginia Power can extend at its option for an additional 12 years. The
other agreement is with UtiliCorp United Inc. and Aquila Energy Marketing
Corporation and covers the sale of the capacity of and electric energy from our
power facility's other generating unit for an initial term of 15 years and seven
months, which Aquila/UtiliCorp can extend at its option for an additional five
years. When our agreements with Virginia Power and Aquila/UtiliCorp expire, we
will either enter into new long-term power purchase agreements with other
customers and/or will sell the capacity of and energy from our power facility on
a "merchant" basis. This means that we will sell our capacity and electric
energy to the market on the basis of shorter term or "spot" contracts.
These power purchase agreements require Virginia Power and Aquila/UtiliCorp
to provide us with the natural gas which we will use to fuel the generating
units that are dedicated to the applicable purchaser. In addition, both of these
power purchase agreements require the applicable purchaser to make the following
payments to us:
(1) a monthly "reservation" payment based on the tested capacity and
availability of the units dedicated to the purchaser;
(2) an "energy" payment based on the amount of energy that we actually
produce for the purchaser and deliver to the interconnection point
between our power facility and the utility transmission systems described
below; and
(3) other payments, including payments based upon the fuel efficiency of the
generating units and the number of times we start up the units each year.
Both of these power purchase agreements allow the power purchaser to dispatch
the units we have dedicated to them, meaning that the power purchasers have the
right to control how much electricity they want their dedicated units to
produce. However, even if we are not dispatched at all by Virginia Power and
Aquila/UtiliCorp, they will still have to pay us a reservation payment as
provided under the power purchase agreements.
17
<PAGE>
OPERATION OF OUR POWER FACILITY. Cogentrix Batesville Operations, LLC,
which is a subsidiary of Cogentrix Energy, Inc., has agreed to operate most of
our project for 27 years. Under the operation and maintenance agreement that we
have entered into with this operator, we will pay Cogentrix Batesville
Operations its reimbursable expenses plus a fee of $41,667 per month, which
escalates annually, to perform customary operations and maintenance services for
most of our project. We will agree to pay this fee to Cogentrix Batesville
Operations only if we have allocated the required funds to our debt service and
reserve accounts in accordance with the financing documents. We will also pay
Cogentrix Batesville Operations its reimbursable expenses plus a fee of
$390,000, payable in ten monthly installments, for services performed by
Cogentrix Batesville Operations prior to the date on which our units are
scheduled to enter commercial operation.
PANOLA COUNTY INFRASTRUCTURE RELATED TO OUR FACILITY. In order for our
power facility to operate it needs access to gas and water. Panola County has
almost completed the construction of pipelines and related facilities that we
will use to transport gas and water to our power facility and to transport
wastewater away from our power facility. The construction of this
infrastructure, which is being done for Panola County by three contractors, is
98% complete. Although all work on the infrastructure has not been completed by
the contractors, the infrastructure has been placed in service and is being used
to support completion of our power facility. In the future, Panola County might
transfer its ownership of the infrastructure to the Industrial Development
Authority of Panola County. In anticipation of this possible transfer, we have
entered into lease agreements with both Panola County and the Industrial
Development Authority under which we have leased the Panola County
infrastructure on terms that give us the right to use the capacity of the
infrastructure to an extent that should be sufficient to operate our power
facility.
GAS PIPELINE INTERCONNECTIONS. Our power facility is connected through the
lateral gas pipeline to the Tennessee Gas Pipeline Company's and ANR Pipeline
Company's interstate gas pipelines. The ANR Pipeline and Tennessee Gas
interconnection facilities have been completed, and each is capable of
delivering our power facility's entire fuel requirements to the lateral gas
pipeline. We plan to contract with an experienced gas pipeline operator to
coordinate operation of the lateral gas pipeline with ANR Pipeline and Tennessee
Gas.
WATER SUPPLY. Through the infrastructure described above, we have the
ability to obtain water from Enid Lake and to dispose of our power facility's
wastewater into the Little Tallahatchie River. We have entered into an agreement
with the United States government that will allow us to withdraw water from Enid
Lake. In addition, we have obtained the permits we will need to dispose of water
into the Little Tallahatchie River. The operation and maintenance of the water
supply and discharge pipelines and water intake system will be performed by
Cogentrix Batesville Operations.
ELECTRICAL INTERCONNECTIONS. In order to deliver electricity to our power
purchasers, we have arranged to have our power facility interconnected to two
utility transmission systems. We have entered into separate interconnection
agreements with each of the Tennessee Valley Authority and Entergy
Mississippi, Inc., each of which has an initial term of 35 years. These
agreements require us to construct and install a portion of the equipment that
will be used to interconnect our power facility with the transmission grids,
which BVZ Power Partners, Lauren Constructors, North American Transformer, Inc.
and Siemens Power Transmission and Distribution, LLC have done, and require the
Tennessee Valley Authority and Entergy to construct the remainder of that
equipment, at our expense. Following the completion of the Tennessee Valley
Authority and Entergy system upgrades described in the next paragraph, we expect
each of these interconnections to be capable of accepting the entire electrical
output of our power facility under most operating conditions. These agreements
allow the Tennessee Valley Authority and Entergy to disconnect or curtail our
power facility's output to overcome reliability problems, to facilitate
restoration of line or equipment outages, for maintenance activities or if a
hazardous condition exists.
18
<PAGE>
Although our power purchasers are responsible for the transmission of our
electricity from our interconnection point across the Tennessee Valley Authority
and Entergy transmission grids, we have agreed with the Tennessee Valley
Authority and Entergy to pay for the costs of upgrading their transmission
systems so that each transmission system can handle the entire electrical output
of our power facility under most operating conditions. These upgrades will be
owned by the Tennessee Valley Authority and Entergy. In exchange, the Tennessee
Valley Authority and Entergy have agreed to credit us or our power purchasers an
amount equal to the lesser of (1) the revenues that they receive from our power
purchasers and their customers for transmission services provided for the
delivery of energy from our power facility and (2) the total costs paid by us
for the system upgrades. Our recovery of these credits is dependent upon the
availability of transmission service from the Tennessee Valley Authority and
Entergy for, and the use of this transmission service by, our power purchasers
and their customers.
OUR FINANCING PLAN
We estimate that the total cost of developing, constructing, financing and
commissioning our project and the gas and water infrastructure that our facility
will use will be approximately $396,406,000. We had an outstanding loan, which
we used to pay $136,600,000 of development and construction costs associated
with our project and the Panola County gas and water infrastructure. We used
$136,600,000 of the net proceeds of the private bonds to repay that loan in
full. We used or will use the rest of the net proceeds of the private bonds to
pay a portion of the remaining costs of our project. The net proceeds that we
received from the sale of the private bonds covered approximately 86% of the
total project costs described above. To cover the rest of those costs, LSP
Batesville Holding, LLC will make equity contributions to us from time to time
in the aggregate amount of $54,000,000 after we have used all of the proceeds of
the private bonds. To support this equity contribution obligation, Cogentrix
Energy, Inc. has obtained a $54,000,000 letter of credit for the benefit of the
holders of the bonds and our other senior creditors. We will have no obligation
to reimburse draws under this letter of credit.
19
<PAGE>
RISK FACTORS
AN INVESTMENT IN THE BONDS INVOLVES A SIGNIFICANT DEGREE OF RISK, INCLUDING
THE RISKS DESCRIBED BELOW. YOU SHOULD CAREFULLY CONSIDER THE RISKS DESCRIBED
BELOW AND THE OTHER INFORMATION CONTAINED IN THIS PROSPECTUS BEFORE MAKING AN
INVESTMENT IN THE BONDS.
EXCHANGE OFFER RISK
THERE MAY BE ADVERSE CONSEQUENCES IF YOU DO NOT EXCHANGE YOUR PRIVATE BONDS
BECAUSE THEY WILL CONTINUE TO BE AFFECTED BY TRANSFER RESTRICTIONS AND MAY BE
MORE DIFFICULT TO SELL.
If you do not exchange your private bonds in the exchange offer, then you will
continue to be affected by the transfer restrictions on the private bonds
described in the offering circular distributed for the sale of the private
bonds. In general, the private bonds may not be offered or sold unless they are
registered or exempt from registration under the Securities Act of 1933 and
applicable state securities laws. Except as required by the registration rights
agreement, we do not intend to register resales of the private bonds under the
Securities Act of 1933. You should refer to "The Exchange Offer" for information
about how to tender your private bonds.
The tender of private bonds under the exchange offer will reduce the
principal amount of the private bonds outstanding, which may have an adverse
effect upon, and increase the volatility of, the market price of the private
bonds due to a reduction in liquidity.
CONSTRUCTION AND OPERATING RISKS
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 large power plant projects,
including:
1) shortages of equipment, materials or labor;
2) work stoppages or other labor disputes;
3) weather problems;
4) unforeseen engineering, environmental, permitting or geological
problems;
5) unanticipated cost increases for reasons beyond our control or our
contractors' control; and
6) other unforeseen circumstances.
If any of these kinds of 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. Any of
these results could decrease the amount of cash that we have available, and
therefore could cause us to be unable to make payments on the bonds and our
other debt when due.
We received a force majeure notice from BVZ Power Partners, the construction
contractor for our power facility, and ABB Power Generation, Inc., the
manufacturer of our steam turbines, with respect to transportation delays
incurred during the delivery of one of the Virginia Power generating unit's
steam turbine generators to our power facility. We requested that ABB Power
Generation provide additional information to support the claim of force majeure.
In response to our request, ABB Power Generation has recently provided
information indicating a total of 21 days of delay and an 18 day claim of force
majeure for delay in the delivery of the steam turbine generator. We do not
believe that the delays in transportation of the steam turbines constitute a
force majeure event. However, a final resolution of the issue has not yet
occurred and, in any event, the 21 day transportation delay could have an
adverse impact on the schedule for completing our power facility.
20
<PAGE>
BVZ Power Partners has indicated in its monthly progress reports that it is
evaluating the impacts of abnormally high rainfall during several months of
construction. The implication is that BVZ Power Partners could submit a claim of
force majeure to us in the future. To date, BVZ Power Partners has not submitted
a force majeure claim.
WE MAY INCUR ADDITIONAL COSTS OR EXPERIENCE A REDUCTION IN REVENUE UNDER OUR
POWER PURCHASE AGREEMENTS IF THE GENERATING UNITS INCLUDED IN OUR POWER FACILITY
ARE NOT OPERATING BY THE DATE ON WHICH OUR DELIVERY OBLIGATIONS UNDER OUR POWER
PURCHASE AGREEMENTS BEGIN. MOREOVER, BVZ POWER PARTNERS HAS NOT GUARANTEED THAT
IT WILL COMPLETE THE GENERATING UNITS BY THAT DATE.
We have agreed with Virginia Power and Aquila/UtiliCorp that their
respective generating units will be able to begin delivering power to them by
June 1, 2000, which date may be extended as a result of force majeure or other
excused delays. However, BVZ Power Partners has not guaranteed that it will
substantially complete our power facility by this date. Instead, BVZ Power
Partners has guaranteed to substantially complete the two units that will
provide power to Virginia Power by July 16, 2000 and July 26, 2000 and to
substantially complete the unit that will provide power to Aquila/UtiliCorp by
July 31, 2000. Each of these dates may be extended in accordance with the terms
of the construction contract in some circumstances. For example, the July 16,
2000 date may be extended if any portion of the 21 day transportation delay
associated with the ABB Power Generation steam turbine generator is determined
to be a force majeure event. If BVZ Power Partners does not substantially
complete the units by the day following the guaranteed completion dates, as
those dates may be extended under the construction contract, BVZ Power Partners
will have to pay us the delay liquidated damages described in the construction
contract. However, we will not receive any liquidated damages from BVZ Power
Partners for any period between the start of our delivery obligations under the
power purchase agreements and the day following the guaranteed completion dates
under the construction contract.
If the generating units are not substantially complete by the date on which
we have agreed to begin delivery under our power purchase agreements, we may:
(1) be required to supply replacement power to Virginia Power or reimburse
Virginia Power for any incremental replacement power cost that Virginia
Power incurs between the date on which we have agreed to begin delivery
under the Virginia Power power purchase agreement and the date on which
each Virginia Power unit is substantially complete, up to a maximum of
$5,660,000 per unit;
(2) be required to do one of the following:
- supply Aquila/UtiliCorp with replacement power,
- reimburse Aquila/UtiliCorp for any incremental replacement power cost
that they incur or
- elect a delivery delay adjustment to the reservation payments that
Aquila/UtiliCorp must pay us under the Aquila/UtiliCorp power purchase
agreement,
in each case, between the date on which we have agreed to begin delivery
under the Aquila/ UtiliCorp power purchase agreement and the date on
which the Aquila/UtiliCorp unit is substantially complete; and
(3) incur other increased costs as a result of the delay and forego some
revenues under our power purchase agreements during the period of delay.
The current construction schedule that has been provided to us by BVZ Power
Partners anticipates that substantial completion of the two Virginia Power units
and the one Aquila/Utilicorp unit will occur on May 10, 2000, June 5, 2000 and
June 27, 2000, respectively. Therefore, one Virginia Power unit and the
Aquila/Utilicorp unit are projected to be complete after June 1, 2000, the date
on which, unless adjusted for excused delays, we are required to begin
delivering power to Virginia Power and Aquila/ UtiliCorp under the power
purchase agreements. As a result of these projected completion dates, we
21
<PAGE>
have notified Virginia Power and Aquila/Utilicorp of the projected completion
dates and we have notified Aquila/Utilicorp of our election to incur a delivery
delay adjustment in the event that the Aquila/Utilicorp unit is completed after
the date on which we agreed to begin delivery of energy under the
Aquila/Utilicorp power purchase agreement. If BVZ Power Partners were to
complete the second Virginia Power unit by June 5, 2000, we would either supply
replacement power to Virginia Power or reimburse Virginia Power for the cost of
incremental replacement power during the period from June 1, 2000 to June 5,
2000. Our reimbursement would be limited by the $5,660,000 limit described
above. Accordingly, construction delays generally, together with the fact that
we have committed to specified delivery dates with our power purchasers while
BVZ Power Partners has not committed to complete the units by those dates, could
cause us to be unable to make payments on the bonds and our other debt when due.
THE LIQUIDATED DAMAGES THAT WE MAY RECEIVE FROM OUR CONTRACTORS MAY NOT
FULLY COMPENSATE US FOR OUR LOSSES IF THERE IS A CONSTRUCTION DELAY.
BVZ Power Partners is obligated to pay us delay liquidated damages if it
fails to substantially complete a generating unit by the day after it has
guaranteed that it will do so. Because BVZ Power Partner's delay liquidated
damages are limited to the lesser of (1) for each delayed unit, 5% of the total
price of the construction contract and (2) 15% of the total price of the
construction contract in the aggregate, we cannot assure you that the delay
liquidated damages will fully compensate us for the replacement power costs,
increased expenses and other costs that we may incur due to a delay for which
BVZ Power Partners is responsible. In addition, BVZ Power Partners is not
obligated to pay us delay liquidated damages if it was not responsible for a
delay, such as delays caused by our actions or our other contractors' actions or
by events beyond BVZ Power Partners' control. Any of these events could extend
BVZ Power Partners' guaranteed completion dates, which would delay the
commencement of BVZ Power Partners' obligation to pay us delay liquidated
damages.
BVZ POWER PARTNERS MAY BE ENTITLED TO EXTENSIONS OF ITS GUARANTEED
COMPLETION DATES, WHICH WOULD DELAY THE DATE BY WHICH WE WOULD BE ENTITLED TO
RECEIVE DELAY LIQUIDATED DAMAGES FROM BVZ POWER PARTNERS.
BVZ Power Partners will be entitled to an extension of its guaranteed
completion dates if any portion of the 21 day transportation delay associated
with the ABB Power Generation steam turbine generator is determined to be a
force majeure event. BVZ Power Partners also will be entitled to an extension of
its guaranteed completion dates if we are unable to provide consumables,
including water, gas and electrical backfeed, to BVZ Power Partners so that BVZ
Power Partners may perform its tests as scheduled. Our permanent arrangements
for the supply of water from the water intake system were not in place by the
date required in our contract with BVZ Power Partners. However, we made
arrangements to provide BVZ Power Partners with water from the Batesville city
potable water system and have since provided BVZ Power Partners with water from
the water intake system. Prior to completion of the water pre-treatment system,
we cannot assure you that the quality and quantity of water available from these
arrangements will be adequate to perform the testing scheduled by BVZ Power
Partners. If they are not adequate, BVZ Power Partners may not be able to
perform its tests on schedule, and this could delay the completion of our power
facility.
Any extension in BVZ Power Partners' guaranteed completion dates would delay
the date by which we would be entitled to receive delay liquidated damages from
BVZ Power Partners, and could further increase the gap between the date by which
our delivery obligations under our power purchase agreements begin and the
guaranteed completion dates.
OUR REVENUES COULD DECREASE, AND OUR COSTS COULD INCREASE, AS A RESULT OF
BVZ POWER PARTNERS' UNSATISFACTORY FULFILLMENT OF PERFORMANCE STANDARDS.
22
<PAGE>
If the completed generating units comprising our power facility are not able
to satisfy the performance standards that are guaranteed by BVZ Power Partners,
we may find that:
1) our revenue is reduced because our power facility is not capable of
producing as much electricity as we expected it would;
2) our expenses increase because our power facility is less efficient and
therefore requires more fuel;
3) we are unable to operate our power facility in compliance with
applicable permits and laws; or
4) our power purchasers may terminate their agreements with us, if the
performance deficiency causes a material breach of those agreements.
THE LIQUIDATED DAMAGES THAT WE MAY RECEIVE FROM BVZ POWER PARTNERS MAY NOT
FULLY COMPENSATE US FOR OUR LOSSES IF OUR COMPLETED POWER FACILITY DOES NOT
SATISFY ITS PERFORMANCE REQUIREMENTS.
BVZ Power Partners is obligated to pay us performance liquidated damages if
the generating units cannot satisfy tests that measure their net power output
and net heat rate, among other things, against the guaranteed standards included
in the construction contract that we entered into with BVZ Power Partners. The
construction contract limits the aggregate amount of performance liquidated
damages payable by BVZ Power Partners to the lesser of (1) for each deficient
generating unit, 15% of the total price of the construction contract and
(2) the amount of bonus payments to BVZ Power Partners plus 30% of the total
price of the construction contract, less any delay damages payable by BVZ Power
Partners. As a result, we cannot assure you that the performance liquidated
damages will fully compensate us for the losses that we may suffer due to any
unit's failure to satisfy the performance guarantees. In addition, under some
circumstances BVZ Power Partners may not be obligated to pay us performance
liquidated damages until the expiration of a remediation period. Any deficiency
or delay in the payment of liquidated damages could decrease the amount of cash
that we have available at a time when our power facility is not operating as
efficiently as designed, and therefore could make us unable to make payments on
the bonds and our other debt when due.
THE AMOUNT THAT WE HAVE BUDGETED TO COVER INCREASED COSTS, AND THE AMOUNT OF
OUR INSURANCE COVERAGE, MAY BE INSUFFICIENT TO COVER UNANTICIPATED COST
OVERRUNS.
Our project budget includes a contingency line item of approximately
$19,768,000 that is designed to cover things like change orders under the
various construction contracts, the cost of fuel consumed by our power facility
during testing in excess of the revenue received from the sale of test energy,
the payment of taxes that may become due during the construction period, and
other increased costs due to force majeure and other events that may increase
our expenses. In addition, we are required to maintain casualty risk insurance
during the construction period, including delayed opening insurance covering a
period of approximately 18 months with a 30-day deductible per occurrence.
However, we cannot assure you that these contingency funds or the proceeds of
this insurance coverage will be sufficient to pay for any unanticipated costs
not set forth in the project budget.
THE OPERATION OF OUR POWER FACILITY INVOLVES MANY RISKS, INCLUDING
TECHNOLOGY RISK, OPERATING RISK, PERIODIC TESTING RISK, AVAILABILITY RISK AND
THE RISK OF EVENTS BEYOND OUR CONTROL, EACH OF WHICH, IF IT MATERIALIZED, COULD
DECREASE OUR OPERATING REVENUES OR INCREASE OUR COSTS AND LEAVE US WITH LESS
MONEY TO MAKE PAYMENTS ON THE BONDS.
The operation of power generation facilities like our power facility
involves many risks, including:
(1) performance below expected levels of output or efficiency;
(2) breakdown, failure and/or interruptions of power generation equipment,
transmission lines, pipelines or other necessary equipment or processes;
23
<PAGE>
(3) under-performance during facility testing;
(4) failure to operate the facility optimally and reliably;
(5) labor disputes;
(6) violation of permit requirements; and
(7) operator error or catastrophic events such as fires, explosions,
earthquakes and floods, which could result in personal injury, loss of
life, severe damage or destruction of our project, pollution or
environmental damage and suspension of operations.
Plants using similar technology have had problems with respect to excess
pollutant emissions and turbine blade cracking. Moreover, because our power
facility is under construction, we have no actual operating results from our
power facility and we cannot fully predict its performance. Furthermore, because
the reservation payments that Virginia Power and Aquila/UtiliCorp are required
to pay us are based on the tested capacity of, and are reduced due to decreased
availability of, the generating units dedicated to them, if any unit fails to
operate at the expected performance levels the payments that we receive from
Virginia Power and Aquila/UtiliCorp may be lower than the amounts shown in the
projected operating results contained in the independent engineer's report. The
occurrence of the kinds of events listed above could significantly decrease our
revenues, significantly increase our costs and/or impair our ability to make
payments on the bonds and our other debt when due. Although we have insurance to
protect against some of these risks, the insurance proceeds may not be adequate
to cover lost revenues, increased expenses or other costs related to these
occurrences. In addition, the insurance that we currently have may not be
available in the future at commercially reasonable rates.
WE DEPEND ON A NUMBER OF OTHER PEOPLE TO CONSTRUCT AND OPERATE OUR PROJECT,
AND ON A SMALL NUMBER OF POWER PURCHASERS TO PROVIDE ALL OF OUR REVENUES.
We are highly dependent on many people to construct and operate our project,
including the following:
1) various contractors for the construction of our power facility;
2) Panola County and the Panola County Industrial Development Authority for
our lease of the infrastructure we will use to transport water to and
from our power facility and natural gas to our power facility;
3) Cogentrix Batesville Operations and other operators for the operation
and maintenance of our power facility and its infrastructure;
4) the Tennessee Valley Authority and Entergy Mississippi, Inc. for our
ability to deliver our electricity to our power purchasers and for the
construction of some interconnection facilities and the transmission
system upgrades;
5) Tennessee Gas Pipeline Company and ANR Pipeline Company for the
transportation of natural gas to our power facility and for the
construction of some interconnection facilities;
6) the United States government for our ability to withdraw water from Enid
Lake; and
7) Virginia Power and Aquila/UtiliCorp, during the term of our power
purchase agreements with them, for purchases of electric generating
capacity and energy from our power facility.
If any of these people breach their obligations to us, or terminate their
agreements with us, our revenues could decrease materially and we could be
unable to make payments on the bonds and our other debt when due.
24
<PAGE>
OUR POWER PURCHASE AGREEMENTS WITH VIRGINIA POWER AND AQUILA/UTILICORP WILL
EXPIRE BEFORE THE MATURITY OF THE BONDS. AFTER THESE AGREEMENTS EXPIRE, WE WILL
HAVE TO FIND OTHER LONG-TERM CUSTOMERS AND/OR MAKE SHORT-TERM SALES.
Our agreement with Virginia Power is currently set to expire in June 2013,
and our agreement with Aquila/UtiliCorp is currently set to expire in
December 2015. Although both Virginia Power and Aquila/UtiliCorp have the option
to extend their agreements, we cannot assure you that they will do so. When our
agreements with them expire, we will either enter into new power purchase
agreements with other customers and/or make short-term or "spot" sales in which
case our power facility will be what is known in the industry as a "merchant"
plant. We cannot assure you that our net revenues generated from merchant sales
or new power purchase agreements will be sufficient to allow us to make payments
on the bonds and our other debt when due.
BECAUSE OUR CURRENT POWER PURCHASERS HAVE AGREED TO PROVIDE US WITH ALL OF
THE NATURAL GAS THAT WE NEED TO PRODUCE POWER FOR THEM, WE HAVE NOT ENTERED INTO
ANY OTHER GAS SUPPLY CONTRACTS; THEREFORE, WE ARE DEPENDENT UPON OUR CURRENT
BUYERS TO PROVIDE ALL OF OUR NATURAL GAS.
If our future purchasers do not agree to supply us with natural gas, as
Virginia Power and Aquila/ UtiliCorp have, we will have to obtain natural gas
ourselves. Currently, we do not have any agreements with gas suppliers for
procurement or delivery of natural gas to our power facility. If we are unable
to enter into gas supply or transportation agreements at competitive rates in
the future, we could incur significant additional costs. As a result, we may be
unable to make payments on the bonds and our other debt when due.
WE CANNOT MAKE RETAIL SALES OF ELECTRICITY; THEREFORE, WE HAVE A SMALLER
CUSTOMER BASE AND MAY GENERATE LOWER REVENUES THAN IF WE WERE ABLE TO MAKE
RETAIL SALES.
Our status as an exempt wholesale generator under federal law prohibits us
from making retail sales of electricity in the United States. We currently
anticipate that electric capacity and energy generated by our power facility
will be sold primarily in the wholesale market if and after our power facility
becomes a merchant plant. Nevertheless, if we wanted to participate directly in
the retail electric market, we would not be able to do so unless there were a
change in federal law. See "Business--Regulation." Because our sales are limited
to wholesale customers, we have a smaller customer base and may generate lower
revenues than we may have been able to generate if we had a larger customer
base.
WE MAY NOT ALWAYS HAVE OPEN ACCESS TO TRANSMISSION SERVICE AFTER OUR POWER
PURCHASE AGREEMENTS EXPIRE. IN ADDITION, WE MAY NOT BE ABLE TO RECOVER THE
AMOUNTS THAT WE MUST PAY THE TENNESSEE VALLEY AUTHORITY AND ENTERGY TO UPGRADE
THEIR TRANSMISSIONS SYSTEMS.
Although we have entered into agreements with the Tennessee Valley Authority
and Entergy to interconnect our power facility to their transmission systems, we
do not have any agreements in place for the transmission of electricity from the
interconnection point across the Tennessee Valley Authority's and Entergy's
transmission systems. If our future power purchasers do not agree to take
responsibility for transmission service, as Virginia Power and Aquila/UtiliCorp
have, we will have to obtain this service ourselves. While the current
regulatory framework does not allow transmission providers to deny access to
electric generators on a discriminatory basis, we cannot assure you that, under
the current regulatory framework or under a different future regulatory
structure, transmission service will always be available to us or that the price
of available transmission service would enable us to compete effectively in the
merchant power market. If we are unable to obtain electric transmission service
at competitive rates when needed, we could incur significant additional costs.
As a result we may be unable to make payments on the bonds and our other debt
when due.
THE TENNESSEE VALLEY AUTHORITY MAY TERMINATE ITS AGREEMENT WITH US, AND, IF
IT DOES, WE MAY HAVE DIFFICULTY DELIVERING POWER TO OUR CUSTOMERS.
25
<PAGE>
At any time at least five years after the commercial operation date of our
power facility, the Tennessee Valley Authority may terminate their
interconnection agreement with us if we refuse to amend the agreement to be
consistent with the terms being offered by the Tennessee Valley Authority to
other generating facilities at the time. As a result, while under the current
regulatory framework the Tennessee Valley Authority must allow open access to
its system and any amendment to the Tennessee Valley Authority interconnection
agreement must not be discriminatory, we cannot assure you that the terms of the
Tennessee Valley Authority interconnection agreement will not change in the
future in a manner that could cause us to be unable to make payments on the
bonds and our other debt when due.
WE MAY PAY MORE FOR THE TRANSMISSION UPGRADES THAN WE CURRENTLY ANTICIPATE
AND WE MAY RECEIVE FEWER TRANSMISSION UPGRADE CREDITS THAN WE CURRENTLY
ANTICIPATE.
We have agreed to pay all costs associated with upgrades of Entergy's and
the Tennessee Valley Authority's transmission systems relating to the
interconnection of our power facility with their systems. These upgrades will be
owned by Entergy and the Tennessee Valley Authority. In exchange, the Tennessee
Valley Authority and Entergy have agreed to credit us or our power purchasers an
amount equal to the lesser of (1) the revenues that they receive from our power
purchasers and their customers for transmission services provided for the
delivery of energy from our power facility and (2) the total costs paid by us
for the system upgrades. Our recovery of these credits is dependent upon the
availability of transmission service from the Tennessee Valley Authority and
Entergy for, and the use of this transmission service by, our power purchasers
and their customers. The projected operating results included in the independent
engineer's report contain assumptions regarding the amount of system upgrade
credits that independent electricity market and fuel consultant has projected
that we will receive each year. We cannot assure you that the actual amount and
timing of system upgrade credits that we receive will be the same as those in
the projected operating results. In addition, the costs associated with these
upgrades may be higher than we currently anticipate. If it turns out that we pay
significantly more to fund the transmission upgrades than we receive in return
as system upgrade credits, then our ability to make payments on the bonds and
our other debt when due may be adversely impacted.
WE ARE DEPENDENT ON GOVERNMENTAL AUTHORITIES FOR OUR USE OF THE
INFRASTRUCTURE THAT WILL TRANSFER NATURAL GAS TO OUR POWER FACILITY AND WATER TO
AND FROM OUR POWER FACILITY. PANOLA COUNTY AND OTHER GOVERNMENTAL ENTITIES THAT
WE HAVE CONTRACTS WITH COULD TRY TO CLAIM SOVEREIGN IMMUNITY IF WE SUED THEM TO
ENFORCE OUR RIGHTS.
We lease the infrastructure for our power facility from Panola County and
the Industrial Development Authority. This makes us dependent on Panola County
and the Industrial Development Authority for our use of the Panola County
infrastructure, including the lateral gas and water pipelines, which are
critical to the operation of our power facility. If we were unable to use the
lateral gas and water pipelines for any reason and our power facility's
generating units were not available to Virginia Power and Aquila/UtiliCorp as a
result, then the reservation payments from Virginia Power and Aquila/ UtiliCorp
would be reduced due to the unavailability of their units. This could cause us
to be unable to make payments on the bonds and our other debt when due.
In some cases, private parties cannot sue a governmental authority because
the governmental authority claims the benefit of what is known as "sovereign
immunity." Although we have been advised by our Mississippi counsel, Butler Snow
O'Mara Stevens & Canada PLLC, that Panola County and the Industrial Development
Authority would not, under current law, be entitled to claim sovereign immunity
if we try to sue them in court to enforce their obligations to us under the
infrastructure agreements, we cannot assure you that Panola County, the
Industrial Development Authority, the United States and other governmental
authorities that we might have contracts with would not be entitled to
successfully claim sovereign immunity. If that happened, we would not be able to
enforce
26
<PAGE>
our rights against Panola County and the Industrial Development Authority under
the infrastructure lease agreements or the United States under our water supply
agreement. This, too, could cause us to be unable to make payments on the bonds
and our other debt when due. In addition, although you will have a lien on our
interests in these use agreements, you also may find it difficult to enforce
your rights under these agreements if you foreclose on our project. Finally, the
bondholders do not have a lien on the assets comprising the Panola County
infrastructure. Therefore, if you foreclose on our project, you will not be able
to take possession of the Panola County infrastructure, and will have to rely on
enforcing our rights under the lease agreements in order to be able to utilize
these important assets. If you are unable to do so, you may be unable to operate
our power facility, and may therefore not receive as much as you may otherwise
have received if you were to dispose of our power facility at a foreclosure
sale.
THE FAILURE OF OUR COMPUTER SYSTEMS, OR THE COMPUTER SYSTEMS OF OUR
CUSTOMERS AND SUPPLIERS, TO BE YEAR 2000 COMPLIANT MAY HAVE AN ADVERSE EFFECT ON
OUR REVENUES.
Some computer systems cannot recognize dates which contain the year 2000.
Because the construction of our power facility is not complete, we have not
tested all of our systems to determine if they have this year 2000 problem.
Also, we do not know if all of the systems of our customers and suppliers are
year 2000 compliant. If our systems or the systems of any of our customers,
suppliers or interconnecting utilities have the year 2000 problem, these systems
could fail or cause erroneous results when used. This could cause a disruption
or delay in the construction or operation of our power facility. A disruption or
delay could result in a decrease in the level of revenues that we receive from
the operation of our power facility. If we have less revenues, we will have
fewer funds available to make payments on the bonds and our other debt when due.
REGULATORY RISKS
OUR BUSINESS IS AFFECTED BY SUBSTANTIAL REGULATIONS AND PERMITTING
REQUIREMENTS AND WE COULD BE FACED WITH INCREASED COSTS, OR BE PREVENTED FROM
OPERATING OUR POWER FACILITY, AS A RESULT OF CHANGES IN THOSE REGULATIONS OR
REQUIREMENTS.
There are many federal, state and local laws that pertain to power
generation and that are designed to protect human health and the environment.
These laws impose numerous requirements on the construction, ownership and
operation of our power facility and its infrastructure. For example, we must
obtain and comply with permits for air emissions, water withdrawal, waste water
discharges, construction in wetlands, and other regulated activities. Each
permit contains its own set of requirements. We also must implement management
practices for handling hazardous materials, preventing spills, planning for
emergencies, ensuring worker safety, and addressing other operational issues. If
we fail to comply with these requirements, we could be prevented from completing
or operating our power facility or its infrastructure. Moreover, modifications
to our power facility or its infrastructure to comply with these requirements
could be expensive.
CHANGING REGULATIONS MAY REQUIRE US, OR OTHERS WE WORK WITH, TO OBTAIN
ADDITIONAL APPROVALS. THIS COULD BE EXPENSIVE. IN ADDITION, IF WE ARE UNABLE TO
OBTAIN THESE APPROVALS, WE COULD BE UNABLE TO OPERATE OUR POWER FACILITY.
The structure of federal and state energy regulation is currently, and may
continue to be, affected by challenges and restructuring proposals. Although we
believe that we have obtained all material energy-related approvals currently
required to construct, operate and use our power facility and its
infrastructure, we may require additional regulatory approvals in the future due
to a change in existing laws and regulations, a change in our power purchasers
or for other reasons.
We cannot assure you that we, our power purchasers or our contractors or
suppliers will be able to obtain any required regulatory approvals or necessary
modifications to existing regulatory approvals, or be able to maintain existing
required regulatory approvals. We also cannot assure you that we will be
27
<PAGE>
able to operate our power facility in accordance with all of our permits and
approvals. If we cannot timely obtain and maintain any regulatory approvals or
are unable to timely satisfy any related conditions, we could be prevented from
operating our power facility or making sales to our power purchasers, or we
could incur additional costs. Loss of revenues or additional costs could cause
us to be unable to make payments on the bonds and our other debt when due.
CHANGING LAWS AND REGULATIONS COULD INCREASE OUR OPERATIONAL COSTS OR EXPOSE
US TO LIABILITY.
Laws and regulations affecting us, our power facility and the infrastructure
for our power facility may change in a way that could cause us to be unable to
make payments on the bonds and our other debt when due. For example, changes in
laws or regulations could impose more stringent or comprehensive requirements on
the operation and maintenance of our power facility or its infrastructure, or
could expose us to liability for actions taken in compliance with laws
previously in effect or for actions taken or conditions caused by unrelated
third parties.
In addition, we could be responsible for the costs of remediating
contamination from existing or future off-site sources that are subsequently
identified at the project site or the project easements. Any payment by us of
such remediation costs could cause us to be unable to make payments on the bonds
and our other debt when due.
A CHANGE IN OUR REGULATORY STATUS COULD HAVE AN ADVERSE IMPACT ON OUR
REVENUES.
We currently sell the electricity generated by our power facility to two
wholesale customers, Virginia Power and Aquila/UtiliCorp, which in turn sell the
electricity to retail customers. Because we sell electricity only to wholesale
customers, we are considered an exempt wholesale generator, under the Energy
Policy Act of 1992 and the Federal Energy Regulatory Commission's interpretation
of this Act. Our exempt wholesale generator status keeps us from being
considered a public utility under the Federal Power Act, the Public Utility
Holding Company Act of 1935 and state laws applicable to public utilities.
After the expiration of our power purchase agreements with Virginia Power
and Aquila/UtiliCorp, we intend to continue to sell electricity produced by our
power facility only to wholesale customers. However, if we were to sell
electricity to a retail customer, or if the exempt wholesale generator status
was no longer available as a way of avoiding public utility status, we would be
affected by the following types of regulations applicable to public utilities:
- federal regulations requiring, among other things, that public utilities
register with the Securities and Exchange Commission, obtain the
Securities and Exchange Commission's approval to issue securities, to
acquire securities or utility assets or any other interest in any
business, including investment in other power facilities, and file annual
and other periodic reports with the Securities and Exchange Commission;
and
- state regulations restricting the rates that public utilities can charge
to their customers and governing the financial and organizational aspects
of, and the issuance of securities by, public utilities.
Limits on the rates we are permitted to charge to our customers and the
increased regulatory burden of being a public utility could decrease the amount
of revenues earned from the operation of our power facility. A decrease in our
revenues would result in our having fewer funds available to pay our operating
expenses and to make principal and interest payments on the bonds and our other
debt when due.
INCREASED COMPETITION IN THE MARKET FOR ELECTRIC POWER COULD DECREASE THE
AMOUNT OF REVENUES WE EARN FROM THE OPERATION OF OUR POWER FACILITY.
Until recently, the electric power market was not competitive. However,
competition in both the wholesale and retail electric power markets has
increased significantly in the past few years. We do not expect this increased
competition to have a significant effect on us while our power purchase
28
<PAGE>
agreements with Virginia Power and Aquila/UtiliCorp are in effect. However,
after the termination of these agreements, we will have to sell the electricity
produced by our power facility in the increasingly competitive power markets if
we are not able to enter into new long-term power purchase agreements. The
prices that we are able to charge for sales of electricity in the competitive
markets may be less than the prices we currently charge to Virginia Power and
Aquila/UtiliCorp. If so, our revenues will decrease and we will have fewer funds
available to pay our operating expenses and to make principal and interest
payments on the bonds and our other debt when due.
FINANCING RISKS
IF WE AND THE FUNDING CORPORATION DEFAULT ON THE BONDS, YOUR RECOURSE WILL
BE LIMITED TO THE ASSETS AND CASH FLOWS OF OUR POWER FACILITY.
We and the Funding Corporation are co-issuers of the bonds and are equally
responsible for making payments on the bonds. No one else, including our
partners, shareholders, affiliates, directors, officers or the people who own or
work for them or us, is responsible for making payments on the bonds or in any
way guarantee the payment of the bonds. The Funding Corporation has no ongoing
business and only nominal assets, and really cannot be viewed as a source of
payment. Our ability to make payments on the bonds will be entirely dependent on
our ability to construct our power facility and to operate it at levels which
provide sufficient revenues, after the payment of our operations and maintenance
costs, to make payments on the bonds and our other debt when due.
The bonds are secured only by (1) our power facility and our contracts and
permits, (2) a lien on the partnership interests in us and (3) a lien on the
capital stock of the Funding Corporation and of our general partner. We cannot
assure you that, if we and the Funding Corporation default on the bonds and you
foreclose on and sell our project, you will receive sufficient proceeds to pay
all amounts that we and the Funding Corporation owe you on the bonds. In
addition, there are 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 that you
need to effectively do so.
WE HAVE A LARGE AMOUNT OF EXISTING INDEBTEDNESS, WHICH MAY HAVE AN ADVERSE
IMPACT ON YOU. FOR EXAMPLE, THE REVENUES WE EARN MAY NOT BE SUFFICIENT TO TIMELY
MAKE OUR SCHEDULED PAYMENTS ON ALL OF OUR INDEBTEDNESS, INCLUDING THE BONDS.
Our large amount of indebtedness, which currently totals $326,000,000 plus
current liabilities of $33,456,000, could have important consequences to you.
For example, it could:
1) make it more difficult for us to satisfy our obligations with respect to
the bonds;
2) increase our vulnerability to general adverse economic and industry
conditions;
3) limit our ability to fund future working capital, capital expenditures
and other project costs;
4) require a substantial portion of our cash flow from operations for debt
payments;
5) limit our flexibility to plan for, or react to, changes in our business
and the industry in which we operate;
6) place us at a competitive disadvantage compared to our competitors that
have less debt; and
7) limit our ability to borrow additional funds that we may need to
complete and operate our project.
WE MAY INCUR ADDITIONAL DEBT, OR BE REQUIRED TO REIMBURSE DRAWS UNDER
LETTERS OF CREDIT, THAT COULD LEAVE US WITH LESS MONEY AVAILABLE TO MAKE
PAYMENTS ON THE BONDS WHEN DUE.
We may incur additional debt, including additional series of bonds, to pay
for capital improvements and expansions of our power facility and for other
purposes. This permitted indebtedness may rank equally with the bonds and share
ratably in the collateral which secures the bonds. This may
29
<PAGE>
reduce the benefits of the collateral to you and your ability to control actions
taken by or on behalf of you and the other secured parties with respect to the
collateral.
In addition, in order to secure our obligations under our power purchase
agreements, we have provided an irrevocable standby letter of credit to Virginia
Power and may be required to provide an irrevocable standby letter of credit or
other security to Aquila/UtiliCorp. If Virginia Power or Aquila/ UtiliCorp draw
upon any of these letters of credit, we will be required to reimburse the banks
that have provided these letters of credit. Our obligations to reimburse these
banks will rank equally with our obligations to make payments on the bonds. The
financing documents require us to pay all equally ranking obligations on a pro
rata basis. Therefore, if we are required to reimburse the banks for drawings
under these letters of credit, we will have less money available to make
payments on the bonds when due.
WE ARE RELYING ON PROJECTIONS OF THE FUTURE PERFORMANCE OF OUR POWER
FACILITY, AND IF OUR ACTUAL RESULTS ARE LESS FAVORABLE THAN THOSE CONTAINED IN
THE PROJECTED OPERATING RESULTS, THEN WE MAY NOT GENERATE ENOUGH REVENUES TO
MAKE PAYMENTS ON THE BONDS OR OUR OTHER DEBT WHEN DUE.
The report by R.W. Beck, the independent engineer for our project, contains
projected operating results that are based on assumptions and forecasts of our
ability to generate revenues and of our expected costs. R.W. Beck made some of
the assumptions used in the projected operating results after performing its
technical and economic evaluation of our power facility, and made other
assumptions of business and economic conditions generally. R.W. Beck has
informed us that it believes these assumptions to be reasonable. However, R.W.
Beck has not reviewed the Panola County infrastructure construction contracts or
our electrical substation and transmission line construction contracts for
purposes of determining whether the facilities being constructed according to
those contracts will be technically compatible with the rest of our power
facility. C.C. Pace made some of the assumptions used by R.W. Beck in the
projected operating results based on its evaluation of the fuel and electricity
markets in the southeast. C.C. Pace has informed us that it believes these
assumptions to be reasonable. We agree that all of the assumptions underlying
the projected operating results are reasonable. Nevertheless, all the
assumptions on which the projected operating results are based could be affected
by significant uncertainties, and neither we nor any other person can predict
with any certainty whether they will prove to be true. KPMG LLP, our independent
certified public accountants, have not reviewed the projected operating results
and do not express any opinion on the projected operating results.
The projections are not necessarily an indication of our future performance.
In fact, our actual results will differ, perhaps materially, from those in the
projected operating results. Therefore, we are not making, and you should not
infer, any representation about the likely existence of any particular future
set of facts or circumstances. If our actual results are less favorable than
those shown in the projected operating results or if the assumptions we used in
preparing the projected operating results prove to be incorrect, we may not
generate revenues sufficient to make payments on the bonds or our other debt
when due.
WE MAY NOT HAVE THE ABILITY TO RAISE THE FUNDS NECESSARY TO FINANCE THE
CHANGE OF CONTROL OFFER REQUIRED BY THE INDENTURE FOR THE BONDS.
Upon the occurrence of specific kinds of change of control events which we
cannot necessarily control, we will be required to offer to repurchase all
outstanding bonds. However, it is possible that we will not have sufficient
funds at the time of the change of control to make the required repurchase of
bonds.
YOU MAY FIND IT DIFFICULT TO TRANSFER THE EXCHANGE BONDS DUE TO THE LACK OF
A PUBLIC TRADING MARKET.
The exchange bonds are new securities for which there is no existing market.
Accordingly, we cannot assure you that a market will develop for the exchange
bonds or that if a market does develop,
30
<PAGE>
that it will be liquid. The initial purchasers of the private bonds, Credit
Suisse First Boston, Scotia Capital Markets and TD Securities, have advised us
that they currently intend to make the market in the exchange bonds. However,
the initial purchasers of the private bonds are not obligated to do so, and any
market making with respect to the exchange bonds may be discontinued at any time
without notice. We do not intend to apply for a listing of the exchange bonds on
any securities exchange or on any automated dealer quotation system.
The liquidity of, and trading market for, the exchange bonds also may be
adversely affected by general declines in the market for similar securities or
by changes in our financial performance. A market decline may adversely affect
liquidity and trading markets independent of our financial performance and
prospects.
THIS PROSPECTUS CONTAINS FORWARD-LOOKING STATEMENTS THAT ARE DEPENDENT UPON
CIRCUMSTANCES AND EVENTS WHICH MAY BE OUTSIDE OF OUR CONTROL.
This prospectus includes forward-looking statements. We have based these
forward looking statements on our current expectations and assumptions about
future events, and the projections and assumptions about future events of our
independent consultants, R.W. Beck and C.C. Pace. These forward looking
statements are affected by various risks and uncertainties that may be outside
our control, including, among other things:
- governmental, statutory, regulatory or administrative changes or
initiatives affecting us, our power plant or our contracts;
- construction risks, including unanticipated costs not included in our
budget, such as cost overruns and the assessment of property taxes, and
completion delays;
- operating risks, including equipment failure, environmental compliance
issues, dispatch levels for our power plant, availability of our power
plant, heat rate and output, transmission credits and the amounts and
timing of revenues and expenses;
- the cost and availability of fuel and transmission service for our power
plant;
- the enforceability of the long-term power purchase agreements for our
power plant;
- the ongoing creditworthiness of our power purchasers; and
- competition from other power plants, including new plants that may be
developed in the future.
We use words like "anticipate," "estimate," "project," "plan," "expect" and
similar expressions to help identify forward looking statements in this
prospectus.
In light of these and other risks, uncertainties and assumptions, actual
events or results may be very different from those expressed or implied in the
forward-looking statements in this prospectus, or may not occur.
BANKRUPTCY RISKS
FEDERAL AND STATE STATUTES ALLOW COURTS, UNDER SPECIFIC CIRCUMSTANCES, TO
VOID OUR OBLIGATIONS UNDER THE BONDS.
Under the federal bankruptcy law and comparable provisions of state
fraudulent transfer laws, our obligations under the bonds could be voided or
subordinated to all of our other debts if, among other things, at the time that
we issue the bonds, we:
(1) received less than reasonably equivalent value or fair consideration for
the issuance of the bonds; and
(2) were insolvent or rendered insolvent as a result of issuing the bonds;
or
(3) were engaged in a business or transaction for which our remaining assets
constituted unreasonably small capital; or
31
<PAGE>
(4) intended to incur, or believed that we would incur, debts beyond our
ability to pay the debts as they mature.
The same analysis would apply to the Funding Corporation as well. In
addition, any payment that we or the Funding Corporation made on the bonds could
be voided and required to be returned to us or the Funding Corporation, as
applicable, or to a fund for the benefit of our respective creditors.
The measures of insolvency for purposes of these fraudulent transfer laws
will vary depending upon the law applied in any proceeding to determine whether
a fraudulent transfer has occurred. Generally, however, we would be considered
insolvent if:
(1) the sum of our debts, including contingent liabilities, were greater
than the fair saleable value of all of our assets; or
(2) the present fair saleable value of our assets were less than the amount
that would be required to pay our probable liability on our existing
debts, including contingent liabilities, as they become absolute and
mature; or
(3) we could not pay our debts as they become due.
Again, the same analysis would apply to the Funding Corporation.
We used $3,000,000 of the net proceeds of the private bonds to pay
development fees to our affiliates. Nevertheless, because we received value from
these affiliates in the form of development services prior to paying this fee,
we do not believe that, as a result of paying this fee, we have received less
than reasonably equivalent value or fair consideration for issuing the private
bonds. After giving effect to our issuance of the private bonds, we believe that
we are not insolvent, we do not have unreasonably small capital for the business
in which we are engaged, and we have not incurred debts beyond our ability to
pay those debts as they mature. However, we cannot assure you that a court would
apply this standard or agree with our conclusions.
In addition, because (1) both we and the Funding Corporation are equally
responsible for making payments on the bonds, (2) the Funding Corporation did
not receive any of the proceeds of the bonds and (3) the Funding Corporation has
no assets to speak of, the Funding Corporation may in fact be considered to have
received less than reasonably equivalent value for issuing the bonds and to be
insolvent.
IF WE, THE FUNDING CORPORATION OR ONE OF THE COUNTERPARTIES TO OUR CONTRACTS
ARE THE SUBJECT OF BANKRUPTCY PROCEEDINGS, YOUR ABILITY TO FORECLOSE ON THE
COLLATERAL SECURING THE BONDS, AS WELL AS YOUR RECEIPT OF PAYMENTS ON THE BONDS,
COULD BE SIGNIFICANTLY IMPAIRED.
If we or the Funding Corporation seek the protection of the bankruptcy laws,
or if one of our or the Funding Corporation's creditors begins a bankruptcy
proceeding against us or the Funding Corporation, your rights to foreclose upon
our project are likely to be significantly impaired. In addition, we cannot
predict how long payments on the bonds could be delayed following the
commencement of a bankruptcy case involving us or the Funding Corporation.
Finally, because part of the collateral securing the bonds consists of our
contracts, if we or any counterparty to any one of those contracts were the
subject of bankruptcy proceedings, then we, that counterparty or a trustee
appointed in our or the counterparty's bankruptcy case could chose to reject the
contract. If that occurred, you could not specifically enforce the rejected
contract.
32
<PAGE>
THE EXCHANGE OFFER
PURPOSE OF THE EXCHANGE OFFER
We and the Funding Corporation sold the private bonds on May 21, 1999 to
Credit Suisse First Boston, TD Securities and Scotia Capital Markets under the
purchase agreement. Those initial purchasers subsequently sold the private bonds
to "qualified institutional buyers", as defined in Rule 144A under the
Securities Act of 1933, in reliance on Rule 144A. As a condition to the sale of
the private bonds, we and the Funding Corporation entered into the registration
rights agreement with those initial purchasers on May 21, 1999. We and the
Funding Corporation agreed in the registration rights agreement that, unless the
exchange offer is not permitted by applicable law or Securities and Exchange
Commission policy, we would:
- file with the Securities and Exchange Commission a registration statement
under the Securities Act with respect to the exchange bonds as soon as
reasonably practicable after May 21, 1999;
- use our reasonable best efforts to cause the registration statement to
become effective under the Securities Act on or prior to 270 days after
May 21, 1999;
- keep continuously effective the registration statement for a period of
120 days or until the consummation of the exchange offer; and
- use our best efforts to consummate the exchange offer within 30 days from
the date on which notice that the registration statement was declared
effective by the Securities and Exchange Commission is mailed.
A copy of the registration rights agreement has been filed as an exhibit to
the registration statement of which this prospectus is a part.
RESALE OF THE EXCHANGE BONDS
In order to participate in the exchange offer, a holder must represent to
us, among other things, that:
- the person acquiring the exchange bonds in the exchange offer is doing so
in the ordinary course of its business, whether or not that person is the
registered holder of the private bonds;
- the holder is not engaging in and does not intend to engage in a
distribution of the exchange bonds;
- the holder does not have an arrangement or understanding with any person
to participate in a distribution of the exchange bonds; and
- the holder is not our "affiliate," as defined under Rule 405 under the
Securities Act.
Based on an interpretation by the Securities and Exchange Commission's staff
set forth in no-action letters issued to third parties unrelated to us, we
believe that, with the exceptions set forth below, exchange bonds issued in the
exchange offer may be offered for resale, resold and otherwise transferred by
holders of the exchange bonds without compliance with the registration and
prospectus delivery provisions of the Securities Act unless the holder:
- is our "affiliate" within the meaning of Rule 405 under the Securities
Act;
- is a broker-dealer who purchased private bonds directly from us for resale
in reliance on Rule 144A or any other available exemption under the
Securities Act;
- acquired the exchange bonds in the exchange offer other than in the
ordinary course of the holder's business; or
- has an arrangement or understanding with any person to engage in the
distribution of the exchange bonds.
33
<PAGE>
Any holder who tenders in the exchange offer for the purpose of
participating in a distribution of the exchange bonds cannot rely on this
interpretation by the Securities and Exchange Commission's staff and must comply
with the registration and prospectus delivery requirements of the Securities Act
for a secondary resale transaction. Each broker-dealer that receives exchange
bonds for its own account in exchange for private bonds, where the private 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 for
any resale of those exchange bonds. Broker-dealers who acquired private bonds
directly from us and not as a result of market-making activities or other
trading activities may not rely on the staff's interpretations discussed above
or participate in the exchange offer and must comply with the prospectus
delivery requirements of the Securities Act in order to sell the private bonds.
We will make this prospectus available to any participating broker-dealer for
any resale of this kind for a period of 30 days after the expiration of the
exchange offer.
TERMS OF THE EXCHANGE OFFER
Upon the terms and in compliance with the conditions set forth in this
prospectus and in the letter of transmittal that you have received, we will
accept any and all private bonds validly tendered and not withdrawn prior to the
expiration date for the exchange offer, which is [ ], 2000. We will
issue $1,000 principal amount of exchange bonds in exchange for each $1,000
principal amount of outstanding private bonds surrendered in the exchange offer.
Private bonds may be tendered only in integral multiples of $1,000.
The form and terms of the exchange bonds are the same as the form and terms
of the private bonds, except that:
- the exchange bonds will be registered under the Securities Act and,
therefore, the exchange bonds will not bear legends restricting their
transfer; and
- holders of the exchange bonds will not be entitled to any of the rights of
holders of private bonds under the registration rights agreement, which
rights will terminate upon the consummation of the exchange offer.
The exchange bonds will evidence the same indebtedness as the private bonds
which they replace and will be issued under, and be entitled to the benefits of,
the indenture, which also authorized the issuance of the private bonds, so that
both the series A bonds and the series C bonds will be treated as a single class
of debt securities under the indenture and so that both the series B bonds and
the series D bonds will be treated as a single class of debt securities under
the indenture.
As of the date of this prospectus, $326,000,000 in aggregate principal
amount of the private bonds are outstanding and registered in the name of a
nominee for The Depository Trust Company. Only a registered holder of the
private bonds or the holder's legal representative or attorney-in-fact may
participate in the exchange offer. There will be no fixed record date for
determining registered holders of the private bonds entitled to participate in
the exchange offer.
Holders of the private bonds do not have any appraisal or dissenters' rights
under the indenture due to the exchange offer. We intend to conduct the exchange
offer in accordance with the provisions of the registration rights agreement and
the applicable requirements of the Securities Act of 1933, the Securities
Exchange Act of 1934 and the rules and regulations of the Securities and
Exchange Commission.
We will be deemed to have accepted validly tendered private bonds when and
if we have given oral or written notice of acceptance to the exchange agent. The
exchange agent will act as agent for the tendering holders of private bonds for
the purposes of receiving the exchange bonds from us and the Funding
Corporation.
Holders who tender private bonds in the exchange offer will not be required
to pay brokerage commissions or fees or, other than as described in the letter
of transmittal that you have received,
34
<PAGE>
transfer taxes with respect to the exchange of private bonds in the exchange
offer. We will pay all charges and expenses which are incurred because of the
exchange offer, other than the applicable taxes described below.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS
The expiration date for the exchange offer is 5:00 p.m., New York City time
on [ ], 2000, unless we, in our sole discretion, extend the exchange
offer, in which case the expiration date will be the latest date and time to
which we extend the exchange offer.
In order to extend the exchange offer, we will notify the exchange agent of
any extension by oral or written notice, mail to the registered holders an
announcement of the extension and issue a press release or other public
announcement which will include disclosure of the approximate number of private
bonds deposited to date, each prior to 9:00 a.m., New York City time, on the
next business day after the previously scheduled expiration date. Without
limiting the manner in which we may choose to make a public announcement of any
delay, extension, amendment or termination of the exchange offer, we will have
no obligation to publish, advertise or otherwise communicate any public
announcement, other than by making a timely release to an appropriate news
agency.
We reserve the right, in our sole discretion:
- to delay accepting any private bonds;
- to extend the exchange offer;
- if any conditions set forth below under the caption "--Conditions" are not
satisfied, to terminate the exchange offer by giving oral or written
notice of the delay, extension or termination to the exchange agent; or
- to amend the terms of the exchange offer in any manner.
In order to keep the registration statement effective for the period
required by the registration rights agreement, we may file post-effective
amendments to the registration statement.
INTEREST ON THE EXCHANGE BONDS
The exchange bonds for the series A bonds will bear interest at a rate equal
to 7.164% per annum and the exchange bonds for the series B bonds will bear
interest at a rate equal to 8.160% per annum. Interest on the exchange bonds
will be payable semi-annually in arrears on each January 15 and July 15,
commencing January 15, 2000. Holders of exchange bonds will receive interest on
January 15, 2000 from the date of initial issuance of the exchange bonds, plus
an amount equal to the accrued interest on the private bonds from the date of
initial delivery to the date of their exchange for exchange bonds. Holders of
private bonds that are accepted for exchange will be deemed to have waived the
right to receive any interest accrued on the private bonds, other than as set
forth in the previous sentence.
POTENTIAL INCREASE IN THE INTEREST RATE FOR THE PRIVATE BONDS
If the registration statement of which this prospectus is a part is not
declared effective by February 15, 2000, the interest rate on the private bonds
will be increased by 0.50% per annum from and after February 15, 2000 until the
registration statement of which this prospectus is a part is declared effective
and the exchange offer has been commenced. Upon consummation of the exchange
offer, holders of private bonds will no longer be entitled to any increase in
the rate of interest on the private bonds, but the private bonds will still be
governed by the indenture under which the private bonds were issued.
35
<PAGE>
PROCEDURES FOR TENDERING
Only a registered holder of private bonds may tender private bonds in the
exchange offer. To tender in the exchange offer, a holder of private bonds must
complete, sign and date the letter of transmittal, or a facsimile of the letter
of transmittal, have its signatures guaranteed if required by the letter of
transmittal, and mail or otherwise deliver the letter of transmittal or the
facsimile to the exchange agent at the address set forth below under the caption
"--Exchange Agent" for receipt prior to the expiration date for the exchange
offer. In addition either:
- certificates for the private bonds must be received by the exchange agent
along with the letter of transmittal;
- a timely confirmation of a book-entry transfer of the private bonds, if
this procedure is available, into the exchange agent's account at The
Depository Trust Company in accordance with the procedure for book-entry
transfer described below, must be received by the exchange agent prior to
the expiration date for the exchange offer; or
- you must comply with the guaranteed delivery procedures described below.
Your tender, if not withdrawn prior to the expiration date, will constitute
an agreement between you and us and the Funding Corporation in accordance with
the terms and conditions set forth in this prospectus and in the letter of
transmittal.
THE METHOD OF DELIVERY OF PRIVATE BONDS AND THE LETTER OF TRANSMITTAL AND
ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT YOUR ELECTION AND RISK.
INSTEAD OF DELIVERY BY MAIL, WE RECOMMEND THAT YOU USE AN OVERNIGHT OR HAND
DELIVERY SERVICE, PROPERLY INSURED. IN ALL CASES, YOU SHOULD ALLOW SUFFICIENT
TIME TO ASSURE DELIVERY TO THE EXCHANGE AGENT BEFORE THE EXPIRATION DATE. YOU
SHOULD NOT SEND ANY LETTER OF TRANSMITTAL OR PRIVATE BONDS TO US OR THE FUNDING
CORPORATION. YOU MAY REQUEST YOUR BROKERS, DEALERS, COMMERCIAL BANKS, TRUST
COMPANIES OR NOMINEES TO EFFECT THE ABOVE TRANSACTIONS FOR YOU.
Any beneficial owner whose private 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 the
registered holder to tender on the beneficial owner's behalf. If the beneficial
owner wishes to tender on its own behalf, the beneficial owner must, prior to
completing and executing the letter of transmittal and delivering the owner's
private bonds, either make appropriate arrangements to register ownership of the
private bonds in the owner's name or obtain a properly completed bond power from
the registered holder. The transfer of registered ownership may take
considerable time.
Signatures on a letter of transmittal or a notice of withdrawal described
below must be guaranteed by an eligible institution of the type described below,
unless the relevant private bonds are tendered:
- by a registered holder who has not completed the box titled "Special
Delivery Instructions" on the letter of transmittal; or
- for the account of an eligible institution of the type described below.
If signatures on a letter of transmittal or a notice of withdrawal must be
guaranteed, the guarantee must be made by:
- a member firm of a registered national securities exchange or of the
National Association of Securities Dealers, Inc.;
- a commercial bank or trust company having an office or correspondent in
the United States; or
- an "eligible guarantor institution" within the meaning of Rule 17Ad-15
under the Exchange Act which is a member of one of the recognized
signature guarantee programs identified in the letter of transmittal.
36
<PAGE>
If the letter of transmittal is signed by a person other than the registered
holder of any private bonds listed in the letter of transmittal, the private
bonds must be endorsed or accompanied by a properly completed bond power, signed
by the registered holder as the registered holder's name appears on the private
bonds.
If the letter of transmittal or any private 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,
these persons should so indicate when signing, and unless waived by us and the
Funding Corporation, evidence satisfactory to us and the Funding Corporation of
their authority to so act must be submitted with the letter of transmittal.
The exchange agent and The Depository Trust Company have confirmed that any
financial institution that is a participant in The Depository Trust Company's
system may utilize The Depository Trust Company's automated tender offer program
to tender private bonds.
All questions as to the validity, form, eligibility, including time of
receipt, acceptance and withdrawal of tendered private bonds will be determined
by us in our sole discretion, which determination will be final and binding. We
reserve the absolute right to reject any and all private bonds not properly
tendered or to refuse to accept the tender of any private bonds if our
acceptance of the tender of those bonds would be unlawful in the opinion of our
legal counsel. We also reserve the right to waive any defects, irregularities or
conditions of tender as to particular private 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 tenders of private bonds must be cured within a
time period determined by us. Although we intend to notify holders of defects or
irregularities with respect to tenders of private bonds, neither we, the
exchange agent nor any other person will incur any liability for failure to give
notification. Tenders of private bonds will not be deemed to have been made
until all unwaived defects or irregularities have been cured or waived.
While we have no present plan to acquire any private bonds that are not
tendered in the exchange offer or to file a registration statement to permit
resales of any private bonds that are not tendered in the exchange offer, we
reserve the right in our sole discretion:
- to purchase or make offers for any private bonds that remain outstanding
after the expiration date for the exchange offer; or
- as set forth below under the caption "--Conditions," to terminate the
exchange offer and, to the extent permitted by law, to purchase private
bonds in the open market, in privately negotiated transactions or
otherwise.
The terms of any of these purchases or offers could differ from the terms of
the exchange offer.
By tendering, each holder of private bonds will represent to us that, among
other things:
- the exchange bonds to be acquired by the holder of private bonds in the
exchange offer are being acquired by the holder in the ordinary course of
its business;
- the holder has no arrangement or understanding with any person to
participate in the distribution of the exchange bonds;
- if the holder is a resident of the State of California, it falls under the
self-executing institutional investor exemption set forth under
Section 25102(i) of the Corporate Securities Law of 1968 and
Rules 260.102.10 and 260.105.14 of the California Blue Sky Regulations;
- if the holder is a resident of Pennsylvania, it falls under the
self-executing institutional investor exemption set forth under Sections
203(c), 102(d) and (k) of the Pennsylvania Securities Act of 1972,
Section 102.111 of the Pennsylvania Blue Sky Regulations and an
interpretive opinion dated November 16, 1985;
37
<PAGE>
- the holder acknowledges and agrees that any person who is a broker-dealer
registered under the Exchange Act or is participating in the exchange
offer for the purposes of distributing the exchange bonds must comply with
the registration and prospectus delivery requirements of the Securities
Act for a secondary resale transaction of the exchange bonds and cannot
rely on the position of the staff of the Securities and Exchange
Commission set forth in the no-action letters described above;
- the holder understands that a secondary resale transaction described in
the clause above and any resales of exchange bonds obtained by the holder
in exchange for private bonds acquired by the holder directly from us and
the Funding Corporation should be covered by an effective registration
statement containing the selling securityholder information required by
Item 507 or Item 508, as applicable, of Regulation S-K of the Securities
and Exchange Commission; and
- the holder is not an "affiliate," as defined in Rule 405 under the
Securities Act, of either us or the Funding Corporation.
If the holder is a broker-dealer that will receive exchange bonds for the
holder's own account in exchange for private bonds that were acquired as a
result of market-making activities or other trading activities, the holder will
be required to acknowledge in the letter of transmittal that the holder will
deliver a prospectus for any resale of exchange bonds. However, by so
acknowledging and by delivering a prospectus, the holder will not be deemed to
admit that it is an "underwriter" within the meaning of the Securities Act.
RETURN OF PRIVATE BONDS
If any tendered private bonds are not accepted for any reason set forth in
the terms and conditions of the exchange offer or if private bonds are withdrawn
or are submitted for a greater principal amount than the holders desire to
exchange, we or the exchange agent will return the unaccepted, withdrawn or
non-exchanged private bonds without expense to the tendering holder as promptly
as practicable. In the case of private bonds tendered by book-entry transfer
into the exchange agent's account at The Depository Trust Company in accordance
with the book-entry transfer procedures described below, the private bonds will
be credited to an account maintained with The Depository Trust Company as
promptly as practicable.
BOOK-ENTRY TRANSFER
The exchange agent will make a request to establish an account with respect
to the private bonds at The Depository Trust Company for purposes of the
exchange offer within two business days after the date of this prospectus, and
any financial institution that is a participant in The Depository Trust
Company's systems may make book-entry delivery of private bonds by causing The
Depository Trust Company to transfer private bonds into the exchange agent's
account at The Depository Trust Company in accordance with The Depository Trust
Company's procedures for transfer. However, although delivery of private bonds
may be effected through book-entry transfer at The Depository Trust Company, the
letter of transmittal or a facsimile of the letter of transmittal, with any
required signature guarantees and any other required documents, must, in any
case, be transmitted to and received by the exchange agent at the address set
forth below under the caption "--Exchange Agent" on or prior to the expiration
date for the exchange offer or in accordance with the guaranteed delivery
procedures described below.
GUARANTEED DELIVERY PROCEDURES
Holders who wish to tender their private bonds and (1) whose private bonds
are not immediately available or (2) who cannot deliver their private bonds, the
letter of transmittal or any other required documents to the exchange agent
prior to the expiration date, may effect a tender if:
(1) the tender is made through an eligible institution of the type described
above;
38
<PAGE>
(2) prior to the expiration date, the exchange agent receives from the
eligible institution a properly completed and duly executed notice of
guaranteed delivery substantially in the form provided by us, by
facsimile transmission, mail or hand delivery, setting forth the name and
address of the holder, the certificate number(s) of the private bonds and
the principal amount of private bonds tendered, stating that the tender
is being made by the notice of guaranteed delivery and guaranteeing that,
within five New York Stock Exchange trading days after the expiration
date for the exchange offer, the letter of transmittal, or a facsimile of
the letter of transmittal, together with the certificate(s) representing
the private bonds in proper form for transfer or a book-entry
confirmation, as the case may be, and any other documents required by the
letter of transmittal, will be deposited by the eligible institution with
the exchange agent; and
(3) a properly executed letter of transmittal, or a facsimile of the letter
of transmittal, as well as the certificate(s) representing all tendered
private bonds in proper form for transfer and all other documents
required by the letter of transmittal are received by the exchange agent
within five New York Stock Exchange trading days after the expiration
date for the exchange offer.
Upon request to the exchange agent, the exchange agent will send a notice of
guaranteed delivery to holders who wish to tender their private bonds according
to the guaranteed delivery procedures set forth above.
WITHDRAWAL OF TENDERS
Except as otherwise provided in this prospectus, tenders of private bonds
may be withdrawn at any time prior to the expiration date for the exchange
offer.
If you want to withdraw your tender of private bonds in the exchange offer,
the exchange agent must receive a written or faxed notice of withdrawal at its
address set forth below prior to the expiration date for the exchange offer. Any
notice of withdrawal must:
- specify the name of the person having deposited the private bonds to be
withdrawn;
- identify the private bonds to be withdrawn, including the certificate
number or numbers and principal amount of the private bonds; and
- be signed by the holder in the same manner as the original signature on
the letter of transmittal by which its private bonds were tendered,
including any required signature guarantees.
All questions as to the validity, form and eligibility, including time of
receipt, of these notices will be determined by us in our sole discretion, and
our determination will be final and binding on all parties. Any private bonds so
withdrawn will be deemed not to have been validly tendered for purposes of the
exchange offer and no exchange bonds will be issued in exchange for these
private bonds unless the private bonds so withdrawn are validly retendered.
Properly withdrawn private bonds may be retendered by following one of the
procedures described above under the caption "--Procedures for Tendering" at any
time prior to the expiration date for the exchange offer.
CONDITIONS
Notwithstanding any other term of the exchange offer, we will not be
required to accept for exchange, or exchange the exchange bonds for, any private
bonds, and may terminate the exchange offer as provided in this prospectus
before the acceptance of private bonds, if the exchange offer violates
applicable law, rules or regulations or an applicable interpretation of the
staff of the Securities and Exchange Commission.
If we determine in our sole discretion that any of these conditions are not
satisfied, we may:
39
<PAGE>
- refuse to accept any private bonds and return all tendered private bonds
to the tendering holders;
- extend the exchange offer and retain all private bonds tendered prior to
the expiration of the exchange offer; however, holders will retain their
rights to withdraw their private bonds; or
- waive unsatisfied conditions with respect to the exchange offer and accept
all properly tendered private bonds that have not been withdrawn.
If the waiver constitutes a material change to the exchange offer, we will
promptly disclose that waiver by means of a prospectus supplement that will be
distributed to the registered holders of the private bonds, and we will extend
the exchange offer for a period of five to ten business days, depending upon the
significance of the waiver and the manner of disclosure to the registered
holders, if the exchange offer would otherwise expire during that five to ten
business day period.
TERMINATION OF REGISTRATION AND OTHER RIGHTS
All rights under the registration rights agreement, including registration
rights, of holders of the private bonds eligible to participate in the exchange
offer will terminate upon consummation of the exchange offer, except with
respect to our continuing obligations to indemnify holders of the private bonds
and related parties against various liabilities, including liabilities under the
Securities Act of 1933.
EXCHANGE AGENT
We have appointed The Bank of New York as the exchange agent for the
exchange offer. If you have questions or need assistance, or if you would like
additional copies of this prospectus or of the letter of transmittal or a notice
of guaranteed delivery, you should contact the exchange agent at the following
address, phone and fax numbers:
<TABLE>
<S> <C>
BY REGISTERED OR CERTIFIED MAIL: BY HAND DELIVERY:
The Bank of New York The Bank of New York
101 Barclay Street, 16th Floor 101 Barclay Street, 16th Floor
New York, NY 10286 New York, NY 10286
Attention: Corporate Trust Administration Attention: Corporate Trust Administration
BY OVERNIGHT DELIVERY: BY FACSIMILE:
The Bank of New York (212) 815-5915
101 Barclay Street, 16th Floor
New York, NY 10286 CONFIRM BY TELEPHONE:
Attention: Corporate Trust Administration (212) 815-5939
</TABLE>
FEES AND EXPENSES
We will bear the expenses of soliciting tenders. We are making the principal
solicitation for tenders by mail. However, we may make additional solicitations
by facsimile, telephone or in person through our officers and regular employees
and those of our affiliates.
We have not retained any dealer-manager for the exchange offer and will not
make any payments to brokers, dealers or others soliciting acceptances of the
exchange offer. However, we will pay the exchange agent reasonable and customary
fees for its services and will reimburse it for its reasonable out-of-pocket
expenses incurred because of the exchange offer.
40
<PAGE>
We will pay the cash expenses to be incurred because of the exchange offer,
which we estimate will be approximately $305,000. These expenses include
registration fees, fees and expenses of the exchange agent and the trustee,
accounting and legal fees and printing costs, among others.
We will pay all transfer taxes, if any, applicable to the exchange of
private bonds in the exchange offer. If, however, a transfer tax is imposed for
any reason other than the exchange of the private bonds in the exchange offer,
then the amount of the transfer tax, whether imposed on the registered holder or
any other person, will be payable by the tendering holder. If satisfactory
evidence of payment of these taxes or exemption from these taxes is not
submitted with the letter of transmittal, the amount of the transfer taxes will
be billed directly to the tendering holder.
CONSEQUENCE OF FAILURES TO EXCHANGE
Participation in the exchange offer is voluntary. We urge holders of the
private bonds to consult their financial and tax advisors in making their own
decisions on what action to take.
The private bonds that are not exchanged for the exchange bonds in the
exchange offer will remain restricted securities. Accordingly, those private
bonds may be offered, resold, pledged or otherwise transferred only:
- to a person who the seller reasonably believes is a qualified
institutional buyer, as defined in Rule 144A under the Securities Act of
1933, in a transaction meeting the requirements of Rule 144A, outside the
United States to a foreign person in a transaction meeting the
requirements of Rule 904 under the Securities Act of 1933, or in
accordance with another exemption from the registration requirements of
the Securities Act of 1933, and based upon an opinion of counsel if we so
request;
- to us or the Funding Corporation; or
- under an effective registration statement.
and, in each case, in accordance with any applicable securities laws of any
State of the United States or any other applicable jurisdiction.
ACCOUNTING TREATMENT
For accounting purposes, we will recognize no gain or loss as a result of
the exchange offer. We will amortize the expenses of the exchange offer over the
term of the exchange bonds.
41
<PAGE>
USE OF PROCEEDS
We will not receive any proceeds from the exchange offer. The net proceeds
received by us from the private bonds were approximately $324,290,000, after
deducting discounts and commissions and other fees and expenses related to the
offering of the private bonds paid by us.
ESTIMATED SOURCES AND USES OF FUNDS
The following table sets forth the estimated sources and uses of funds for
our development, construction, financing and commencement of commercial
operation of our project and the Panola County infrastructure, including the
issuance of the bonds. We cannot assure you that these estimates will correspond
to the actual uses of funds required to complete our project or the Panola
County infrastructure. Proceeds from the sale of the private bonds net of
disbursements made on the date the private bonds were issued were deposited in
an account called the construction account and applied in accordance with the
financing documents. The bondholders and our other senior secured creditors have
a lien on the construction account. See "Description of the Principal Financing
Documents--Common Agreement--Deposit and Disbursement--Construction Account."
<TABLE>
<CAPTION>
(IN THOUSANDS)
SOURCES OF FUNDS: --------------
<S> <C>
7.164% series A senior secured bonds due January 15, 2014... $150,000
8.160% series B senior secured bonds due July 15, 2025...... 176,000
Equity Investment(1)........................................ 54,000
Infrastructure Funds(2)..................................... 16,406
--------
Total Sources........................................... $396,406
========
USES OF FUNDS:
Repayment of Indebtedness (as of May 13, 1999)(3)........... $136,600
Engineering, Procurement, Construction...................... 144,362
Start-up costs and spare parts(4)........................... 5,273
Contractor's Fee............................................ 1,944
Construction Management(5).................................. 1,419
Development and Financing Fees(6)........................... 6,996
Gas, Water and Electrical Facilities(7)..................... 25,689
Electrical Interconnections................................. 15,458
Debt Service Reserve........................................ 12,551
Contingency(8).............................................. 23,383
Construction Interest Expense(9)............................ 25,971
Interest Income(10)......................................... (3,240)
--------
Total uses.............................................. $396,406
========
</TABLE>
- ------------------------
(1) See "Description of the Principal Financing Documents--Equity
Arrangements--Equity Commitment Obligation." As of January 31, 2000 we had
not yet received any portion of the equity investment.
(2) Consists of amounts that (1) the State of Mississippi has paid or will pay
us to reimburse us for most of what we spent on the development and
construction of the Panola County infrastructure and (2) Panola County has
paid or will pay to the construction contractors for any remaining costs due
under the Panola County infrastructure contracts. See "Business--Our
Company--The Panola County Infrastructure". As of January 31, 2000, we had
received about $14,278,000 from the State of Mississippi as a reimbursement.
42
<PAGE>
(3) This loan incurred interest at a rate of LIBOR, which is a rate per annum
equal to the offered rate for U.S. dollar deposits in the London Interbank
Market two days prior to the beginning of the interest period for the loan
divided by 100% and minus the reserve requirement for the loan, plus 1 1/8%.
This loan would have matured on December 15, 2001.
(4) Includes the $390,000 fee to be paid to Cogentrix Batesville Operations
under the operation and maintenance agreement for services provided prior to
the commencement of commercial operation.
(5) Includes the $333,333 fee to be paid to LSP Management, LLC under the
management services agreement for services provided prior to June 1, 2000.
(6) Includes a development fee paid to one of our affiliates, as described in
the definition of "Project Costs."
(7) Includes the costs of constructing the Panola County infrastructure and
related change orders.
(8) Includes Panola County infrastructure funds to be received in the amount of
$16,406,000 (see Note 2, above), $2,115,000 to be paid for the water
pretreatment system and $1,500,000 to be paid to Yalobusha County.
(9) Reflects an interest rate of 7.164% for the series C bonds, and an interest
rate of 8.160% for the series D bonds.
(10) Reflects an assumed annual interest rate of 5.50% on funds in interest
bearing accounts and actual interest income through November 30, 1999.
43
<PAGE>
CAPITALIZATION
The following tables set forth our capitalization as of December 31, 1999
and as adjusted to give effect to our issuance of the bonds. The private bonds
surrendered in exchange for the exchange bonds will be retired and canceled and
cannot be reissued. Accordingly, issuance of the exchange bonds will not result
in any increase or decrease in our indebtedness or that of the Funding
Corporation. As such, no effect has been given to the exchange offer in the
tables set forth below. In addition, we have not adjusted the following tables
to reflect (1) obligations of LSP Batesville Holding to make equity
contributions to us in an aggregate amount of $54,000,000 after we spend all of
the proceeds of the private bonds or (2) our contingent obligations to reimburse
draws under the Virginia Power letters of credit, in an aggregate face amount of
$11,320,000.
<TABLE>
<CAPTION>
DECEMBER 31, 1999
----------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
LONG-TERM DEBT:
Series A senior secured bonds due 2014.................... 150,000 150,000
Series B senior secured bonds due 2025.................... 176,000 176,000
-------- --------
Total long-term debt.................................... $326,000 $326,000
PARTNERS' CAPITAL (DEFICIT):
Capital contributions..................................... 1 1
Net income accumulated during the development stage(1).... 3,426 3,426
Distributions to partners(1).............................. (5,374) (5,374)
-------- --------
Total partners' capital (deficit)....................... (1,947) (1,947)
-------- --------
Total long-term debt and partners' capital
(deficit)........................................... $357,509 $357,509
======== ========
</TABLE>
- ------------------------
(1) Income derived principally from a payment made to us by a potential power
purchaser upon the expiration of an option that it had to cause us to sell
power to it. Distributions of this income were made in 1996 and 1997.
44
<PAGE>
SELECTED FINANCIAL DATA
The following selected financial data has been taken from the financial
statements of LSP Energy Limited Partnership and LSP Batesville Funding
Corporation. The information set forth below should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition" and the financial
statements and related notes included in this prospectus.
STATEMENT OF OPERATIONS DATA:
<TABLE>
<CAPTION>
FOR THE PERIOD FOR THE PERIOD
FOR THE YEAR ENDED FROM INCEPTION FROM INCEPTION
DECEMBER 31, (FEBRUARY 7, 1996) (FEBRUARY 7, 1996)
------------------------------------ TO DECEMBER 31, TO DECEMBER 31,
1999 1998 1997 1996 1999
----------- --------- ---------- ------------------ ------------------
<S> <C> <C> <C> <C> <C>
LSP ENERGY LIMITED PARTNERSHIP
Revenues..................... $ -- $ -- $5,224,084 $158,205 $5,382,289
Operations and maintenance
expenses................... 918,782 -- -- -- 918,782
Project management expenses.. 367,277 142,222 -- -- 509,899
General and administrative
expenses................... 218,635 301,603 4,205 3,744 528,187
----------- --------- ---------- -------- ----------
Net income (loss)............ $(1,504,694) $(443,725) $5,219,879 $154,461 $3,425,921
=========== ========= ========== ======== ==========
LSP BATESVILLE FUNDING
CORPORATION
Revenues..................... $ -- $ -- N/A N/A $ --
General and administrative
expenses................... 5,960 -- N/A N/A 5,960
----------- --------- ---------- -------- ----------
Net loss..................... $ (5,960) $ -- N/A N/A $ (5,960)
=========== ========= ========== ======== ==========
</TABLE>
BALANCE SHEET DATA:
<TABLE>
<CAPTION>
DECEMBER 31
-------------------------------------------------------------
1999 1998 1997 1996 1995
------------ ----------- -------- ---------- --------
<S> <C> <C> <C> <C> <C>
LSP ENERGY LIMITED PARTNERSHIP
Current assets............................... $ 54,657,970 $ 140,933 $ -- $ -- N/A
Contract retainage payable................... $ 11,944,208 -- -- -- --
Current liabilities.......................... 37,213,545 13,662,781 -- -- N/A
Investments.................................. -- -- -- 3,544,461 N/A
Property and construction in progress........ 296,509,139 83,429,694 -- -- N/A
Deferred revenue............................. -- -- -- 3,500,000 N/A
Total assets................................. 361,266,126 94,102,400 -- 3,544,461 N/A
Contract retainage payable................... -- 2,882,344 -- -- N/A
Long-term debt............................... 326,000,000 78,000,000 -- -- N/A
Partners' capital (deficit).................. $ (1,947,419) $ (442,725) $ -- $ 44,461 N/A
LSP BATESVILLE FUNDING CORPORATION
Current assets............................... $ 1,000 $ 1,000 N/A N/A N/A
Current liabilities.......................... 5,960 -- N/A N/A N/A
Total assets................................. 1,000 1,000 N/A N/A N/A
Stockholder's equity (deficit)............... $ (4,960) $ 1,000 N/A N/A N/A
OUR RATIO OF EARNINGS TO FIXED CHARGES(1)...... N/A N/A N/A N/A N/A
</TABLE>
- ------------------------
(1) Earnings were insufficient to cover fixed charges by $20,512,833 and
$2,258,725 during the years ended December 31, 1999 and 1998, respectively.
Capitalized interest including amortization of debt issuance and financing
costs was $19,008,000 ($14,962,000 before amortization) and $1,815,000
($1,581,000 before amortization) for the years ended December 31, 1999 and
1998, respectively. For all periods prior to 1998 we incurred no fixed
charges; therefore our ratio of earnings to fixed charges for those periods
is not meaningful.
45
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
GENERAL
Since our formation in 1996, we have been developing and constructing our
power facility. In addition, up until November 1999, we were developing and
constructing the Panola County gas and water infrastructure that our power
facility will use under contracts with three construction contractors. In
November 1999, we transferred to Panola County those construction contracts, all
of the completed portions of the Panola County infrastructure, all of the Panola
County infrastructure work in progress, real estate rights related to the Panola
County infrastructure and permits related to the Panola County infrastructure.
In exchange for that transfer, the State of Mississippi agreed to reimburse us
for the amounts that we spent on (1) the development of the Panola County
infrastructure, (2) the acquisition of Panola County infrastructure related
easements and (3) construction of the Panola County infrastructure from
April 11, 1999 until we transferred the Panola County infrastructure to Panola
County. In addition, Panola County is now obligated to pay the Panola County
infrastructure construction contractors the amounts still due to those
contractors under their contracts.
Our power facility has not yet generated any operating revenues. We expect
that the total cost of developing, constructing and financing our power facility
and the Panola County infrastructure will be approximately $396,406,000. We
capitalized the costs pertaining to the construction of our power facility and
the Panola County infrastructure as property and construction in progress and
the costs pertaining to the financing of our power facility and the Panola
County infrastructure as debt issuance and financing costs, and we included
these items as assets on our balance sheets.
RESULTS OF OPERATIONS
During 1996 we entered into an option purchase agreement with a third party.
Under the terms of the option purchase agreement, the third party had the option
to purchase 750 megawatts of capacity and dispatchable energy for a specified
term from our power facility. As consideration for this option, the third party
made an initial option payment to us of $3,500,000 in 1996, and an additional
option payment of $1,500,000 in 1997. Both option payments were placed in escrow
to secure performance of our obligations under the option purchase agreement.
Under the terms of the escrow agreement, we were allowed to withdraw investment
earnings on the funds placed in escrow but could not withdraw the principal
amount placed in escrow until the funds were released under the option purchase
agreement. Revenues of approximately $224,000 and $158,000 in 1997 and 1996,
respectively, consisted of investment earnings on these escrow funds. Effective
November 1, 1997, the option purchase agreement expired unexercised and, under
the terms of the option purchase agreement, we were permitted to retain the
$5,000,000 of option payments which were held in escrow. Accordingly, we
recognized the option payments as revenue. We expensed the costs incurred under
the escrow agreement in 1997 and 1996. We have no continuing financial
commitments under the option purchase agreement.
We expensed the project development costs not directly related to the
construction and financing of the project. For the year ended December 31, 1998,
project development expenses not directly related to the construction and
financing of the project of approximately $444,000 consisted of legal fees of
approximately $302,000 pertaining to contract negotiations and regulatory
matters and other general and administrative expenses of approximately $142,000.
For the year ended December 31, 1999 project development expenses not
directly related to the construction and financing of the project aggregated
approximately $586,000, which amount consisted of legal fees of approximately
$189,000 pertaining to contract negotiations and regulatory matters,
approximately $133,000 of management fees and approximately $234,000 of labor
charges, related benefits and taxes and other management expenses incurred under
the management services agreement with LSP Management.
46
<PAGE>
Operations and maintenance expenses for the year ended December 31, 1999 of
approximately $919,000 consisted primarily of costs incurred under the
operations and maintenance agreement with Cogentrix Batesville Operations. These
costs consist primarily of approximately $718,000 of Cogentrix Batesville
Operations labor charges, related taxes and benefits and $156,000 of
precommencement services.
LIQUIDITY AND CAPITAL RESOURCES
We are using the net proceeds from the issuance of the private bonds, the
$54,000,000 of equity contributions that we will receive from LSP Batesville
Holding from time to time, and the reimbursements payments that we have and will
receive from Panola County to pay the costs of developing, constructing and
financing our power facility and the Panola County infrastructure. Prior to the
issuance of the private bonds, we funded these costs with the proceeds of our
loan facility. We repaid this loan of $136,600,000 in full on May 21, 1999 with
a portion of the net proceeds of the private bonds.
As of December 31, 1999, our principal sources of liquidity were the
$36,121,000 of remaining proceeds from the issuance of the private bonds,
$14,278,000 of Panola County infrastructure reimbursement funds received from
the State of Mississippi, plus investment earnings on such funds of
approximately $3,148,000, and the $54,000,000 of equity contributions that we
will receive from LSP Batesville Holding from time to time after we have spent
all of the proceeds of the private bonds. The remaining proceeds from the
issuance of the private bonds and the Panola County infrastructure reimbursement
funds are held by the trustee and are invested primarily in short term
commercial paper rated at least A-1 by Standard & Poor's Rating Group or at
least P-1 by Moody's Investors Service, Inc. LSP Batesville Holding's obligation
to contribute equity to us under its equity contribution agreement is supported
by a letter of credit naming Congentrix Energy, Inc. as the account party. This
letter of credit has been issued by a bank rated at least A2 by Moody's
investors Service, Inc. and at least A by Standard & Poor's Rating Group.
The net proceeds from the issuance of the private bonds and the $54,000,000
of equity contributions that we will receive from LSP Batesville Holding were
designed to be sufficient to fund the costs of developing and constructing our
power facility and the Panola County infrastructure. Accordingly, we were able
to pay the costs associated with the Panola County infrastructure prior to
receiving Panola County infrastructure reimbursement funds from the State of
Mississippi. As of December 31, 1999, we had received $14,278,000 of Panola
County infrastructure reimbursement funds from the State. This reimbursement has
been reflected as a reduction in property and construction in progress in the
accompanying financial statements. We allocated the $14,278,000 that we received
from the State, and we will allocate any additional reimbursement funds that we
receive from the State, to the contingency line item of our budget. In addition,
now that we are no longer responsible for constructing the Panola County
infrastructure, we will reallocate unspent funds from the Panola County
infrastructure line item of our budget to the contingency line item of our
budget. Adding these funds to our contingency will allow us to apply these funds
to pay for any project cost overruns that we may have. If we do not experience
cost overruns, or if our cost overruns are less than the amount of our
contingency, we will be able to distribute unused contingency if we satisfy the
distribution conditions contained in the financing documents.
47
<PAGE>
Total estimated facility and Panola County infrastructure costs, and
facility and Panola County infrastructure costs incurred as of December 31,
1999, by major category are as follows:
<TABLE>
<CAPTION>
COSTS INCURRED
TOTAL ESTIMATED AS OF
COSTS DECEMBER 31, 1999
--------------- -----------------
<S> <C> <C>
Construction of plant.......................... $244,767,000 $224,716,000
Elecrical and gas interconnection costs........ 22,340,000 19,042,000
Electrical facilities.......................... 9,200,000 9,134,000
Infrastructure costs........................... 18,618,000 17,327,000
Interest expense during construction........... 26,460,000 16,777,000
Debt service reserve........................... 12,551,000 --
Contingency.................................... 19,768,000 --
Development fees and financing costs........... 28,245,000 28,145,000
Spare parts, equipment and material............ 3,623,000 1,013,000
Construction management........................ 1,987,000 1,411,000
Operations and maintenance..................... 1,650,000 984,000
Casualty risk insurance........................ 1,362,000 1,362,000
All other costs................................ 5,835,000 3,831,000
------------ ------------
Total...................................... $396,406,000 $323,742,000
============ ============
</TABLE>
As of December 31, 1999, costs incurred on our power facility and the Panola
County infrastructure were approximately $323,742,000. Included in this amount
is approximately $296,509,000, net of the Panola County infrastructure
reimbursement funds of approximately $14,278,000, of property and construction
in progress, approximately $10,099,000 of debt issuance and financing costs and
approximately $908,000 of inventory and other current assets. In addition,
$1,948,000 of costs incurred had been expensed as of December 31, 1999. As of
December 31, 1999, we had expended approximately $289,677,000 of cash.
Costs expensed to December 31, 1999 is comprised primarily of $509,000,
$874,000 and $491,000 of costs incurred for the management services agreement
with LSP Management, the operations and maintenance agreement with Cogentrix
Batesville Operations and legal fees pertaining to contract negotiations and
regulatory matters, respectively. Costs incurred under the management services
agreement with LSP Management and the operations and maintenance agreement with
Cogentrix Batesville Operations are components of the construction management
and operations and maintenance categories, respectively, in the table above.
Legal fees are a component of the all other costs category. Other components of
the all other costs category include expenses related to land and easements and
consultants fees. BVZ Power Partners anticipates that construction of our power
facility will be completed during the second quarter of 2000.
FACILITY CONSTRUCTION COSTS
BVZ Power Partners is constructing our power facility under a $240,174,000
construction contract, excluding sales and use tax. BVZ Power Partners has
committed to completing the construction and start-up to specified performance
levels of the two Virginia Power generating units and the Aquila/ UtiliCorp
generating unit on or prior to July 16, 2000, July 26, 2000, and July 31, 2000,
respectively, unless these dates are adjusted in accordance with the
construction contract. As of December 31, 1999 BVZ Power Partners estimated that
its engineering, procurement and construction of our power facility was about
93% complete, and total costs incurred were approximately $222,664,000,
including approximately $11,091,000 of retainage. Retainage is that
contractually specified percentage of the contract value that is withheld from
the current payment due to the construction contractor until the construction
contractor completes its work under the construction contract.
48
<PAGE>
Lauren Constructors, Inc. is constructing our power facility's water
pretreatment system. The water pretreatment system is designed to ensure that
water supplied to our power facility is of the quality specified in the
construction contract with BVZ Power Partners. The lump sum price for this
contract is approximately $1,703,000. As of December 31, 1999, approximately
$207,000 of the contract has been completed and invoiced to us, including
approximately $10,000 of retainage. Lauren Constructors estimates that the water
pretreatment system will be completed on or prior to April 7, 2000.
Kruger, Inc. is the supplier of the water pretreatment system equipment. The
lump sum price for this contract is about $415,000, which includes all costs
associated with the engineering, manufacturing and delivery of the water
pretreatment system equipment. The water pretreatment equipment was delivered to
our power facility during January 2000. As of December 31, 1999, approximately
$166,000 of the contract had been completed and invoiced to us, including
approximately $8,300 of retainage.
At December 31, 1999 and 1998, we had approximately $16,299,000 and
$13,848,000, respectively, of outstanding invoices, including retainage, under
these contracts.
ELECTRICAL AND GAS INTERCONNECTION COSTS
We are paying the costs of the interconnection facilities and system
upgrades that are being constructed by the Tennessee Valley Authority and
Entergy.
The costs of the Tennessee Valley Authority interconnection facilities and
system upgrades are approximately $4,000,000 and $9,500,000 respectively. As of
December 31, 1999, approximately $12,556,000 of these costs had been invoiced to
us by the Tennessee Valley Authority. The costs of the Entergy interconnection
facilities and system upgrades are approximately $1,100,000 and $7,100,000,
respectively. As of December 31, 1999, approximately $6,286,000 of these costs
had been invoiced to us by Entergy.
At December 31, 1999 and 1998, we had approximately $3,757,000 and
$2,077,000 of outstanding invoices, respectively, under these contracts.
We are entitled to receive system upgrade credits in the amount of the
incremental revenue received by the Tennessee Valley Authority and Entergy for
future transmission services procured for the delivery of energy from our power
facility. The amount of these credits, if any, may not exceed the total costs of
the system upgrades paid for by us.
ELECTRICAL FACILITIES COSTS
Lauren Constructors, Inc. is constructing our electrical substation and
transmission lines that will interconnect with the Tennessee Valley Authority
and Entergy transmission systems. The lump sum price of this contract is
approximately $4,714,000, including change orders. As of December 1999, the
total contract value was invoiced to us, including about $228,000 of retainage.
North American Transformer, Inc. is supplying four single-phase transformers
to be incorporated into our electrical substation. The lump sum price of this
contract is approximately $3,683,000. As of December 31, 1999, the total
contract value was invoiced to us, including approximately $368,000 of
retainage. All four transformers have been installed, tested and energized.
Siemens Power Transmission and Distribution, LLC is supplying thirteen
circuit breakers to be incorporated into our electrical substation. The lump sum
price of this contract is approximately $722,000. As of December 31, 1999, the
total contract value was invoiced to us, including approximately $72,000 of
retainage. All the circuit breakers have been delivered and installed within the
electrical substation.
At December 31, 1999 we had approximately $782,000 of outstanding invoices,
including retainage, under these contracts. At December 31, 1998, there were no
amounts outstanding under these contracts. Approximately $239,000 of retainage
under these contracts has been released.
49
<PAGE>
PANOLA COUNTY INFRASTRUCTURE COSTS
WATER
Robinson Mechanical Contractors, Inc. is constructing the intake facilities
that will draw water from Enid Lake and pump it to our power facility. The lump
sum price of this contract is approximately $5,256,000, including change orders.
As of December 31, 1999 Robinson Mechanical estimated that its engineering,
procurement and construction was approximately 91% complete, and total costs we
incurred were approximately $4,080,000. As of December 31, 1999, we had
outstanding accounts payable to Robinson Mechanical of approximately $150,000.
Garney Companies, Inc. has constructed a water supply pipeline to transport
water from Lake Enid to our power facility and a wastewater discharge pipeline
to transport wastewater from our power facility to the Little Tallahatchie
River. The lump sum price of this contract is approximately $4,528,000,
including change orders. The water supply and wastewater discharge pipelines
were tested and declared complete on August 5, 1999. As of December 31, 1999 the
total contract value had been invoiced to us. As of December 31, 1999, we had
outstanding accounts payable to Garney of approximately $20,000.
At December 31, 1999, we had approximately $170,000 of outstanding invoices,
including retainage, under these contracts. At December 31, 1998, there were no
amounts outstanding under these contracts. Approximately $884,000 of retainage
under these contracts has been released. As previously noted, we transferred
these contracts to Panola County in November 1999.
GAS
Big Warrior Corporation is constructing a lateral gas pipeline and related
facilities to transport natural gas from two interstate gas pipelines to our
power facility. The lump sum price of this contract is approximately $8,565,000,
including change orders. As of December 31, 1999 Big Warrior estimated that its
engineering, procurement and construction was about 99% complete, and total
costs we incurred were approximately $8,450,000. As of December 31, 1999, we had
no outstanding accounts payable to Big Warrior. Construction of the pipeline has
been sufficiently completed to allow delivery of fuel gas to our power facility
as necessary to support equipment testing and startup.
At December 31, 1999 we had no outstanding invoices under this contract. At
December 31, 1998, there were no amounts outstanding under this contract.
Approximately $583,000 of retainage under this contract has been released. As
previously noted, we transferred this contract to Panola County in November
1999.
INTEREST COSTS
During construction, we capitalize interest costs net of interest income on
excess proceeds from loans under our loan facility and the private bonds. As of
December 31, 1999 and 1998, capitalized interest was approximately $16,777,000
and $1,581,000, respectively, net of interest income of approximately $3,167,000
and $1,000, respectively. Cash paid for interest was approximately $3,172,000
and $1,426,000 for the years ended December 31, 1999 and 1998, respectively.
Accrued interest payable as of December 31, 1999 was approximately $15,345,000.
This amount plus interest through January 15, 2000 of approximately $925,000 was
paid on January 15, 2000. These amounts were paid from the net proceeds of the
private bonds and the Panola County infrastructure reimbursement funds which are
on deposit in our construction account. The bondholders and our other senior
secured lenders have a security interest in the construction account.
DEVELOPMENT FEES AND FINANCING COSTS
We paid a development fee of $14,000,000 to Granite Power Partners II, L.P.
in consideration for development activities provided to us prior to the offering
of the private bonds. As of December 31,
50
<PAGE>
1999 we had incurred about $14,145,000 of costs to finance our power facility.
Development fees and amortization of financing fees have been capitalized as a
component of construction in progress as of December 31, 1999.
SPARE PARTS, EQUIPMENT AND MATERIALS
Through a letter agreement dated July 20, 1998, we have committed to
purchase and Westinghouse Power Generation has agreed to sell combustion turbine
parts for our power facility. The price for the initial order of parts is about
$2,096,000. We will receive a 20% discount from the original agreement price
adjusted for inflation for any subsequent orders. As of December 31, 1999 we had
purchased and received about $734,000 of spare parts.
CONSTRUCTION MANAGEMENT
LSP Management provides management services to us under a management
services agreement. Under this management services agreement, LSP Management
manages our business affairs during the construction and operation of our power
facility. LSP Management is reimbursed for its reasonable and necessary expenses
incurred in performing its services and also receives a monthly management fee
of approximately $33,300 during the construction and operation of our power
facility. As of December 31, 1999, LSP Management had billed us approximately
$1,411,000 under the management services agreement. Construction management
costs not directly associated with the construction of our power facility of
approximately $509,000 have been expensed.
OPERATIONS AND MAINTENANCE
Our power facility is operated and maintained under a long-term operations
and maintenance agreement with Cogentrix Batesville Operations. The initial term
of the operations and maintenance agreement is 27 years. Under the terms of the
agreement we are required to pay Cogentrix Batesville Operations a fixed fee of
$390,000, payable in ten monthly installments, for services provided during the
construction of our power facility and a fixed monthly fee of approximately
$42,000 during the operation of our power facility. We also are required to
reimburse Cogentrix Batesville Operations for all labor costs, including payroll
and taxes, subcontractor costs and other costs deemed reimbursable by us. As of
December 31, 1999, Cogentrix Batesville Operations had billed us approximately
$984,000 under the operations and maintenance agreement. Costs incurred under
this agreement not directly associated with the construction of our power
facility of approximately $874,000 have been expensed.
CONTINGENCY
Our original project budget includes a line item, which we refer to as
"contingency", of approximately $10,649,000 that is designed to cover things
like change orders under the various construction contracts, the cost of fuel
consumed by our power facility during testing in excess of the revenue received
from the sale of test energy, and other increased costs due to force majeure and
other events that may increase our expenses. As of December 31, 1999, we had
reduced our available contingency by approximately $1,067,000 for change orders
under our various construction contracts, by approximately $2,115,000 for the
cost of the water pretreatment contract, by $1,500,000 for our payment to
Yalobusha County under our contract with it, and by approximately $2,605,000 for
budget overruns. Offsetting these reductions will be an increase to our
contingency of approximately $16,406,000 as a result of (1) the Panola County
infrastructure reimbursement payments that have and will be made to us by the
State of Mississippi under the previously described arrangements and (2) our
reallocation of the amounts that we had previously allocated to the Panola
County infrastructure construction line item of our budget and have not yet
spent, because Panola County is now obligated to pay amounts due under the
Panola County infrastructure construction contracts.
51
<PAGE>
INSURANCE
We are required to maintain casualty risk insurance during the construction
period, including delayed opening insurance covering a period of approximately
18 months with a 30-day deductible per occurrence. The cost of this insurance
was approximately $1,362,000.
As with any power generation facility, the construction of the project
involves certain risks, including shortages of labor, work stoppages, labor
disputes, weather interference, engineering, environmental, permitting and
unanticipated cost increases for reasons beyond our and our construction
contractors' control. The occurrence of one or more of these events could
significantly increase our expenses, which could adversely impact our ability to
make payments of principal and interest on the exchange bonds and our other debt
when due. Not all risks are insured and the proceeds from our insurance
applicable to covered risks may not be adequate to cover our increased expenses.
POST-COMPLETION LIQUIDITY
Subsequent to the completion of our power facility, our primary sources of
liquidity will be two long-term power purchase agreements for the sale of the
capacity of and electric energy from our power facility and any remaining
amounts in our contingency. One of these power purchase agreements is with
Virginia Power and covers the sale of the capacity of and electric energy from
two of our generating units for an initial term of 13 years, which Virginia
Power can extend at its option for an additional 12 years. The other agreement
is with Aquila/UtiliCorp and covers the sale of the capacity of and electric
energy from our other generating unit for an initial term of 15 years and seven
months, which Aquila/UtiliCorp can extend at its option for an additional five
years.
These agreements require Virginia Power and Aquila/UtiliCorp to provide us
with the natural gas which we will use to fuel the generating units that are
dedicated to the applicable purchaser. In addition, both of these power purchase
agreements require the applicable purchaser to pay us
(1) a monthly "reservation" payment based on the tested capacity and
availability of the generating units dedicated to the purchaser,
(2) an "energy" payment based on the amount of energy that we actually
produce for the purchaser and deliver to the interconnection point
between our power facility and the utility transmission systems and
(3) other payments, including payments based upon the fuel efficiency of our
generating units and the number of times the purchaser starts up our
generating units each year.
Both of these power purchase agreements allow the power purchasers to dispatch
the generating units we have dedicated to them, meaning that the power
purchasers have the right to control how much electricity they want their
dedicated units to produce. However, even if we are not dispatched at all by
Virginia Power and Aquila/UtiliCorp, they will still have to pay us the
reservation payment as provided under the power purchase agreements.
We have agreed with Virginia Power and Aquila/UtiliCorp that their
respective generating units will be able to begin delivering power to them by
June 1, 2000, which date may be extended as a result of certain excused delays.
However, BVZ Power Partners has not guaranteed that it will substantially
complete our power facility by this date. Instead, BVZ Power Partners has
guaranteed to substantially complete the two units that will provide power to
Virginia Power by July 16, 2000 and July 26, 2000 and to substantially complete
the unit that will provide power to Aquila/UtiliCorp by July 31, 2000. Each of
these dates may be extended under the construction contract in some
circumstances to give BVZ Power Partners more time to substantially complete the
units.
We have received a force majeure notice from BVZ Power Partners and ABB
Power Generation Inc., the steam turbine generator manufacturer, with respect to
transportation delays incurred during the delivery of one of the Virginia Power
unit's steam turbine generators to our power facility. We have requested that
ABB Power Generation provide additional information to support the claim of
force
52
<PAGE>
majeure. In response to our request ABB Power Generation has recently provided
information indicating a total of 21 days of delay and an 18 day claim of force
majeure for delay in the delivery of the steam turbine generator. We do not
believe that the delay in transportation of the steam turbine generator
constitutes a force majeure event. A final resolution of the issue has not yet
occurred. BVZ Power Partners has stated that it is working extra hours, multiple
shifts and weekends in an attempt to meet its originally projected target
completion dates. If it is determined that the delay in the delivery of the
steam turbine constitutes a force majeure event under the BVZ Power Partners
contract, BVZ Power Partners would be entitled to a day for day extension of the
guaranteed completion date with respect to that Virginia Power unit. We have
informed Virginia Power of the occurrence of a potential force majeure event as
a result of a delay in the delivery of the Virginia Power unit's steam turbine
generator that was beyond our reasonable control and without our fault or
negligence. If it is determined that the delay in the delivery of the steam
turbine constitutes a force majeure event under the Virginia Power power
purchase agreement, the date that we are required to deliver power under the
Virginia Power power purchase agreement would be extended day for day for the
number of days of the force majeure event.
A gap of 46 to 61 days currently exists between the guaranteed completion
dates under the BVZ Power Partners construction contract and the guaranteed
power delivery dates under the power purchase agreements. This gap may be
increased if BVZ Power Partners is successful in its claim that the steam
turbine delay constitutes a force majeure event under the BVZ Power Partners
construction contract and we are unsuccessful in our claim that the steam
turbine delay constitutes a force majeure event under the Virginia Power power
purchase agreement. This gap, and any further delay in construction and start-up
of our power facility beyond June 1, 2000, may obligate us to:
(1) provide replacement power to Virginia Power or reimburse Virginia Power
for any incremental replacement power costs during the period of delay, up to a
maximum of $11,320,000 and
(2) provide replacement power to Aquila/UtiliCorp, reimburse
Aquila/UtiliCorp for any incremental replacement power cost during the period of
delay, or incur an adjustment to the reservation payment payable to us under the
Aquila/UtiliCorp power purchase agreement.
The current construction schedule provided to us by BVZ Power Partners
anticipates that the construction and start-up of the two Virginia Power units
and the Aquila/UtiliCorp unit will occur on May 10, 2000, June 5, 2000 and
June 27, 2000, respectively. We have notified both Virginia Power and
Aquila/UtiliCorp of these revised dates. Based upon the estimated completion
date of June 5, 2000 for one of the Virginia Power units, we will be obligated
for the cost of replacement power for the period from June 1, 2000 to June 5,
2000. We have notified Aquila/UtiliCorp that we will elect to incur an
adjustment to the reservation payment to be received for the period from
June 1, 2000 to June 27, 2000 under the Aquila/UtiliCorp power purchase
agreement. The estimated liability that may result from this period of delay, if
any, cannot presently be determined.
While BVZ Power Partners will be obligated to pay us liquidated damages for
any failure to complete the construction and start-up of our power facility on
or prior to one day after the guaranteed completion dates, no delay damages will
be due from BVZ Power Partners with respect to any unit during the respective
gap periods described above. In addition, because the delay liquidated damages
are limited, we cannot assure you that the delay liquidated damages will fully
compensate us for replacement power costs or other costs associated with delays
for which BVZ Power Partners is responsible.
We are required to provide security to support our obligations under the
Virginia Power power purchase agreement. We have satisfied this requirement by
providing letters of credit for the benefit of Virginia Power. The Virginia
Power letters of credit have an initial face amount of $5,660,000. This amount
will increase to a maximum of $11,320,000 if we fail to meet certain milestones
under the Virginia Power power purchase agreement. Prior to the commercial
operation date for the Virginia Power dedicated units, the Virginia Power
letters of credit will not be replenished if they are drawn
53
<PAGE>
upon. However, we will be required to reimburse the issuing bank if these
letters of credit are drawn. Upon the commercial operation date for the Virginia
Power dedicated units, the Virginia Power letters of credit will be adjusted to
a face amount of $5,660,000 and will be subject to replenishment if drawn.
Again, we will be required to reimburse the issuing bank if these letters of
credit are drawn. See "Description of the Principal Financing
Documents--Virginia Power L/C Agreement." We also may be required to provide
security to support our obligations under the Aquila/UtiliCorp power purchase
agreement. This security would be in the form of cash, a surety bond, or a
letter of credit or guarantee from an investment grade entity. If our debt
service coverage ratio for each of the previous four consecutive calendar
quarters is less than 1.25 to 1.00 then we must provide Aquila/UtiliCorp, upon
their request, reasonable security for our obligations. The security must be in
an amount equal to $5.00 per kilowatt of the contract capacity or approximately
$1,300,000. We must maintain this security until the earlier of the date on
which (1) we provide Aquila/UtiliCorp documentation that our debt service
coverage ratio was 1.25 to 1.00 or greater for a period of four consecutive
calendar quarters and (2) the Aquila/UtiliCorp power purchase agreement
terminates, and we have paid in full to Aquila/ UtiliCorp the amounts that we
owe Aquila/UtiliCorp. See "Description of the Principal Project
Documents--Aquila/UtiliCorp Power Purchase Agreement--Credit Support."
Our obligation to pay for or provide replacement power to Virginia Power
during a delay in the commercial operation of the Virginia Power units is
limited to the amount of the Virginia Power letter of credit, which is a maximum
of $11,320,000. Because summer power prices have experienced significant
volatility, it is difficult to project the cost of replacing power from the
Virginia Power units. However, it is possible that in the event of a delay in
the commercial operation of the Virginia Power units the full amount of the
Virginia Power letter of credit may be drawn. In the event of a drawing under
the Virginia Power letter of credit, the drawn amount converts into a five year
amortizing loan payable by us. Consequently, a drawing under the Virginia Power
letter of credit could increase our debt service obligation by up to
approximately $3,500,000 per annum. In the event of a commercial operation delay
of the Aquila/UtiliCorp unit, the delivery delay adjustment under the
Aquila/UtiliCorp power purchase agreement could result in a reduction in the
reservation payments due from Aquila/ UtiliCorp to us until the amount of the
reduction in reservation payments equals the amount of the delivery delay
adjustment. The amount of the delivery delay adjustment is based on the
commercial operation date of the Aquila/UtiliCorp unit. We do not expect the
delivery delay adjustment to exceed approximately $2,000,000 in the aggregate.
We are dependent on the fixed reservation payments and other fixed payments
under the Virginia Power and Aquila/UtiliCorp power purchase agreements to meet
our fixed obligations, including debt service under the exchange bonds. Our
power purchasers' obligations to pay us these fixed payments are dependent upon
our power facility operating at minimum capacity and availability levels. We
expect to achieve the minimum capacity and availability levels; however, any
material shortfall in tested capacity or availability over a significant period
could impact our ability to make payments of principal and interest on the
exchange bonds and our other debt when due.
As with any power generation facility, operation of our power facility will
involve risk, including performance of our power facility below expected levels
of output and efficiency, shut-downs due to the breakdown or failure of
equipment or processes, violations of permit requirements, operator error, labor
disputes, or catastrophic events such as fires, earthquakes, explosions, floods
or other similar occurrences affecting a power generation facility or its power
purchasers. The occurrence of any of these events could significantly reduce or
eliminate revenues generated by our power facility or significantly increase the
expenses of our power facility, adversely impacting our ability to make payments
of principal and interest on the exchange bonds and our other debt when due.
YEAR 2000 ISSUES
The Year 2000 issue exists because many computers systems and applications,
including those embedded in equipment and facilities, use two digit rather than
four digit date fields to designate an
54
<PAGE>
applicable year. As a result, the systems and applications may not properly
recognize the Year 2000 or process data that includes such dates, potentially
causing data miscalculations or inaccuracies or operational malfunctions or
failures. We have included provisions in our construction contracts to help
ensure that our power facility is Year 2000 compliant. The contract with BVZ
Power Partners, for example, requires BVZ Power Partners, directly and through
subcontractors, to design, engineer, procure, construct and test its scope of
work so that its scope of work, including any computer hardware, software and
firmware, will operate accurately, and without interruption, accept, process and
in all manner retain full functionality when referring to, or involving, any
year or date in the twentieth or twenty-first centuries. The other contracts for
the construction of our power facility and the Panola County infrastructure
contain similar provisions.
Our core financial systems, which include applications such as purchasing,
accounts payable and general ledger, were purchased Year 2000 compliant.
No disruptions in the construction or systems of our power facility and the
Panola County infrastructure, or to the operations of any of our significant
third parties, have occurred since the new year as a result of Year 2000 related
issues.
55
<PAGE>
BUSINESS
OUR COMPANY
THE SCOPE OF OUR BUSINESS. We were formed in 1996 to develop, construct,
own, operate and finance our project. Our project is already under construction.
Though we may expand our power facility after the offering of the exchange bonds
by constructing additional electric generation capacity at our power facility
site, we do not intend to engage in any business activities other than those
related to our project. Because none of our power facility's units is
operational yet, we have not yet generated any operating revenues.
OUR INDIRECT OWNERS. We are indirectly owned primarily by LS Power, LLC and
Cogentrix Energy, Inc. LS Power is a privately owned independent power producer
that develops, constructs, owns and operates independent power projects in the
United States. LS Power and its affiliates have completed the financing of more
than 2,000 megawatts of electric generating capacity, including our power
facility, and have approximately 1,400 megawatts of additional capacity in
advanced development. Cogentrix is an independent power producer that acquires,
develops, owns and operates electric generating plants, principally in the
United States. Cogentrix has net ownership interests in 26 facilities comprising
approximately 2,110 megawatts, including our power facility.
OUR CO-ISSUER. Our sister company, LSP Batesville Funding Corporation, is
the co-issuer of the private bonds and will be the co-issuer of the exchange
bonds. The Funding Corporation was formed in 1998 for the sole purpose of
issuing the bonds and incurring other debt to finance our project. The Funding
Corporation has nominal assets and will not conduct any operations.
WE HAVE NO EMPLOYEES. Currently, neither we nor the Funding Corporation has
any employees. We will be dependent upon a number of third parties for the
provision of substantially all the services that we require. See "Risk
Factors--Construction and Operating Risks."
OUR PRINCIPAL EXECUTIVE OFFICE. Our principal executive offices are located
at Two Tower Center, 20th Floor, East Brunswick, New Jersey 08816. Our telephone
number is (732) 249-6750.
OUR PROJECT
OUR POWER FACILITY. Our power facility will be an approximately 837
megawatt natural gas-fired, three combined cycle unit electric generation
facility. Natural gas-fired facilities are those which use natural gas as a fuel
source. Combined cycle facilities are those which use the exhaust heat produced
by the combustion turbine to generate steam, which is in turn used to make
electricity in a steam turbine. Each of the three combined-cycle units of our
facility will therefore contain three main pieces of equipment: (1) a gas-fired
combustion turbine; (2) a heat recovery steam generator; and (3) a steam
turbine, plus auxiliary equipment.
When it is complete, our power facility will contain the following major
equipment, systems and facilities:
- three Westinghouse 501F combustion turbines equipped with dry low NO(x)
combustors;
- three Nooter/Erikson heat recovery steam generators, each equipped with
duct burners;
- three ABB Power Generation steam turbines;
- air quality control and monitoring systems; and
- various associated equipment and facilities, including water treatment
facilities and administration and maintenance buildings.
56
<PAGE>
We currently estimate that our power facility will be completed during the
second quarter of 2000 and that the Panola County infrastructure will be
completed during the first quarter of 2000.
R.W. Beck, the independent engineer for our project, discusses the major
technical components of our facility in its report, which is included in Annex B
to this prospectus. We encourage you to read the R.W. Beck report in its
entirety.
KEY PROJECT PARTICIPANTS. The table below indicates some of the principal
participants in our project and our company.
<TABLE>
<S> <C>
Funding Corporation.................. LSP Batesville Funding Corporation, our affiliate and the
co-issuer of the bonds.
LSP Batesville Holding............... LSP Batesville Holding, LLC, our limited partner and the
sole shareholder of LSP Energy and the Funding Corporation.
LSP Energy........................... LSP Energy, Inc., our general partner.
LS Power............................. LS Power, LLC, one of our indirect owners.
Cogentrix............................ Cogentrix Energy, Inc., one of our indirect owners.
BVZ Power Partners................... BVZ Power Partners-Batesville, a joint venture between Black
& Veatch Construction Inc. and H.B. Zachry Company and the
construction contractor for our power facility, other than
the electrical substation and the transmission lines.
Virginia Power....................... Virginia Electric and Power Company, one of our two
long-term power purchasers.
Aquila/UtiliCorp..................... Aquila Energy Marketing Corporation and UtiliCorp United
Inc., who together constitute our other long-term power
purchaser.
Cogentrix Batesville
Operations......................... Cogentrix Batesville Operations, LLC, a subsidiary of
Cogentrix and the operator of most of our project.
LS Power Management.................. LS Power Management, LLC, a subsidiary of LS Power and the
business manager of our project.
Panola County........................ Panola County, Mississippi, the governmental authority from
whom we lease the gas and water infrastructure for our
project.
Industrial Development Authority..... The Industrial Development Authority of Panola County, which
will acquire the gas and water infrastructure for our power
facility from Panola County after the infrastructure has
been placed in service.
Tennessee Gas........................ Tennessee Gas Pipeline Company, one of the two interstate
gas pipeline companies that has agreed to interconnect its
pipeline with the lateral natural gas pipeline that will
reach our power facility.
ANR Pipeline......................... ANR Pipeline Company, the other interstate gas pipeline
company that has agreed to interconnect its pipeline with
the lateral natural gas pipeline that will reach our power
facility.
</TABLE>
57
<PAGE>
<TABLE>
<S> <C>
Tennessee Valley Authority........... The Tennessee Valley Authority, one of two utility
transmission systems that has agreed to interconnect its
transmission grid to our power facility.
Entergy.............................. Entergy Mississippi, Inc., the other utility transmission
system that has agreed to interconnect its transmission grid
to our power facility.
R.W. Beck............................ R.W. Beck, Inc., which is acting as the independent engineer
for our project and has prepared the report included as
Annex B to this prospectus.
C.C. Pace............................ C.C. Pace Consulting, L.L.C., which is acting as the
independent electricity market and fuel consultant for our
project and has prepared the report included as Annex C to
this prospectus.
</TABLE>
SOME OF OUR PRINCIPAL PROJECT DOCUMENTS. We have entered into a
construction contract with BVZ Power Partners, a joint venture between Black &
Veatch Construction, Inc. and H.B. Zachry Company. BVZ Power Partners has agreed
to design, engineer, procure equipment for, construct, test and start-up our
power facility, other than the electrical substation and transmission lines. We
have agreed to pay BVZ Power Partners a fixed price of approximately
$240,174,000 for doing this work in accordance with the construction contract.
We gave BVZ Power Partners a notice to proceed with the work on our power
facility on August 28, 1998. Since that time, we have agreed on change orders
under the construction contract which have increased the contract price by about
$131,000. Engineering and procurement under the construction contract is
complete, and overall construction is about 90% complete. BVZ Power Partners has
invoiced us for about 89% of the fixed price of the construction contract. We
currently expect that BVZ Power Partners' work on our power facility will be
completed during the third quarter of 2000.
From 1987 to 1996, Black & Veatch Construction, Inc. and H.B. Zachry Company
have been awarded contracts to construct approximately 62,530 megawatts of new
power plant projects. Black & Veatch Construction, Inc. and H.B. Zachry Company
are both equally responsible for performing obligations to us under our
construction contract with BVZ Power Partners. Black & Veatch
Construction, Inc.'s parent, Black & Veatch, LLP, has guaranteed BVZ Power
Partners' obligations to us under the main construction contract. In addition,
Continental Casualty Company, whose insurer financial strength rating is A1 from
Moody's Investors Service, Inc. and A+ (outlook negative) from Standard & Poor's
Ratings Group, has provided us with a performance and payment bond on behalf of
Black & Veatch Construction, Inc. United States Fidelity and Guaranty Company,
whose insurer financial strength rating is A1 from Moody's Investors
Service, Inc. and AA from Standard & Poor's Ratings Group, has provided us with
a performance and payment bond on behalf of H.B. Zachry Company.
We have also entered into several other construction contracts with other
contractors for the design, engineering, procurement, testing and start-up of
our substation and transmission lines. In particular, we entered into an
engineering services contract with Black & Veatch, LLP to develop conceptual
designs and specifications for the substation, the transmission lines and the
Panola County infrastructure that are compatible with the portion of our power
facility that BVZ Power Partners is constructing. Although we believe that these
facilities will be capable of properly interconnecting with the portion of our
power facility that BVZ Power Partners is constructing, R.W. Beck has not
reviewed the electrical substation or transmission line construction contracts
for purposes of determining whether this will be the case.
The substation and transmission line contractor, Lauren Constructors, Inc.,
has been in business since 1985. Since 1996, Lauren Constructors, Inc. has been
awarded construction contracts for
58
<PAGE>
$66,000,000 worth of mechanical and electrical projects. United States Fidelity
and Guaranty Company has provided us with performance and payment bonds on
behalf of Lauren Constructors, Inc.
The transformer supply contractor, North American Transformer, Inc., was
founded in 1906 under the name Pacific Electric Manufacturing. Today, North
American Transformer, Inc. is a division of Rockwell International, which has a
market capitalization of approximately $10,000,000,000. Liberty Mutual Insurance
Company has provided us with performance and payment bonds on behalf of North
American Transformer, Inc.
The circuit breaker supply contractor, Siemens Power Transmission and
Distribution, LLC, was formed in 1996 and is a division of Siemens, A.G.
Siemens, A.G. has been manufacturing circuit breakers since 1937. Siemens Power
Transmission and Distribution, LLC currently manufactures over 1000 circuit
breakers per year and has sales in excess of $50,000,000 per year. Federal
Insurance Company has provided us with performance and payment bonds on behalf
of Siemens Power Transmission and Distribution, LLC.
In addition, we have entered into an operation and maintenance agreement
with Cogentrix Batesville Operations, which is a subsidiary of Cogentrix. This
agreement has a term of 27 years. Under this agreement, we will pay Cogentrix
Batesville Operations its reimbursable expenses plus a fee of $41,667 per month,
which escalates annually, to perform customary operations and maintenance
services for most of our project. We will pay this fee to Cogentrix Batesville
Operations only if we have allocated the required funds to our debt service and
reserve accounts in accordance with the financing documents. We will also pay
Cogentrix Batesville Operations its reimbursable expenses plus a fee of
$390,000, payable in ten monthly installments, for services performed by
Cogentrix Batesville Operations prior to the date on which our power facility
begins commercial operation.
Cogentrix has owned and operated electric generating facilities since 1985.
Cogentrix Batesville Operations and its affiliates have provided or are under
contract to provide operation and maintenance services for approximately 13
projects with a combined total of about 1,630 megawatts of capacity, excluding
our power facility. Four of these projects are natural gas-fired facilities.
Three of these projects utilize combustion turbines similar to those being
installed at our power facility.
To obtain water for our power facility, we have entered into an agreement
with the United States government that will allow us to withdraw water from Enid
Lake. In addition, we have obtained the permits that will allow us to dispose of
our power facility's wastewater into the Little Tallahatchie River.
To connect our power facility to interstate gas pipelines, we have entered
into separate agreements with Tennessee Gas and ANR Pipeline that allow us to
connect the lateral gas pipeline that Panola County is constructing to the
Tennessee Gas and ANR Pipeline pipelines. Tennessee Gas and ANR Pipeline have
agreed to construct, at our expense, the interconnections between the lateral
gas pipeline and each of their respective pipelines. The ANR Pipeline and
Tennessee Gas interconnection facilities have been completed, and each is
capable of delivering our power facility's entire fuel requirements to the
lateral gas pipeline. We plan to contract with an experienced gas pipeline
operator to coordinate operation of the lateral gas pipeline with Tennessee Gas
and ANR Pipeline.
Tennessee Gas operates three pipeline systems consisting of over 16,000
miles of pipeline connecting supply regions in Texas, Louisiana and the Gulf of
Mexico to gas markets in 20 eastern and midwestern states. ANR Pipeline operates
approximately 10,600 miles of pipeline connecting supply regions in the Gulf of
Mexico, the midwest, the Rocky Mountains and Canada to gas markets in 18
midwestern and southern states.
To connect our power facility to transmission lines so that we can transmit
the electricity that we produce to our power purchasers, we have entered into
separate interconnection agreements with each of the Tennessee Valley Authority
and Entergy, each of which has an initial term of 35 years. The
59
<PAGE>
Tennessee Valley Authority can terminate its interconnection agreement if we
fail to agree upon amendments that they are allowed to propose in order to make
our interconnection agreement consistent with agreements that they have with
facilities similar to our power facility. These agreements require us to
construct and install a portion of the equipment that will be used to
interconnect our power facility with the transmission grids, which BVZ Power
Partners and some of our other contractors are in the process of doing, and
require the Tennessee Valley Authority and Entergy to construct the remainder of
that equipment, at our expense. Following the completion of the Tennessee Valley
Authority and Entergy system upgrades described in the next paragraph, we expect
each of these interconnections to be capable of accepting the entire electrical
output of our power facility under most operating conditions. These agreements
allow the Tennessee Valley Authority and Entergy to disconnect or curtail our
power facility to overcome reliability problems, to facilitate restoration of
line or equipment outages, for maintenance activities or if a hazardous
condition exists.
Although our power purchasers are responsible for the transmission of our
electricity from our interconnection point across the Tennessee Valley Authority
and Entergy transmission grids, we have agreed with the Tennessee Valley
Authority and Entergy to pay for the costs of upgrading their transmission
systems so that each transmission system can handle the entire electrical output
of our power facility under most operating conditions. These upgrades will be
owned by the Tennessee Valley Authority and Entergy. In exchange, the Tennessee
Valley Authority and Entergy have agreed to credit us or our power purchasers an
amount equal to the lesser of (1) the revenues that they receive from our power
purchasers or their customers for transmission services provided for the
delivery of energy from our power facility and (2) the total costs paid by us
for the system upgrades. Our recovery of these credits is dependent upon the
availability of transmission service from the Tennessee Valley Authority and
Entergy for, and the use of this transmission service by, our power purchasers
and their customers.
Tennessee Valley Authority's U.S. transmission system includes over 17,000
miles of high-voltage transmission lines delivering power to about 159 power
distributors serving about 7,300,000 people. Entergy's U.S. transmission system
consists of more than 15,500 miles of high voltage transmission lines and 1,450
substations, and serves nearly 2,500,000 customers in four states.
Finally, we have entered into two long-term power purchase agreements for
the sale of the capacity of and electric energy from our power facility. One of
those agreements is with Virginia Power and covers the sale of the capacity of
and electric energy from two of our generating units for an initial term of
13 years, which Virginia Power can extend at its option for an additional
12 years. The other agreement is with Aquila/UtiliCorp and covers the sale of
the capacity of and electric energy from our other generating unit for an
initial term of 15 years and seven months, which Aquila/UtiliCorp can extend at
its option for an additional five years. These agreements require Virginia Power
and Aquila/ UtiliCorp to provide us with the natural gas which we will use to
fuel the generating units that are dedicated to the applicable purchaser. In
addition, both of these power purchase agreements require the applicable
purchaser to pay us:
(1) a monthly "reservation" payment based on the tested capacity and
availability of the generating units dedicated to them;
(2) an "energy" payment based on the amount of energy that we actually
produce for them and deliver to the interconnection point between our
power facility and the utility transmission systems described above, and
(3) other payments, including payments based upon the fuel efficiency of the
generating units and the number of times we start up the units each year.
Both of these power purchase agreements allow the power purchasers to dispatch
the generating units we have dedicated to them, meaning that the power
purchasers have the right to control how much
60
<PAGE>
electricity they want their dedicated units to produce. However, even if we are
not dispatched at all by Virginia Power and Aquila/UtiliCorp, they will still
have to pay us a reservation payment as provided under the power purchase
agreements.
Virginia Power is among the 15 largest regulated electric utilities in the
United States, serving nearly 2,000,000 customers in Virginia and North
Carolina. Virginia Power's long term unsecured debt is rated A3 by Moody's
Investors Service, Inc. and A- by Standard & Poor's Ratings Group. Virginia
Power's parent, Dominion Resources, Inc., is a holding company engaged in
regulated and unregulated electric power, natural gas, financial services and
real estate businesses primarily in the United States. Virginia Power is
required to file reports and other information with the Securities and Exchange
Commission. These materials are available on the Securities and Exchange
Commission's web site, which can be accessed at HTTP://WWW.SEC.GOV.
Aquila Energy Marketing Corporation, a successor by merger to Aquila Power
Corporation, has been a leading power marketer since 1995. Aquila Energy
Marketing Corporation owns equity interests in 17 independent power projects.
Aquila Energy Marketing Corporation's parent, UtiliCorp United Inc., serves
nearly 4,500,000 electric and gas utility customers in eight states, one
Canadian province, the United Kingdom, New Zealand and Australia. UtiliCorp
United Inc.'s long term debt is rated Baa3 by Moody's Investors Service, Inc.
and BBB by Standard & Poor's Ratings Group. UtiliCorp United Inc. is required to
file reports and other information with the Securities and Exchange Commission.
These reports include information about Aquila Energy Marketing Corporation
because it is a wholly-owned subsidiary of UtiliCorp United Inc. The reports and
other information filed by UtiliCorp United Inc. are available on the Securities
and Exchange Commission's web site, which can be accessed at HTTP://WWW.SEC.GOV.
The contracts mentioned above are some of our key project documents. We have
entered into several other important project documents as well. We describe the
documents mentioned above, as well as our other important project documents, in
greater detail under the caption "Description of the Principal Project
Documents." We encourage you to read that section in its entirety.
THE PANOLA COUNTY INFRASTRUCTURE. We have entered into five agreements with
Mississippi governmental entities with respect to the Panola County
infrastructure. Under an inducement agreement, the State of Mississippi agreed
to issue general obligations bonds to finance the infrastructure, Panola County,
and ultimately the Industrial Development Authority, agreed to assume ownership
of the infrastructure, and we agreed to operate and maintain both our power
facility and the infrastructure. As contemplated by the inducement agreement, we
have transfered to Panola County the construction contracts relating to the
infrastructure and our title to the infrastructure already completed or under
construction, together with permanent easements and real estate rights relating
to the infrastructure sites. We paid the costs of developing and constructing
the infrastructure until the State of Mississippi issued general obligation
bonds to finance its reimbursement to us of our infrastructure costs and these
transfers had been made. The State has reimbursed us for $14,278,000 of the
costs that we incurred for development and easement acquisition activities, and
for the construction of the Panola County infrastructure after April 11, 1999.
Under the inducement agreement, we have promised to maintain our power
facility and to keep it capable of being operated other than during periods when
our power facility is not available because of maintenance or repair or for
reasons beyond our control, and to perform our obligations under the other
infrastructure documents, including the use agreements for the lateral pipeline
and the water supply and wastewater discharge systems, which are described
below. In the event we fail to do so, we would be responsible for paying to the
State an amount equal to:
(1) the outstanding principal amount of the general obligation bonds times a
fraction the numerator of which is the number of months remaining in the
term of the general obligation
61
<PAGE>
bonds and the denominator of which is the original number of months in
the term of the general obligation bonds, plus
(2) accrued interest on that principal amount, plus
(3) the costs of redeeming the general obligation bonds.
We also have entered into agreements with Panola County and the Industrial
Development Authority that will allow us to use the Panola County
infrastructure. We have entered into one agreement with respect to the natural
gas lateral pipeline and one with respect to the water supply and wastewater
discharge systems. Each of these agreements is in the form of a lease. Each use
agreement has an initial term which ends on the day which is 30 years after
substantial completion of our power facility. We may renew the leases for
successive ten year terms through the life of our power facility. In return for
our use of the Panola County infrastructure, we promise to operate and maintain,
or arrange for the operation and maintenance of, the infrastructure and to pay
for all operation and maintenance expenses. We currently expect that the
operation and maintenance of the natural gas lateral pipeline will be performed
by Cogentrix Batesville Operations or another experienced gas pipeline operator,
and that operation and maintenance of the water supply and wastewater discharge
systems will be performed by Cogentrix Batesville Operations. We also currently
expect that the City of Batesville, Mississippi will be an additional user of
the capacity of the natural gas lateral pipeline which is in excess of the
capacity required to operate our power facility. We currently expect that there
may be additional users in the future of the water supply and wastewater
discharge systems. In the case of any additional user of the water
infrastructure, we have approval rights over the terms and conditions, under
which additional users will be provided access to use the water infrastructure,
including cost sharing, indemnification and any restrictions resulting from
regulatory limitations.
In consideration for the approval of Yalobusha County, Mississippi and the
Coffeeville School District to construct a portion of the Panola County
infrastructure in that county and district, we have entered into an agreement
with Yalobusha County, Mississippi and the Coffeeville School District to pay
them an aggregate amount equal to $1,500,000. We must make this payment on or
before the first day of February following the first full calendar year after
the year in which our power facility is certified as being substantially
complete.
Finally, in consideration for our use of the Panola County infrastructure,
we have entered into an agreement with, and have promised to pay, Panola
Partnership, Inc., a County governmental entity, a yearly payment equal to
$300,000, which escalates at the compound rate of two percent per annum, so long
as the inducement agreement and lease agreements described above remain in
effect and are not terminated, other than as a result of a default by us.
ENVIRONMENTAL REGULATION. We are affected by many federal, state and local
laws that are designed to protect human health and the environment. These laws
impose numerous requirements on the construction, ownership and operation of our
power facility and the Panola County infrastructure. For example, we must obtain
and comply with permits for air emissions, water withdrawal, wastewater
discharges, construction in wetlands and other regulated activity. Each permit
contains its own set of requirements. We also must implement management
practices for handling hazardous materials, preventing spills, planning for
emergencies, ensuring worker safety and addressing other operational issues. We
believe, and R.W. Beck has concluded, that we have obtained all of the permits
and approvals that are currently necessary to construct and test our power
facility. R.W. Beck also has evaluated and identified the additional permits and
approvals that we will be required to obtain and filings that we will be
required to make prior to beginning to operate our power facility. These
additional permits include a state operating air permit and solid waste
notification for operation, a federal hazardous waste identification number and
spill prevention control and countermeasure plan, and a local right to know
registration for storage of hazardous chemicals. We are not aware of any
circumstances which are reasonably likely to occur that would prevent the
issuance of these remaining
62
<PAGE>
permits and approvals. Although there can be no guarantees, we do not believe
that compliance with applicable environmental requirements will have a material
effect on our capital expenditures, earnings or competitive position.
ENERGY REGULATION. We are also affected by various federal and state laws
pertaining to power generation and sales. The Federal Power Act of 1992
regulates the sale of electricity at wholesale in the United States. The Federal
Energy Regulatory Commission is the federal agency which administers the Federal
Power Act. The Federal Regulatory Commission regulates, among other things, the
rates at which electric power can be sold to wholesale customers. Because we
will sell electricity produced by our power facility to two wholesale customers,
Virginia Power and Aquila/UtiliCorp, we must comply with the Federal Power Act
and the regulations promulgated by the Federal Energy Regulatory Commission
under the Federal Power Act. The rates at which we will sell electricity to
Virginia Power and Aquila/UtiliCorp under the power purchase agreements have
been approved by the Federal Energy Regulatory Commission. We will have to file
copies of the power purchase agreements with the Federal Energy Regulatory
Commission prior to commercial operation of our power facility.
Public utilities have to comply with the Public Utility Holding Company Act
of 1935 and corresponding state laws. The Public Utility Holding Company Act
requires public utilities to, among other things:
- register with the Securities and Exchange Commission;
- obtain Securities and Exchange Commission approval to issue securities, to
acquire securities or utility assets or any other interest in any
business, including investment in other power facilities, and
- file annual and other periodic reports with the Securities and Exchange
Commission.
The state regulations which are applicable to public utilities restrict the
rates the utilities can charge to their customers and govern the financial and
organizational aspects of, and the issuance of securities by, the utilities.
Because we will sell electricity from our power facility to wholesale
customers, we are considered an exempt wholesale generator under the Federal
Power Act. Our exempt wholesale generator status keeps us form being a public
utility under the Public Utility Holding Company Act and corresponding state
laws described above. Accordingly, we do not have to comply with the
requirements and restrictions applicable to public utilities described above. If
we lost our exempt wholesale generator status, we would have to comply with
these requirements and restrictions. This compliance could have a material
adverse effect on our capital expenditures, earnings and/or competitive
position. However, we plan to engage only in exempt activity and are not aware
of any circumstances which are reasonably likely to occur that would result in a
loss of our exempt wholesale generator status.
COMPETITION. The Energy Policy Act laid the groundwork for a competitive
wholesale market for electricity. Among other things, the Energy Policy Act
expanded the Federal Energy Regulatory Commission's authority to order electric
utilities to transmit, or "wheel," third-party electricity over their
transmission lines. In addition, in 1996 the Federal Energy Regulatory
Commission issued Order 888 which requires all electric utilities to file
tariffs providing non-discriminatory, open access wholesale wheeling service on
their transmission systems. This allows qualifying facilities, power marketers
and exempt wholesale generators to more effectively compete in the wholesale
market.
While acting as a significant catalyst for wholesale competition, the Energy
Policy Act did not preempt state authority to regulate retail electric service.
Presently, in Mississippi and in most other states, competition for retail
customers is limited by statutes or regulations granting existing electric
utilities exclusive retail franchises and service territories. Where it exists,
retail competition arises primarily from the ability of business customers to
relocate among utility service territories, to
63
<PAGE>
substitute other energy sources for electric power or to generate their own
electricity. The advisability of retail deregulation has recently been the
subject of intense debate in federal and state forums, both legislative and
regulatory.
As described above, we are an exempt wholesale generator under federal law,
and our power facility is an eligible facility. As such, we are permitted to
sell capacity and electricity in the wholesale markets, but not in the retail
markets. Accordingly, after the termination of the Virginia Power and
Aquila/UtiliCorp power purchase agreements, we may sell our capacity and
electrical output in the wholesale markets or to power marketers who can in turn
make retail sales. Therefore, the deregulation of the retail energy markets
could affect us indirectly, to the extent that it provides additional
opportunities for power marketers to sell power to retail customers. As the
customer base for power marketers expands, power marketers are more likely to
look to wholesale generators like us as a source for the electricity that they
will sell to retail customers.
At this time we cannot predict how changing industry conditions may affect
the future operation of our power facility. However, because we have long-term
contracts to sell electric generating capacity from our power facility to
Virginia Power and Aquila/UtiliCorp, we do not expect competitive forces to have
a significant effect on our business during the terms of these contracts. After
the termination of these power purchase agreements, we may be affected by market
competition for the sale of all of the electric generating capacity and
electrical output of our power facility.
C.C. Pace believes that the southeastern power market in which we operate is
highly competitive compared to other market regions. C.C. Pace bases this
conclusion on the fact that the southeastern market has experienced a high
volume of power transactions over the years compared to other regions. The
following tables, which have been provided to us by C.C. Pace, provide a summary
of power marketer transactions in various regions for the past four years. They
indicate that the southeastern market, which is referred to as the Southeast
Electric Reliability Council in the tables, has been one of the largest regions
in terms of wholesale transaction volume as well as in terms of percentage
growth since 1995. Specifically, purchases have grown from 1,176 gigawatt hours
in 1995 to 73,798 gigawatt hours in 1998, which equates to a 250% average annual
growth rate for wholesale transactions.
64
<PAGE>
POWER MARKETER TRANSACTIONS BY NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL
REGION - GIGAWATT HOURS
PURCHASES
<TABLE>
<CAPTION>
REGION 1995 1996 1997 1998 % GROWTH
<S> <C> <C> <C> <C> <C>
East Central Area Reliability Council.............. 2,434 19,715 73,072 220,685 349.25%
Western Systems Coordinating Council............... 7,542 35,421 96,708 146,108 168.58%
Mid-Atlantic Area Council/PIM...................... 3,255 10,543 34,947 83,985 195.49%
Southeast Electric Reliability Council............. 1,716 29,864 39,537 73,798 250.30%
Mid-American Interconnected Network................ 1,018 5,166 9,883 25,335 192.14%
Southwest Power Pool............................... 483 3,197 4,917 13,622 204.33%
Northeast Power Coordinating Council............... 5,117 4,784 7,886 10,805 28.29%
Electric Reliability Council of Texas.............. 504 2,315 4,736 7,029 140.70%
Mid-Continent Area Power Pool...................... 124 1,712 2,735 5,171 247.12%
Florida Reliability Coordinating Council........... 216 872 1,076 1,097 71.78%
</TABLE>
SALES
<TABLE>
<CAPTION>
REGION 1995 1996 1997 1998 % GROWTH
<S> <C> <C> <C> <C> <C>
East Central Area Reliability Council.............. 2,137 11,487 51,385 226,612 373.31%
Western Systems Coordinating Council............... 6,710 30,719 96,747 140,343 175.52%
Southeast Electric Reliability Council............. 3,433 32,385 42,526 83,189 189.38%
Mid-Atlantic Area Council/PIM...................... 4,810 17,211 35,200 79,735 154.98%
Mid-American Interconnected Network................ 770 5,595 18,760 23,058 210.58%
Northeast Power Coordinating Council............... 9,694 8,631 9,779 14,210 13.60%
Southwest Power Pool............................... 545 3,696 6,110 12,360 183.09%
Electric Reliability Council of Texas.............. 112 3,937 6,317 10,348 351.90%
Mid-Continent Area Power Pool...................... 28 1,646 3,098 5,962 496.66%
Florida Reliability Coordinating Council........... 525 3,816 3,057 4,166 30.47%
</TABLE>
65
<PAGE>
C.C. Pace also believes that sustained energy demand growth in the
southeastern power market over the next 20 years will be higher than most
regions in the United States and makes the southeastern market both the largest
and the fastest growing demand center. The following table, which has been
provided to us by C.C. Pace, provides a summary of expected regional peak demand
growth reported by southeast utility companies through 2007. As indicated in
this table, of those regions with greater than approximately 50,000 megawatts
peak demand, C.C. Pace expects the southeastern region to be the fastest growing
region. Despite its size, the southeastern region is paralleled only by the
Electric Reliability Council of Texas region, which represents most of Texas, in
terms of growth. However, considering that the Electric Reliability Council of
Texas is nearly half the size of the southeastern region, in absolute growth
measured in megawatts, C.C. Pace believes that demand in the southeastern region
is growing faster.
REGIONAL PEAK DEMAND AND UTILITIES' PROJECTED GROWTH
<TABLE>
<CAPTION>
1997 PEAK DEMAND % GROWTH
(MEGAWATTS) (1998-2007)
<S> <C> <C>
REGION:
OVER 50,000 MEGAWATTS
Western Systems Coordinating Council........................ 110,001 1.86%
East Central Area Reliability Council....................... 93,492 1.67%
Southeast Electric Reliability Council...................... 92,583 2.05%
UNDER 50,000 MEGAWATTS
Electric Reliability Council of Texas....................... 50,541 2.23%
Mid-Atlantic Area Council/PIM............................... 49,454 1.41%
Northeast Power Coordinating Council........................ 49,269 1.39%
Mid-American Interconnected Network......................... 45,887 1.57%
Florida Reliability Coordinating Council.................... 35,375 2.08%
Mid-Continent Area Power Pool............................... 29,787 1.27%
</TABLE>
In addition to the volume of power marketer transactions and the demand for
electric power in the southeastern region, the competitive environment in this
region is, and will continue to be, affected by the level of generating
resources in the region. According to information obtained by C.C. Pace from a
report filed by the National Electric Reliability Council sub-regions with the
U.S. Energy Information Administration, the total generating capacity in the
southeastern region in 1996 was 96,341 megawatts and this volume is projected to
grow by approximately 15.3% to 111,115 megawatts between 1996 and 2006.
Additional conclusions reached by C.C. Pace, and assumptions used by C.C.
Pace, are summarized in the section of this prospectus entitled "Reports of
Third Party Consultants."
INSURANCE. We currently maintain and intend to continue to maintain a
comprehensive insurance program underwritten by recognized insurance companies
licensed to do business in Mississippi. This insurance program includes general
liability, automobile liability, workers' compensation, employer's liability,
builder's risk, all-risk property, business interruption, environmental
impairment liability, cargo liability and aircraft liability insurance. We
believe that the limits and deductibles for these insurance coverages are
comparable to those carried by comparable facilities of similar size.
LEGAL PROCEEDINGS. Other than legal proceedings involving our application
for various governmental approvals required to operate our power facility, which
are described in the independent engineer's report prepared by R.W. Beck,
neither we nor the Funding Corporation is a party to any legal proceedings. See
"Annex B--Independent Engineer's Report--Status of Permits and Approvals."
66
<PAGE>
OWNERSHIP AND MANAGEMENT
OWNERSHIP
LSP Batesville Holding holds all of our limited partnership interests and
all of the shares of capital stock of the Funding Corporation. LSP
Energy, Inc., a wholly-owned subsidiary of LSP Batesville Holding, holds all of
our general partnership interests. LSP Batesville Holding is owned by Granite II
Holding, LLC and Cogentrix/Batesville, LLC. Granite II Holding, LLC is owned by
Granite Power Partners II, LP. Granite Power Partners II, L.P. is a limited
partnership, and its partners are LS Power, LLC, which has a 21% general
partnership interest and a 54% limited partnership interest, Chase Manhattan
Capital, L.P., which has a 12.5% limited partnership interest, and Cogen Grantor
Trust UA (Joseph Cogen, trustee), which has a 12.5% limited partnership
interest. Cogentrix/Batesville, LLC is indirectly wholly owned by Cogentrix
Energy, Inc. LS Power, LLC owns 100% of the membership interests in LS Power
Management, LLC, the non-member manager of LSP Batesville Holding and the
manager who is responsible for performing various administrative and management
functions with respect to our project in accordance with the management services
agreement.
Several of the executive officers and directors of the Funding Corporation
and of LSP Energy, Inc., which is our general partner, and their families, own
interests in LS Power. Collectively, these executive officers and directors and
their families own approximately 90% of LS Power. LS Power owns 75% of Granite
Power Partners II, L.P., which indirectly owns 48.63% of LSP Batesville Holding.
LSP Batesville Holding, directly or indirectly, owns 100% of us and of the
Funding Corporation. LSP Batesville Holding, therefore, has voting and
investment power with respect to our securities. The operating agreement of LSP
Batesville Holding provides that in order for LSP Batesville Holding to dispose
of our securities or those of the Funding Corporation or vote our securities or
those of the Funding Corporation with respect to significant decisions regarding
the development, construction, financing or operation of our project, both of
Granite II Holding, LLC and Cogentrix/Batesville LLC must authorize LSP
Batesville Holding to do so. In addition, the partnership agreement of Granite
Power Partners II, L.P. provides that in order for Granite Power Partners II,
L.P. to authorize its subsidiary to authorize LSP Batesville Holding to dispose
of our securities or those of the Funding Corporation or vote our securities or
those of the Funding Corporation with respect to significant decisions regarding
our project, each of LS Power and the other two limited partners of Granite
Power Partners II, L.P. must authorize Granite Power Partners II, L.P. to do so.
Accordingly, LS Power (and, therefore, our executive officers and directors or
those of the Funding Corporation that own interests in LS Power) cannot
independently direct LSP Batesville Holding to exercise its voting and
investment power with respect to the securities of us or the Funding
Corporation. None of our executive officers or directors or those of the Funding
Corporation has any interest, direct or indirect, in Cogentrix/ Batesville, LLC
or in the other two limited partners of Granite Power Partners II, L.P. Given
the foregoing, we believe that none of our executive officers and directors or
those of the Funding Corporation beneficially owns any equity interest in us or
the Funding Corporation. The following tables set forth information about the
beneficial ownership of us and the Funding Corporation.
67
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
<TABLE>
<CAPTION>
PERCENT OF TOTAL
NAME AND ADDRESS OF BENEFICIAL OWNER TYPE OF OWNERSHIP INTEREST OWNERSHIP INTEREST
- ------------------------------------ ------------------------------------- ------------------
<S> <C> <C>
LSP ENERGY, INC.............................. General Partnership Interest 1%
c/o LS Power Management, LLC
Two Tower Center, 20th Floor
East Brunswick, NJ 08816
LSP BATESVILLE HOLDING, LLC.................. Limited Partnership Interest 99%
c/o LS Power Management, LLC
Two Tower Center, 20th Floor
East Brunswick, NJ 08816
</TABLE>
LSP BATESVILLE FUNDING CORPORATION
<TABLE>
<CAPTION>
NAME AND ADDRESS OF BENEFICIAL OWNER TYPE OF SECURITY PERCENT OF CLASS
- ------------------------------------ ------------------------------------- ----------------
<S> <C> <C>
LSP BATESVILLE HOLDING, LLC.................... Common Stock 100%
c/o LS Power Management, LLC
Two Tower Center, 20th Floor
East Brunswick, NJ 08816
</TABLE>
ADJUSTMENTS TO THE OWNERSHIP OF LSP BATESVILLE HOLDING
Granite Power Partners II, L.P. and Cogentrix/Batesville, LLC have agreed to
recalculate their respective ownership interests in LSP Batesville Holding upon
the occurrence of events such as the issuance of the private bonds. The
recalculation with respect to the private bonds has been made and resulted in
the percentages set forth in the chart on page 15.
MANAGEMENT
OUR MANAGEMENT. All of our management functions are the responsibility of
LSP Energy, Inc., our general partner. LSP Energy, Inc. receives no fees or
other compensation from us as a result of its performance of management
functions. We have delegated some management functions to LS Power Management
under the management services agreement. These management functions include,
among others, preparation of financial statements, filing of tax returns,
maintenance of government approvals, supervision of independent contractors and
procurement of insurance.
68
<PAGE>
The names and positions of the executive officers and directors of LSP
Energy, Inc. are shown below. Directors are elected annually and each elected
director holds office until a successor is elected. Officers are chosen from
time to time by vote of the board of directors.
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- -------- ------------------------------------------
<S> <C> <C>
Mikhail Segal............................. 49 President and Director
Clarence J. Heller........................ 43 Executive Vice President and Assistant
Secretary
Frank E. Hardenbergh...................... 56 Senior Vice President, Secretary and
Director
Robert Brooks............................. 52 Senior Vice President
Michael P. Witzing........................ 35 Vice President
Paul G. Thessen........................... 31 Assistant Vice President
Mark Brennan.............................. 42 Treasurer
Andrew Stidd.............................. 42 Director
</TABLE>
MIKHAIL SEGAL. Mr. Segal, president and co-founder of LS Power and its
affiliates since 1990, has more than 20 years experience in the electric utility
and independent power industry, managing project development, financing,
engineering and marketing activities. To date, Mr. Segal has taken projects
totaling 2,200 megawatts from concept through financing. Mr. Segal has a Masters
of Science degree in Electrical Engineering from Kharkov Polytech Institute in
the Ukraine. Mr. Segal co-managed LS Power as a Managing Director from 1990
through 1996 and has served as President and Chief Executive Officer of
LS Power since February 1996.
CLARENCE J. HELLER. Mr. Heller has been an Executive Vice President of LS
Power and LSP Energy since May 1994 and is responsible for coordinating all
development activities, including project conceptualization, contract
negotiations, environmental permitting, regulatory approvals and project
financing. Mr. Heller joined LS Power in 1991 as Vice President, Midwest Region.
Mr. Heller has served in various management and development capacities on
projects totaling more than 2,000 megawatts. Mr. Heller is a registered
Professional Engineer in the State of Missouri, earned his Bachelor of Science
degree in Electrical Engineering from the University of Missouri-Rolla and
earned a Masters Degree in Business Administration from Washington University.
FRANK E. HARDENBERGH. Mr. Hardenbergh, the Senior Vice President, General
Counsel and Secretary of LS Power and its affiliates since May 1998, is
responsible for the finance and corporate operations of LS Power and its
affiliates. Mr. Hardenbergh joined LS Power in December 1993 as Vice President,
General Counsel and Secretary. Mr. Hardenbergh has more than 13 years experience
in the independent power business with concentration in project finance and
project development. During this period he has had senior business
responsibilities for the development and project financing of independent power
projects totaling more than 2,000 megawatts. Mr. Hardenbergh holds a Juris
Doctorate and a Bachelor of Arts degree from the University of North Carolina at
Chapel Hill.
ROBERT BROOKS. Mr. Brooks, a Senior Vice President of LS Power and certain
of its affiliates since 1998, is responsible for all new business development
activities, including the development and implementation of marketing
strategies. Mr. Brooks joined LS Power in August 1994 as Vice President,
Marketing. Mr. Brooks has a diverse background in the power generation industry.
He has held various engineering and management positions in the manufacturing,
project management, sales and marketing segments of the industry. Mr. Brooks
holds a Bachelor of Science degree in Industrial Engineering
69
<PAGE>
from North Carolina State University and a Masters degree in Business
Administration from Winthrop University.
MICHAEL P. WITZING. Mr. Witzing has been Vice President, Project
Development of LS Power and LSP Energy since September 1998 and is responsible
for management of the development and construction phase of LS Power's projects.
Mr. Witzing joined LS Power in January 1997 as a Project Manager and was a Plant
Engineer for Sithe Energies from 1994 to December 1996. Mr. Witzing has more
than 12 years experience in the power industry and has been involved in various
operational, engineering and performance analysis activities. Mr. Witzing
graduated from the Cooper Union with Bachelor and Masters of Engineering Degrees
in Mechanical Engineering, and is a Registered Professional Engineer in the
State of New York.
PAUL G. THESSEN. Mr. Thessen has been an Assistant Vice President of LS
Power and of LSP Energy since January 1996 and is responsible for all technical
and contractual development activities. Mr. Thessen joined LS Power in 1992 as
Assistant Project Manager. These activities include permitting, regulatory
approvals, site acquisition, transmission line right-of-way procurement,
electrical and gas utility interfaces, coordination with the design/construction
contractor, fuel supply and transportation contracts, steam sales contracts and
interface with local officials and the general community. Mr. Thessen graduated
Summa Cum Laude with a Bachelor of Science degree in Electrical Engineering from
the University of Missouri-Rolla.
MARK BRENNAN. Mr. Brennan has been the Controller and Assistant Treasurer
of LS Power since January 1999 and is the Treasurer of LSP Energy and is
responsible for the accounting, administrative and financial reporting needs of
LS Power and LSP Energy. Mr. Brennan was Senior Manager for KPMG, LLP from July
1993 to April 1995, was Assistant Controller for Journal Register Company from
April 1995 to October 1997 and was Controller of LS Power from October 1997 to
January 1999. He is a Certified Public Accountant with over eleven years of
experience in public and private accounting. Mr. Brennan holds a Bachelor of
Science degree in Commerce from Rider University (previously Rider College).
ANDREW STIDD. Mr. Stidd is a director of LSP Energy and the Funding
Corporation and has over ten years of experience in the structured finance
industry, with an emphasis on providing management services to special purpose
vehicles and the administration of commercial paper programs. Mr. Stidd
coordinated the formation of Global Securitization Services, LLC and is
responsible for the daily operations of all special purpose vehicles managed by
that firm. Mr. Stidd has been the President and Chief Operating Officer of
Global Securitization Services since December 1996. Mr. Stidd handles all legal
and rating agency issues for that firm and works directly with senior management
of that firm's clients in addressing structuring and operating issues that arise
from their asset securitization programs. From April 1987 to December 1996,
Mr. Stidd was the Vice President and Chief Operating Officer of Lord Securities
Corporation. Mr. Stidd serves as an independent director for a number of
structured finance programs which securitize assets such as credit card pools,
equipment leases and trade receivables.
Global Securitization Services, LLC will receive a nominal fee in connection
with Mr. Stidd's service as a director of LSP Energy, the Funding Corporation
and their affiliates. None of our other directors or executive officers, or any
of the other directors or executive officers of LSP Energy or the Funding
Corporation, receives any compensation for serving in these positions. These
officers also function as officers of LS Power Management. Under the management
services agreement, we pay LS Power Management a management fee of $400,000 per
year adjusted for inflation, a portion of which compensates LS Power Management
for the time spent by its officers on our project. However, the salaries of
these officers are not in any way linked to our payment of the management fee.
These officers would receive their salaries regardless of whether we paid or had
any obligation to pay the
70
<PAGE>
management fee. The primary purpose of our payment of the management fee to LS
Power Management is to compensate LS Power Management, not to compensate these
officers.
THE FUNDING CORPORATION'S MANAGEMENT. The names and positions of the
executive officers and directors of the Funding Corporation are shown below.
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- -------- ------------------------------------------
<S> <C> <C>
Mikhail Segal............................. 48 President and Director
Clarence J. Heller........................ 43 Executive Vice President and Assistant
Secretary
Frank E. Hardenbergh...................... 55 Senior Vice President, Secretary and
Director
Michael P. Witzing........................ 35 Vice President
Mark Brennan.............................. 42 Treasurer
Andrew Stidd.............................. 42 Director
</TABLE>
For biographical information on each of these directors and officers, see
"--Our management" above.
REPORTS OF INDEPENDENT CONSULTANTS
THE INDEPENDENT ENGINEER'S REPORT
We have included a report dated May 13, 1999 of R.W. Beck, the independent
engineer for our project, as Annex B to this prospectus. R.W. Beck's report
contains, among other things:
- a description of the principal participants in our project, which include
us, the contractor engaged to construct the majority of our power facility
and the company engaged to operate our power facility after it is
completed;
- a description of the site on which our power facility will be located,
including means of access, the subsurface conditions at the site and an
environmental assessment of the site;
- a description of our power facility, including the design criteria for our
power facility, the mechanical equipment to be used in our power facility,
the off-site requirements for our power facility and the electrical and
natural gas interconnections for our power facility;
- a review of the technology to be used in our power facility;
- estimates of our power facility's reliability, availability and useful
life;
- a review of the status of, and schedule for, the construction of our power
facility;
- a discussion of the performance guarantees and acceptance tests contained
in the construction contract for our power facility;
- a review of the status of the permits and approvals needed to construct
and operate our power facility;
- a discussion of the financing plan for our power facility; and
- projected operating results for our power facility.
71
<PAGE>
CONCLUSIONS OF THE INDEPENDENT ENGINEER
R.W. Beck reached the following conclusions, among others, regarding our
project:
- BVZ Power Partners and the Cogentrix Batesville Operations have previously
demonstrated the capability to perform their responsibilities under the
the construction contract and the operation and maintenance agreement,
respectively.
- Sufficient data has been gathered at the project site to perform the
geotechnical analysis, engineering and reduction of data required to
provide the geotechnical recommendations and detailed site-work and
foundation design criteria needed to properly complete the design for the
power facility. With proper foundation design, and adequate construction
controls to minimize the change in moisture content of the site soils, the
project site should be suitable for construction and operation of the
power facility.
- Based upon R.W. Beck's review of the environmental site assessments for
the site of the power facility, the transmission line right-of-way, the
wastewater pipeline right-of-way, the water supply pipeline right-of-way
and the natural gas pipeline right-of-way:
(1) there are no significant risks identified regarding environmental
contamination at the power facility site; and
(2) there are no site contamination issues that require substantial
investigations or significant allocation of funds.
- The proposed method of design, construction, operation and maintenance of
the power facility has been developed in accordance with generally
acceptable industry practice and has taken into consideration the current
environmental, license and permit requirements that the power facility
must meet.
- After consideration of:
(1) the emissions and blade cracking issues experienced with the two
dual-fuel installations of the 501F-DLN type of combustion turbine
being installed at the power facility, as described in R.W. Beck's
report; and
(2) the effect that single-fuel firing, higher allowable oxides of
nitrogen emission limits, and the other mitigating factors described
in R.W. Beck's report have on these emissions and turbine blade
cracking issues;
the combined cycle technology proposed for the power facility is a sound,
proven method of energy generation and recovery.
- If designed, constructed, operated and maintained as currently proposed by
LSP Energy Limited Partnership, BVZ Power Partners and Cogentrix
Batesville Operations, the power facility should be capable of passing the
acceptance tests included in the construction contract and satisfying the
current environmental, license and permit requirements which the power
facility must meet.
- If designed, constructed, operated and maintained as currently proposed
and dispatched as projected by C.C. Pace, the power facility should be
capable of achieving:
(1) an average annual output of 806,100 kilowatts; and
(2) an average annual net plant heat rate of 7,050 Btu/kilowatt hour
(higher heating value).
- The power facility should be capable of achieving a contract availability
under the power purchase agreements with Virginia Power and
Aquila/UtiliCorp required to avoid reductions in the reservation payments
under those agreements.
72
<PAGE>
- Assuming:
(1) the power facility is designed, constructed, operated and maintained
as proposed by LSP Energy Limited Partnership, BVZ Power Partners and
Cogentrix Batesville Operations;
(2) all equipment is operated in accordance with manufacturers'
recommendations;
(3) all required repairs, refurbishments and replacements are made on a
timely basis; and
(4) natural gas and water used by the power facility are within the
expected range with respect to quantity and quality;
then the power facility will have a useful life extending beyond the term
of the bonds.
- Assuming the absence of events such as:
(1) delivery delays;
(2) labor difficulties;
(3) unusually adverse weather conditions;
(4) force majeure events;
(5) the discovery of hazardous materials or wastes not previously known;
or
(6) other abnormal events prejudicial to normal construction or
installation;
and although the construction contracts that LSP Energy Limited
Partnership has entered into for the electrical substation, transmission
lines and water infrastructure do not provide for the facilities to be
completed by the dates by which BVZ Power Partners needs electrical
backfeed and water in order to conduct tests, commercial operation of the
power facility by June 1, 2000 is achievable and within the previously
demonstrated capabilities of the construction contractor and LSP Energy
Limited Partnership using generally accepted construction and project
management practices.
- The scope and duration of the acceptance tests included in the
construction contract are similar to the tests of other projects with
which R.W. Beck is familiar and should be adequate to verify the
performance guarantees in accordance with the construction contract.
- LSP Energy Limited 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 power facility. While not
all the required permits and approvals have been issued, including some
which cannot be obtained until the power facility is ready to operate,
R.W. Beck is not aware of any technical circumstances that would prevent
the issuance of the remaining permits.
- The estimates which serve as the basis for the construction contract price
and the total construction cost were prepared in accordance with generally
accepted engineering and estimating practices and methods. The
construction contract price and the total construction cost, including the
project contingency, are comparable to the costs and contingency of
similar projects at a similar stage of completion and utilizing similar
technologies with which R.W. Beck is familiar.
- Based upon the estimated interest and reinvestment rate and total uses of
funds estimated by LSP Energy Limited Partnership, the principal amount of
the bonds, when combined with the $54,000,000 of equity that LSP Energy
Limited Partnership expects will be contributed by its parent and interest
income during the construction period, should be sufficient to fund the
total construction cost and interest on the bonds through June 1, 2000.
73
<PAGE>
- The basis for LSP Energy Limited Partnership's estimates of the cost of
operating and maintaining the power facility, including provision for
major maintenance, is reasonable.
- For the base case projected operating results, which assume the extension
of the Virginia Power and the Aquila/UtiliCorp power purchase agreements,
the projected revenues from the sale of electricity are adequate:
(1) to pay annual operating and maintenance expenses, including deposits
to the major maintenance reserve account, fuel expense and other
operating expenses; and
(2) to provide an annual debt service coverage ratio of at least 1.42 in
each year during the term of the bonds and a weighted average debt
service coverage ratio of 1.63 over the term of the bonds.
- If BVZ Power Partners pays LSP Energy Limited Partnership performance
liquidated damages due to a failure to achieve the maximum unit power
output, unit power output or unit heat rate, then the weighted average
debt service coverage ratio over the term of the bonds is projected to
remain at the same level as in the base case projected operating results
for a deficiency consistent with the performance minimums for maximum unit
power output, unit power output and unit heat rate set forth in the
construction contract.
ASSUMPTIONS MADE BY THE INDEPENDENT ENGINEER
The following assumptions and qualifications, among others, are contained in
R.W. Beck's report:
- As the independent engineer, R.W. Beck made no determination as to the
validity and enforceability of any contract, agreement, rule or regulation
applicable to the power facility and its operations. However, for purposes
of its report, R.W. Beck assumed that all contracts, agreements, rules and
regulations will be fully enforceable in accordance with their terms and
that all parties will comply with the provisions of their respective
agreements.
- The construction contract will be implemented as described to R.W. Beck by
LSP Energy Limited Partnership and BVZ Power Partners.
- BVZ Power Partners:
(1) takes into account the information in the environmental site
assessments for the power facility;
(2) completes the geotechnical analysis, engineering and reduction of
data required to provide the geotechnical recommendations and
detailed site-work and foundation design criteria; and
(3) takes into account the geotechnical recommendations during the design
and construction of the power facility.
- BVZ Power Partners and Cogentrix Batesville Operations will construct and
operate the power facility as currently proposed in the construction
contract and the operation and maintenance agreement.
- BVZ Power Partners will undertake generally accepted project management
techniques to closely monitor construction and will react in a timely
fashion to lagging performance so that the power facility will be
constructed in accordance with the construction schedule developed by BVZ
Power Partners.
- Cogentrix Batesville Operations will maintain the power facility in
accordance with generally accepted industry practices, make all required
renewals and replacements in a timely manner,
74
<PAGE>
and will not operate the equipment to cause it to exceed the equipment
manufacturers' recommended maximum ratings.
- Cogentrix Batesville Operations will employ qualified and competent
personnel who will properly operate and maintain the equipment in
accordance with the manufacturers' recommendations and generally accepted
engineering practice, and will generally operate the power facility in a
sound and businesslike manner.
- Inspections, overhauls, repairs and modifications will be planned for and
conducted in accordance with manufacturers' recommendations, and with
special regard for the need to monitor operating parameters to identify
early signs of potential problems.
- The design parameters and delivery dates of the major equipment
incorporated in the power facility will conform to performance and design
data in the construction contract and the construction schedule submitted
by BVZ Power Partners.
- The three generating units will meet the emission guarantees in the
construction contract. Any exceedances will be resolved by the
construction contractor in a manner which does not impact the total
construction cost, the construction schedule, facility availability or
facility operating and maintenance costs.
- All permits and approvals necessary to construct and operate the power
facility will be obtained on a timely basis and any changes in required
permits and approvals will not require changes in design resulting in
either material delays in the scheduled commercial operation date of the
power facility or in significant increases in the costs of the power
facility.
- There will be no increases in the construction contract price and the
other construction costs of the power facility that are greater than the
funded project contingency.
- There will be no excess start-ups as defined in the power purchase
agreements with Virginia Power and Aquila/UtiliCorp.
- The market clearing price used for projecting the sales revenue received
by LSP Energy Limited Partnership after the termination of the power
purchase agreements will be as estimated by C.C. Pace. The capacity
factors of the power facility and associated market-based revenues
assuming an economic dispatch in a market environment will be as estimated
by C.C. Pace.
- Upon commercial operation the debt service reserve account will earn
interest at a rate of 5.5%, as estimated by LSP Energy Limited
Partnership. The major maintenance reserve account will earn interest at a
rate of 5.5%, as estimated by LSP Energy Limited Partnership.
- The Virginia Power letters of credit will not be drawn upon.
- The gross domestic product implicit price deflator and general inflation
will escalate at a rate of 2.6% per year, and the average 1998 natural gas
price will be $2.30/MMBtu and will escalate at a rate of 0.5% per year
above inflation, as estimated by C.C. Pace.
- The non-fuel operating and maintenance expenses of the power facility,
including the cost of overhauls, will be equal to those estimated by LSP
Energy Limited Partnership, and will increase at a rate of 2.6% per year,
except for property taxes, corps of engineer's fees, trustee and rating
agency fees and site use fees, which were based on estimates prepared by
LSP Energy Limited Partnership. Deposits to the major reserve account will
be as estimated by LSP Energy Limited Partnership. The cost of major
maintenance will be as estimated by LSP Energy Limited Partnership as
adjusted for the assumed rate of change in general inflation.
- The principal amount of the bonds will be $326,000,000.
75
<PAGE>
- The annual interest rate on the series A and series B bonds outstanding
upon commencement of commercial operation will be 7.164% and 8.16%,
respectively. Interest will be funded from the proceeds of the bonds
through the June 1, 2000 deposit to the trustee.
- If performance liquidated damages are paid to LSP Energy Limited
Partnership by BVZ Power Partners, the total damages payment will be paid
on the substantial completion date for the power facility and will be used
to repay the bonds on a pro rata basis.
SENSITIVITY ANALYSES PERFORMED BY THE INDEPENDENT ENGINEER
R.W. Beck analyzed the effect of the following sensitivities on the
projected operating results of the power facility:
- 5% reduction in the power facility's availability;
- 5% increase in the power facility's heat rate;
- 10% increase in non-fuel operating expenses;
- 1.4 percentage point increase in the rate of general inflation;
- 3.4 percentage point increase in the rate of general inflation;
- one percentage point increase in the rate of natural gas expense
escalation;
- reduction in the average market energy prices;
- reduction in the average market energy prices and no renewal of the power
purchase agreements; and
- no renewal of the power purchase agreements.
The following chart shows the effect of these sensitivities on LSP Energy
Limited Partnership's projected debt service coverage ratios.
<TABLE>
<CAPTION>
SENSITIVITY CASES
-----------------
YEAR INCREASED INCREASED INCREASED INCREASED REDUCED
ENDING BASE REDUCED INCREASED OPERATING INFLATION INFLATION GAS MARKET
DEC. 31 CASE AVAILABILITY HEAT RATE EXPENSES (4%) (6%) ESCALATION PRICES
- --------------------- ---- ------------ --------- --------- --------- --------- ---------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
2000 1.45 1.37 1.29 1.38 1.76 1.74 1.45 1.44
2001 1.43 1.36 1.31 1.40 1.41 1.38 1.43 1.42
2002 1.43 1.35 1.30 1.39 1.40 1.37 1.43 1.42
2003 1.43 1.35 1.30 1.39 1.40 1.37 1.43 1.42
2004 1.43 1.35 1.29 1.39 1.40 1.37 1.43 1.42
2005 1.42 1.34 1.29 1.38 1.39 1.36 1.42 1.41
2010 1.43 1.34 1.28 1.39 1.35 1.27 1.43 1.41
2015 1.50 1.39 1.27 1.43 1.41 1.24 1.50 1.47
2020 1.92 1.78 1.57 1.81 1.69 1.32 1.93 1.90
Minimum 1.42 1.33 1.24 1.36 1.35 1.24 1.42 1.41
Average 1.63 1.52 1.45 1.57 1.67 1.78 1.60 1.57
<CAPTION>
SENSITIVITY CASES
NO RENEWAL
OF POWER
PURCHASE
AGREEMENTS & NO POWER
YEAR REDUCED PURCHASE
ENDING MARKET AGREEMENT
DEC. 31 PRICES RENEWAL
- --------------------- ------------ ---------
<S> <C> <C>
2000 1.44 1.45
2001 1.42 1.43
2002 1.42 1.43
2003 1.42 1.43
2004 1.42 1.43
2005 1.41 1.42
2010 1.41 1.43
2015 2.97 3.40
2020 5.70 6.66
Minimum 1.41 1.42
Average 2.39 2.66
</TABLE>
THE INDEPENDENT ELECTRICITY MARKET AND FUEL CONSULTANT'S REPORT
C.C. Pace has prepared a report dated May 13, 1999 which discusses the
southeastern power market and the general availability of fuel and fuel
transportation for our power facility. C.C. Pace is an energy consulting firm
that specializes in preparing market forecasts in the power and gas industries
and analyzing fuel supply and transportation arrangements for independent power
projects. Their report is set forth in its entirety as Annex C to this
prospectus. Although we set forth below C.C.
76
<PAGE>
Pace's conclusions about our power facility and the southeastern power market
and some of the assumptions that they made to reach these conclusions, you
should read their report in its entirety.
CONCLUSIONS OF THE INDEPENDENT ELECTRICITY MARKET AND FUEL CONSULTANT
C.C. Pace expressed the following opinions in their report:
- Compared to other power market regions, the southeastern power market is
highly competitive. Some of the industry values considered by C.C. Pace in
reaching this comparative conclusion are described in this prospectus in
the section entitled "Business--Competition." The market's competitiveness
is evidenced by the region's large volume of wholesale power transactions.
The market region represents such a large amount of transactions that the
region has become a market standard for power deliveries referenced by the
New York Mercantile Exchange and Chicago Board of Trade futures contracts.
- C.C. Pace anticipates that given the rapid pace of this wholesale energy
market's development, a competitive and deregulated environment for retail
customers' energy requirements will be implemented on a near- to mid-term
basis, I.E., before the expiration of the power purchase agreements that
LSP Energy Limited Partnership has entered into with Virginia Power and
Aquila/UtiliCorp. The development of this kind of capacity and energy
market will enhance LSP Energy Limited Partnership's ability to make power
sales and should provide additional marketing flexibility to LSP Energy
Limited Partnership when the Virginia Power and Aquila/ UtiliCorp power
purchase agreements expire.
- The technical capability of the power facility to start up and shut down
quickly should allow LSP Energy Limited Partnership's power purchasers, at
times when LSP Energy Limited Partnership's power purchasers control the
operation of the power facility, and LSP Energy Limited Partnership, at
times when LSP Energy Limited Partnership controls the operation of the
power facility, to select operating hours in which revenues and
profitability can be maximized.
- The market for power in the southeast is characterized by:
- sustained energy demand growth expected to continue at a steady annual
average pace of 1.51% to 2.24% over the next 20 years. This sustained
growth rate is higher than virtually any region in the United States
and makes the southeastern market both the largest and the fastest
growing demand center. Some of the industry values considered by C.C.
Pace in reaching this comparative conclusion are described in this
prospectus in the section entitled "Business--Competition";
- ready access to competitively priced gas supply from a diversified
range of sources through an extensive interstate gas pipeline
transmission system;
- natural gas-based generation currently determining market prices for
electricity for 30% of the time, rising to 70% over the next 20 years;
and
- a well-developed electrical transmission system capable of transferring
high volumes of electricity throughout the southeast and covering over
ten states and approximately 20% of the electricity demand in the
United States.
- The most significant factors affecting the pricing of electricity in the
southeastern power market are:
- fuel costs;
- the efficiency and replacement rate of existing generating assets and
capital costs of replacing existing generating assets;
77
<PAGE>
- the cost and efficiency of incremental capacity additions which are
undertaken to meet future energy demand and maintain electricity
transmission system reliability; and
- increases in annual peak demand and energy requirements.
- C.C. Pace's base case market price forecasts are between $29.95 per
megawatt hour and $33.75 per megawatt hour, measured in 1998 real dollars,
for the period from 2000 to 2025. C.C. Pace expects that due to
incremental demand and the large amount of capacity additions necessary to
meet market demand, the southeastern power market will realize an
approximately 0.5% real price increase in electricity prices over the
period from 2000 to 2025, which is almost directly reflective of the real
price escalation of natural gas.
- C.C. Pace's downside case market price forecast is a conservative case in
which there is a 95% probability that market prices will be equal to or
greater than the downside case result obtained. This downside case market
price forecast is between $27.25 per megawatt hour and $32.20 per megawatt
hour, measured in 1998 real dollars, for the period from 2000 to 2025.
Set forth below is a table which summarizes the C.C. Pace base case and
downside case results.
ANNUAL SYSTEM MARKET CLEARING PRICE - BASE AND DOWNSIDE CASE
(1998 REAL DOLLARS)
<TABLE>
<CAPTION>
DOWNSIDE
BASE CASE CASE MARKET
MARKET CLEARING PRICE
CLEARING PRICE PRICE $/MEGAWATT PRICE
YEAR $/MEGAWATT HOUR ESCALATION HOUR ESCALATION
---- --------------- ---------- -------------- ----------
<S> <C> <C> <C> <C>
2000 29.95 27.25
2002 31.20 4.19% 28.99 6.40%
2004 31.79 1.88% 29.48 1.68%
2006 31.66 -0.42% 29.55 0.22%
2008 31.41 -0.79% 29.38 -0.57%
2010 31.75 1.10% 29.84 1.57%
2012 32.49 2.33% 30.60 2.55%
2014 32.78 0.89% 30.89 0.94%
2016 33.39 1.87% 31.52 2.06%
2018 33.76 1.10% 31.71 0.59%
2020 33.94 0.52% 32.22 1.63%
2021 34.06 0.37% 32.12 -0.32%
2022 33.57 1.45% 32.01 -0.34%
2023 33.59 0.08% 32.12 0.35%
2024 33.63 0.12% 32.00 -0.40%
2025 33.78 0.43% 32.20 0.64%
</TABLE>
- The facility represents a low cost, highly competitive and much needed
resource for the growing southeastern market equaling only a small
fraction of the capacity required in the southeastern power market (only
1.85% of the total required expansion capacity) by the year 2020.
- The facility has many strong competitive advantages such as:
- a location which provides low cost access to gas and water;
- direct access to multiple power markets via bi-directional transmission
links into both the Tennessee Valley Authority and Entergy electrical
transmission systems;
- state of the art generation technology which is the most efficient in
the market; and
- close proximity to fuel production regions lowering fuel supply and
transportation costs.
These competitive advantages create an operational profile which suggests
that the facility should be a low cost and profitable resource in the
southeastern power market.
78
<PAGE>
- Virginia Power and Aquila/UtiliCorp, the two initial long-term power
purchasers, have entered into mutually acceptably priced power purchase
agreements with LSP Energy Limited Partnership. Both power purchasers are
active in the wholesale power market and are regionally well-positioned to
operate in the southeastern power market.
- The power purchase agreements are of high strategic value to both Virginia
Power and Aquila/ UtiliCorp, complementing their current utility and
non-utility operations and market positions. Specifically, neither entity
owns or operates any significant amount of generating capacity in the
southeastern power market and, with the facility's capacity, they are able
to trade firm capacity and energy in the southeastern market, doubling
each company's marketing area and allowing them to serve virtually any
customer across ten to twelve states.
- The extension options under the power purchase agreements allow Virginia
Power and Aquila/ UtiliCorp to purchase power at prices that are
approximately 40% lower than the projected market price during the
extension period. This, together with the utilities' current total cost of
generation relative to the prices under these power purchase agreements,
indicates a high likelihood that these power purchase agreements will be
extended by Virginia Power and Aquila/ UltiliCorp.
- Based on the timely construction of pipeline laterals and interconnection
facilities and the facility's maximum hourly fuel demand from the
Tennessee Gas and ANR Pipeline gas pipelines, market priced natural gas
supplies and interstate transportation will be available in sufficient
quantities and on acceptable terms and conditions to support merchant
plant generation requirements from years 13 to 25 of the power facility's
operation. The initial terms of the Virginia Power and Aquila/UtiliCorp
power purchase agreements continue through at least year 13; the Virginia
Power power purchase agreement continues for 13 years and the Aquila/
UtiliCorp power purchase agreement continues for 15 years and 7 months.
LSP Energy Limited Partnership plans to sell all of the facility's power
to Virginia Power and Aquila/UtiliCorp through year 13 and does not expect
to sell any power into the competitive market during that time. Therefore,
it will not be a merchant plant during that time.
- Southeastern market utilities expect consistent and relatively high,
compared to the national average, summer peak demand and energy
requirements to increase at an average annual rate of 2.16% and 1.57% over
the next 10 years, respectively. The chart below, derived from data
obtained by C.C. Pace from a report filed by the National Electric
Reliability Council sub-regions with the U.S. Energy Information
Administration, explains this conclusion in more detail.
79
<PAGE>
SOUTHEAST DEMAND AND ENERGY REQUIREMENTS FORECAST
<TABLE>
<CAPTION>
1996 1997 1998 1999 2000 2001 2002 2003 2004
-------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Peak Demand Summer
(megawatts)............. 87,387 90,686 92,867 94,709 96,763 98,683 100,466 102,307 104,148
Peak Demand Winter
(megawatts)............. 80,995 78,194 80,374 81,926 83,421 85,137 86,848 88,509 90,268
Net Energy for Load
(megawatt hours)........ 473,337 477,045 486,016 491,744 501,873 510,658 517,713 525,811 533,107
System Load Factor........ 61.83% 60.05% 59.74% 59.27% 59.21% 59.07% 58.83% 58.67% 58.43%
------- ------- ------- ------- ------- ------- ------- ------- -------
Summer Change
(megawatts)............. 3,299 2,181 1,842 2,054 1,920 1,783 1,841 1,841
Winter Change
(megawatts)............. (2,801) 2,180 1,552 1,495 1,716 1,711 1,661 1,759
Energy Change (megawatt
hours).................. 3,708 8,971 5,728 10,129 8,785 7,055 8,098 7,296
Summer Change (%)......... 3.78% 2.41 1.98% 2.17% 1.98% 1.81% 1.83% 1.80%
Winter Change (%)......... -3.46% 2.79% 1.93% 1.82% 2.06% 2.01% 1.91% 1.99%
Energy Change (%)......... 0.78% 1.88% 1.18% 2.06% 1.75% 1.38% 1.56% 1.39%
Summer Peak Growth(1)..... 2.16%
Winter Peak Growth(1)..... 1.35%
Energy Growth(1).......... 1.57%
<CAPTION>
2005 2006
-------- --------
<S> <C> <C>
Peak Demand Summer
(megawatts)............. 106,250 108,200
Peak Demand Winter
(megawatts)............. 92,095 92,663
Net Energy for Load
(megawatt hours)........ 544,615 553,028
System Load Factor........ 58.51% 58.35%
------- -------
Summer Change
(megawatts)............. 2,102 1,950
Winter Change
(megawatts)............. 1,827 568
Energy Change (megawatt
hours).................. 11,508 8,413
Summer Change (%)......... 2.02% 1.84%
Winter Change (%)......... 2.02% 0.62%
Energy Change (%)......... 2.16% 1.54%
Summer Peak Growth(1).....
Winter Peak Growth(1).....
Energy Growth(1)..........
</TABLE>
- ------------------------------
(1) Projected average annual rate of increase.
- To provide full access to both the Tennessee Valley Authority and Entergy
power markets, LSP Energy Limited Partnership has arranged for the upgrade
of the Tennessee Valley Authority's and Entergy's transmission facilities.
Under the agreements with the Tennessee Valley Authority and Entergy, LSP
Energy Limited Partnership will be granted transmission upgrade credits up
to the value of the transmission upgrade costs for the transmission of
energy across the Tennessee Valley Authority and Entergy systems. C.C.
Pace estimates that beginning in the first year of the power facility's
operation and continuing until the total transmission upgrade cost is
repaid to LSP Energy Limited Partnership, LSP Energy Limited Partnership
will accumulate additional revenues equal to a minimum of approximately
$3.4 million per year related to these transmission upgrade credits.
80
<PAGE>
ASSUMPTIONS MADE AND METHODOLOGIES USED BY THE INDEPENDENT ELECTRICITY AND FUEL
MARKET CONSULTANT
In reaching the conclusions described above, C.C. Pace made assumptions and
used methodologies that included the following:
- C.C. Pace's principal base case assumptions are set forth in the following
chart:
<TABLE>
<S> <C>
LOAD GROWTH
Energy Demand............................................. 1.51% in 2.24% per year
Peak Demand............................................... 1.51% in 2.24% per year
EXPANSION UNIT COSTS
Combustion Turbine--Installed Costs....................... $300/kilowatt
Combined Cycle--Installed Costs........................... $500/kilowatt
Combustion Turbine--Efficiency (linear improvement)....... 10,100 Btu/kilowatt hour (2000)
9,350 Btu/kilowatt hour (2020)
Combined Turbine--Efficiency (linear improvement)......... 6,860 Btu/kilowatt hour (2000)
6,360 Btu/kilowatt hour (2020)
Natural Gas Henry Hub Price--1998......................... $2.20/MMBtu
EXISTING UNIT COSTS
Fixed Capital Costs....................................... Current Book Value
Fixed & Variable Operation and Maintenance................ Current Derived Cost/0% real escalation
FUEL COST ESCALATION RATES
Natural Gas............................................... 0.5% per year real
Fuel Oil (No. 6 and No. 2)................................ 0.0% per year real
Coal...................................................... -1.0% per year real
Uranium................................................... 0.0% per year real
TRANSFER CAPACITY AND PRICING
SPP-SE to/from Tennessee Valley Authority................. 4,800 megawatt/$1.75/megawatt hour
SPP-SE to/from Southern................................... 2,000 megawatt/$1.82/megawatt hour
Tennessee Valley Authority to/from Southern............... 3,000 megawatt/$2.15/megawatt hour
NUCLEAR AND COAL PLANT PERFORMANCE.......................... 85% Capacity Factor
DEMAND SIDE MANAGEMENT
Annual Interruptible Demand............................... 5.697 - 6,293 megawatt
MACROECONOMIC
Interest Rate............................................. 8.5%
Return on Equity.......................................... 14%
Percent Equity............................................ 30%
</TABLE>
In addition, C.C. Pace assumed that:
(1) there would be no export of energy from the southeastern power market
to the capacity short Midwest or Mid-Atlantic regions;
(2) demand-side management affects peak demand;
(3) expansion unit capital costs are consistent with current market
prices and there are no real price increases in these capital costs;
(4) heat rates are approximately 5% to 7% better than combustion turbine
or combined cycle technology currently available;
(5) the capacity expansion assumptions do not incorporate the probable
requirement for the retirement and replacement of 17,000 megawatts of
nuclear capacity in the later years of the study period;
(6) initial cost recovery is based on current book value which is
significantly below current unit auction value; and
(7) operating capacity factor is approximately 5% to 10% higher than
current average achievable unit capacity factors.
81
<PAGE>
- C.C. Pace's principal downside case assumptions are the same as its base
case assumptions, with the following exceptions:
(1) installed costs for combustion turbines are $250/kilowatt, as opposed
to $300/kilowatt;
(2) installed costs for combined cycle units are $436/kilowatt, as
opposed to $500/kilowatt;
(3) system generation capacity exceeds generation requirements by 2,400
megawatts; and
(4) a 5% improvement in the assumed heat rate efficiency for expansion
capacity.
- C.C. Pace's operational assumptions for the facility are set forth in the
following chart:
<TABLE>
<S> <C>
On-Line Date June 1, 2000
Equivalent Force Outrage Rate 2.80%
Annual Maintenance Requirements 5.2% per year
Net Output 750 megawatts
Variable Operation and Maintenance $1.00 per megawatt hour
Expense
1998 Deliverable Fuel Cost $2.30 per MMBtu-Mississippi
Cost Per Start $2,500
Heat Rate Efficiency 7,050 Btu per kilowatt hour
Minimum Operating Load 175 megawatts
Service Area Location Tennessee Valley Authority
Interconnected Utilities Tennessee Valley Authority, SPP-SE
Transmission Pricing Arrangements Tennessee Valley Authority -SPP-SE @
$0.00 per megawatt hour and Southern
@ $1.82 per megawatt hour
</TABLE>
- C.C. Pace defined the relevant market area for the southeast market by
assessing:
(1) the location of the power facility;
(2) the transmission interconnections and capabilities to which the power
facility would have access over the course of the study period; and
(3) areas where market price and demand growth have indicated a need for
additional resources.
- The C.C. Pace market study does not add expansion units to meet a target
reserve margin, as is the current planning method for regulated utilities.
A competitive market structure dictates, by definition, that participants
will build expansion units only if they expect to receive a sufficient
return on their investment. Therefore, in the C.C. Pace analysis,
expansion units are added to the southeastern market only when the
projected market price can support them.
- To determine the competitive market expansion plan, C.C. Pace followed
five rules or steps to arrive at the optimal expansion plan. These rules
or steps are:
- use of the existing units and planned utility unit additions as the
minimum expansion plans as a starting point;
- the addition of expansion units in each year up to the point that the
whole class of units, i.e. combined cycle or combustion turbines,
receive full cost recovery. This was done up to the point that the next
unit added to the system would not be able to recover its costs;
- unit additions were optimized for each sub-system within the
southeastern power market and for each year of the study period to
yield the largest number of combined cycle units
82
<PAGE>
and combustion turbine units possible while still maintaining full cost
recovery of these units;
- the model determined the optimal cost solution and capacity mix of
combined cycle and combustion turbine technology in each year modeled;
and
- the model did not assume or allow for the retirement of existing
capacity.
- C.C. Pace used a methodology to perform its independent forecast of demand
growth in the southeastern market that included the following two primary
components:
- the use of economic models to forecast annual peak demand and energy
levels based on changes in factors such as population, employment and
income; and
- the translation of historical hourly demand levels and forecasted peak
demand to create predicted hourly load profiles.
- C.C. Pace used the following methodology to determine its long-term fuel
price forecast inputs:
- collection of historical plant level fuel prices for a three year
period from Federal Energy Regulatory Commission and Energy Information
Administration sources;
- comparison of average costs of fuel for particular plants with the
weighted average cost of that fuel for all plants in the market area,
and establishment of ratios of a unit's cost of fuel to the weighted
average;
- not assuming any seasonal price changes for fuels;
- development of long-term fuel escalation factors; and
- application of these forecasted growth rates to the weighted average
price of fuels previously derived.
83
<PAGE>
RELATIONSHIPS AND RELATED TRANSACTIONS
The operator of our project, Cogentrix Batesville Operations, LLC, is a
wholly owned subsidiary of Cogentrix. Under the operation and maintenance
agreement, Cogentrix Batesville Operations will receive a fee of $39,000 per
month for ten months for services performed prior to the date on which our power
facility begins commercial operation and a fee of $41,667 per month on and after
the date on which our power facility begins commercial operation. These fees
will be adjusted annually in accordance with the gross domestic product implicit
price deflator index, which is intended to be a measure of inflation. In
addition, we will reimburse Cogentrix Batesville Operations for the budgeted and
approved expenses it incurs to operate and maintain our project. We will pay
Cogentrix Batesville Operations' post-commercial operation fees only if we have
already allocated the required funds to our debt service and reserve accounts in
accordance with the financing documents. We believe that the terms of the
operation and maintenance agreement are commercially reasonable. See
"Description of the Principal Project Documents--Operation and Maintenance
Agreement" and "Description of the Principal Financing Documents--Common
Agreement--Deposit and Disbursement of Funds."
The manager of our project, LS Power Management, LLC, is a wholly owned
subsidiary of LS Power. As compensation for the services that LS Power
Management will provide us under the management services agreement, LS Power
Management will receive a monthly management fee of $33,333. This fee is
adjusted annually in accordance with the gross domestic product implicit price
deflator index. The fees and reimbursable expenses payable under the management
services agreement are designated as operating expenses under the financing
documents and therefore will be paid prior to the payment of principal of and
interest on the bonds. We believe that the terms of the management services
agreement are commercially reasonable. See "Description of the Principal Project
Documents--Management Services Agreement."
We paid a development fee of $14,000,000 and reimbursed about $2,500,000 of
costs to Granite Power Partners II, L.P. in consideration for development
activities provided prior to the offering of the bonds. No additional fee is
payable to Granite Power Partners II, L.P. by us. The development activities
provided by Granite Power Partners II, L.P. to us consisted of the acquisition
of land rights, coordination of the financing of our project, strategic
planning, contract negotiation and execution, regulatory analysis, the
acquisition of permits for our project and engineering oversight.
84
<PAGE>
DESCRIPTION OF THE PRINCIPAL PROJECT DOCUMENTS
THE FOLLOWING IS A SUMMARY OF OUR PRINCIPAL PROJECT DOCUMENTS. ANY REFERENCE
IN THIS PROSPECTUS TO ANY AGREEMENT INCLUDES ALL EXHIBITS AND AMENDMENTS
EFFECTIVE AS OF THE DATE OF THIS PROSPECTUS. WE ENCOURAGE YOU TO READ THESE
AGREEMENTS. COPIES OF THESE AGREEMENTS HAVE BEEN FILED WITH THE SECURITIES AND
EXCHANGE COMMISSION AS EXHIBITS TO OUR REGISTRATION STATEMENT.
VIRGINIA POWER POWER PURCHASE AGREEMENT
We are party to a power purchase agreement with Virginia Electric and Power
Company dated as of May 18, 1998 which provides for the sale of the electrical
capacity and electricity from two of the generating units at our power facility.
These two units will be dedicated to Virginia Power's use under the Virginia
Power power purchase agreement. Virginia Power is required to file reports and
other information with the Securities and Exchange Commission. These materials
are available on the Securities and Exchange Commission's web site, which can be
accessed at http://www.sec.gov.
MILESTONES, GUARANTEED DELIVERY, AND CONSEQUENCES OF DELAY
The Virginia Power power purchase agreement contains scheduled milestones
which we have agreed to achieve. The milestones include:
<TABLE>
<CAPTION>
MILESTONE MILESTONE DATE
- --------- ----------------
<S> <C> <C>
1. Completion of the foundations for the combustion turbine
generator and the steam turbine generator................... November 1, 1999
2. Delivery of the combustion turbine generator................ December 1, 1999
3. Delivery of the steam turbine generator..................... January 1, 2000
4. Completion of the lateral pipeline.......................... March 31, 2000
5. Completion of pressure testing of the heat recovery steam
generator and steam blows of the piping system and
synchronization with the Entergy system and the Tennessee
Valley Authority system..................................... May 1, 2000
6. Commercial operation date................................... June 1, 2000
</TABLE>
Milestones 1, 2 and 3 have been achieved and it is anticipated that
milestones 4 and 5 will be achieved prior to their milestone dates. However, the
current construction schedule indicates that commercial operation of the two
Virginia Power units will occur on May 10, 2000 and June 5, 2000. Based upon
these scheduled dates, the second Virginia Power unit may not achieve commercial
operation prior to its milestone date.
We have guaranteed delivery of the estimated amount of contract capacity
(283 megawatts for each unit or 566 megawatts total) to Virginia Power starting
on June 1, 2000. The date for guaranteed delivery will be extended on a daily
basis if there is a delay due to a force majeure event or some other event which
is beyond our control. We have agreed that if we do not achieve commercial
operation of either of Virginia Power's units by the guaranteed date, then we
will be responsible for the delivery of capacity and electricity from another
source. If there is an unexcused delay, and Virginia Power requests that we be
responsible for replacement capacity and electricity, we can choose to either:
- arrange for capacity and electricity from another source. In this case
Virginia Power will pay us for this capacity and electricity at the
contract price. We will be responsible for any costs above the contract
price, with our maximum liability limited to $5,660,000 for each unit or
$11,320,000 total; or
85
<PAGE>
- ask Virginia Power to obtain capacity and electricity from another source.
In this case we will pay Virginia Power for the difference between the
cost of replacement power and the cost of power under the contract, with
our liability limited to $5,660,000 for each unit or $11,320,000 total.
Based upon BVZ Power Partners' estimated completion date of June 5, 2000 for
the second Virginia Power unit, we may be liable for the cost of replacement
power for the period from June 1, 2000 to June 5, 2000.
We will begin delivering capacity and electricity from each of Virginia
Power's designated units on the commercial operation date of each unit. The
commercial operation date for a unit is defined as the date of the last to occur
of the following:
- we complete all milestones for the unit;
- we successfully test the unit; and
- we deliver Virginia Power a certificate of the achievement of the
commercial operation date of the unit.
Virginia Power will have the right to terminate the Virginia Power power
purchase agreement if we fail to achieve the commercial operation date by
June 1, 2001, which date can be extended if we experience an event of force
majeure or if Virginia Power fails to deliver fuel to us. Prior to the
commercial operation date, in the case of force majeure, Virginia Power will
have the right to terminate the Virginia Power power purchase agreement if the
duration of the force majeure exceeds 12 months.
SECURITY
We must post completion security in the form of one or more irrevocable
letters of credit to secure our performance under the Virginia Power power
purchase agreement and cover our replacement power obligations. On August 28,
1998, we posted completion security in the form of a letter of credit in the
amount of $5,660,000. If we fail to achieve any milestone for a Virginia Power
unit by the milestone date and that failure may result in a delay of the
commercial operation date, we will be required to post additional completion
security. The total amount of completion security will be computed as the
estimated incremental replacement power cost for the time of the delay in the
commercial operation date, up to a maximum total of $5,660,000 per unit or
$11,320,000 total. If Virginia Power draws upon the completion security, we will
have no obligation to replenish the completion security prior to the commercial
operation date. After the commercial operation date, the completion security
will be released, and we will have the obligation to maintain other security in
an amount equal to $10 per kilowatt of each Virginia Power unit, which we
estimate will be $5,600,000.
COMMISSIONING AND TESTING
Prior to the commercial operation date and every year thereafter, the
contract capacity for each Virginia Power unit will be established according to
testing procedures contained in the Virginia Power power purchase agreement.
Virginia Power may market and sell test electricity for us. We will be
responsible for the cost of fuel needed to generate the test electricity and may
be required to pay Virginia Power a marketing fee of $1 per megawatt hour of
test electricity sold.
TERM
The initial term of the Virginia Power power purchase agreement extends to
the date 13 years after the earlier of the commercial operation date and the
guaranteed delivery date. Virginia Power may extend the term of the Virginia
Power power purchase agreement for an additional 12 years. At
86
<PAGE>
any point during the extended term, Virginia Power may terminate the Virginia
Power power purchase agreement upon 18 months notice.
VIRGINIA POWER OPTION TO BUY
If Virginia Power exercises its option to extend the term of the Virginia
Power power purchase agreement and does not terminate the Virginia Power power
purchase agreement prior to the end of its twenty-fifth year, Virginia Power
will have the option to purchase the Virginia Power units at the end of the
extended term. The purchase price will be $150 per kilowatt of the capacity of
the Virginia Power units.
SALE AND PURCHASE OBLIGATIONS
We are obligated to sell, and Virginia Power is obligated to purchase, the
capacity and electricity of the Virginia Power units. Virginia Power will be
required to accept any replacement power that we deliver if we choose to deliver
replacement power when the Virginia Power units are unavailable in whole or in
part. After the commercial operation date of either unit, we are not obligated
to deliver power from another source, but we may elect to provide replacement
power during a forced outage or a force majeure event, or when either Virginia
Power unit is unavailable for any reason. Virginia Power will make payments for
replacement power as if such power were delivered from a Virginia Power unit. We
are restricted from selling capacity or electricity from either of the Virginia
Power units to any third party during the term of the Virginia Power power
purchase agreement. Virginia Power must make monthly payments to us including a
reservation payment, an energy payment, start-up payments and system upgrade
credits. Virginia Power's aggregate payment to us may be increased or decreased
depending on whether our power facility produces electricity above or below a
specified level of fuel efficiency.
RESERVATION PAYMENTS, RESERVATION CHARGES, AND AVAILABILITY ADJUSTMENTS
The reservation payment for each Virginia Power unit begins on the earlier
to occur of the commercial operation date and the guaranteed delivery date. The
reservation payment for each Virginia Power unit is calculated under a formula
based on the tested capacity of the unit, a reservation charge, and an
availability adjustment factor for the unit:
Reservation Payment = ((standard capacity X standard capacity reservation
charge) + (supplemental capacity X supplemental
capacity reservation charge)) X availability
adjustment factor
The standard capacity is the maximum generating capacity of each Virginia
Power unit without the use of duct firing or steam injection, measured by a test
conducted at least annually. The results of each test will be adjusted to summer
conditions. The standard capacity generally decreases with rising temperature,
so the summer condition adjustment ensures that Virginia Power will only pay for
capacity which will be available in the summer when it is needed most. During
cooler periods, the capacity greater than the amount of capacity available
during the summer is to Virginia Power's benefit. The supplemental capacity is
the additional generating capacity of a Virginia Power unit created by the use
of duct firing or steam injection, measured by a test conducted at least
annually. The results of each test will be adjusted to summer conditions. The
supplemental capacity generally does not vary with temperature. We will have the
right to re-test and re-establish the standard capacity and supplemental
87
<PAGE>
capacity up to four times in any year. Virginia Power will have the right to
require a re-test once a year. The reservation charges for each year are as
follows:
<TABLE>
<CAPTION>
STANDARD CAPACITY RESERVATION SUPPLEMENTAL CAPACITY RESERVATION
CONTRACT YEAR CHARGE ($/KW-MONTH) CHARGE ($/KW-MONTH)
- ------------- ----------------------------- ---------------------------------
<S> <C> <C>
1-5..................................... 5.00 3.25
6-13.................................... 6.00 3.50
14-25(extended term).................... 4.50 3.00
</TABLE>
If the commercial operation date of either Virginia Power unit occurs prior
to the guaranteed delivery date, the reservation charge for that Virginia Power
unit prior to the guaranteed delivery date will be $4.00 per kilowatt per month
for standard capacity and $0.00 for supplemental capacity.
The availability adjustment factor is meant to adjust the reservation
payment according to how reliably each unit operates. The availability
adjustment factor is calculated in several steps with the end result being a
decrease in the reservation payment if a unit performs poorly during a year,
particularly if a unit performs poorly during the summer peak.
The first step in the calculation of the availability adjustment factor is
keeping track of all forced outage hours for each Virginia Power unit. In
general, any hour in which a unit cannot deliver power when needed is counted as
a forced outage hour unless the hour has been pre-agreed as an outage or unless
the outage is otherwise excused. A forced outage hour in the Virginia Power
Power Purchase Agreement is defined as any hour in which a unit is not fully or
partially available to generate the electricity required by Virginia Power other
than:
- scheduled maintenance hours;
- force majeure hours;
- excused hours;
- hours when an emergency condition is occurring on the Tennessee Valley
Authority's or Entergy's electrical transmission system;
- non-delivery due to imbalances if we are responsible for imbalance
penalties; and
- hours in which we elect to be responsible for replacement power, which are
described below under "--Forced Outages and Replacement Power".
For example, if a critical piece of equipment breaks, and it is not due to a
force majeure event such as a tornado, then all of the hours in which Virginia
Power would have dispatched the unit will be counted as forced outage hours
until the equipment is repaired or replaced, unless we elect to be responsible
for replacement power during the outage. Similarly, if a piece of equipment
breaks which causes the output of a unit to be 50% of the maximum output of the
unit, and the breakage is not due to a force majeure event and we do not elect
to be responsible for replacement power, then 50% of each hour in which Virginia
Power would have dispatched the unit until the equipment is repaired or replaced
will be counted as forced outage hours.
The second step in the calculation of the availability adjustment factor
takes into consideration the relative value of each unit during the summer
electricity peak season. Having the unit available to generate electricity in
the summer is more valuable than having it available at other times of the year.
We have agreed to reflect this increased value in the calculation of the
availability adjustment factor by using a weighing factor to weight each forced
outage hour before calculating the availability adjustment
88
<PAGE>
factor. The weighing factor for each forced outage hour of each Virginia Power
unit is shown in the table below:
<TABLE>
<CAPTION>
MONTH MONTHLY WEIGHING FACTOR
- ----- -----------------------
<S> <C>
January................................................. .075
February................................................ .075
March................................................... .035
April................................................... .035
May..................................................... .085
June.................................................... 1.50
July.................................................... 2.50
August.................................................. 2.50
September............................................... 1.00
October................................................. .035
November................................................ .035
December................................................ .075
</TABLE>
The next step in calculating the availability adjustment factor is to total
the weighted forced outage hours over the previous 12 months. By having a
12 month rolling average, the effect of any large forced outage on the
reservation payment is not only on the current month, but is also smoothed over
the next 11 months. The availability adjustment factor for any month is
calculated according to the following algorithm based on the total 12-month
weighted forced outage hours:
During the first year: availability adjustment factor = (8,760-twelve month
equivalent forced
outage hours)/8,391.
After the first year:
If the twelve month equivalent forced outage hours are less than or
equal to 1,752, then the availability adjustment factor = (8,760-twelve
month equivalent forced outage hours)/8,515;
If the twelve month equivalent forced outage hours are between 1,752 and
2,628, then the availability adjustment factor = (8,760-(twelve month
equivalent forced outage hours + 0.25 X (twelve month equivalent forced
outage hours-1,752)))/8,515
If the twelve month equivalent forced outage hours are greater than
2,628, then the availability adjustment factor = (8,760-(twelve month
equivalent forced outagehours + 0.25 X (twelve month equivalent forced
outage hours-1,752)))/8,515
If the twelve month equivalent forced outage hours are greater than
2,628, then the availability adjustment factor = (8,760-(twelve month
equivalent forced outage hours + 0.25 X (2,628 - 1,752) + 0.40 X (twelve
month equivalent forced outage hours-2,628)))/8,515
In other words, for each Virginia Power unit, we can incur 369 weighted
forced outage hours during the first contract year and 245 equivalent forced
outage hours in each subsequent year without any reduction in our reservation
payment. After the first contract year, each month we will calculate the number
of weighted forced outage hours occurring during the prior twelve month period.
For every 1% of equivalent outage hours over 245, the reservation payment will
be reduced by 1%. For every 1% of equivalent outage hours over 1,752, the
reservation payment will be reduced by 1.25%. For every 1% of equivalent outage
hours over 2,628, the reservation payment will be reduced by 1.4%.
ENERGY PAYMENTS
The energy payment is equal to the product of the electricity delivered to
Virginia Power at the interconnection point with the Tennessee Valley Authority
or Entergy systems times a rate of $1.00 per megawatt hour, increasing at 3% per
calendar year.
89
<PAGE>
START PAYMENTS
If the number of starts for either Virginia Power unit exceeds 250 per
contract year, Virginia Power will pay us a start payment calculated as the
product of $5,000 per start multiplied by the number of starts greater than 250.
If a Virginia Power unit fails to successfully start (during testing,
commissioning or otherwise thereafter), we will reimburse Virginia Power for the
fuel consumed during the failed start. If a Virginia Power unit trips after a
successful start, we will reimburse Virginia Power for the fuel consumed during
the start.
SYSTEM UPGRADE CREDITS
Under our interconnection agreements with the Tennessee Valley Authority and
Entergy, the Tennesssee Valley Authority and/or Entergy could provide Virginia
Power with a credit or discount for transmission service due to our payment for
system upgrades on the Tennessee Valley Authority's and Entergy's systems.
Although the Tennessee Valley Authority and Entergy have agreed to pay these
credits to us directly, Virginia Power has agreed to pay us a system upgrade
credit in the amount of any payment, credit or discount received by Virginia
Power under its transmission service agreements with Entergy and the Tennessee
Valley Authority, to the extent attributable to our payment for upgrades of the
Tennessee Valley Authority and Entergy systems.
GUARANTEED HEAT RATE PAYMENTS
Virginia Power will pay us, or we will pay Virginia Power, the difference
between the cost of fuel actually consumed by the Virginia Power units while
they are dispatched above minimum load and the cost of fuel that would have been
consumed based on a guaranteed fuel efficiency, as described below under "--Heat
Rate Guarantee."
OPERATION AND MAINTENANCE
We must operate and maintain the Virginia Power units and the common
facilities in accordance with prudent industry practice and the requirements of
the Virginia Power power purchase agreement, which requires us, for example, to
comply with law. We must inform Virginia Power on a daily basis of the
generation capacity of each Virginia Power unit and any limitations,
restrictions, deratings or outages affecting that Virginia Power unit for the
next day. We must provide Virginia Power ongoing access to the site and various
operational information.
MAINTENANCE SCHEDULING
Each year we and Virginia Power will work together to develop a proposed
schedule for the scheduled maintenance outages of our power facility for the
next year based upon Virginia Power's projected dispatch schedule. We have
agreed not to schedule maintenance during the months of June, July, August,
September, January and February without Virginia Power's consent. The number of
allotted days for scheduled maintenance outages of each Virginia Power unit is
14 days in the years in which a combustor inspection will occur, 21 days in the
years in which a hot gas inspection will occur and 28 days in the years in which
a major inspection will occur.
We may also perform up to 120 hours per year of additional scheduled
maintenance outages at night or during weekends and holidays with one day's
prior written notice to Virginia Power. Virginia Power has the right to delay an
additional scheduled maintenance as long as Virginia Power pays for any costs
associated with the delay.
We must use commercially reasonable efforts to minimize any scheduled
maintenance outage.
90
<PAGE>
SCHEDULING, DISPATCH AND DELIVERY
Each Virginia Power unit will be fully dispatchable and capable of automatic
generation control and will operate on automatic generation control if directed
by Virginia Power or the designated control center on behalf of Virginia Power.
On a daily basis, Virginia Power will provide us with the projected hourly
schedule for dispatch for the following day. Each Virginia Power unit must
operate consistent with manufacturers' recommendations and design parameters
agreed upon between Virginia Power and us, such as a minimum steady-state load
of 70% of the standard capacity.
FORCED OUTAGES AND REPLACEMENT POWER
In the event of a forced outage that results in a reduction of at least 50
megawatts in the capacity of either Virginia Power unit, or in the event of a
reduction in the capacity of either unit that lasts for a continuous period of
ten days or longer, we may at our option avoid counting the outage as a forced
outage in the calculation of the availability adjustment factor by being
responsible for replacement power. This means that we can elect to provide
replacement power or we can elect to pay Virginia Power the incremental cost of
replacement power greater than the cost under the contract as described below.
Whenever either unit trips off-line or is unavailable for a reason that is
not excused, the following process is initiated. Within four hours of the
beginning of the outage, we must notify Virginia Power of our election regarding
replacement power during the first few days of the outage. During the initial
period from the commencement of the outage through midnight of the second
following day our election may be either:
- to pay Virginia Power the incremental cost of obtaining replacement
capacity and electricity greater than the cost of capacity and electricity
under the Virginia Power power purchase agreement; or
- to count the outage hours as forced outage hours in the calculation of the
availability adjustment factor of the unit.
During the outage we will try diligently to remedy the situation. If the
outage continues until midnight of the second day following the beginning of the
outage, then we are required to notify Virginia Power of our assessment of the
situation, the expected end of the outage, and our election of one of the
options described below for the duration of the outage. Beginning at 10:00 a.m.
of the second day following the beginning of the outage and until the outage is
over we may elect:
- to provide replacement capacity and electricity, in which case we will be
paid for replacement capacity and electricity as if it were supplied from
the unavailable unit;
- to require Virginia Power to secure replacement capacity and electricity,
in which case we will pay Virginia Power for any incremental cost of
obtaining replacement capacity and electricity which is greater than the
cost of capacity and electricity under the Virginia Power power purchase
agreement; or
- to count the outage hours as a forced outage in the calculation of the
availability adjustment factor.
If either period of the outage has been designated to count toward forced
outage hours in the availability adjustment calculation, then Virginia Power
will provide us with the estimated dispatch of the unit in order to determine
the number of forced outage hours. Within two days after a unit has returned to
service, Virginia Power will provide us with an estimate of when the unit would
have been dispatched, based on the market prices during the period. Only hours
in which we would have been dispatched will count as forced outage hours.
91
<PAGE>
Replacement power will consist of electric generating capacity and
electricity having substantially similar characteristics to the capacity and
electricity to be supplied by us under the Virginia Power power purchase
agreement.
We have agreed to reevaluate the process described above after at least two
years, at Virginia Power's election, with the objective of the reevaluation to
be to eliminate any undue administrative burden on either party.
ELECTRICAL INTERCONNECTION
We will own, operate, maintain and control all of the electrical
interconnection facilities up to the point of interconnection of our power
facility with Entergy's and the Tennessee Valley Authority's systems. Virginia
Power will be responsible for obtaining and paying for the provision of
transmission services and any ancillary or control area services required by the
Federal Energy Regulatory Commission, Entergy, the Tennessee Valley Authority,
any independent system operator or any other transmission utility for the
delivery and transmission of electricity beyond the interconnection points
between our power facility and the Tennessee Valley Authority and Entergy
systems. Virginia Power is obligated to make reservation payments under the
Virginia Power power purchase agreement whether or not transmission service is
available for the output of either Virginia Power unit. We are excused from
non-performance if our power facility is disconnected from the Tennessee Valley
Authority or Entergy system due to a Tennessee Valley Authority or Entergy
system emergency. See "--Force Majeure Events and Delivery Excuse" "--Entergy
Interconnection Agreement" and "--Tennessee Valley Authority Interconnection
Agreement."
FUEL ARRANGEMENTS
The Virginia Power power purchase agreement is what is referred to as a
tolling arrangement. Virginia Power is obligated to supply and pay for fuel for
each Virginia Power unit. Virginia Power will continue to make reservation
payments under the Virginia Power power purchase agreement whether or not it is
able to deliver fuel to our power facility (as long as its inability to deliver
fuel is not due to our negligence, such as if we do not interconnect our power
facility to any gas transportation pipelines). Virginia Power will pay us, or we
will pay Virginia Power, the difference between the cost of fuel actually
consumed by the Virginia Power units while they are dispatched above minimum
load and the cost of fuel that would have been consumed based on a guaranteed
fuel efficiency as described below under "--Heat Rate Guarantee."
Virginia Power is obligated to arrange, procure, supply, nominate, balance,
transport and deliver to the lateral natural gas pipeline the amount of fuel
necessary for each of the Virginia Power units to generate the electrical output
expected to be dispatched by Virginia Power from that Virginia Power unit.
We have the right to require Virginia Power to provide fuel to us during the
commissioning and testing of the Virginia Power units prior to the commercial
operation date. We must notify Virginia Power no later than ten days prior to
the date on which such fuel will be needed and will reimburse Virginia Power for
the delivered cost of that fuel associated with any fuel used during the
commissioning of the Virginia Power units.
We must obtain all governmental approvals required for the ownership,
construction, operation and maintenance of the lateral natural gas pipeline. We
must construct or cause the construction of the lateral natural gas pipeline in
a timely manner and with a capacity sufficient to deliver fuel to operate our
entire power facility at its hourly maximum output level. We must operate and
maintain the lateral natural gas pipeline and reserve transportation rights on
the lateral natural gas pipeline sufficient for the delivery of fuel to operate
our entire power facility at its hourly maximum output level. No other
92
<PAGE>
person can have a right to transport fuel on the lateral natural gas pipeline
superior to Virginia Power except as may be required by law.
HEAT RATE GUARANTEE
Virginia Power will pay us, or we will pay Virginia Power, the difference
between the cost of fuel actually consumed by the Virginia Power units while
they are dispatched above minimum load and the cost of fuel that would have been
consumed based on a guaranteed fuel efficiency or "heat rate". Heat rate is the
common technical term in the industry to measure fuel efficiency, and is the
amount of heat input per unit output. The only significant difference between
fuel efficiency and heat rate is that the measurement units of heat rate are
inverted from what is normally thought of as fuel efficiency, so as efficiency
increases, the heat rate decreases.
93
<PAGE>
A tracking account will be maintained to track for each Virginia Power unit
the difference between the actual amount of fuel required to generate the
dispatched electricity and the amount of fuel expected to be required to
generate the dispatched electricity based on the guaranteed heat rate. The fuel
used by each Virginia Power unit for operations below the minimum load during
start-ups and shutdowns is not considered in this calculation. There is no heat
rate guarantee below minimum load. If the actual amount of fuel required to
generate the dispatched electricity above minimum load varies from the expected
amount of fuel at the guaranteed heat rate, then a balance will accrue in the
tracking account to credit us or Virginia Power as appropriate. The amount added
or subtracted from the tracking account will be the actual fuel cost increase or
fuel cost savings, or the best estimate if the actual amount can not be exactly
known. If the actual amount of fuel consumed is greater than the amount of fuel
calculated on the basis of the guaranteed heat rate then we will pay Virginia
Power the actual or estimated cost for the excess fuel. If the actual amount of
fuel consumed is less than the amount of fuel calculated on the basis of the
guaranteed heat rate then Virginia Power will pay us an amount equal to the
actual or estimated cost of the fuel savings. The guaranteed heat rate for each
Virginia Power unit at the standard capacity is 7,000 BTU per kilowatt hour.
This value is adjusted upwards for loads less than full standard capacity to
account for fuel efficiency decreases at lower load points than the optimal
output. The guaranteed heat rate for supplemental capacity is 9,500 BTU per
kilowatt hour.
FORCE MAJEURE EVENTS AND DELIVERY EXCUSE
Either party is excused from performing its obligations due to events which
are not in its reasonable control and without the fault or negligence of the
party claiming the force majeure event. The Virginia Power power purchase
agreement contains several examples of force majeure events such as floods,
hurricanes, tornadoes, sabotage, terrorism, war, riots, public disorders and
emergency conditions. The power purchase agreement identifies the following
events as events which are not force majeure events:
- causes or events affecting the performance of third party suppliers of
goods or services except to the extent caused by an event that is
otherwise a force majeure event;
- causes or events resulting from ambient temperature;
- failures or delays caused by a strike at the project, except to the extent
caused by a national strike;
- the unavailability of equipment which could have been avoided by prudent
industry practices;
- changes in market conditions that affect the price of energy or capacity;
- failure to timely apply for government approvals; and
- delivery excuse.
We have informed Virginia Power that the delay in the delivery of the
Virginia Power generating unit's steam turbine was an event beyond our
reasonable control and without our fault or negligence and thus would constitute
a force majeure event under the Virginia Power power purchase agreement.
However, Virginia Power did not initially agree with our assertion and
resolution of the issue is pending our resolution of the issue with BVZ Power
Partners.
If a party fails to perform under the Virginia Power Power Purchase
Agreement because of a force majeure event, and such nonperformance continues
for a period exceeding 12 consecutive months, the other party may terminate the
Virginia Power power purchase agreement.
We are not liable for or deemed in breach of the Virginia Power power
purchase agreement to the extent performance of our obligations is delayed or
prevented by circumstances defined in the
94
<PAGE>
agreement as "delivery excuse". Our failure to deliver is excused when it is due
to the non-performance of Virginia Power, such as if Virginia Power fails to
arrange for fuel to be supplied and delivered to our power facility, or fails to
arrange for transmission of electricity away from our power facility. We are
also excused from non-performance due to any event of default of Virginia Power,
any delay or failure by Virginia Power in giving any approval within the times
required, any delay or failure by Virginia Power in performing any of its
obligations, or any emergency condition presenting an imminent danger or
significant disruption on the Entergy system or the Tennessee Valley Authority
system that results directly from an act or failure to act by Virginia Power.
During periods when we cannot perform our obligations, referred to as delivery
excuses, Virginia Power will continue to make reservation payments to us, and
such non-delivery hours will not count as forced outage hours in the
availability adjustment factor calculation.
DEFAULTS AND REMEDIES
The following constitute events of default under the Virginia Power power
purchase agreement:
- the failure of either party to make undisputed payments within 30 days
after notice that such payment is due;
- the failure of either party to comply with any material provision of the
Virginia Power power purchase agreement within 30 days after notice has
been given, or up to 90 days after notice has been given if reasonable
diligence is being used to cure the failure;
- a bankruptcy, insolvency or similar event affecting either party;
- our failure to provide the required completion security within 30 days
after notice by Virginia Power, or our failure to maintain the required
completion security within 10 days after notice by Virginia Power;
- either party's failure to comply with the assignment provisions of the
Virginia Power power purchase agreement;
- any representation made by either party that is found to be false in any
material respect;
- our willful act of providing or selling capacity from the Virginia Power
units to a person other than Virginia Power;
- our willful act of tampering with the metering equipment for the purpose
of defrauding Virginia Power; or
- our abandonment of our power facility.
Upon an event of default, the non-defaulting party may establish a date
between 5 and 10 business days of notice on which the Virginia Power power
purchase agreement will be canceled if the event of default has not been cured,
withhold any payment due to the defaulting party under the Virginia Power power
purchase agreement until the event of default is cured, and pursue any other
remedies available at law or in equity.
INDEMNIFICATION
We will indemnify and hold harmless Virginia Power, and Virginia Power will
indemnify and hold us harmless, from all claims, demands, losses, liabilities
and expenses for personal injury or death or damage to property arising out of
the indemnifying party's performance under the Virginia Power power purchase
agreement.
95
<PAGE>
LIMITATION ON LIABILITY
Prior to the commercial operation date of the Virginia Power units, our
liability to Virginia Power, other than with respect to indemnity or a liability
due to the willful sale of electricity from the Virginia Power units to a third
party or otherwise in violation of the Virginia Power power purchase agreement,
will be limited to the amount of completion security required to be provided
under the Virginia Power power purchase agreement. After the commercial
operation date of either Virginia Power unit, our liability to Virginia Power
will not exceed $40 million during the initial term, $70 million from the end of
the initial term until December 31 of contract year 17, and $100 million from
January 1 of contract year 17 until the end of the extended term. The Virginia
Power power purchase agreement provides that unless expressly provided otherwise
in the Virginia Power power purchase agreement, neither party will be liable to
the other for consequential, incidental, punitive, exemplary or indirect damages
suffered by that party or by any customer or any purchaser of that party, lost
profits or other business interruption damages, by statute, in tort or contract,
under any indemnity provision or otherwise.
ASSIGNMENT
The Virginia Power power purchase agreement may not be assigned by either
party without the other party's prior written consent. No consent is required if
we assign the Virginia Power power purchase agreement to any party providing
financing for our power facility and its successors and assigns. No consent is
required if Virginia Power assigns the Virginia Power power purchase agreement
to Dominion Resources or any wholly-owned subsidiary of Dominion Resources, if
at the time of assignment, the assignee has a long-term debt credit rating at or
above the lowest of A- from Standard and Poor's Ratings Group, Baal from Moody's
Investors Service, Inc. or the credit rating of Virginia Power at the time of
the assignment. In addition, the assignee must assume all of the obligations of
Virginia Power under the Virginia Power power purchase agreement and other
related agreements.
The collateral agent or its transferee or assignee may assume our
obligations under the Virginia Power power purchase agreement as long as our
power facility is maintained and operated at all times by an experienced
operating entity or an affiliate of an experienced operating entity. In
addition, the transferee or assignee must have a tangible net worth no less than
our tangible net worth on August 28, 1998, and the transferee or assignee or any
affiliate of that entity must not have been an adverse party in litigation with
Virginia Power or any of its affiliates within the preceding 18 months. In
addition, upon acceleration of some of our loans, Virginia Power will be offered
the opportunity to purchase those loans.
AQUILA POWER PURCHASE AGREEMENT
We are a party to a power purchase agreement with Aquila Energy Marketing
Corporation and UtiliCorp United Inc. dated as of May 21, 1998 which provides
for the sale of the electrical capacity and electricity generated from one unit
at our power facility. One unit will be dedicated to Aquila/ UtiliCorp's use
under the Aquila/UtiliCorp power purchase agreement. UtiliCorp United Inc. has
appointed Aquila Energy Marketing Corporation as its agent under the
Aquila/UtiliCorp power purchase agreement. UtiliCorp United Inc. is required to
file reports and other information with the Securities and Exchange Commission.
These reports include information about Aquila Energy Marketing Corporation
because it is a wholly-owned subsidiary of UtiliCorp United Inc. The reports and
other information filed by UtiliCorp United Inc. are available on the Securities
and Exchange Commisson's web site, which can be accessed at http://www.sec.gov.
GUARANTEED DELIVERY, COMMISSIONING AND TESTING, AND CONSEQUENCES OF DELAY
We have guaranteed delivery of the estimated amount of contract capacity
(defined to be 279 megawatts) to Aquila/UtiliCorp starting on June 1, 2000. This
guaranteed date will be extended on a
96
<PAGE>
daily basis if there is a delay due to a force majeure event or some other event
which is beyond our control. If there is an unexcused delay in the commercial
operation date of the Aquila/UtiliCorp unit beyond the guaranteed date then we
must elect one of the following:
- to arrange for capacity and electricity from another source. In this case
Aquila/UtiliCorp will pay us for this capacity and electricity at the
contract price. We will be responsible for any costs above the contract
price;
- to request Aquila/UtiliCorp to obtain capacity and electricity from
another source. In this case we will pay Aquila/UtiliCorp for the
difference between the cost of their replacement power and the cost of
power under the contract. If we do not provide Aquila/UtiliCorp the proper
notices of a delay in the commercial operation date, this case will
automatically occur; or
- to make an adjustment to the reservation payment during the period between
the guaranteed delivery date and the commercial operation date of the
Aquila/UtiliCorp unit. This adjustment to the reservation payment each
month will be based on a value factor for the month as described below
under "--Availability Adjustment". Any adjustment greater than the
reservation payment for a month will be provided to Aquila/UtiliCorp as a
credit toward the reservation payments in future months. We may make this
election only if we give Aquila/UtiliCorp a notice of delay of the
commercial operation date at least 90 days prior to the guaranteed
delivery date.
The current construction schedule indicates that substantial completion of
the Aquila/UtiliCorp unit will occur on June 27, 2000. As a result of this
projected delay, we have notified Aquila/UtiliCorp of our election to incur a
delivery delay adjustment in the event that the Aquila/UtiliCorp unit is delayed
beyond the guaranteed delivery date.
We will begin delivering capacity and electricity from Aquila/UtiliCorp's
unit on the commercial operation date of the unit. The commercial operation date
is defined as the date on which we have certified that the unit has successfully
completed its capacity tests. We have agreed to not declare commercial operation
of the Aquila/UtiliCorp unit prior to June 1, 2000.
Prior to the commercial operation date and every year thereafter, the
contract capacity will be established according to testing procedures contained
in the Aquila/UtiliCorp power purchase agreement. The contract capacity is the
sum of the standard capacity and the supplemental capacity. The standard
capacity is the maximum generating capacity of the Aquila/UtiliCorp unit at
summer conditions at full combustion turbine output without the use of duct
firing or steam injection. The standard capacity generally decreases with rising
temperature, so the summer condition adjustment ensures that Aquila/UtiliCorp
will only pay for capacity which will be available in the summer when it is
needed most. During cooler periods, the capacity greater than the amount of
capacity available at summer conditions is to Aquila/UtiliCorp's benefit. The
supplemental capacity is the generating capacity of the Aquila/UtiliCorp unit in
excess of the standard capacity created by the use of duct firing and steam
injection. The supplemental capacity generally does not vary widely with
temperature. The contract capacity must be measured in increments of 1 megawatt,
rounded down to the nearest megawatt. The standard capacity can be no less than
235 megawatts and no greater than 260 megawatts. The supplemental capacity can
be no less than 20 megawatts and no greater than 36 megawatts. In the event that
the contract capacity is less than 235 megawatts but greater than 210 megawatts,
Aquila/UtiliCorp's sole remedy is to reduce its reservation payment to the level
based on the tested contract capacity. In the event that the contract capacity
is less than or equal to 210 megawatts, we will have the opportunity to cure
this capacity shortfall while at the same time either supplying replacement
power to Aquila/UtiliCorp or paying Aquila/UtiliCorp's incremental costs of
replacement power purchases up to a contract capacity of 210 megawatts. In the
event that we cannot cure the shortfall within 240 days, Aquila/UtiliCorp may
declare us in default and terminate the Aquila/ UtiliCorp power purchase
agreement.
97
<PAGE>
At our option, Aquila/UtiliCorp will market and sell any test electricity.
We must provide any fuel at our expense to generate the test electricity and an
additional $0.03 per MMBtu and we must pay Aquila/UtiliCorp a marketing fee of
$0.25 per megawatt hour of test electricity sold.
Aquila/UtiliCorp may terminate the Aquila/UtiliCorp power purchase agreement
if we are unable to achieve the commercial operation date by June 1, 2001,
subject to an extension of up to 12 months to June 1, 2002 if the commercial
operation date is delayed as a result of a force majeure event or delivery
excuse and the guaranteed delivery date has occurred by June 1, 2001.
TERM
The initial term of the Aquila/UtiliCorp power purchase agreement extends to
the date 15 years and seven months after the guaranteed delivery date.
Aquila/UtiliCorp may extend the term of the Aquila/UtiliCorp power purchase
agreement for an additional 5 years, upon at least 29 months prior notice to us.
SALE AND PURCHASE OBLIGATIONS
We are obligated to sell, and Aquila/UtiliCorp is obligated to purchase, the
capacity of the Aquila/ UtiliCorp unit and associated electricity, other than
test electricity. Aquila/UtiliCorp will be required to accept any replacement
power that we deliver if we choose to deliver replacement power when the
Aquila/UtiliCorp unit is unavailable. After commercial operation of the
Aquila/UtiliCorp unit, we are not obligated to deliver power from another
source, but we may elect to provide replacement power during a forced outage or
a force majeure event or when Aquila/UtiliCorp's unit is unavailable for any
reason. Aquila/UtiliCorp must make monthly payments to us that include a
reservation payment, an energy payment, start-up payments and system upgrade
credits. Aquila/UtiliCorp's aggregate payment to us may be increased or
decreased depending on whether the Aquila/UtiliCorp unit produces electricity
above or below a specified level of fuel efficiency or "guaranteed heat rate".
RESERVATION PAYMENTS
The reservation payments begin on the guaranteed delivery date. The
reservation payments for the Aquila/UtiliCorp unit are calculated according to a
formula based on the tested capacity of the Aquila/ UtiliCorp unit and the
reservation charge as described below:
<TABLE>
<S> <C>
Reservation (contract capacity up to 267 megawatts X reservation
payment = charge) + (surplus supplemental capacity greater than 267
megawatts X surplus reservation rate)
</TABLE>
The reservation charge for the first five years after the guaranteed
delivery date is $4.90 and the reservation charge is $5.00 at any time after the
first five years after the guaranteed delivery date, including during the
extended term. The surplus reservation rate is $2.50. The contract capacity is
the sum of the standard capacity and supplemental capacity at summer conditions,
measured by a test conducted at least annually. We will have the right to retest
and reestablish the contract capacity at any time upon 48 hours notice and
Aquila/UtiliCorp will have the right to require such a retest upon five days
notice if Aquila/UtiliCorp believes that the contract capacity is overstated by
at least 10 megawatts for a period of at least 90 days.
AVAILABILITY ADJUSTMENT
The availability adjustment is meant to adjust the reservation payment
according to how reliably the unit operates. The availability adjustments are
calculated in several steps with the end result being a decrease in the
reservation payment if the unit performs poorly during a year, particularly if
the unit performs poorly during the summer. The availability adjustment occurs
monthly with an annual availability adjustment true-up.
98
<PAGE>
The first step in the calculation of the availability adjustment is keeping
track of all forced outage hours for the Aquila/UtiliCorp unit. In general, any
hour in which the unit cannot deliver power when dispatched is counted as a
forced outage hour unless the hour has been pre-agreed as an outage or unless
the hour is otherwise excused. A forced outage hour is defined as any hour in
which a unit is not fully or partially available to generate the electricity
requested by Aquila/UtiliCorp other than:
- scheduled maintenance hours;
- force majeure hours;
- excused hours;
- non-delivery due to imbalances if we are responsible for the payment of
any penalty imposed by the interconnected utility for the imbalance; or
- hours in which we elect to be responsible for replacement power, which are
described below under "--Forced Outages and Replacement Power".
For example, if a critical piece of equipment breaks, and it is not due to a
force majeure event such as a tornado, then all of the hours in which
Aquila/UtiliCorp would have dispatched the unit will be counted as forced outage
hours until the equipment is repaired or replaced, unless we elect to be
responsible for replacement power during the outage. Similarly, if a piece of
equipment breaks which causes the output of a unit to be 50% of the maximum
output of the unit, and the breakage is not due to a force majeure event and we
do not elect to be responsible for replacement power, then 50% of each hour in
which Aquila/UtiliCorp would have dispatched the unit until the equipment is
repaired or replaced will be counted as forced outage hours.
The second step in the calculation of the availability adjustment is the
determination of an availability adjustment factor for each month. The
availability adjustment factor for a month in which the number of forced outage
hours are less than 4% of the hours during which the Aquila/UtiliCorp unit would
have been available is 1.00. The availability adjustment factor for a month in
which the number of forced outage hours is greater than 4% of the hours during
which the Aquila/UtiliCorp unit would have been available decreases on a 1:1
basis for forced outage hours greater than 4%.
The monthly availability adjustment is calculated according to the formula
below:
<TABLE>
<S> <C>
Monthly availability (the sum of the unadjusted reservation payments for each
adjustment = month of the calendar year in which the monthly availability
adjustment is being computed) X the value factor for each
month shown in the table below X (1 MINUS the availability
adjustment factor)
</TABLE>
The calculation of the monthly availability adjustment takes into
consideration the relative value of the unit during the summer electricity peak
season. Having the unit available to generate electricity in the summer is more
valuable than other times of the year. We have agreed to reflect this increased
99
<PAGE>
value in the calculation of the availability adjustment by using the weighing
factor. The weighing factors for each month are as shown below:
<TABLE>
<CAPTION>
YEAR 2000 WEIGHING FACTOR
- --------- ---------------
<S> <C>
June........................................................ 14.4%
July........................................................ 26.3%
August...................................................... 24.2%
September................................................... 10.2%
October..................................................... 9.4%
November.................................................... 7.7%
December.................................................... 7.8%
</TABLE>
<TABLE>
<CAPTION>
YEAR 2001--END OF TERM WEIGHING FACTOR
- ---------------------- ---------------
<S> <C>
January..................................................... 8.3%
February.................................................... 7.1%
March....................................................... 4.5%
April....................................................... 3.9
May......................................................... 6.2%
June........................................................ 10.0%
July........................................................ 18.3%
August...................................................... 17.2%
September................................................... 7.3%
October..................................................... 6.1%
November.................................................... 5.6%
December.................................................... 5.5%
</TABLE>
The total effect of each monthly availability adjustment is to reduce a
monthly reservation payment by the relative weight of the reservation payment
during the year if the unit is unexpectedly unavailable greater than 4% of the
otherwise available hours of the month.
The annual availability adjustment true-up is calculated in the same manner
as the availability adjustment for a month, but with an allowance of 3% of the
hours during which the Aquila/UtiliCorp unit that would have been available
during such year had no forced outage occurred. If the annual availability
adjustment for any year is greater than the sum of monthly availability credits
previously determined for that year, then the difference is due to
Aquila/UtiliCorp as a credit against the reservation payments otherwise due.
The reservation payments may be adjusted as a result of any delay in
achieving commercial operation of the Aquila/UtiliCorp unit beyond the
guaranteed delivery date. If such a delay occurs, we may adjust the reservation
payments during the period after the guaranteed delivery date until the
commercial operation date. Each month during such period the delivery delay
adjustment would be calculated and subtracted from the reservation payment due
to us for such month.
<TABLE>
<S> <C>
Delivery Delay [(reservation charge) X (months in the year) X number of
Adjustment = days of delay in the month X 267 megawatts X weighing factor
for the month shown in the table above)]/number of days in
the month
</TABLE>
If the delivery delay adjustment is greater than the reservation payment due
to us for a month, any remaining amounts of such delivery delay will be used as
a credit to Aquila/UtiliCorp toward the reservation payment in future months.
100
<PAGE>
ENERGY PAYMENTS
The energy payment is equal to the product of the electricity delivered to
Aquila/UtiliCorp at the interconnection point with the Tennessee Valley
Authority or Entergy systems times a rate of $1.00 per megawatt hour multiplied
by an index based on the gross domestic product implicit price deflator index.
START PAYMENTS
If the number of starts of the Aquila/UtiliCorp unit exceeds 200 per year,
then Aquila/UtiliCorp must pay us the product of $5,000 and the number of starts
in excess of 200.
SYSTEM UPGRADE CREDITS
Under our interconnection agreements with the Tennessee Valley Authority and
Entergy, the Tennessee Valley Authority and/or Entergy could provide
Aquila/UtiliCorp with a credit or discount for transmission service due to our
payment for system upgrades on the Tennessee Valley Authority's and Entergy's
systems. Although the Tennessee Valley Authority and Entergy have agreed to pay
these credits to us directly, the Aquila/UtiliCorp power purchase agreement has
a provision for Aquila/ UtiliCorp to pay us a system upgrade credit in the
amount of any payment, credit or discount received by them under their
agreements with Entergy and the Tennessee Valley Authority, to the extent such
credit is attributable to our payment for system upgrades.
GUARANTEED HEAT RATE PAYMENTS
Aquila/UtiliCorp will pay us, or we will pay Aquila/UtiliCorp, the
difference between the cost of fuel actually consumed by the Aquila/UtiliCorp
unit while it is dispatched above minimum load and the cost of fuel that would
have been consumed based on a guaranteed fuel efficiency as described below
under "--Heat Rate Guarantee."
OPERATION AND MAINTENANCE
We must operate and maintain the Aquila/UtiliCorp unit and common facilities
in accordance with prudent industry practice and the other requirements of the
Aquila/UtiliCorp power purchase agreement, which requires us, for example, to
comply with all laws. We must inform Aquila/UtiliCorp on a daily basis of the
generating capacity of the Aquila/UtiliCorp unit and any limitations,
restrictions, deratings or outages affecting the Aquila/UtiliCorp unit for the
next day. We must provide Aquila/ UtiliCorp with ongoing access to the site and
various operational information concerning our power facility.
MAINTENANCE SCHEDULING
Each year we and Aquila/UtiliCorp will work together to develop a schedule
for the maintenance outages of the Aquila/UtiliCorp unit based upon
Aquila/UtiliCorp's projected dispatch schedule. We have agreed not to perform
any scheduled maintenance on the Aquila/UtiliCorp unit during the period from
June 15 through September 15 without Aquila/UtiliCorp's consent. The number of
hours allotted for scheduled maintenance hours of the Aquila/UtiliCorp unit is
336 hours in the years in which a combustion inspection will occur, 480 hours in
the years in which a hot gas inspection will occur and 840 hours in the years in
which a major inspection will occur. We may also reschedule up to 120 hours per
year of scheduled maintenance outages with at least two days notice.
SCHEDULING, DISPATCH AND DELIVERY
The Aquila/UtiliCorp unit will be fully dispatchable by Aquila/UtiliCorp,
and will operate on automatic generation control if directed by Aquila/UtiliCorp
or the designated control center on behalf
101
<PAGE>
of Aquila/UtiliCorp. On a daily basis, Aquila/UtiliCorp will provide us with the
projected hourly scheduled dispatch of the following day. The Aquila/UtiliCorp
unit must operate consistent with manufacturers' recommendations and design
parameters agreed upon by Aquila/UtiliCorp and us, such as a minimum
steady-state load of 70% of the standard capacity.
FORCED OUTAGES AND REPLACEMENT POWER
A forced outage is defined in the Aquila/UtiliCorp power purchase agreement
to be the inability the Aquila/UtiliCorp unit to partially or fully generate its
output as dispatched by Aquila/UtiliCorp, other than due to scheduled
maintenance, force majeure or a delivery excuse. In the event of a forced
outage, we may, at our option, avoid incurring the forced outage hours by
providing or paying for replacement power.
Whenever a forced outage of the Aquila/UtiliCorp unit occurs, the following
process is initiated. As soon as possible, and no later than 48 hours after the
beginning of the outage, we must notify Aquila/UtiliCorp of our assessment of
the situation, the expected duration of the outage, and our election regarding
replacement power during the initial portion of the outage and during the
remainder of the outage. During the initial portion of the outage, which is the
period from the beginning of the outage until midnight of the second following
day, we may elect either:
- to pay Aquila/UtiliCorp for the incremental cost of obtaining replacement
capacity and electricity in excess of the costs of capacity and
electricity under the Aquila Power Purchase Agreement; or
- to count the hours as forced outage hours in the calculation of the
availability adjustment.
Our election for the remainder of the outage may be:
- to provide replacement capacity and electricity to Aquila/UtiliCorp. In
this case, we will be paid for such replacement capacity and electricity
as if it were supplied from the Aquila/UtiliCorp unit;
- to require Aquila/UtiliCorp to secure replacement capacity and
electricity. In this case we would pay Aquila/UtiliCorp's incremental cost
of obtaining replacement capacity and electricity in excess of the cost of
capacity and electricity under the Aquila/UtiliCorp power purchase
agreement; or
- to count the outage hours as forced outage hours when calculating the
availability adjustment factor.
During the outage we will try diligently to remedy the situation. The outage
will end when the Aquila/UtiliCorp unit returns to service.
Replacement power will consist of electric generating capacity and
electricity having substantially similar characteristics to the capacity and
electricity to be supplied under the Aquila/UtiliCorp power purchase agreement.
ELECTRICAL INTERCONNECTION
We will own, operate, maintain and control all of the interconnection
facilities up to the point of interconnection of our power facility with
Entergy's and/or the Tennessee Valley Authority's systems. Aquila/UtiliCorp will
be responsible for obtaining and paying for the provision of transmission
services and any ancillary or control area services required by the Federal
Energy Regulatory Commission, Entergy, the Tennessee Valley Authority, any
independent system operator or any other transmission utility for the delivery
and transmission of electricity beyond the interconnection points between our
power facility and the Tennessee Valley Authority and Entergy systems.
Aquila/UtiliCorp is obligated to continue to make reservation payments under the
Aquila/UtiliCorp power purchase agreement whether
102
<PAGE>
or not transmission service is available for the output of the Aquila/UtiliCorp
unit. We are excused from non-performance if our power facility is disconnected
from the Tennessee Valley Authority or Entergy systems due to a Tennessee Valley
Authority or Entergy system emergency. See "--Force Majeure Events and Delivery
Excuse," "--Entergy Interconnection Agreement" and "--Tennessee Valley Authority
Interconnection Agreement."
FUEL ARRANGEMENTS
The Aquila/UtiliCorp power purchase agreement is what is referred to as a
tolling arrangement. Aquila/UtiliCorp is obligated to supply and pay for fuel
for the Aquila/UtiliCorp unit. Aquila/UtiliCorp will continue to make
reservation payments under the Aquila/UtiliCorp power purchase agreement whether
or not they are able to deliver fuel to our power facility (as long as their
inability to deliver fuel is not due to our negligence, such as if we do not
interconnect our power facility to any gas transportation pipelines).
Aquila/UtiliCorp will pay us, or we will pay Aquila/UtiliCorp, the difference
between the cost of fuel actually consumed by the Aquila/UtiliCorp unit while it
is dispatched above minimum load and the cost of fuel that would have been
consumed based on a guaranteed fuel efficiency, as described below under "--Heat
Rate Guarantee".
Aquila/UtiliCorp is obligated to arrange, procure, supply, nominate,
balance, transport and deliver to the lateral natural gas pipeline the amount of
fuel necessary for the Aquila/UtiliCorp unit to generate the net electrical
output dispatched by Aquila/UtiliCorp from the Aquila/UtiliCorp unit.
We have the right to require Aquila/UtiliCorp to provide fuel to us during
the commissioning and testing of the Aquila/UtiliCorp unit prior to the
commercial operation date.
Aquila/UtiliCorp must use all commercially reasonable efforts to cause any
fuel delivered to be in conformity with the quality requirements under the ANR
Pipeline and Tennessee Gas agreements. Aquila/UtiliCorp must pay for any costs
resulting from cleaning and clearing our power facility due to our acceptance of
fuel not conforming to such quality requirements. In addition, Aquila/UtiliCorp
will use commercially reasonable efforts to deliver gas at a specified pressure
level. As to fuel not conforming to the pressure requirements, depending upon
the degree of nonconformity, we may either declare a force majeure and not
accept the fuel due to such nonconformity or elect to accept the fuel despite
the nonconformity. If we elect to declare force majeure due to such
nonconformity, Aquila/ UtiliCorp will be relieved from its obligation to pay the
reservation payment. If any portion of the capacity of the Aquila/UtiliCorp unit
is not available as a result of the force majeure event for more than 336
consecutive hours or 505 cumulative hours in any calendar year, Aquila/UtiliCorp
will have the right to cause the installation of gas compression at our power
facility, and the costs of the installation will be shared equally by
Aquila/UtiliCorp and us. If Aquila/UtiliCorp elects not to cause the
installation of gas compression, then Aquila/UtiliCorp will be obligated to pay
us the reservation payment associated with all hours of the force majeure event
for that calendar year.
We must obtain all governmental approvals required for the ownership,
construction, operation and maintenance of the lateral natural gas pipeline, and
we must construct or cause the construction of the lateral natural gas pipeline
in a timely manner and with a capacity sufficient to deliver fuel to operate our
entire power facility at its hourly maximum output level. We must operate and
maintain the lateral natural gas pipeline and reserve transportation rights on
the lateral natural gas pipeline sufficient for the delivery of fuel to operate
our entire power facility at its hourly maximum output level. No other person
can have a right to transport fuel on the lateral natural gas pipeline superior
to Aquila/UtiliCorp except as may be required by law. We will supply
Aquila/UtiliCorp with access to the Trunkline Gas Company pipeline as long as
that access does not increase our costs or affect our schedule.
103
<PAGE>
HEAT RATE GUARANTEE
Aquila/UtiliCorp will pay us, or we will pay Aquila/UtiliCorp, the
difference between the cost of fuel actually consumed by the Aquila/UtiliCorp
unit while it is dispatched above minimum load and the cost of fuel that would
have been consumed based on a guaranteed fuel efficiency or "heat rate". Heat
rate is the common technical term in the industry to measure fuel efficiency,
and is the amount of heat input per unit output. The only significant difference
between fuel efficiency and heat rate is that the measurement units of heat rate
are inverted from what is normally thought of as fuel efficiency, so as fuel
efficiency increases, the heat rate decreases.
A tracking account will be maintained to track the difference between the
actual amount of fuel required to generate the dispatched electricity and the
amount of fuel expected to be required to generate the dispatched electricity
based on the guaranteed heat rate. The fuel used for operations below the
minimum load during start-ups and shutdowns is not considered in this
calculation. There is no heat rate guarantee below minimum load. If the actual
amount of fuel required to generate the dispatched electricity varies from the
expected amount of fuel required to generate the dispatched electricity at the
guaranteed heat rate, then a balance will accrue in the tracking account to
credit us or Aquila/UtiliCorp as appropriate. The amount added or subtracted
from the tracking account will be the actual fuel cost increase or fuel cost
savings, or the best estimate if the actual amount cannot be exactly known. If
the actual amount of fuel consumed is greater than the amount of fuel calculated
on the basis of the guaranteed heat rate, then we will pay Aquila/UtiliCorp the
actual or estimated cost for the excess fuel. If the actual amount of fuel
consumed is less than the guaranteed heat rate, then Aquila/ UtiliCorp will pay
us an amount equal to the actual or estimated cost of the fuel savings. The
guaranteed heat rate is determined by the product of a seasonal standard heat
rate (7.000 MMBtu per megawatt hour for June through September and 6.900 MMBtu
per megawatt hour for October through May) multiplied by a predetermined heat
rate adjustment factor for partial load. This heat rate adjustment factor is
always greater than 1.000 in order to account for fuel efficiency decreases at
lower load points than the optimal output. The guaranteed heat rate for the
supplemental capacity is 9.500 MMBtu/MWh.
CREDIT SUPPORT
We must provide Aquila/UtiliCorp the documentation of our debt service
coverage ratio which we provide to the collateral agent. If our debt service
coverage ratio for each of the previous four consecutive calendar quarters is
less than 1.25 to 1.00 then we must provide Aquila/UtiliCorp, upon their
request, reasonable security for our obligations. The security must be in an
amount equal to $5.00 per kilowatt of the contract capacity or approximately
$1,300,000. We must maintain this security until the earlier of the date on
which:
- we provide Aquila/UtiliCorp documentation that our debt service coverage
ratio was 1.25 to 1.00 or greater for a period of four consecutive
calendar quarters; or
- the termination of the agreement, and the full payment by us to
Aquila/UtiliCorp of all amounts that we owe Aquila/UtiliCorp.
FORCE MAJEURE EVENTS AND DELIVERY EXCUSE
Either party is excused from performing its obligations due to events which
are not in its reasonable control and which do not result from its fault or
negligence. The Aquila/UtiliCorp power purchase agreement contains several
examples of force majeure events such as floods, hurricanes, tornadoes,
sabotage, terrorism, war, riots or public disorders and emergency conditions.
The power purchase agreement identifies the following events as events which are
not force majeure events:
- causes or events resulting from ambient temperature;
104
<PAGE>
- failures or delays caused by a strike at the project, except to the extent
caused by a national strike;
- the unavailability of equipment except to the extent caused by an event
that is otherwise a force majeure event and could not have been avoided by
prudent industry practices;
- changes in market conditions that affect the price of energy or capacity;
- failure to timely apply for government approvals; and
- delivery excuse.
If a party fails to perform under the Aquila/UtiliCorp power purchase agreement
because of a force majeure event, and the non-performance continues for a period
exceeding 18 consecutive months, the other party may terminate the
Aquila/UtiliCorp power purchase agreement. If the guaranteed delivery date or
the commercial operation date is delayed for a period exceeding 12 months due to
force majeure events, Aquila/UtiliCorp may terminate the Aquila/UtiliCorp power
purchase agreement. If we are unable to deliver all or part of the actual
contract capacity of the Aquila/UtiliCorp unit due to a force majeure event
affecting us, then Aquila/UtiliCorp will not be obligated to make the payment
associated with the capacity which was not available due to that force majeure
event. A force majeure event will not affect Aquila/UtiliCorp's obligation to
pay the reservation payment for replacement power and will not affect any other
payment obligation of Aquila/UtiliCorp.
We are not liable for or in breach of the Aquila/UtiliCorp power purchase
agreement to the extent performance of our obligations is delayed or prevented
by circumstances defined in the agreement as "delivery excuse". Our failure to
deliver is excused when it is due to non-performance of Aquila/ UtiliCorp, such
as if Aquila/UtiliCorp fails to arrange for fuel to be supplied and delivered to
our power facility, or fails to arrange for transmission of electricity away
from our power facility. We are also excused from non-performance due to any
event of default of Aquila/UtiliCorp, any delay or failure by Aquila/UtiliCorp
in giving any approval within the times required, any delay or failure by
Aquila/UtiliCorp in performing any of its obligations or any emergency condition
presenting an imminent danger or significant disruption on the Entergy system or
the Tennessee Valley Authority system that results directly from an act or
failure to act by Aquila/UtiliCorp. During periods when we cannot perform our
obligations, referred to as delivery excuses, Aquila/UtiliCorp will continue to
make reservation payments to us, and the non-delivery hours will not count as
forced outage hours in the availability adjustment calculation.
DEFAULTS AND REMEDIES
The following are events of default under the Aquila/UtiliCorp power
purchase agreement:
- the failure of either party to make a payment within 30 days after notice
that payment is due;
- the failure of either party to comply with any material provision of the
Aquila/UtiliCorp power purchase agreement within 30 days after notice has
been given, or up to 90 days after notice has been given if reasonable due
diligence is being used to cure the failure;
- any bankruptcy, insolvency or similar event affecting either party which
is not cured within 60 days for voluntary events and within 90 days for
involuntary events;
- the failure of either party to comply with the assignment provisions which
is not cured within 30 days after notice;
- any representation made by either party found to be false in any material
respect which is not cured within 30 days after notice; or
- our failure to maintain a contract capacity of at least 210 megawatts for
a period of 240 days.
105
<PAGE>
Upon an event of default, the non-defaulting party may establish a date,
which will be 30 days after notice is given, on which the Aquila/UtiliCorp power
purchase agreement would be canceled if the event of default has not been cured,
withhold any payment due, and pursue any other remedies available at law or in
equity.
INDEMNIFICATION
We will indemnify and hold harmless Aquila/UtiliCorp, and Aquila/UtiliCorp
will indemnify and hold us harmless, from all claims, demands, losses,
liabilities and expenses for personal injury or death or damage to property
arising out of the indemnifying party's performance under the Aquila/UtiliCorp
power purchase agreement.
LIMITATION ON LIABILITY
Prior to the commercial operation of the Aquila/UtiliCorp unit, our
liability to Aquila/UtiliCorp is limited to paying only the incremental costs of
any replacement power through the termination date of the Aquila/UtiliCorp power
purchase agreement. After the commercial operation date of the Aquila/UtiliCorp
unit we have no obligation to supply replacement power other than as reflected
in the calculation of the availability adjustment or the termination remedies
available under the Aquila/UtiliCorp power purchase agreement.
Aquila/UtiliCorp's liability to us is limited only to the reservation payments
through the term of the agreement. The Aquila/UtiliCorp power purchase agreement
provides that, unless expressly provided otherwise in the Aquila/UtiliCorp power
purchase agreement, neither party is liable to the other for consequential,
incidental, punitive, exemplary or indirect damages, lost profits or other
business interruption damages, by statute, in tort or contract or any other
indemnity provision or otherwise.
ASSIGNMENT
Aquila Energy Marketing Corporation may assign the Aquila/UtiliCorp power
purchase agreement to any affiliate of UtiliCorp without our consent provided
that UtiliCorp remains a party to the Aquila/UtiliCorp power purchase agreement
and remains jointly and severally liable for the assignee's obligations in the
Aquila/UtiliCorp power purchase agreement.
Other than described above, neither party may assign the Aquila/UtiliCorp
power purchase agreement without the other party's prior written consent, such
consent not to be unreasonably withheld. It has been agreed that it is not
reasonable to withhold consent to an assignment to a party if the assignee has a
credit rating equal to or greater than the credit rating of the assigning party.
If the collateral agent forecloses on our interests in our power facility
based on a breach under a power purchase agreement relating to the output of any
unit other than the Aquila/UtiliCorp unit, then, so long as the Aquila/UtiliCorp
power purchase agreement is a valid and binding agreement, the foreclosing party
will be required to assume and perform our obligations under the
Aquila/UtiliCorp power purchase agreement on a prospective basis, but will not
be required to assume any outstanding liability under the agreement.
CONSTRUCTION CONTRACT
We are party to the Turnkey Engineering, Procurement and Construction
Contract dated as of July 22, 1998 with BVZ Power Partners-Batesville. BVZ Power
Partners is a joint venture between Black & Veatch Construction, Inc. and H.B.
Zachry Company. The construction contract provides for the design, engineering,
procurement, and construction of our entire power facility, other than the
electrical substation and transmission lines. BVZ Power Partners' work under the
construction contract is not complete until they have successfully tested our
power facility. We issued a notice to proceed to BVZ Power Partners commencing
BVZ Power Partners' work on August 28, 1998.
106
<PAGE>
CHANGE ORDERS
The construction contract has been amended by the notice to proceed and the
following Change Orders:
- Change Order 001 effective as of October 22, 1998,
- Change Order 002 effective November 2, 1998,
- Change Order 003 effective November 5, 1998,
- Change Order 004 effective November 5, 1998,
- Change Order 005 effective December 10, 1998,
- Change Order 006 effective February 1, 1999,
- Change Order 007 effective April 12, 1999,
- Change Order 008 effective July 2, 1999,
- Change Order 009 effective September 23, 1999,
- Change Order 010 effective October 25, 1999, and
- Change Order 011 effective October 25, 1999.
- Change Order 012 effective December 15, 1999.
- Change Order 013 effective December 15, 1999.
- Change Order 014 effective January 5, 2000.
The effect of these change orders on the construction contract are described
below.
CONSTRUCTION CONTRACT PRICE AND GUARANTEED COMPLETION DATES
The fixed price under this construction contract is $240,174,000, which
reflects a net increase of $176,000 in the contract price as a result of the
eleven change orders we have issued.
The guaranteed completion dates under the construction contract as adjusted
by the change orders are:
- July 16, 2000 for the first unit,
- July 26, 2000 for the second unit and
- July 31, 2000 for the third unit.
If BVZ Power Partners does not meet the guaranteed completion dates, it will be
liable for liquidated damages for delay as described below under "--Liquidated
Damages for Delay".
JOINT AND SEVERAL LIABILITY; SURETY
H.B. Zachry Company and Black & Veatch Construction, Inc. are jointly and
severally liable under the construction contract. Black & Veatch, LLP, the
parent of Black & Veatch Construction, Inc., has executed a guarantee agreement
dated July 22, 1998, guaranteeing all performance and payments by BVZ Power
Partners under the construction contract.
A performance bond in the amount of $239,998,300 and a payment bond in the
amount of $239,998,300 have been supplied for the construction contract by
Continental Casualty Company (whose insurer financial strength rating is Al from
Moody's Investors Services and A+ (outlook negative) from Standard & Poor's
Ratings Group) acting as surety for Black & Veatch
107
<PAGE>
Construction, Inc. and the United States Fidelity and Guaranty Company (whose
insurer financial strength rating is Al from Moody's Investors Services and AA
from Standard & Poor's Ratings Group) acting as surety for H.B. Zachry Company.
The performance and payment bonds support BVZ Power Partners' obligations
under the construction contract. If BVZ Power Partners fails to perform the
construction contract, the surety under the performance bonds will arrange for
BVZ Power Partners to complete and perform the construction contract, undertake
to perform and complete the construction contract itself, through its agents or
through independent contractors, or arrange for a third party to perform and
complete the construction contract.
If BVZ Power Partners fails to pay for labor, materials, and equipment
furnished for use in the performance of the construction contract then under the
payment bond, the surety will arrange for that payment.
BVZ POWER PARTNERS'S RESPONSIBILITIES
BVZ Power Partners is responsible for all aspects of the work under the
construction contract other than our responsibilities under the construction
contract, which are described below.
In connection with its undertakings, BVZ Power Partners acknowledges:
- the satisfactory nature, location, character and accessibility of the site
for its work;
- any existence of surface or subsurface obstacles to its work, the location
and character of existing or adjacent work or structures and other general
and local conditions which might effect its work or the performance of its
work;
- that the contract price and construction schedule are based on and reflect
the existence of these conditions;
- that BVZ Power Partners will not be entitled to a change order as a result
of the existence of these conditions.
If any pre-existing hazardous materials or archeological remains or
artifacts are discovered, BVZ Power Partners has no obligation to remove, handle
or transport those items. To the extent that these pre-existing items or their
removal delays their work, BVZ Power Partners may request a change in the
schedule and/or the contract price.
In addition, BVZ Power Partners must provide to us a list of spare parts and
expendable materials for all major machinery, equipment, materials, supplies and
other goods supplied under the construction contract.
OUR RESPONSIBILITIES
We are responsible to:
- pay for major equipment and other machinery and materials, including the
combustion turbine generators, the steam turbine generators, the heat
recovery steam generators and the transformers;
- provide the electrical, natural gas, water and other interconnection
facilities that are not within BVZ Power Partners' responsibility;
- make reasonable efforts to purchase and deliver the spare parts and
expendable materials for all major machinery, equipment, materials,
supplies and other goods supplied under the construction contract prior to
the substantial completion of the first unit; and
108
<PAGE>
- supply all of the consumable items required for commissioning, operation
and testing of our power facility. This includes all chemicals,
lubricants, fuel, water, electricity and other utilities, except excess
fuel used during testing as described below.
BVZ Power Partners must pay for any fuel consumed in excess of an allocated test
fuel quantity of 2,924,000 MMBtu. The gross revenue received by us from the sale
of energy during any acceptance test will be credited to BVZ Power Partners up
to the aggregate cost incurred by BVZ Power Partners for the test fuel in excess
of 2,924,000 MMBtu.
PAYMENT AND ACCEPTANCE OF WORK
The current contract price of $240,174,000 is the sum of BVZ Power Partners'
direct costs and our costs of approximately $160,000,000 for major equipment
which we have directly purchased or will directly purchase. The contract price
excludes any tax reimbursements to be made by us to BVZ Power Partners and could
be adjusted by change order. Payments are made to BVZ Power Partners based upon
a schedule of values for the construction of our power facility. The schedule of
values follows the construction schedule, with specific amounts due after the
completion of specific elements of our power facility. BVZ Power Partners must
submit monthly invoices detailing its progress toward meeting each element on
the construction schedule. We will pay accordingly, provided we do not reject
BVZ Power Partners' claim of completion of an item, and provided that BVZ Power
Partners does not submit an invoice which would result in over 105% of the
estimated cash flow in the schedule of values being invoiced. We have received
invoices from BVZ Power Partners totaling approximately $224,542,000 (excluding
the tax reimbursements).
As security for BVZ Power Partners' performance under the construction
contract, we will retain 5% of each monthly payment until the later of
- substantial completion of their work, including completion of the
acceptance tests or completion and
- expiration of any remedial construction plan, and the payment of any
liquidated damages. A remedial construction plan will be created if BVZ
Power Partners gives us notice that they will not complete their work by
the guaranteed completion date. During the remedial period, we will assess
liquidated damages for the delay.
At the time of completion or the expiration of any remedial construction plan,
we will pay the retained amount less an amount equal to twice the estimated cost
of punchlist items. Punchlist items are loose-ends which have not been
completed, but are not required to operate our power facility commercially in a
safe manner. An example of a punchlist item is to apply paint to a building. We
will pay BVZ Power Partners the retained amounts quarterly as the punchlist
items are completed.
We may withhold payment for any defective work not remedied and any liens or
claims that BVZ Power Partners is liable for other than:
- third party claims provided for and accepted by an insurance company;
- uninsured damages;
- default by BVZ Power Partners;
- overpayment; or
- a good faith dispute.
109
<PAGE>
TITLE TO WORK AND RISK OF LOSS
BVZ Power Partners guarantees that the legal title to its work and the
materials and equipment it provides under the construction contract will pass
free and clear of any liens, claims, security interests or other encumbrances
upon each progress payment. BVZ Power Partners will bear the risk of loss, care
and custody and control of any equipment and materials until the substantial
completion of each related unit and its common facilities.
WARRANTIES
BVZ Power Partners warrants that:
- the work and equipment will be new when installed and free from defects or
deficiencies in materials, workmanship, title or otherwise;
- each generating unit and that portion of our power facility covered by the
construction contract will be designed, engineered and constructed in
accordance with the requirements of the construction contract;
- the installation of the materials and equipment will be in substantial
accordance with the manufacturers' requirements;
- the work will be year 2000 compliant; and
- the work will be performed in accordance with all laws and capable of
operating in compliance with all laws.
Each generating unit's warranty extends one year after its substantial
completion. For the common facilities the warranty extends one year from
substantial completion of our power facility. We may extend the warranty on the
three units for an additional year for an additional $1,539,000. The warranties
do not extend to:
- defects or deficiencies resulting from ordinary wear and tear;
- failure to operate or maintain our power facility properly; or
- our negligence, unless it is a result of our reliance on information or
instructions provided by BVZ Power Partners.
LIQUIDATED DAMAGES FOR DELAYS
The current guaranteed completion dates for the three units are July 16,
2000, July 26, 2000 and July 31, 2000, subject to adjustment by change order. If
BVZ Power Partners fails to substantially complete a unit by the day following
its guaranteed completion date, then BVZ Power Partners must pay liquidated
damages to us for each 24-hour period thereafter that BVZ Power Partners does
not substantially complete that unit. The liquidated damages accrue in the
amount of $43,333 per unit per day in the months from May through September and
$33,333 per unit per day in the months from October through April.
If we cannot operate a unit by the day following the substantial completion
of a unit due to interference, damage or hindrance by BVZ Power Partners
relating to the construction and achievement of substantial completion of any
other unit or the common facilities, BVZ Power Partners must pay delay
liquidated damages during the non-operation of that unit:
- if prior to the guaranteed completion date, in an amount payable on the
guaranteed completion date equal to the liquidated damages rate less
$21,667 per unit per day from May through September and $16,667 per unit
per day from October through April and
110
<PAGE>
- if after the guaranteed completion date then at a rate of $43,333 per unit
from May through September and $33,333 from October through April.
If we cannot operate any unit or our power facility due solely to the
failure of any acceptance tests conducted after the substantial completion of a
unit or our power facility, then BVZ Power Partners must pay delay liquidated
damages for the duration of the non-operation period at a rate of $43,333 per
unit from May through September and $33,333 from October through April.
111
<PAGE>
PERFORMANCE GUARANTEES AND LIQUIDATED DAMAGES FOR PERFORMANCE
BVZ Power Partners must achieve the following performance guarantees:
<TABLE>
<CAPTION>
PERFORMANCE GUARANTEE GUARANTEED VALUE
---------------------- ---------------------------------
<S> <C> <C>
Maximum Unit Power Output
Guarantee (1).................... 285,400 kW 95 DEG.F, 60% relative humidity,
duct burner in service,
evaporative cooler in service,
power augmentation in service
Unit Power Output Guarantee
(1).............................. 248,290 kW 95 DEG.F, 60% relative humidity,
duct burner not in service,
evaporative cooler in service,
power augmentation out of service
Unit Heat Rate Guarantee (1)..... 6,769 Btu/kWh (HHV) 95 DEG.F, 60% relative humidity,
duct burner not in service,
evaporative cooler in service,
power augmentation out of service
Auxiliary Load Guarantee......... 15,300 kW 95 DEG.F, 60% relative humidity,
duct burner not in service,
evaporative cooler in service,
power augmentation out of service
Maximum Auxiliary Load
Guarantee........................ 18,900 kW 95 DEG.F, 60% relative humidity,
duct burner in service,
evaporative cooler in service,
power augmentation in service
</TABLE>
- ------------------------
(1) The Guarantee Value represents "gross" performance. To obtain "net"
auxiliary loads must be subtracted.
112
<PAGE>
BVZ Power Partners must also achieve guaranteed values for cooling tower
performance, availability, reliability, start-up, sound level, emissions, and
equipment capabilities.
As one of the requirements to achieve substantial completion of a unit, the
performance tests will have to demonstrate for that unit at least 96.25% of the
unit power output guarantee, 94.25% of the maximum unit power output guarantee
and not more than 104.25% of the unit heat rate guarantee. These three
performance levels are collectively the performance minimums.
If a unit achieves the performance minimums but not the performance
guarantees by its specified completion date, BVZ Power Partners will have an
additional 300 days from the specified completion date to achieve the
performance guarantees. If BVZ Power Partners still fails to achieve those
performance guarantees, BVZ Power Partners must pay performance liquidated
damages. The performance liquidated damages vary by acceptance test and the
level of deviation from the respective performance guarantee.
BONUSES FOR EARLY COMPLETION AND PERFORMANCE
If BVZ Power Partners substantially completes all three units prior to the
guaranteed completion date specified for the third unit then we must pay BVZ
Power Partners a bonus of $50,000 for each 24-hour period of early completion.
BVZ Power Partners is also entitled to performance bonuses for exceeding some of
the output related guaranteed values.
The aggregate bonus that BVZ Power Partners can earn for early completion
cannot exceed $3,000,000. The aggregate bonuses that BVZ Power Partners can earn
for early completion and performance bonuses, together, cannot exceed
$5,000,000.
LIMITATION ON LIABILITY
The aggregate liability of BVZ Power Partners cannot exceed:
- 5% of the contract price on account of any individual unit with respect to
delay liquidated damages;
- 15% of the contract price on account of any individual unit with respect
to delay and performance liquidated damages;
- 30% of the contract price, plus the full amount of any bonuses received by
BVZ Power Partners for our power facility with respect to delay and
performance liquidated damages.
BVZ Power Partners' aggregate liability, including all liquidated damages
for delay and performance, whether arising out of tort (including negligence),
strict liability or any other cause of action (other than the indemnification of
third parties) is limited to 100% of the contract price.
EVENTS OF DEFAULT AND TERMINATION
We may terminate the construction contract if BVZ Power Partners fails to
cure the following defaults within the applicable cure periods:
- a transfer or sale of all or substantially all of BVZ Power Partners'
assets;
- a merger by BVZ Power Partners with or into another entity;
- the institution of bankruptcy proceedings seeking to adjudicate BVZ Power
Partners bankrupt or insolvent which are not dismissed within 30 days;
- a general assignment for the benefit of creditors or the appointment of a
receiver for BVZ Power Partners due to its insolvency;
113
<PAGE>
- the institution of a voluntary bankruptcy by BVZ Power Partners or other
similar reorganization;
- the failure, neglect, refusal or inability to provide sufficient material,
equipment, services or labor to perform under the terms of the
construction contract if not diligently pursued within 15 days or cured
within 30 days of notice;
- the failure to make prompt payment of undisputed invoices due to
subcontractors within 15 days of notice;
- a disregard for or breach of any laws if not diligently pursued within
15 days or cured within 30 days of notice;
- a breach of any representation or warranty given to us if not diligently
pursued within 15 days or cured within 30 days of notice;
- a failure to correct any defective work performed under the construction
contract or within the warranty period if not diligently pursued within
15 days or cured within 30 days of notice; or
- a default of a material obligation under the construction contract if not
diligently pursued within 15 days or cured within 30 days of notice.
We may also terminate the construction contract if BVZ Power Partners fails
to substantially complete our power facility by the guaranteed completion date
and cannot thereafter present a remedial plan that reasonably demonstrates that
BVZ Power Partners can achieve substantial completion of our power facility by
300 days after the guaranteed completion date.
If we terminate the construction contract early for cause then we may employ
any other contractor to complete the work. BVZ Power Partners will be liable for
any costs above the contract price. Upon termination by us, all liquidated
damages then due must be paid by BVZ Power Partners.
In addition, we may terminate the construction contract for convenience in
whole or in part at any time. If this occurs then BVZ Power Partners must
immediately cease their work, place no further orders, attempt to cancel any
pending orders and execute only that work necessary for the preservation and
protection of the already completed work. Upon a cancellation for convenience we
are only liable to BVZ Power Partners for any unpaid aspects of their work
properly performed by BVZ Power Partners, all retained amounts and all necessary
costs of the termination.
BVZ Power Partners may terminate the construction contract if we fail to pay
undisputed amounts more than 90 days after they are due or if we fail to remedy
any non-monetary default under the construction contract within 30 days of
notice of such default.
CHANGES IN WORK
No changes to the work or adjustments to the schedule, price or other agreed
upon conditions may occur under the construction contract except in accordance
with a change order in writing describing the change and its effect, if any,
that is approved by the parties.
SUSPENSION
We may suspend the performance of all or any portion of BVZ Power Partners'
work. At any time thereafter, we may require BVZ Power Partners to resume
performance of the suspended work. If this occurs we will extend the guaranteed
completion dates and the construction schedule by a reasonable amount of time
necessary to account for the suspended period and the contract price may be
increased. Beginning 10 days after a payment is due, BVZ Power Partners may
suspend their work during any period that we fail to pay to BVZ Power Partners
any undisputed amounts.
114
<PAGE>
INDEMNIFICATION
BVZ Power Partners must indemnify us, our lenders and the independent
engineer from any third party actions, proceedings, claims, damages,
liabilities, interest, attorney's fees, costs and expenses arising from bodily
injury or property damage caused by BVZ Power Partners' or its subcontractors'
negligent act or omission or the presence, discharge, release or threatened
release of any hazardous materials brought onto the site by BVZ Power Partners
or a subcontractor.
We and BVZ Power Partners must defend and indemnify each other against all
claims made by any governmental authority claiming taxes, duties or fees that we
or BVZ Power Partners, respectively, are responsible for. These tax
indemnification obligations survive the completion of our power facility and the
expiration or termination of the construction contract. They continue for the
period of the applicable statute of limitations for the assessment and
collection of these taxes.
FORCE MAJEURE
Either party is excused from performing its obligations due to an event
which is beyond its reasonable control, such as a tornado, which are commonly
known as force majeure events. An event of force majeure under the construction
contract is defined to mean any act or event beyond the control of, and without
the fault or negligence of, the entity relying on the act or event, if it
prevents performance of an obligation by that entity, and is reasonably
unforeseeable. The contract provides examples of force majeure events such as
acts of God, landslides, lightning, earthquakes, fires or explosions, floods,
epidemic, hurricanes, tornadoes, abnormal severe storms, accidents or delays in
transportation that are a direct result of events enumerated in the contract,
acts of a public enemy, wars, blockades, riots, rebellions, sabotage,
insurrections, governmental actions or inactions or civil disturbance and
national, local or regional strikes. Regional or local strikes do not constitute
force majeure events if they involve BVZ Power Partners' or any subcontractor's
employees at the project. The following events do not constitute force majeure
events under the construction contract:
- financial inability;
- inability to obtain labor, equipment or materials unless the inability is
the result of a force majeure event;
- equipment failures due to wear and tear or defects;
- changes in market conditions that affect the costs of goods or services;
and
- the failure to timely apply for permits or approvals.
BVZ Power Partners must give us notice within 24 hours after BVZ Power
Partners has actual knowledge of a force majeure event. In this notice BVZ Power
Partners must also identify the event, the effect, the anticipated delay and
additional costs due to the force majeure event. If it is impracticable to give
such information BVZ Power Partners will provide us with supplemental notices as
is reasonably possible. Within 10 days of receipt of the notice we will alter
the construction contract to account for the increased costs of performance
and/or extension of time. If we do not accept BVZ Power Partners' force majeure
finding then the propriety of the change order must be submitted to dispute
resolution.
ASSIGNMENT
We may assign all or part of our right, title and interest in the
construction contract to any of our affiliates, our lenders or successors to the
ownership of our power facility without the prior written consent of BVZ Power
Partners. In any other case than listed in the previous sentence, prior written
consent of BVZ Power Partners is required for an assignment.
115
<PAGE>
BVZ Power Partners cannot assign any part or all of its interest in the
construction contract without our prior written consent.
ENGINEERING SERVICES AGREEMENT
We entered into a contract with Black & Veatch, LLP dated as of July 24,
1998 for the engineering services related to construction of the following
infrastructure for our power facility:
- the gas pipeline;
- the water intake system at Enid Lake;
- the water pipeline;
- the wastewater discharge line; and
- our project's substation and transmission lines.
In this capacity Black & Veatch, LLP must:
- develop the conceptual design and the turnkey bid packages for these
facilities; and
- develop the conceptual design for the interconnection of the
infrastructure provided under each of the other construction contracts for
our power facility.
We must:
- obtain all necessary permits and licenses;
- provide all of the required specifications;
- provide Black & Veatch, LLP with any soil data; and
- advise Black & Veatch, LLP of the existence of all hazardous materials and
any related disposal plans.
We must pay to Black & Veatch, LLP the sum of 2.1 times its payroll costs
plus expenses upon receipt of an invoice. We also must pay a carrying charge of
1.5% per month on all amounts unpaid 30 days following an invoice. A total of
approximately $269,000 has been paid under the terms of this agreement.
This contract will remain in effect until Black & Veatch deems that it has
fulfilled its obligations under the agreement or until the agreement is
terminated or cancelled by either us or Black & Veatch.
116
<PAGE>
COMBUSTION TURBINE PARTS BLANKET ORDER
Through a letter agreement dated July 20, 1998, we have committed to
purchase and Westinghouse Power Generation has agreed to sell combustion turbine
parts for our power facility.
SPARE PARTS
We must purchase from Westinghouse Power Generation all combustion turbine
spare parts for a combustion turbine required during the earlier of:
- the first 48,000 equivalent base load operating hours of the combustion
turbine; or
- the period ending eight years from commercial operation of the combustion
turbine.
The spare parts must be delivered within Westinghouse Power Generation's
standard lead times, but in any event must be delivered within twelve months of
the request. If we require the spare parts earlier than the standard lead times:
- Westinghouse Power Generation must attempt to expedite the delivery;
- both parties must attempt to agree on any additional charges to be paid by
us for expediting the order; and
- if Westinghouse Power Generation cannot deliver the parts quickly enough
or we and Westinghouse Power Generation cannot agree on the additional
charges, then we may purchase the spare parts from another source that can
deliver the parts substantially earlier.
PRICE
The price for the initial order of parts is $2,095,606. We will receive a
20% discount from the original agreement price adjusted for inflation for any
subsequent orders. We may elect to re-negotiate the letter agreement if the
market price of the spare parts significantly decreases.
WARRANTIES
Westinghouse Power Generation warrants that all parts will be free of
defects in workmanship and materials for the earliest of:
- 42 months from delivery;
- 12 months from installation in the combustion turbine;
- 8,000 equivalent base load operating hours after installation in the
combustion turbine; or
- 400 equivalent starts.
However, the warranty will not extend longer than one year after the
expiration of the term of the letter agreement.
EQUIVALENT BASE LOAD OPERATING HOURS AND EQUIVALENT STARTS
The timing of maintenance and parts purchases, the warranties and the term
of the letter agreement are linked to the amount of wear and tear on the
combustion turbine parts, which is measured according to equivalent base load
operating hours and equivalent starts.
Equivalent base load operating hours is a measurement of the operation time
that will result in approximately the same wear and tear as one hour of
operation at base load burning natural gas. One hour of operating on natural gas
at base load is one equivalent base load operating hour. Some operations, such
as operation burning fuel oil, will cause more than one hour of equivalent wear
and
117
<PAGE>
tear. Therefore, one hour of operation on fuel oil is counted as more than one
equivalent base load operating hour. Although our power facility will not have
the capability to burn fuel oil, we may have some operations where equivalent
base load operating hours accumulate more rapidly than for one hour of
operations.
Equivalent starts refers to the number of normal starts that would result in
approximately the same wear and tear as that caused by a normal start burning
natural gas. A normal start results when the unit is started on natural gas
according to the manufacturer's procedures. An event such as a trip off-line, an
accelerated start or a start on fuel oil are counted as more than one equivalent
start.
OPERATION AND MAINTENANCE AGREEMENT
We are party to an operation and maintenance agreement with Cogentrix
Batesville Operations dated August 24, 1998, under which Cogentrix Batesville
Operations must provide operation and maintenance services for most of our
project. Cogentrix Batesville Operations is an affiliate of ours. We believe
that the terms of the operation and maintenance agreement are commercially
reasonable. The operation and maintenance services under the operation and
maintenance agreement are divided into two phases, the pre-commencement phase
and the operational phase. The term of the agreement is for 27 years after
substantial completion of the first generating unit of our power facility.
PRE-COMMENCEMENT PHASE SERVICES
The pre-commencement phase provides for the transition of our project from
construction to completion and ends upon the substantial completion of the first
unit. Cogentrix Batesville Operations' responsibilities during this phase
include:
- staffing and hiring;
- recruiting and training the personnel to operate our project;
- developing the on-site rules, regulations and procedures;
- operating and maintaining our project (where not the obligation of BVZ
Power Partners); and
- providing a pre-commencement phase budget and monthly progress reports as
described below.
OPERATIONAL PHASE SERVICES
Cogentrix Batesville Operations responsibilities during the operational
phase include:
- performing all operation and maintenance for each unit and our project;
- arranging for the procurement of all materials and services required for
the operation and maintenance services;
- performing the daily administration and coordination of the power purchase
agreements and the electrical interconnection agreements;
- performing the daily administration and coordination of the fuel supply;
- providing all reports, data and other information required by any
agreements or permits; and
- providing an annual operating budget and an annual operating plan.
118
<PAGE>
PRE-COMMENCEMENT PHASE BUDGET
Cogentrix Batesville Operations must submit a proposed pre-commencement
phase budget that contains itemized estimates of:
- payroll, relocation and recruitment costs of employees;
- subcontractor costs;
- insurance costs;
- management fees; and
- material and service costs.
OPERATIONAL PHASE BUDGET
Prior to the operational phase of our project Cogentrix Batesville
Operations must propose an annual operating budget that contains estimates of
the items listed above under "--Pre-Commencement Phase Budget" and a proposed
inventory plan. We must approve any variation in this estimate from the agreed
upon pre-commencement phase budget or in any line item of the annual operating
budget that is the greater of 10% of that line item or $25,000.
REPORTING
Cogentrix Batesville Operations must submit the following reports:
- monthly progress reports covering all maintenance and operations for that
month, any procurements, capital improvements, labor relations and
significant interactions with power purchasers, other utilities or
governmental authorities and reimbursable costs from the budget;
- an annual operating plan that, pending our approval, describes the annual
operation;
- an annual maintenance plan for our project including hours of operation,
holidays to be observed, schedule of services, consumption of fuels,
projections of electricity sales and any other information that we may
require;
- an annual report comparing our project's operations with the annual
operating plan and annual operating budget;
- a monthly report summarizing the daily amounts of fuel delivered and
accepted at our project and consumed by each generating unit; and
- a proposed operation and maintenance plan, including scheduled outages,
major maintenance plans and a budget, for the next three years.
PAYMENT
We must pay Cogentrix Batesville Operations:
- all reimbursable costs; and
- an operating fee. The fee will be $390,000, payable in ten monthly
installments for the work performed during the pre-commencement phase. The
fee will be $500,000 per year, adjusted for inflation, payable in equal
monthly installments during the operational phase. The monthly fee is only
paid if we have sufficient funds for our debt service and reserve accounts
in accordance with the financing documents.
We must also pay some subcontractors for materials and services outside the
scope of Cogentrix Batesville Operations' obligation under the operation and
maintenance agreement. For example, the
119
<PAGE>
purchase of combustion turbine spare parts under the combustion turbine spare
parts blanket order described above is outside of the operation and maintenance
agreement.
TERMINATION
We may terminate the operation and maintenance agreement if:
- Cogentrix Batesville Operations fails to perform under the agreement in
accordance with prudent operating practices and, as a result of this
failure, an availability adjustment factor as calculated under each of the
power purchase agreements of at least 92% is not maintained for any
fifteen consecutive month period and cash distributions are prohibited
from being distributed for two consecutive quarters;
- an availability adjustment factor of 90% is not maintained for a 15
consecutive month period and during that period our senior debt service
coverage ratio is less than 1.10:1.00 for two consecutive quarters;
- damage to a substantial portion of our project that cannot be repaired
within one calendar year occurs; or
- a work stoppage occurs by Cogentrix Batesville Operations' on-site
personnel and Cogentrix Batesville Operations fails to provide replacement
workers within ten days.
Upon termination, Cogentrix Batesville Operations must:
- discontinue its services;
- make reasonable efforts to cancel or assign to us or a replacement
operator any subcontractor contracts; and
- take any other action as may be reasonably requested by us.
We must pay Cogentrix Batesville Operations any amounts due under the
contract through the time of termination and for any reasonable costs they incur
in implementing the termination.
DEFAULT
Each of the following will constitute an event of default by either us or
Cogentrix Batesville Operations under the operation and maintenance agreement:
- a material breach of the agreement for which a cure is not being
diligently pursued within 30 days and which has not been cured within
90 days of notice, unless a material breach has occurred three times in a
twelve month period, in which case no cure period will apply;
- the voluntary filing of a bankruptcy petition, liquidation or
reorganization;
- admission of insolvency or inability to pay debts;
- the filing of an involuntary bankruptcy petition, liquidation or
reorganization, for which a cure is not diligently pursued within 30 days
and which has not been cured within 90 days of notice;
- failure to maintain good standing in the relevant state of organization;
or
- assignment for the benefit of creditors.
If the default is not cured as provided in the agreement, then the
non-defaulting party may terminate the agreement, exercise any other remedy
available to it under the agreement and/or pursue another remedy under law or in
equity.
120
<PAGE>
INDEMNIFICATION/LIMITATION ON LIABILITY
Each party to the operation and maintenance agreement indemnifies, holds
harmless and defends the other against all liabilities, claims, demands, suits,
legal proceedings, judgments, awards, losses, damages, costs or expenses
(including reasonable legal fees and expenses) for bodily injuries, death or
tangible property damage of third parties caused by any negligent act or
omission, willful misconduct or strict liability of the indemnifying party or of
anyone acting under that party's direction and control, including
subcontractors. With the exception of indemnities to third parties, neither
parties' liability can exceed the pre-commencement phase fee if the liability
accrues during the pre-commencement phase or the management fee for the year in
which the liability accrues if the liability accrues during the operational
phase.
HAZARDOUS MATERIALS
We must indemnify, hold harmless and defend Cogentrix Batesville Operations
against all liability and costs incurred under environmental laws based on or
related to preexisting hazardous materials at the project site. Cogentrix
Batesville Operations must indemnify, hold harmless and defend us against all
liability and costs with respect to hazardous materials introduced on the
project site because of the services provided by them in violation of applicable
law. Cogentrix Batesville Operations must arrange for the proper collection,
removal and disposal of any hazardous materials furnished, used, applied,
generated or stored at the project site. All costs associated with the
transporting and disposing of the hazardous materials to or from the project
site are considered reimbursable costs.
ASSIGNMENT
Cogentrix Batesville Operations cannot assign the operation and maintenance
agreement without our prior written consent, except for the assignment to:
- a successor as the result of a merger, consolidation or reorganization;
- a purchaser of Cogentrix Batesville Operations that is experienced in the
operation and maintenance of facilities like ours; or
- an affiliate of Cogentrix Batesville Operations, as long as this transfer
does not release Cogentrix Batesville Operations of its obligations.
MANAGEMENT SERVICES AGREEMENT
We are party to a management services agreement with LS Power Management
dated August 24, 1998 to provide for management and administrative services for
our project. LS Power Management is an affiliate of ours. We believe that the
terms of the management services agreement are commercially reasonable. The
agreement commences upon the notice to proceed under the construction contract
and ends 27 years after substantial completion of the first generating unit of
our power facility.
In providing the management and administrative services, LS Power Management
must:
- handle all financial matters;
- perform all accounting tasks necessary to maintain accurate financial
records of the business and prepare and file all necessary tax returns in
cooperation with an independent public accounting firm;
- prepare and submit all filings required under any laws, regulations or
ordinances and procure and maintain all governmental approvals required;
- engage and supervise any independent contractors;
121
<PAGE>
- purchase any materials, supplies and equipment required;
- procure and maintain all insurance required; and
- supervise and monitor all of our contracts pertaining to the construction
and operation of our project.
PAYMENTS
We must pay LS Power Management:
- reasonable and necessary expenses incurred in its performance under this
contract, including the portion of employee salaries, other than executive
officer salaries, attributable to the management of our project. LS Power
Management must submit a yearly budget to us for our approval detailing
these expenses. For the year ended December 31, 1999 and for the year
ended December 31, 1998, LS Power Management billed us approximately
$1,043,000 and $368,000, respectively. We must approve any variation in
that budget; and
- a fee. The fee will be $400,000 per year, adjusted for inflation, payable
in equal monthly installments.
TERMINATION
A material breach of the management services agreement or failure to cure a
non-monetary breach within 30 days of notice constitutes grounds for termination
of the agreement by the non-defaulting party. However, our failure to pay a
disputed amount is not grounds for termination. LS Power Management may
terminate the agreement after the first 10 years of service under the agreement.
We may terminate the agreement if LS Power Management and its affiliates'
ownership interest in us equals or falls below 10%, although we must pay LS
Power Management's fee for 12 months after the termination.
INDEMNIFICATION
LS Power Management must indemnify us and our affiliates and any party
providing us senior debt financing from any claim, suit or judgment and costs
and expenses that arise because of any act or omission on LS Power Management's
part, up to a limit of $500,000. We must indemnify LS Power Management and its
affiliates from any claim, suit or judgment and costs and expenses that arise
because of any act or omission on our part or on the part of anyone, including
LS Power Management, acting on our behalf, up to a limit of $500,000. However,
our indemnity excludes any act or omission caused by a breach of the management
services agreement or by any gross negligence or willful misconduct on the part
of LS Power Management.
DISPUTE RESOLUTION
Any dispute involving matters of accounting treatment must be resolved
through the binding resolution of a three member accounting panel consisting of
an accountant appointed by each party and a third party accountant. Any other
claims must first be mediated by a senior manager of each party. Failing that,
either party may seek legal remedies or arbitration.
122
<PAGE>
ENTERGY INTERCONNECTION AND OPERATING AGREEMENT
We are a party to an interconnection and operating agreement with Entergy,
dated May 18, 1998, as amended as of August 18, 1998, which allows us to
interconnect our power facility to Entergy's transmission system.
TERM OF AGREEMENT
The term of this agreement is 35 years, commencing on the date our power
facility is interconnected to Entergy's transmission system. The agreement
automatically renews for succeeding five-year terms unless either party gives
three years written notice prior to the date of termination.
OUR INTERCONNECTION FACILITIES
We must design, construct, operate and maintain our interconnection
facilities. Our interconnection facilities include all electric metering,
protection and other facilities which are located on our side of the
interconnection point. The interconnection point is located at Entergy's
existing substation. The design specifications and requirements for our
interconnection facilities must be reviewed and approved by Entergy.
ENTERGY'S INTERCONNECTION FACILITIES
Entergy must design, construct, install, own, operate and maintain its
interconnection facilities and system upgrades. Entergy's interconnection
facilities will include all the necessary equipment required to interconnect
Entergy's system with our interconnection facilities. We will reimburse Entergy
for all reasonable costs associated with performing this work. The cost for the
reimbursable interconnection facilities work is estimated to be approximately
$1,100,000. Entergy has established its interconnection to our power facility
substation and has completed final testing of its interconnection.
Both parties have constructed their respective interconnection facilities to
comply with the Entergy interconnection agreement and in response to the
changing requirements of Entergy's systems. Both parties will makes changes to
their facilities at our expense, unless the facilities are determined to be
Entergy's interconnection facilities, in which case Entergy will install, own
and maintain the facilities, but at our expense. In addition, both parties will
install, own and maintain metering equipment. We are responsible for all costs
of administration, initial installation and changes associated with metering.
TRANSMISSION SERVICE NOT INCLUDED
The Entergy interconnection agreement does not cover transmission service.
Under our power purchase agreements with Virginia Power and Aquila/UtiliCorp,
the power purchasers are responsible for arranging the transmission services
necessary for delivery from the interconnection point into and across Entergy's
system. To the extent energy produced by our power facility is transmitted over
Entergy's transmission system, the transmission service will be purchased at the
rates established by Entergy's tariff.
COST OF UPGRADED FACILITIES AND SYSTEM UPGRADE CREDITS
System upgrades include all upgrades or improvements made to Entergy's
existing transmission system in order to interconnect and deliver energy from
our power facility to Entergy's system. We will reimburse Entergy for all
reasonable costs associated with performing this work. The cost of the upgrade
work is estimated to be approximately $7,100,000. Entergy expects to complete
its system upgrade work by December 1999. Entergy will credit us directly or
through our power purchasers with a system upgrade credit equal to the charges
we or our power purchasers pay for the transmission
123
<PAGE>
service under Entergy's tariff used to deliver power form our power facility.
The Entergy system upgrade credit will not exceed the cost of the Entergy system
upgrades paid for by us.
CONTROL AND OPERATION
We must operate our power facility to meet the voltage schedules designated
by Entergy's operation personnel, which must be within the normal operating
range of our power facility and consistent with the voltage schedules provided
by the Tennessee Valley Authority. Consistent with Entergy's current effective
transmission tariff, an appropriate adjustment to the charge for reactive supply
and voltage control will be made to reflect the contribution of reactive supply
and voltage support made by our power facility.
RESPONSIBILITY FOR SYSTEM PROTECTION
We must install and maintain, at our own expense, adequate equipment
required to protect Entergy's system and its customers from faults occurring at
our power facility and to protect our interconnection facilities and our power
facility from faults occurring on the Entergy system or other systems. At our
own expense, we will maintain operating communications with Entergy's system
dispatcher and will install a remote terminal unit to gather and transmit data
from our meters to a location designated by Entergy.
DISCONNECTION OR CURTAILMENT OF OUR POWER FACILITY
Entergy has the right to disconnect our interconnection facilities without
notice if in Entergy's reasonable opinion a hazardous condition exists and
immediate disconnection is necessary to protect persons, Entergy's facilities or
other customer facilities from damage. Entergy will:
- use reasonable care and cooperate reasonably with us to avoid and minimize
interruptions in the acceptance of capacity and energy from our power
facility,
- keep us fully informed as to the anticipated duration of each
interruption, and
- restore connection and resume acceptance of capacity and energy from us as
soon as practicable.
Entergy has the right to curtail deliveries of energy from us or disconnect
our interconnection facilities:
- for our failure to comply with the material provisions of the Entergy
interconnection agreement;
- to overcome system reliability problems;
- to facilitate restoration of line or equipment outages; or
- for any reason otherwise permitted by applicable rules or regulations.
Entergy will use reasonable care to avoid and minimize curtailments or
disconnections and to coordinate any curtailments or disconnections with
scheduled outages or maintenance of our power facility. Any interruption,
curtailment or disconnection of our interconnection facilities will be done in
accordance with good utility practice, will not be inconsistent with the open
access transmission policies of the Federal Energy Regulatory Commission and
will be limited to the extent necessary to effectively relieve the condition
causing the interruption, curtailment or disconnection. Entergy will keep us
fully informed as to the anticipated duration of each curtailment or
disconnection, and will resume acceptance of deliveries of capacity and energy
from us as soon as practicable.
Entergy has the right to file rate schedules with the Federal Energy
Regulatory Commission concerning any services Entergy deems necessary for
reliable and orderly bulk power supply system
124
<PAGE>
management, including, but not limited to, any standby or related services that
may arise from our failure to meet our schedule of deliveries across facilities
covered by the interconnection agreement.
PAYMENTS
We will reimburse Entergy for all actual costs reasonably incurred and
properly documented by Entergy with respect to the design, construction and
installation of Entergy's interconnection facilities, system upgrades and all
related equipment. If we fail to make our monthly payments, Entergy has the
right to suspend its performance of work or other obligations under the
interconnection agreement until such time as any overdue amounts have been paid
in full. Entergy has submitted invoices for reimbursement for a total of
$6,286,000.
FORCE MAJEURE
Entergy will not be responsible for any non-performance under the
interconnection agreement to the extent due to a cause beyond Entergy's control,
whether occurring on Entergy's electric system or any connecting electric
system, as long as Entergy attempts in good faith and with reasonable diligence
to alleviate such situation.
We will not be responsible, to the extent due to a cause beyond our control,
if we are unable to perform an obligation imposed on us by the interconnection
agreement, except for the obligation to make payments of money, as long as we
attempt in good faith and with reasonable diligence to alleviate the situation.
INDEMNITY
We will indemnify and hold harmless Entergy from and against any and all
losses and expenses arising from our power facility or our interconnection
facilities. The indemnity will not apply if the injury or damage is due to the
sole negligence or willful misconduct of Entergy.
ASSIGNMENT
With the exception of specific circumstances outlined below, the Entergy
interconnection agreement cannot be assigned by us or Entergy without the
written consent of the other party, which consent cannot be unreasonably
withheld. Each party may assign the interconnection agreement without consent in
the case of the sale or merger of a substantial portion of its properties. We
may assign the interconnection agreement to our lenders for a financing of our
power facility without Entergy's consent.
TENNESSEE VALLEY AUTHORITY INTERCONNECTION AGREEMENT
We are party to an interconnection agreement with the Tennessee Valley
Authority dated as of July 22, 1998 which allows us to interconnect our power
facility to the Tennessee Valley Authority's transmission system.
TERM OF AGREEMENT AND AMENDMENTS
The primary term of the Tennessee Valley Authority interconnection agreement
is approximately 35 years. Any time after the fifth year, the Tennessee Valley
Authority may request that we amend the agreement in order to make the agreement
consistent with the Tennessee Valley Authority's then current standard
interconnection agreement with other generating facilities similar to our power
facility. If, despite good faith negotiation, we and the Tennessee Valley
Authority fail to reach agreement on the proposed amendments within six months,
the Tennessee Valley Authority may terminate the agreement upon giving us one
years' prior notice.
125
<PAGE>
OUR INTERCONNECTION FACILITIES
We must:
- install, operate and maintain our interconnection facilities, which
consist of the equipment on our side of the interconnection point which
interconnects our power facility to the Tennessee Valley Authority's
interconnection facilities;
- provide battery and station service power for some of the Tennessee Valley
Authority interconnection facilities;
- make available to the Tennessee Valley Authority a portion of our
switchhouse to be maintained and used by the Tennessee Valley Authority;
and
- provide the technical specifications and design drawings for the Tennessee
Valley Authority system protection facilities to the Tennessee Valley
Authority for review, inspection and approval.
We are responsible for the cost of any future changes to our interconnection
facilities due to changes in the Tennessee Valley Authority system conditions
and requirements or any changes made at our discretion.
Our interconnection facilities are currently interconnected to and are
delivering power from the Tennessee Valley Authority interconnection facilities.
TENNESSEE VALLEY AUTHORITY INTERCONNECTION FACILITIES
The Tennessee Valley Authority must install at our expense and thereafter
own, operate and maintain the Tennessee Valley Authority interconnection
facilities. The Tennessee Valley Authority has estimated the cost of their
interconnection facilities to be $4 million. The Tennessee Valley Authority
interconnection facilities include the communication facilities and other
equipment located on the Tennessee Valley Authority's side of the
interconnection point necessary to accept electrical energy from our power
facility. The interconnection point is located at a Tennessee Valley Authority
substation existing in Batesville, Mississippi.
We will be responsible for the cost of any changes to the Tennessee Valley
Authority's interconnection facilities that are required due to changes in the
Tennessee Valley Authority's system conditions and requirements or due to our
request.
The Tennessee Valley Authority has completed its interconnection to our
power facility substation and is providing permanent facility backfeed.
TRANSMISSION SERVICE NOT INCLUDED
The Tennessee Valley Authority interconnection agreement does not cover
transmission service. Under our power purchase agreements with Virginia Power
and Aquila/Utilicorp, the power purchasers are responsible for arranging
transmission services across the Tennessee Valley Authority's system for the
term of the power purchase agreements. To the extent energy produced by our
power facility is transmitted over the Tennessee Valley Authority's transmission
system, the transmission service will be purchased at the rates established by
the Tennessee Valley Authority's tariff.
COST OF UPGRADED FACILITIES AND SYSTEM UPGRADE CREDITS
The Tennessee Valley Authority will need to upgrade some of its facilities
in conjunction with the establishment of the point of interconnection. We will
be responsible for all actual costs incurred by the Tennessee Valley Authority
for the design, construction and installation of the upgraded facilities. The
Tennessee Valley Authority has estimated the cost of their system upgrades to be
$9.5 million. When changes to the upgraded facilities become necessary to ensure
the protection and continued safe and
126
<PAGE>
reliable operation of the Tennessee Valley Authority's system, or when we
request them, the Tennessee Valley Authority will make the changes at our
expense.
The Tennessee Valley Authority will credit us with a system upgrade credit
equal to the charges for the transmission service used to deliver power from our
power facility. A credit will continue to be paid by the Tennessee Valley
Authority until credits have been paid equal to the cost of the Tennessee Valley
Authority system upgrades paid for by us.
The Tennessee Valley Authority expects to complete its system upgrades by
April 1, 2000. The Tennessee Valley Authority has indicated that prior to
completion of its system upgrades, its system is capable of accepting up to
approximately 600 megawatts of total generation. We do not expect that this
limitation will have any impact on BVZ Power Partners' schedule for
commissioning of the generating units.
CONTROL AND OPERATION
The Tennessee Valley Authority must submit to us a written voltage schedule
consistent with the voltage schedules provided by Entergy. We must comply with
the schedule and install, operate and maintain the equipment needed for
compliance. If energy produced by our power facility is transmitted across the
Tennessee Valley Authority system, an appropriate adjustment to the charge for
reactive supply and voltage control will be made to reflect the contribution to
reactive supply and voltage support made by our power facility.
Each day we must inform the Tennessee Valley Authority of the forecasted
hourly generation levels of our power facility for the following day, including
any anticipated outages. We must ensure that there are a sufficient number of
qualified personnel for operating and monitoring our power facility and for
coordinating operations of our power facility with the Tennessee Valley
Authority's system.
DISCONNECTION OR CURTAILMENT OF OUR POWER FACILITY
Subject to good utility practice, the Tennessee Valley Authority may require
us to disconnect our power facility from the Tennessee Valley Authority system
or to interrupt, suspend or curtail deliveries from our power facility in the
following circumstances:
- if, in the Tennessee Valley Authority's sole opinion, a condition exists
which presents a physical threat to persons or property such that
disconnection appears necessary;
- to overcome system reliability problems caused by an emergency or an
outage of Tennessee Valley Authority equipment or generation facilities;
- if necessary to construct, install, maintain, inspect or test any part of
the interconnection facilities or any other affected part of the Tennessee
Valley Authority system; or
- to facilitate restoration of line or equipment outages.
The Tennessee Valley Authority will restore connection and resume
performance of its obligations under the interconnection agreement, as soon as
practicable.
ENERGY SCHEDULE
We must make every attempt to ensure that during each hour the amount of
power provided is equal to or greater than the schedule of energy delivered by
the Tennessee Valley Authority to third parties. In the event a difference
occurs between the scheduled amount and the power provided, we will be required
to pay the appropriate compensation applied to the difference, consistent with
similar power production facilities, under comparable circumstances, located in
the Tennessee Valley Authority control area.
127
<PAGE>
DEFAULT
The Tennessee Valley Authority has the right to terminate the
interconnection agreement upon defaults by us which include:
- bankruptcy or insolvency which is not cured within 60 days of notice, with
longer notice periods for involuntary bankruptcy or other proceedings;
- delinquency in payments which is not cured within 30 days of notice;
- refusal to comply with any material provision of the interconnection
agreement regarding the balancing on an hourly basis of electrical output
from our power facility and scheduling of energy to third parties which is
not cured within 60 days of notice; or
- failure to comply with any other material provision of the interconnection
agreement which is not cured within 60 days of notice.
When the interconnection agreement is terminated, other than as a result of
the Tennessee Valley Authority's breach, we must pay the Tennessee Valley
Authority for the cost of retiring its interconnection facilities. The Tennessee
Valley Authority must abandon any land rights to property owned or controlled by
us from which the Tennessee Valley Authority interconnection facilities are
removed and for which the Tennessee Valley Authority no longer has any need.
PAYMENTS
We are responsible for and must reimburse the Tennessee Valley Authority for
all actual costs reasonably incurred and properly documented by the Tennessee
Valley Authority with respect to the design, construction and installation of
the Tennessee Valley Authority interconnection facilities, upgraded facilities
and all related equipment. TVA has submitted invoices for reimbursement for a
total of $12,556,000.
FORCE MAJEURE
Neither party can be held responsible or liable for any non-performance of
their respective obligations under the interconnection agreement to the extent
due to a force beyond the non-performing party's reasonable control, as long as
the non-performing party uses its best efforts to remedy its inability to
perform.
INDEMNITY
We must indemnify and hold harmless the Tennessee Valley Authority from and
against all losses or expenses arising from our power facility or our
interconnection facilities. The indemnity will not apply if the injury or damage
is caused by the sole negligence or willful misconduct of the Tennessee Valley
Authority.
ASSIGNMENT
Neither party may assign the interconnection agreement without the written
consent of the other party, which consent cannot be unreasonably withheld. No
consent is required for:
- assignments to an affiliate of the assignor, where the assignee has
assumed all of the obligations of the assignor, provided that the assignee
has demonstrated financial capacity at least equal to that of the
assignor;
- assignments due to the sale or merger of a substantial portion of a
party's properties, including its interconnection facilities; or
- our assignment of the agreement to our lenders.
128
<PAGE>
ANR GAS PIPELINE INTERCONNECTION AGREEMENT
We entered into an interconnection agreement with ANR Pipeline Company dated
July 29, 1998 to establish an interconnection in Sardis, Mississippi between the
ANR Pipeline interstate natural gas pipeline system and our lateral natural gas
pipeline.
DESIGN, ENGINEERING AND CONSTRUCTION
Under the ANR Pipeline interconnection agreement, we are responsible for the
design, engineering and construction of our interconnection facilities. In
addition, we are responsible for the design and installation of a pressure
control device to protect and isolate any pipeline facilities of third parties
located downstream from our interconnection facilities. Each party must design,
engineer and construct its portion of the interconnection. Each party will own
title to its interconnection facilities and is responsible for insuring those
interests. These interconnection facilities will be constructed and installed on
land owned by ANR Pipeline at ANR Pipeline's Sardis Compressor Station.
Prior to construction of the interconnection facilities, each party must
submit to the other party for review and approval drawings, specifications and
construction procedures for the interconnection facilities. The ANR Pipeline
interconnection facilities have been completed, tested and are ready to be
placed into service.
OWNERSHIP, COSTS AND EXPENSES
We will be required to fully reimburse ANR Pipeline for all reasonable
costs, up to $250,000, incurred by ANR Pipeline with respect to the design,
engineering, construction, testing and placing in service of the ANR Pipeline
interconnection facilities. We may also be required to reimburse ANR Pipeline
for, and indemnify and hold ANR Pipeline harmless against, any incremental
federal taxes that will be due by ANR Pipeline if the costs of the ANR Pipeline
interconnection facilities are deemed to be a contribution in aid of
construction under the Internal Revenue Code. ANR Pipeline must use commercially
reasonable efforts to minimize these costs.
OPERATION AND MAINTENANCE
Each party is generally responsible for the operation, maintenance, repair
and replacement of its portion of the interconnection facilities, and for all
associated cost, expense and risk. However, ANR Pipeline will:
- operate and perform minor maintenance within the capability of ANR
Pipeline's field technicians on the gas measurement equipment;
- operate, but not maintain, that portion of our interconnection facilities
located on ANR Pipeline-owned land at the Sardis Compressor Station; and
- in the case of an emergency involving our interconnection facilities, take
steps and incur expense as ANR Pipeline determines are necessary to abate
the emergency and to safeguard life and property. We will reimburse ANR
Pipeline for all costs and expenses reasonably incurred by ANR Pipeline
with respect to emergencies.
All gas delivered by ANR Pipeline to us at the interconnection facilities
will conform to the specifications set forth in the General Terms and Conditions
of ANR Pipeline's Federal Energy Regulatory Commission Gas Tariff, Second
Revised Volume 1 or any successor to this tariff. The gas will be delivered at
ANR Pipeline's prevailing line pressure. We and ANR Pipeline will each make
reasonable efforts to control our and its respective prevailing line pressure to
permit gas to enter our lateral pipeline.
129
<PAGE>
Custody of the gas will transfer from ANR Pipeline to us or our power
purchasers after it passes through the custody transfer point. The custody
transfer point is located where the ANR Pipeline interconnection facilities and
our interconnection facilities are connected. The actual quantity of gas
delivered by ANR Pipeline to us will be determined using the recorded meter
information at this custody transfer point.
PERMITS
We and ANR Pipeline are responsible for securing and paying for all
approvals, permits, certificates and authorizations required for the
construction and operation of our individual portions of the interconnection
facilities.
EASEMENT
ANR Pipeline will grant us, on a fee-free basis, an easement for the parcels
of land required for our interconnection facilities.
TERM AND TERMINATION
The ANR Pipeline interconnection agreement will remain in full force and
effect until it is terminated by the mutual agreement of both parties or our
final removal and/or abandonment of our interconnection facilities. Upon notice,
either party may terminate the interconnection agreement if the other party has
materially breached its obligations.
LIABILITY AND INDEMNIFICATION
Each party will indemnify the other party for losses, claims, liens,
expenses and damages arising out of its performance or failure to perform its
obligations under the interconnection agreement.
130
<PAGE>
ASSIGNMENT
Neither party may assign the interconnection agreement without the written
consent of the other party, which consent may not be unreasonably withheld,
except that each party has the right to assign the agreement, without consent:
- to a financially responsible affiliate with an equal or higher credit
rating;
- for reason of its financing; or
- in our case, to a public or governmental entity for the financing of our
power facility's infrastructure.
FORCE MAJEURE EVENT
Neither party will be responsible or liable for any non-performance of its
obligations under the interconnection agreement to the extent caused by an event
of force majeure, so long as the non-performing party attempts in good faith and
with reasonable diligence to remedy its inability to perform.
TENNESSEE GAS FACILITIES AGREEMENT
We have entered into to a facilities agreement with Tennessee Gas dated
June 23, 1998 to establish the tap facilities and connecting facilities for the
interconnection between the Tennessee Gas natural gas pipeline system and our
lateral natural gas pipeline.
TAP FACILITIES
The Tennessee Gas tap facilities are those components (i.e., valves, pipe)
which interconnect the existing Tennessee Gas natural gas pipeline with the
Tennessee Gas connecting facilities.
Tennessee Gas or its designee must design, install, construct, inspect and
test the tap facilities. Tennessee Gas must apply for and obtain any applicable
permits or approvals required for the construction, operation and maintenance of
the tap facilities. Tennessee Gas will own the tap facilities. Construction of
the tap facilities is complete.
Tennessee Gas must operate, repair, replace and maintain the tap facilities
at its own cost and expense. We must provide support for any regulatory
authorization or permitting requirements necessary for the tap facilities.
Tennessee Gas must ensure its work under the facilities agreement is in
accordance with Tennessee Gas' design specifications, sound and prudent natural
gas industry practice and applicable laws.
CONNECTING FACILITIES
We must:
- design, install, construct and test the connecting facilities;
- submit drawings, required permits and documentation to Tennessee Gas for
approval to verify compliance with applicable specifications;
- make changes and modifications required to comply with Tennessee Gas
specifications;
- reimburse Tennessee Gas for the costs associated with inspections
requested by us and with installation of the connecting facilities;
- provide support for any regulatory authorization or permitting
requirements necessary for any required Tennessee Gas connecting
facilities;
131
<PAGE>
- acquire all necessary rights-of-way and permits for the connecting
facilities and for the site upon which the connecting facilities will be
located;
- provide pressure regulation and over-pressure protection for our
facilities downstream of the connecting facilities;
- inject odorant, if any, at levels required by regulatory authorities; and
- operate and maintain the connecting facilities at our own cost and
expense.
Tennessee Gas is responsible for the operation of the measurement
facilities.
We must ensure that our work under the facilities agreement is in accordance
with Tennessee Gas' design specifications, sound and prudent natural gas
industry practice and applicable laws.
ACCESS
Tennessee Gas has the right of access to the connecting facilities installed
by us to install tap facilities and to inspect, test and witness our testing of
the connecting facilities. Tennessee Gas also has the right to inspect the
connecting facilities at all reasonable times to ensure that the facilities are
installed, operated and maintained correctly.
PAYMENT
We must pay Tennessee Gas for all costs they incur for the design,
installation, inspection and testing of the tap facilities, inspection of the
connecting facilities and any expenses incurred by Tennessee Gas for the
installation of the connecting facilities. Tennessee Gas has notified us that
the total cost may exceed the estimated cost of $231,000 by more than 20%.
Tennessee Gas has submitted invoices for a total of $231,000.
TERM AND TERMINATION
The term of the Tennessee Gas facilities agreement is from April 15, 1998
until the final removal and/or abandonment of any tap facilities and connecting
facilities, unless sooner terminated by us or by Tennessee Gas:
- as a result of our failure to make timely payments;
- if gas has not flowed through the connecting facilities for a period of 12
consecutive months; or
- in the event we have or our designee has caused the connecting facilities
to be disconnected or removed.
Tennessee Gas cannot cause the final removal and/or abandonment of any tap
facilities and connecting facilities without approval of the Federal Energy
Regulatory Commission.
LIABILITY AND INDEMNIFICATION
Each party agrees to protect, defend, indemnify and hold harmless the other
party from losses, claims, liens, demands and causes of action arising out of
its negligence, gross negligence or willful misconduct solely related to
activities performed under the Tennessee Gas facilities agreement.
LIENS
Each party must notify the other of any lien encumbering the property of the
other party on which interconnection related work is located. The other party
can require a bond to indemnify it from the lien.
132
<PAGE>
ASSIGNMENT
Neither party may assign the facilities agreement without the written
consent of the other party, except that either party may assign to any
subsidiary or affiliated company the performance and exercise of its obligations
or rights as long as the assignee performs its obligations. We may assign the
agreement to a public government entity without Tennessee Gas' consent.
FORCE MAJEURE
Neither party is liable in damages for acts, omissions or circumstances as a
result of force majeure, so long as suspension of performance is no longer than
the duration of the force majeure.
WATER SUPPLY STORAGE AGREEMENT
The water supply storage agreement with the United States of America
represented by the District Engineer of the Vicksburg District of the United
States Army Corps of Engineers, dated June 8, 1998, and amended March 15, 1999,
provides for storage in Enid Lake of our industrial water supply. Enid Lake is
approximately 15 miles south of our power facility site. The United States Army
Corps of Engineers constructed and now operates the lake to control flooding in
the region.
TERM
The water supply storage agreement continues for the life of the Federal
government's Enid Lake project. In the event the Federal government no longer
operates Enid Lake, our rights associated with storage may continue if we
execute a separate agreement or additional supplemental agreement with the new
operator.
OUR RIGHTS
We have an undivided 7.8% of the storage capacity in Enid Lake between the
elevations of 205.0 and 230.0 feet. This is estimated to contain 4,500 acre-feet
after adjustments for sediment deposits. We may withdraw water from Enid Lake to
the extent that our storage space allows and we may construct any required
works, plants and pipelines necessary for diverting or withdrawing the water.
The Federal government must reserve 4,500 acre-feet of storage for us for up to
24 months while we design and construct our water intake storage structure. If
we cannot complete construction within that time, we may terminate the water
supply storage agreement.
RIGHTS OF THE FEDERAL GOVERNMENT
The Federal government reserves the right to control and use all of the
allocated storage in Enid Lake in order to control flooding in the area. The
Federal government further reserves the right to take any necessary measures in
its operation of Enid Lake to preserve life and any property, including the
right not to make downstream releases as the Federal government deems necessary.
The Federal government makes no representations to us with respect to the
quality or availability of the water and assumes no responsibility for the
treatment of the water. Nothing in the water supply storage agreement affects or
diminishes the Federal government's statutory or sovereign powers with respect
to the operation and maintenance of Enid Lake.
SEDIMENTATION SURVEYS
The District Engineer will make sedimentation surveys during the term of the
water supply storage agreement at intervals not to exceed 15 years unless the
District Engineer determines that these surveys are unnecessary. If the District
Engineer determines that Enid Lake has been affected by unanticipated
sedimentation distribution then it will redistribute the sediment reserve
storage space among all of the
133
<PAGE>
parties utilizing and served by Enid Lake, including our storage space. The
total available storage space will be reallocated maintaining each party's
proportionate share of Enid Lake.
USE OF WATER AND METERING
We are solely responsible for the regulation of our water use. We must
install metering devices to measure the amount of water withdrawn from Enid Lake
and give monthly statements of our withdrawals to the Federal government. We
must acquire any water rights required by state law or regulation for
utilization of the storage. Prior to construction, the District Engineer must
approve the design, location and installation of any facility built to withdraw
water from the storage space.
PAYMENTS
For the period of up to 24 months that we use the Federal government
reserved 4,500 acre-feet of storage while our water intake structure is designed
and constructed, we must pay to the Federal government $1.00 per acre-foot per
year for the use of the Federal government reserved 4,500 acre-feet storage
($4,500 yearly).
We must pay to the Federal government an amount equal to the cost allocated
to the water storage rights acquired by us, which is 7.8% of the water storage
rights at Enid Lake. Our cost is estimated to be $1,111,898, but may be adjusted
in the year in which the initial payment is made. This cost is payable over the
life of the Enid Lake flood control project, but not to exceed 30 years from the
due date of the first annual payment. The first payment must be made the earlier
of 30 days after our initial use of the storage or within 24 months after
notification by the District Engineer that the water supply storage agreement is
effective.
The unpaid balance of our storage cost will accrue interest at a rate
determined under Section 932 of the 1986 Water Resources Development Act. In
1998, the rate was 6.75%. At this interest rate our combined yearly principal
and interest payments would total $81,800, with the first payment to be applied
solely against the principal. The interest rate will be adjusted prior to the
first payment to reflect the appropriate interest rate. Thereafter, the interest
rate will be adjusted at five year intervals.
In addition to the annual water storage cost, we must pay, annually, 0.682%
of (1) the costs of any repair, rehabilitation or replacement of Enid Lake
features as a result of any joint use with another entity utilizing Enid Lake
and (2) the annual joint-use operation and maintenance expenses.
Upon completion of all of our payments we have the permanent right to use
the water supply storage space in Enid Lake so long as we continue to pay the
annual operation and maintenance costs and costs of any necessary repairs,
rehabilitation or replacement that Enid Lake requires.
ENVIRONMENTAL QUALITY
During the construction, operation and maintenance of the water supply
storage space we must prevent environmental pollution, particularly through the:
- reduction of air pollution;
- reduction of water pollution;
- minimization of noise levels;
- on-site and off-site disposal of waste; and
- prevention of landscape damage and defacement.
134
<PAGE>
RELEASE OR CLAIMS
We release the Federal government, its officers, agents and employees from
any liability for any claim of damages which may be asserted as a result of
storage in Enid Lake, the withdrawal or release of the water from Enid Lake or
the construction, operation and maintenance of our water supply facilities,
except for damages due to the Federal government's negligence or fault.
ASSIGNMENT
We cannot transfer or assign any rights or grant any interest, privilege or
license in the water supply storage agreement without the approval of the
Secretary of the Army or his duly authorized representative. The agent for the
secured parties is a third party beneficiary of the water supply storage
agreement.
AD VALOREM TAX CONTRACT
Pursuant to an Ad Valorem Tax Contract dated as of August 28, 1998 with the
County of Panola, Mississippi, the City of Batesville, Mississippi, the
Mississippi Department of Economic and Community Development acting for and on
behalf of the State of Mississippi and the Panola County Tax Assessor/
Collector, these government entities granted to us several tax reductions and
incentives to construct our project in Batesville. The government entities have
agreed that we are eligible for a fee-in-lieu-of-taxes of not less than
one-third of our state and local taxes.
FEE-IN-LIEU OF TAXES AMOUNT
The fee-in-lieu-of-taxes amount which we must pay equals one-third of the
taxes assessed against us, our power facility, our inventories and any
assessable interest of the industrial water supply system, the wastewater
disposal system, the fire protection system and the lateral gas pipeline. The
fee-in-lieu-of-taxes amount will never be less than $1,900,000 per year. The
fee-in-lieu-of-taxes could also be affected by millage changes.
TERM
The fee-in-lieu-of-taxes is for a 10 year period beginning on the first
January 1st after our power facility has been substantially completed and we
have spent at least $100,000,000 on the construction of our power facility.
However, if both of these events occur between January 1st and March 1st of the
same year then the term will commence on January 1st of that year.
FUTURE ADDITIONS
To the extent lawfully permitted, the government entities party to the ad
valorem tax contract will apply the contract to any expansions, improvements or
equipment replacements so long as we comply with our material obligations under
the ad valorem tax contract. If any of the exemptions or credits expire as a
result of statute, then we are "grandfathered" into the exemptions or credits to
the extent permissible under law.
TERMINATION
We must maintain our power facility and keep it capable of being operated
other than during periods when our power facility is not available because of
maintenance or repair or for reasons beyond our control. If we fail to do so,
the ad valorem tax contract will terminate on the January 1st following our
failure.
135
<PAGE>
ASSIGNABILITY
We may assign the ad valorem tax contract as long we substantially comply
with the terms of the contract and obtain written approval from Panola County.
INFRASTRUCTURE USE CONTRACTS
We have entered into five agreements with Mississippi governmental entities
with respect to the Panola County infrastructure. Under an inducement agreement,
the State of Mississippi agreed to issue general obligation bonds to finance the
infrastructure, Panola County (and ultimately the Industrial Development
Authority) agreed to assume ownership of the infrastructure, and we agreed to
operate and maintain both our power facility and the infrastructure. As
contemplated by the inducement agreement, we have transferred to Panola County
the construction contracts relating to the infrastructure and our title to the
infrastructure already completed or under construction, together with permanent
easements and real estate rights relating to the infrastructure sites. We paid
the costs of developing and constructing the infrastructure until the State of
Mississippi issued general obligation bonds to finance its reimbursement to us
of our infrastructure costs and these transfers had been made. The State has
reimbursed us for $14,278,000 of the costs that we incurred for development and
easement acquisition activities, and for the construction of the infrastructure
after April 11, 1999.
Under the inducement agreement, we have promised to maintain our power
facility and to keep it capable of being operated other than during periods when
our power facility is not available because of maintenance or repair or for
reasons beyond our control and to perform our obligations under the other
infrastructure financing documents, including the use agreements for the lateral
pipeline and the water supply and wastewater discharge systems. In the event we
fail to do so, we would be responsible for paying to the State an amount equal
to:
(1) the outstanding principal amount of the general obligation bonds times a
fraction the numerator of which is the number of months remaining in the
term of the general obligation bonds and the denominator of which is the
original number of months in the term of the general obligation bonds,
plus
(2) accrued interest on that principal amount, plus
(3) the costs of redeeming the general obligation bonds.
We also have entered into agreements with Panola County and the Industrial
Development Authority that will allow us to use the Panola County
infrastructure. We have entered into one use agreement with respect to the
natural gas lateral pipeline and one use agreement with respect to the water
supply and wastewater discharge systems. Each of these agreements is in the form
of a lease. Each use agreement has an initial term which expires 30 years after
substantial completion of our power facility. We may renew the use agreements
for successive 10 year terms through the life of our power facility. In return
for our use of the Panola County infrastructure, we promise to operate and
maintain, or arrange for the operation and maintenance of, the Panola County
infrastructure and to pay for all operation and maintenance expenses. We
currently expect that the operation and maintenance of the natural gas lateral
pipeline will be performed by Cogentrix Batesville Operations or another
experienced gas pipeline operator, and that operation and maintenance of the
water supply and wastewater discharge systems will be performed by Cogentrix
Batesville Operations. We also currently expect that the City of Batesville,
Mississippi will be an additional user of the capacity of the natural gas
lateral pipeline which is in excess of the capacity required to operate our
power facility. We currently expect that there may be additional users in the
future of the water supply and wastewater discharge systems. In the case of any
additional user of the water infrastructure, we have approval rights over the
terms and conditions under which additional users will be provided access to use
the water infrastructure, including cost sharing, indemnification and any
restrictions resulting form regulatory limitations.
136
<PAGE>
In consideration for the approval of Yalobusha County, Mississippi and the
Coffeeville School District to construct a portion of the Panola County
infrastructure in that county and district, we have entered into an agreement
with Yalobusha County, Mississippi and the Coffeeville School District to pay
them an aggregate amount equal to $1,500,000. We must make this payment on or
before the first day of February following the first full calendar year after
the year in which our power facility is certified as being substantially
complete.
Finally, in consideration for our use of the Panola County infrastructure,
we have entered into an agreement with, and have promised to pay, Panola
Partnership, Inc., a Panola County governmental entity, a yearly payment equal
to $300,000, which escalates at the compound rate of 2% per annum, so long as
the inducement agreement and the use agreements described above remain in effect
and are not terminated, other than as a result of a default by us.
137
<PAGE>
DESCRIPTION OF THE EXCHANGE BONDS
GENERAL
We and the Funding Corporation will issue the exchange bonds under the
indenture dated May 21, 1999 among us, the Funding Corporation and The Bank of
New York, as trustee. The exchange bonds will evidence the same indebtedness as
the private bonds which they replace, and will be entitled to the benefits of
the indenture. The form and terms of the exchange bonds are the same as the form
and terms of the bonds, except that:
(1) the exchange bonds will have been registered under the Securities Act,
and, therefore, the exchange bonds will not bear legends restricting
their transfer; and
(2) holders of the exchange bonds will not be entitled to the rights of
holders of the private bonds under the registration rights agreement that
will terminate upon the consummation of the exchange offer.
The terms of the exchange bonds include those stated in the indenture and
those made part of the indenture by reference to the Trust Indenture Act of 1939
as in effect on the date of the indenture. You can find the definitions of
certain terms used in this description in Annex A to this prospectus. The
following description is a summary of the material provisions of the exchange
bonds and the indenture. It does not restate the exchange bonds and the
indenture in their entirety. We urge you to read the exchange bonds and the
indenture because they, and not this description, define your rights as a holder
of the exchange bonds. You may obtain a copy of the exchange bonds and the
indenture from us.
PRINCIPAL, MATURITY AND INTEREST
We and the Funding Corporation will issue the exchange bonds in two series
in the following total principal amounts: $150,000,000 7.164% series C senior
secured bonds due 2014; and $176,000,000 8.160% series D senior secured bonds
due 2025. The series C bonds will mature on January 15, 2014, and the Series D
bonds will mature on July 15, 2025.
Each series of exchange bonds will bear interest at the annual rate
applicable to that series stated on the cover of this prospectus from May 21,
1999. We and the Funding Corporation will be required to pay interest on the
bonds on each January 15 and July 15, commencing January 15, 2000, to the
holders of record on the immediately preceding January 1 and July 1. Interest on
the exchange bonds will accrue from the most recent date to which interest has
been paid or, if no interest has been paid, from May 21, 1999. Interest will be
computed on the basis of a 360-day year consisting of twelve 30-day months.
138
<PAGE>
We and the Funding Corporation will be required to pay principal of the
series C bonds as follows:
<TABLE>
<CAPTION>
PERCENTAGE OF PRINCIPAL
PAYMENT DATE AMOUNT PAYABLE
- ------------ -----------------------
<S> <C>
July 15, 2001............................................... 2.75%
January 15, 2002............................................ 2.75%
July 15, 2002............................................... 2.30%
January 15, 2003............................................ 2.30%
July 15, 2003............................................... 2.45%
January 15, 2004............................................ 2.45%
July 15, 2004............................................... 2.60%
January 15, 2005............................................ 2.60%
July 15, 2005............................................... 3.80%
January 15, 2006............................................ 3.80%
July 15, 2006............................................... 4.15%
January 15, 2007............................................ 4.15%
July 15, 2007............................................... 4.20%
January 15, 2008............................................ 4.20%
July 15, 2008............................................... 4.35%
January 15, 2009............................................ 4.35%
July 15, 2009............................................... 4.50%
January 15, 2010............................................ 4.50%
July 15, 2010............................................... 4.70%
January 15, 2011............................................ 4.70%
July 15, 2011............................................... 5.10%
January 15, 2012............................................ 5.10%
July 15, 2012............................................... 5.10%
January 15, 2013............................................ 5.10%
July 15, 2013............................................... 4.00%
January 15, 2014............................................ 4.00%
</TABLE>
139
<PAGE>
We and the Funding Corporation will be required to pay principal of the
series D bonds as follows:
<TABLE>
<CAPTION>
PERCENTAGE OF PRINCIPAL
PAYMENT DATE AMOUNT PAYABLE
- ------------ -----------------------
<S> <C>
July 15, 2014............................................... 2.65%
January 15, 2015............................................ 2.65%
July 15, 2015............................................... 2.85%
January 15, 2016............................................ 2.85%
July 15, 2016............................................... 2.85%
January 15, 2017............................................ 2.85%
July 15, 2017............................................... 3.00%
January 15, 2018............................................ 3.00%
July 15, 2018............................................... 2.90%
January 15, 2019............................................ 2.90%
July 15, 2019............................................... 3.45%
January 15, 2020............................................ 3.45%
July 15, 2020............................................... 2.15%
January 15, 2021............................................ 2.15%
July 15, 2021............................................... 5.25%
January 15, 2022............................................ 5.25%
July 15, 2022............................................... 5.35%
January 15, 2023............................................ 5.35%
July 15, 2023............................................... 5.40%
January 15, 2024............................................ 5.40%
July 15, 2024............................................... 6.90%
January 15, 2025............................................ 6.90%
July 15, 2025............................................... 14.50%
</TABLE>
The principal of, premium, if any, and interest on the exchange bonds will
be payable, and the exchange bonds will be exchangeable and transferable, at the
office or agency that we and the Funding Corporation maintain in the Borough of
Manhattan, The City of New York for those purposes. Initially that office will
be the office of the trustee located at 101 Barclay Street, Floor 21 West, New
York, New York 10286, Attention: Corporate Trust Administration. Alternatively,
at our option, we and the Funding Corporation may make interest payments on the
exchange bonds by check mailed to the addresses of the persons entitled to
payment as those addresses appear in the security register.
The exchange bonds will not be entitled to the benefit of any sinking fund.
ISSUANCE OF ADDITIONAL BONDS
We and the Funding Corporation may issue additional bonds under the
indenture in accordance with the conditions described in the indenture. So long
as we and the Funding Corporation comply with these conditions, the amount of
additional bonds that we and the Funding Corporation can issue under the
indenture is unlimited. Any additional bonds will rank equivalent in right of
payment to the bonds and will vote on all matters with the bonds. For purposes
of this "Description of the Exchange Bonds," reference to the bonds does not
include additional bonds unless otherwise indicated. No offering of any
additional bonds is being or will in any manner be deemed to be made by this
prospectus. We describe the conditions under which we may issue additional bonds
under the caption "Description of Principal Financing Documents--Covenants of Us
and the Funding Corporation--Limitation on Our Indebtedness."
140
<PAGE>
NONRECOURSE OBLIGATIONS
The obligations to pay principal of, premium, if any, and interest on the
exchange bonds will be obligations only of us and the Funding Corporation. None
of our or the Funding Corporation's partners, shareholders, affiliates,
employees, officers, directors or any other person or entity will guarantee the
exchange bonds or have any obligation to make any payments on the exchange
bonds.
SECURITY
The exchange bonds will be secured by:
- a mortgage on the Site and the Easements;
- a security interest in substantially all of our personal property and all
of the personal property of the Funding Corporation, other than the Aquila
PPA Reserve Account;
- a pledge by LSP Batesville Holding and LSP Energy of all of their
interests in us;
- a pledge by LSP Batesville Holding of all of the capital stock of LSP
Energy; and
- a pledge by LSP Batesville Holding of all of the capital stock of the
Funding Corporation.
Any additional bonds issued under the indenture will share equally and
ratably in this collateral with the exchange bonds. Other indebtedness may also
share equally and ratably in the collateral with the exchange bonds. See
"Description of Principal Financing Documents--Indenture--Certain
Covenants--Limitation on Liens." In addition, the lien in favor of the
Collateral Agent under the security documents will automatically be released
upon our conveyance or disposition of the assets described on page 153 of this
prospectus under the caption "--Prohibition on Fundamental Changes and
Disposition of Assets".
RANKING
The exchange bonds:
- will be senior secured obligations of us and the Funding Corporation;
- will rank equivalent in right of payment to all of our other senior
secured obligations and all those of the Funding Corporation; and
- will rank senior in right of payment to all of our existing and future
subordinated debt and all that of the Funding Corporation.
RATINGS
Moody's and S&P have assigned the exchange bonds ratings of "Baa3" and
"BBB-", respectively. Each of these ratings reflects only the view of the
applicable rating agency at the time the rating was issued, and any explanation
of the significance of these ratings may be obtained only from the rating
agencies. We cannot assure you that any ratings will remain in effect for any
given period of time or that these ratings will not be lowered, suspended or
withdrawn entirely by the applicable rating agency. Any lowering, suspension or
withdrawal of a rating by a rating agency may have an adverse effect on the
market price or marketability of the exchange bonds.
OPTIONAL REDEMPTION
Each series of the exchange bonds will be redeemable, at our option, at any
time in whole or from time to time in part, on not less than 30 nor more than
60 days' prior notice to the holders of that series of exchange bonds, on any
date prior to its maturity, at a redemption price equal to:
- 100% of the outstanding principal amount of the exchange bonds being
redeemed; plus
- accrued and unpaid interest on the exchange bonds being redeemed to but
not including the redemption date; PLUS
- a Make-Whole Premium.
In no event will the redemption price ever be less than 100% of the
principal amount of the exchange bonds being redeemed plus accrued and unpaid
interest on those bonds to the redemption date.
141
<PAGE>
MANDATORY REDEMPTION
IF A CASUALTY EVENT OCCURS
If:
- a Casualty Event occurs,
- we receive more than $5,000,000 of Casualty Proceeds because of the
Casualty Event, and
- either:
- we decide not to rebuild, repair or restore our project after the
Casualty Event, or
- our project cannot be rebuilt, repaired or restored to operate on a
Commercially Feasible Basis and the independent engineer for our project
confirms this fact,
then we and the Funding Corporation will have to use the Casualty Proceeds that
we receive to redeem exchange bonds and prepay any of the other Senior Secured
Obligations that require prepayment upon receipt of these proceeds. The
redemption price for the exchange bonds being redeemed will be equal to 100% of
the outstanding principal amount of the exchange bonds being redeemed PLUS
accrued and unpaid interest on the exchange bonds being redeemed to but not
including the date of redemption.
If:
- a Casualty Event occurs,
- we receive Casualty Proceeds because of the Casualty Event,
- our project can be rebuilt, repaired or restored to operate on a
Commercially Feasible Basis and the independent engineer for our project
confirms this fact, and
- more than $5,000,000 of Casualty Proceeds are left over after we finish
rebuilding, repairing or restoring our project,
then, after giving effect to the cost of such rebuilding, repairing or
restoring of our project, we and the Funding Corporation will have to use the
remaining Casualty Proceeds that we receive in excess of $5,000,000 to redeem
exchange bonds and prepay any of the other Senior Secured Obligations that
require prepayment upon receipt of these proceeds unless we and the Funding
Corporation receive written confirmation that the Casualty Event (after taking
into consideration the rebuilding, repair or restoration) will not result in a
Rating Downgrade. The redemption price for the exchange bonds being redeemed
will be equal to 100% of the outstanding principal amount of the exchange bonds
being redeemed PLUS accrued and unpaid interest on the exchange bonds being
redeemed to but not including the date of redemption.
IF AN EXPROPRIATION EVENT OCCURS
If:
- an Expropriation Event occurs,
- we receive more than $5,000,000 of Expropriation Proceeds because of the
Expropriation Event, and
- either:
- we decide not to rebuild, repair or restore our project after the
Expropriation Event, or
- our project cannot be rebuilt, repaired or restored to operate on a
Commercially Feasible Basis and the independent engineer for our project
confirms this fact,
142
<PAGE>
then we and the Funding Corporation will have to use the Expropriation Proceeds
that we receive to redeem exchange bonds and prepay any of the other Senior
Secured Obligations that require prepayment upon receipt of these proceeds. The
redemption price for the exchange bonds being redeemed will be equal to 100% of
the outstanding principal amount of the exchange bonds being redeemed PLUS
accrued and unpaid interest on the exchange bonds being redeemed to but not
including the date of redemption.
If:
- an Expropriation Event occurs,
- we receive Expropriation Proceeds because of the Expropriation Event,
- our project can be rebuilt, repaired or restored to operate on a
Commercially Feasible Basis and the independent engineer for our project
confirms this fact, and
- more than $5,000,000 of Expropriation Proceeds are left over after we
finish rebuilding, repairing or restoring our project,
then, after giving effect to the cost of such rebuilding, repairing or restoring
our project, we and the Funding Corporation will have to use the remaining
Expropriation Proceeds that we receive in excess of $5,000,000 to redeem
exchange bonds and prepay any of the other Senior Secured Obligations that
require prepayment upon receipt of these proceeds unless we and the Funding
Corporation receive written confirmation that the Expropriation Event (after
taking into consideration the rebuilding, repair or restoration) will not result
in a Rating Downgrade. The redemption price for the exchange bonds being
redeemed will be equal to 100% of the outstanding principal amount of the
exchange bonds being redeemed PLUS accrued and unpaid interest on the exchange
bonds being redeemed to but not including the date of redemption.
IF A TITLE EVENT EXISTS
If:
- a Title Event exists,
- the collateral agent receives more than $5,000,000 of Title Proceeds
because of the Title Event, and
- either:
- we decide not to fix the Title Event, or
- the Title Event cannot be fixed so that our project is able to operate on
a Commercially Feasible Basis and the independent engineer for our
project confirms this fact,
then we and the Funding Corporation will have to use the Title Proceeds that the
collateral agent receives to redeem exchange bonds and prepay any of the other
Senior Secured Obligations that require prepayment upon receipt of these
proceeds. The redemption price for the exchange bonds being redeemed will be
equal to 100% of the outstanding principal amount of the exchange bonds being
redeemed PLUS accrued and unpaid interest on the exchange bonds being redeemed
to but not including the date of redemption.
If:
- a Title Event exists,
- the collateral agent receives Title Proceeds because of the Title Event,
143
<PAGE>
- the Title Event can be fixed so that our project can operate on a
Commercially Feasible Basis and the independent engineer for our project
confirms this fact, and
- more than $5,000,000 of Title Proceeds are left over after the Title Event
is fixed,
then, after giving effect to the fixing of the Title Event, we and the Funding
Corporation will have to use the remaining Title Proceeds that the collateral
agent receives in excess of $5,000,000 to redeem exchange bonds and prepay any
of the other Senior Secured Obligations that require prepayment upon receipt of
these proceeds unless we and the Funding Corporation receive written
confirmation that the Title Event (after taking into consideration the fixing of
the Title Event) will not result in a Rating Downgrade. The redemption price for
the exchange bonds being redeemed will be equal to 100% of the outstanding
principal amount of the exchange bonds being redeemed PLUS accrued and unpaid
interest on the exchange bonds being redeemed to but not including the date of
redemption.
IF ONE OR MORE OF OUR POWER CONTRACTS IS BOUGHT-OUT
If we receive more than $10,000,000 of proceeds from PPA Buy-Outs, we and
the Funding Corporation will have to use these proceeds to redeem exchange bonds
and prepay any of the other Senior Secured Obligations that require prepayment
upon receipt of these proceeds unless we and the Funding Corporation receive
written confirmation that the PPA Buy-Outs will not result in a Rating
Downgrade. The redemption price for the exchange bonds being redeemed will be
equal to 100% of the outstanding principal amount of the exchange bonds being
redeemed PLUS accrued and unpaid interest on the exchange bonds being redeemed
to but not including the date of redemption.
IF WE RECEIVE PERFORMANCE LIQUIDATED DAMAGES
If we receive more than $10,000,000 of Performance Liquidated Damages under
the Construction Contract, we and the Funding Corporation will have to use these
proceeds to redeem exchange bonds and prepay any of the other Senior Secured
Obligations that require prepayment upon receipt of these proceeds unless we and
the Funding Corporation receive written confirmation that the circumstance which
resulted in our receipt of Performance Liquidated Damages will not result in a
Rating Downgrade. The redemption price for the exchange bonds being redeemed
will be equal to 100% of the outstanding principal amount of the exchange bonds
being redeemed PLUS accrued and unpaid interest on the exchange bonds being
redeemed to but not including the date of redemption.
IF WE RECEIVE DEFAULT EQUITY CONTRIBUTIONS
If we receive Default Equity Contributions and the Senior Secured Parties
decide to apply these Default Equity Contributions to the redemption or
prepayment of Senior Secured Obligations in accordance with the Intercreditor
Agreement, we and the Funding Corporation will have to use these proceeds to
redeem exchange bonds and prepay any of the other Senior Secured Obligations
that require prepayment upon receipt of these proceeds. The redemption price for
the exchange bonds being redeemed will be equal to 100% of the outstanding
principal amount of the exchange bonds being redeemed PLUS accrued and unpaid
interest on the exchange bonds being redeemed to but not including the date of
redemption.
REDEMPTION AT THE OPTION OF THE BONDHOLDERS
IF A CHANGE OF CONTROL OCCURS
If a Change of Control occurs, any bondholder can request that we and the
Funding Corporation redeem all or a portion of the exchange bonds held by that
bondholder. In response to any such request, we and the Funding Corporation will
be required to redeem all exchange bonds which are specified in the request at a
redemption price equal to 101% of the outstanding principal amount of
144
<PAGE>
the exchange bonds being redeemed plus accrued and unpaid interest on the
exchange bonds being redeemed to but not including the date of redemption.
IF MONIES REMAIN ON DEPOSIT IN THE DISTRIBUTION SUSPENSE ACCOUNT
If:
- funds remain on deposit in the Distribution Suspense Account for at least
12 months in a row,
- we and the Funding Corporation decide to have the Bondholders vote on
whether we and the Funding Corporation should use these funds to redeem
bonds, and
- bondholders holding at least 66 2/3% of the outstanding bonds vote to have
us and the Funding Corporation use these funds to redeem bonds,
then we and the Funding Corporation will have to use the funds which have
remained on deposit in the Distribution Suspense Account for at least 12 months
in a row to redeem exchange bonds and prepay any of the other Senior Secured
Obligations that require prepayment under these circumstances. The redemption
price for the exchange bonds being redeemed will be equal to 100% of the
outstanding principal amount of the exchange bonds being redeemed PLUS accrued
and unpaid interest on the exchange bonds being redeemed to but not including
the date of redemption. If we and the Funding Corporation are not required to
redeem bonds and prepay other Senior Secured Obligations with those funds
following the vote of the bondholders, and if none of the other senior secured
obligations requires us to apply these funds to their prepayment, then we will
be permitted to distribute those funds to our partners without regard to the
satisfaction of any Distribution Conditions relating to the Senior Debt Service
Coverage Ratio or the Projected Senior Debt Service Coverage Ratio.
TERMS OF MANDATORY REDEMPTION
If the exchange bonds are redeemed because of any of the foregoing
provisions, the proceeds used to redeem the exchange bonds will be applied:
- pro rata to the exchange bonds and the other Senior Secured Obligations
which require redemption or repayment, based upon the then outstanding
principal amounts of the exchange bonds and those other Senior Secured
Obligations; and
- pro rata among each series of bonds and additional bonds issued upon the
indenture, based upon the then outstanding principal amounts of each
series of bonds and additional bonds.
We and the Funding Corporation will mail a notice of redemption to each
holder of the series of bonds or additional bonds being redeemed at that
holder's address of record. Interest will cease to accrue on any series of bonds
or additional bonds on and after the redemption date.
BOOK-ENTRY, DELIVERY AND FORM
The exchange bonds will be represented by one or more global bonds in
registered form issued to The Depository Trust Company and registered in the
name of Cede & Co., as nominee of The Depository Trust Company. The trustee will
act as custodian of each global bond for The Depository Trust Company or will
appoint a sub-custodian to act in that capacity. Because a nominee of The
Depository Trust Company will be the holder of record of each global bond, each
person owning a beneficial interest in a global bond must rely upon the
procedures of the institutions having accounts with The Depository Trust Company
to exercise or be entitled to any of the rights of a holder.
If you are an Institutional Accredited Investor, we and the Funding
Corporation will issue your exchange bonds to you or your nominee as registered
definitive exchange bonds, without coupons,
145
<PAGE>
rather than to Cede & Co. We and the Funding Corporation will also issue
definitive bonds instead of global bonds if:
- we or the Funding Corporation advise the trustee in writing that The
Depository Trust Company is no longer willing or able to discharge
properly its responsibilities as depositary for the exchange bonds and we
and the Funding Corporation do not locate a qualified successor within
120 days;
- we or the Funding Corporation elect to terminate the book-entry system
through The Depository Trust Company for the exchange bonds; or
- after an Event of Default occurs, beneficial owners of not less than 51%
of the outstanding principal amount of the bonds represented by the global
bonds advise the trustee through The Depository Trust Company in writing
that the continuation of a book-entry system through The Depository Trust
Company, or a successor, with respect to the bonds is no longer in the
beneficial owners' best interest.
The Depository Trust Company has advised us and the Funding Corporation as
follows:
- The Depository Trust Company is a limited-purpose trust company organized
under the New York Banking Law, a "banking organization" within the
meaning of the New York Banking Law, a member of the Federal Reserve
System, a "clearing corporation" within the meaning of the New York
Uniform Commercial Code, and a "clearing agency" registered under the
provisions of Section 17A of the Exchange Act; and
- The Depository Trust Company was created to hold securities of
institutions that have accounts with The Depository Trust Company
participants and to facilitate the clearance and settlement of securities
transactions among its participants in those securities through electronic
book-entry changes in accounts of the participants, eliminating the need
for physical movement of securities certificates.
Upon the issuance of the global bonds, The Depository Trust Company will
credit on its book-entry registration and transfer system the respective
principal amounts of the exchange bonds represented by the global bonds to the
accounts of participants. Ownership of beneficial interests in the global bonds
will be limited to participants or persons that may hold interests through
participants. Ownership of beneficial interests in the global bonds will be
shown on, and the transfer of those ownership interests will be effected only
through, records maintained by The Depository Trust Company (with respect to
participants' interests) and its participants (with respect to the owners of
beneficial interests in the global bonds other than participants).
Payment of principal of and interest on exchange bonds represented by the
global bonds registered in the name of and held by The Depository Trust Company
or its nominee will be made to The Depository Trust Company or its nominee, as
the case may be, as the registered owner and holder of the global bonds.
We and the Funding Corporation expect that The Depository Trust Company or
its nominee, upon receipt of any payment of principal or interest in respect of
a global bond, will credit participants' accounts with payments in amounts
proportionate to their respective beneficial interests in the principal amount
of the global bond as shown on the records of The Depository Trust Company or
its nominee. We and the Funding Corporation also expect that payments by
participants to owners of beneficial interests in the global bonds held through
participants will be governed by standing instructions and customary practices,
as is now the case with securities held for the accounts of customers in bearer
form or registered in street name, and will be the responsibility of the
participants. Neither we, the Funding Corporation, the trustee nor any paying
agent will have any responsibility or liability for any aspect of the records
relating to, or payments made on account of, beneficial ownership interests in
the
146
<PAGE>
global bonds for any exchange bonds, or for maintaining, supervising or
reviewing any records relating to the beneficial ownership interests, or for any
other aspect of the relationship between The Depository Trust Company and its
participants or the relationship between those participants and owners of
beneficial interests in the global bonds owning through those participants.
TRANSFER AND EXCHANGE
A bondholder may transfer or exchange exchange bonds only in accordance with
the restrictions on transfer contained in the indenture. The security registrar
and the trustee may require a bondholder, among other things, to furnish
appropriate endorsements and transfer documents and we and the Funding
Corporation may require a bondholder to pay any taxes and fees required by law
or permitted by the indenture. We and the Funding Corporation are not required
to transfer or exchange any exchange bond for a period of 15 days before a
selection of exchange bonds to be redeemed.
The registered holder of an exchange bond will be treated as the owner of
the exchange bond for all purposes.
147
<PAGE>
DESCRIPTION OF THE PRINCIPAL FINANCING DOCUMENTS
Following are summaries of the financing documents that were executed for
our issuance of the private bonds. We have filed the financing documents as
exhibits to the registration statement of which this prospectus is a part.
INDENTURE
GENERAL
We and the Funding Corporation issued the private bonds, and will issue the
exchange bonds, under the indenture. We and the Funding Corporation issued the
private bonds in two series under two supplemental indentures which set forth
the terms of each series, and we and the Funding Corporation will issue the
exchange bonds in two series under two supplemental indentures which set forth
the terms of each series.
COVENANTS OF US AND THE FUNDING CORPORATION
The indenture contains various covenants, including the following:
LIMITATION ON OUR INDEBTEDNESS
We cannot create or incur or suffer to exist any Indebtedness, other than
the following Indebtedness ("Permitted Indebtedness"):
- the Senior Secured Obligations;
- purchase money or capital lease obligations up to $5,000,000 incurred to
finance readily replaceable personal property;
- trade accounts payable, other than for borrowed money, which arise in the
ordinary course of business and which are payable within 90 days;
- guarantees of Permitted Indebtedness;
- replacements for or financings of the Virginia Power letters of credit;
- subordinated indebtedness issued to us by one of our partners or
affiliates which is not secured by the collateral that secures the
exchange bonds;
- working capital loans up to $10,000,000 that are used to pay O&M Costs;
- subject to the restrictions contained in the financing documents,
Indebtedness incurred under any agreement providing for the issuance of
one or more Debt Service Reserve L/Cs or Aquila Reserve L/Cs;
- Indebtedness incurred for Required Modifications, as long as either of the
following conditions is satisfied:
(a) the minimum Projected Senior Debt Service Coverage Ratio for each
fiscal year for the remaining term of the bonds, after taking into
account this Indebtedness and provided that for purposes of this
calculation operating revenues will be based on the assumption that
each Power Purchase Agreement expires at the end of its initial term
unless an extension notice has been given under that agreement, is
greater than or equal to:
(1) 1.20/1.00 during the 100% PPA Period;
(2) 1.35/1.00 during the Two-Thirds PPA Period; and
148
<PAGE>
(3) 1.50/1.00 during the One-Third PPA Period and the Merchant
Period, as certified by us and confirmed by the independent
engineer for our project, or
(b) the incurrence of this Indebtedness will not result in a Rating
Downgrade;
- Indebtedness incurred for Optional Modifications, as long as either of the
following conditions is satisfied:
(a) after taking into account this Indebtedness:
(1) the minimum Projected Senior Debt Service Coverage Ratio for each
fiscal year during the remaining term of the bonds is greater
than or equal to the following ratios, provided that for purposes
of this calculation operating revenues will be based on the
assumption that each Power Purchase Agreement expires at the end
of its initial term unless an extension notice has been given in
accordance with that agreement:
(1) 1.45/1.00 during the 100% PPA Period;
(2) 1.70/1.00 during Two-Thirds PPA Period; and
(3) 2.00/1.00 during the One-Third PPA Period and the Merchant
Period, as certified by us and confirmed by the independent
engineer for our project; and
(2) the average annual Projected Senior Debt Service Coverage Ratio
during the remaining term of the bonds is greater than or equal
to the following ratios, provided that for purposes of this
calculation operating revenues will be based on the assumption
that each Power Purchase Agreement expires at the end of its
initial term unless an extension notice has been given in
accordance with that agreement:
(1) 1.45/1.00 during the 100% PPA Period;
(2) 1.75/1.00 during the Two-Thirds PPA Period; and
(3) 2.25/1.00 the One-Third PPA Period and the Merchant Period,
as certified by us and confirmed by the independent engineer
for our project; or
(b) the incurrence of this Indebtedness will not result in a Rating
Downgrade;
- Indebtedness incurred for Expansion Modifications, as long the incurrence
of this Indebtedness will not result in a Rating Downgrade;
- Bonding Arrangements for a Good Faith Contest or as otherwise permitted
under the Transaction Documents; and
- indemnities and similar obligations arising under the Transaction
Documents.
LIMITATION ON LIENS
We cannot create or suffer to exist or permit any Lien upon any of our
properties, other than the following Liens ("Permitted Liens"):
- Liens specifically created or required to be created by the indenture or
any other financing document;
- Liens securing Senior Secured Obligations;
- Liens for Bonding Arrangements permitted by the indenture consisting of
Liens on cash collateral and related investments held as cash cover for
the Bonding Arrangements in an
149
<PAGE>
aggregate amount, at any time outstanding, not exceeding $7,000,000 plus
monies from amounts otherwise available to our partners as a distribution
permitted in accordance with the terms described under the caption
"Distributions";
- Liens for taxes which are either not yet due or are due but payable
without penalty or are the subject of a Good Faith Contest;
- any exceptions to title existing on May 21, 1999 and set forth on the
Title Policy;
- defects, easements, rights of way, restrictions, irregularities,
encumbrances and clouds on title and statutory Liens that do not
materially impair the property affected and that do not individually or in
the aggregate materially impair the value of the security interests
granted under the Security Documents;
- deposits or pledges to secure statutory obligations or appeals, release of
attachments, stay of execution or injunction, performance of bids,
tenders, contracts (other than for the repayment of borrowed money) or
leases, or for purposes of like general nature in the ordinary course of
business;
- Liens for worker's compensation, unemployment insurance or other social
security or pension or similar obligations;
- legal or equitable encumbrances deemed to exist because of the existence
of any litigation or other legal proceeding if they are the subject of a
Good Faith Contest;
- mechanics', workmen's, materialmen's, suppliers', construction or other
similar Liens arising in the ordinary course of business or incident to
the construction, operation, repair, restoration or improvement of any
property for obligations which are not yet due or which are the subject of
a Good Faith Contest;
- Liens on assets acquired with the proceeds of permitted purchase money or
capital lease obligations and Liens on cash collateral and related
investments held as cash cover with respect to replacements for the
Virginia Power Letter of Credit or Aquila/UtiliCorp letters of credit;
- a Lien in favor of Aquila/UtiliCorp on the Aquila PPA Reserve Account;
- Liens to secure any other Permitted Indebtedness, so long as such Liens:
(a) are not superior in right to the Liens provided to the Bondholders
under the Security Documents, and
(b) secure such Indebtedness equally and ratably with the bonds or on a
basis subordinated to the bonds; and
- Liens substantially similar to certain of the Liens described above so
long as any such Lien, if foreclosed upon, would not reasonably be
expected to result in a Material Adverse Effect.
DISTRIBUTIONS
We cannot make a distribution to our equity holders unless the following
conditions (the "Distribution Conditions") are satisfied on the distribution
date:
- all required transfers and payments described under the caption "--Common
Agreement--Deposit and Disbursement of Funds" have been completed;
150
<PAGE>
- immediately after giving effect to the proposed distribution, the Account
Balance Amount will be equal to or greater than the Account Reserve
Requirement (this condition applies only if the distribution date is not a
Scheduled Payment Date);
- no Default or Event of Default has occurred and is continuing or will
result from the distribution;
- if the Test Period consists entirely of the Two-Thirds PPA Period and/or
the 100% PPA Period, the following conditions must be satisfied:
(a) the Senior Debt Service Coverage Ratio is greater than or equal to
the Required Ratio for the six-month period preceding the
distribution date or, with respect to a distribution date that occurs
within six months after the Commercial Operation Date, the period
commencing on the Commercial Operation Date and ending on the
distribution date, and
(b) the Projected Senior Debt Service Coverage Ratio is greater than or
equal to the Required Ratio for the six-month period succeeding the
distribution date;
- if a portion of the Test Period consists of the 100% PPA Period and/or the
Two-Thirds PPA Period and a portion of the Test Period consists of the
One-Third PPA Period and/or the Merchant Period, the following conditions
must be satisfied:
(a) for the portion of the Test Period which consists of the 100% PPA
Period and/or the Two-Thirds PPA Period:
(1) the Senior Debt Service Coverage Ratio for that portion is
greater than or equal to the Required Ratio during the period
beginning on the date which is six months prior to the
distribution date and ending on the distribution date;
(2) the Projected Senior Debt Service Coverage Ratio for that portion
is greater than or equal to the Required Ratio during the period
beginning on the distribution date and ending on the date which
is six months after the distribution date; and
(b) for the portion of the Test Period which consists of the One-Third
PPA Period and/or the Merchant Period:
(1) the Senior Debt Service Coverage Ratio for that portion is
greater than or equal to the Required Ratio during the period
beginning on the date which is one year prior to the distribution
date and ending on the distribution date, PROVIDED that this
portion will not be taken into account unless it consists of at
least two fiscal quarters;
(2) the Projected Senior Debt Service Coverage Ratio for the portion
of the period described below which consists of the One-Third PPA
Period and/or the Merchant Period is greater than or equal to the
Required Ratio during the period beginning on the distribution
date and ending on the later of (x) the date which is two years
after the distribution date if that portion includes at least one
year which consists entirely of the One-Third PPA Period and/or
the Merchant Period and (y) the earliest date after the date
described in clause (x) which results in that portion including
at least one year which consists entirely of the One-Third PPA
Period and/or the Merchant Period;
- if the Test Period consists entirely of the One-Third PPA Period and/or
the Merchant Period, the following conditions must be satisfied:
(a) the Senior Debt Service Coverage Ratio is greater than or equal to
the Required Ratio for the one-year period preceding the distribution
date, and
151
<PAGE>
(b) the Projected Senior Debt Service Coverage Ratio is greater than or
equal to the Required Ratio for the two-year period succeeding the
distribution date;
- the funds in the Revenue Account, the O&M Account, the Major Maintenance
Account and, after giving effect to the proposed distribution, the
Distribution Suspense Account, will be sufficient, in our reasonable
judgment, to meet our ongoing working capital needs;
- the Completion Date has occurred; and
- the distribution date is on or after the last business day of
September 2000.
Notwithstanding the foregoing, if, as described under the caption
"Description of the Exchange Bonds--Redemption at the Option of the
Bondholders," the bondholders elect not to require us to redeem bonds with
amounts that have been on deposit in the Distribution Suspense Account for at
least 12 months in a row, then we may, taking into consideration the terms of
other facilities which may constitute Senior Secured Obligations (other than
additional bonds issued under the indenture), distribute these amounts to our
equity holders without regard to the satisfaction of the Senior Debt Service
Coverage Ratio and the Projected Senior Debt Service Coverage Ratio tests set
forth above, as long as we satisfy the other Distribution Conditions.
AMENDMENTS TO PROJECT DOCUMENTS
We cannot:
- terminate, amend, waive or modify any of the Project Documents to which we
are a party,
- exercise any rights we may have to consent to any assignment of any of the
Project Documents by the other Project Parties, or
- exercise any option under any of the Project Documents to which we are a
party
unless the termination, amendment, waiver, modification, assignment or exercise:
- would not reasonably be expected to result in a Material Adverse Effect,
as certified in an officer's certificate supplied by us; or
- is reasonably necessary in order to maintain a Power Purchase Agreement in
full force and effect, as certified in an officer's certificate supplied
by us; or
- is necessary in order for us to be in compliance with applicable law or to
be able to obtain or maintain, or comply with the terms and conditions of,
any governmental approval necessary for us to conduct our business as
currently conducted or as proposed to be conducted or to permit our
project to maintain its certification as an Eligible Facility or us to
maintain our certification as an EWG, as certified in an officer's
certificate; or
- is the result of:
(a) a change in tariffs or similar publicly promulgated rates approved by
any governmental authority which are incorporated by reference into a
Project Document, or
(b) implementation of provisions requiring adjustments to price or volume
under, and in accordance with, the terms of a Project Document, if we
exercise good faith and commercially reasonable efforts to negotiate
price changes under these provisions for adjustments to price so as
not to result in a Material Adverse Effect; or
- is reasonably necessary in order to implement an Expansion Modification
for which it has been determined that no Rating Downgrade will occur; or
- is permitted by the covenant described under the caption "--Change
Orders."
152
<PAGE>
PROHIBITION ON FUNDAMENTAL CHANGES AND DISPOSITION OF ASSETS
We cannot enter into any transaction of merger or consolidation, change our
form of organization or our business, or liquidate or dissolve ourself, or
suffer any liquidation or dissolution, unless contemporaneously reconstituted
with no adverse effect on the Senior Secured Parties.
We cannot purchase or otherwise acquire all or substantially all of the
assets of any other person except as contemplated by the Transaction Documents.
In addition, except as contemplated by the Transaction Documents, we cannot
sell, lease (as lessor) or transfer (as transferor) any property or assets
material to the operation of our project except:
- in the ordinary course of business to the extent that:
(a) the property is worn out or is no longer useful or necessary for the
operation of our project, or
(b) the sale, lease or transfer is required to comply with any applicable
law or to obtain, maintain or comply with the terms and conditions of
any governmental approval necessary for us to conduct our business in
accordance with the Project Documents;
- under the Infrastructure Financing Documents or the Common Facilities
Agreement; and
- real property and related personal property and rights to be transferred
to an Expansion Party for purposes of developing an Expansion, PROVIDED
that such transfer (a) does not result in a Rating Downgrade or (b) (1)
would not reasonably be expected to result in a Material Adverse Effect,
as certified by us, and (2) will not have an adverse effect on the
operation or technical integrity of our project, including, without
limitation, as to availability and anticipated financial performance, as
certified by the independent engineer for our project.
Notwithstanding the foregoing, we may amend or otherwise modify any easement
agreement in order to substitute easements or specify the location of an
easement, so long as we are in compliance with the conditions contained in the
indenture.
INFRASTRUCTURE FINANCING DOCUMENTS
We cannot approve, consent to or agree to any decision to permit any person
to use the Panola County infrastructure under the terms of the Infrastructure
Financing Documents, to the extent we have the right to do so under the
Infrastructure Financing Documents, unless (1) we are required to permit the use
of the Panola County infrastructure by such person under the Infrastructure
Financing Documents or (2) such approval, consent or agreement would not
reasonably be expected to result in (x) a Material Adverse Effect, as certified
by us, or (y) a material adverse effect on the operation of the project, as
confirmed in writing by the independent engineer for our project.
REPLACEMENT POWER
We cannot elect to provide Replacement Power unless we enter into an
Acceptable Replacement Power Arrangement and we are physically constrained from
generating and delivering power. However, if during any period our provision of
Replacement Power causes us to incur cumulative losses of more than $5,000,000
over the losses we would have incurred if, during that period, we had elected a
derating of capacity of our project under any Power Purchase Agreement, we will
not be permitted to continue to provide Replacement Power unless the provision
of Replacement Power would not reasonably be expected to result in a Material
Adverse Effect, as certified by us.
153
<PAGE>
ADDITIONAL DOCUMENTS
We cannot enter into any material agreements, contracts or other
arrangements or commitments other than the following:
- the Transaction Documents;
- power purchase agreements, fuel supply and transportation agreements,
transmission agreements and other agreements, contracts or other
arrangements entered into by us for the purchase of fuel for or the sale
of electricity from our project, which, in each case, do not result in the
breach of, or conflict with the terms of, any then-existing Power Purchase
Agreement;
- Acceptable Replacement Power Arrangements;
- a Common Facilities Agreement, as long as the execution, delivery and
performance by us of such agreement (a) does not result in a Rating
Downgrade or (b) (1) would not reasonably be expected to result in a
Material Adverse Effect, as certified by us, and (2) will not have an
adverse effect on the operation or technical integrity of our project,
including without limitation as to anticipated financial performance, as
certified by the independent engineer for our project;
- the Infrastructure Financing Documents; and
- agreements, contracts or other arrangements or commitments which are:
(a) contemplated by the Transaction Documents, or
(b) entered into by us with respect to the disposition of assets which
the financing documents permit us to sell, transfer, assign, lease or
sublease, or
(c) entered into by us in the ordinary course of business and which are
included in the construction budget or the annual operating budget,
or
(d) in substitution for existing agreements, contracts or other
arrangements which are on substantially similar terms and conditions,
or
(e) entered into for an Expansion and which (a) do not result in a Rating
Downgrade or (b) would not reasonably be expected to result in a
Material Adverse Effect.
CHANGE ORDERS
We cannot initiate or consent to any change order under the Construction
Contract, unless either:
- each of the following conditions is satisfied:
(a) we certify to the trustee and the collateral agent that:
(1) the change order would not reasonably be expected to result in a
Material Adverse Effect;
(2) the implementation of the change order is not reasonably expected
to cause the Completion Date to occur after the Date Certain; and
(3) the change order is reasonable and is consistent with sound
engineering practice; and
(b) unless the independent engineer for our project has concurred in
writing with the certifications set forth in clauses (a)(1), (2) and
(3), the change order does not individually exceed $3,000,000, 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, exceed $6,000,000; or
154
<PAGE>
- each of the following conditions is satisfied:
(a) the change order is for an Expansion and (1) does not result in a
Rating Downgrade or (2) would not reasonably be expected to result in
a Material Adverse Effect; and
(b) unless the independent engineer for our project has approved such
change order, the change order does not individually exceed
$3,000,000, 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, exceed $6,000,000.
FUEL PLAN
We must deliver to the trustee, the collateral agent and the Rating Agencies
a fuel plan reasonably acceptable to the independent engineer and the
independent electricity market and fuel consultant for our project no later than
six months prior to the earlier of the following:
(1) the expiration of the term of the Virginia Power PPA; or
(2) the expiration of the term of the Aquila PPA.
ELECTRICITY MARKET UPDATES
We must cause the independent electricity market and fuel consultant to
provide updated electricity price projections in the following circumstances:
(1) if we reasonably believe that updated projections are necessary to allow
us to make certifications for purposes of making distributions; and
(2) every three years if required to support those certifications.
We also may be required to obtain a forecast prepared by the independent
electricity market and fuel consultant supporting the operating revenue
calculations prepared for the purpose of determining whether we are permitted to
incur Additional Indebtedness.
ADDITIONAL COVENANTS OF US
We also must:
(1) maintain our existence and properties;
(2) obtain, maintain and comply with all necessary governmental approvals;
(3) comply with applicable laws;
(4) maintain insurance for our project;
(5) keep the bonds equivalent in right of payment and ability to share in
the collateral with our other senior debt;
(6) deliver financial statements, notices of default, construction reports,
notices of power purchase agreement buy-outs and other documents to the
trustee;
(7) construct our project in a timely manner in accordance with applicable
law, prudent utility practices, governmental approvals and the Project
Documents;
(8) operate and maintain our project in compliance with prudent utility
practices, applicable laws, governmental approvals and the Project
Documents;
(9) deliver annual operating budgets to the trustee, the collateral agent,
the independent engineer for our project and the Rating Agencies;
(10) prepare a major maintenance plan;
155
<PAGE>
(11) submit an annual report covering the status of the insurance for our
project;
(12) provide the independent engineer for our project, the trustee and the
collateral agent reasonable inspection rights and the right to witness
the performance tests;
(13) maintain our EWG status and our project's Eligible Facility status;
(14) pay our taxes; and
(15) use the proceeds from the sale of the bonds only for the purposes set
forth in the indenture.
We also cannot engage in the following activities:
(1) conducting any business other than the construction, ownership,
operation, maintenance, administration, financing and expansion of our
project;
(2) making investments other than Permitted Investments;
(3) entering into non-arm's-length transactions with affiliates; and
(4) establishing employee benefit plans which result in the imposition of
material liabilities on us.
The affirmative and negative covenants described above are affected by a
number of important qualifications and exceptions which are set forth in full in
the indenture.
COVENANTS OF THE FUNDING CORPORATION
The Funding Corporation must:
(1) maintain its existence and properties;
(2) obtain, maintain and comply with governmental approvals;
(3) comply with applicable laws; and
(4) pay its taxes.
The Funding Corporation cannot engage in the following activities:
(1) incurring any Indebtedness other than Permitted Indebtedness (which will
be aggregated with all Permitted Indebtedness incurred by us whenever any
Permitted Indebtedness is limited by an aggregate dollar limitation);
(2) creating any Liens on its properties other than Permitted Liens;
(3) engaging in any business other than the financing of our project;
(4) merging, consolidating, changing its form of organization or liquidating
or dissolving itself;
(5) entering into non-arm's-length transactions with affiliates; and
(6) making any investments other than Permitted Investments.
The affirmative and negative covenants of the Funding Corporation described
above are affected by a number of important qualifications and exceptions which
are set forth in full in the indenture.
EVENTS OF DEFAULT AND REMEDIES
Each of the following events is an event of default under the indenture (an
"Event of Default"):
- we or the Funding Corporation fails to pay or cause to be paid any
principal of, premium, if any, or interest on any bond when the same
becomes due and payable, whether by scheduled maturity or required
redemption or by acceleration or otherwise, and such failure continues
uncured for 15 or more days; or
- we make, or the Funding Corporation makes, a misrepresentation that
results in, or is reasonably expected to result in, a Material Adverse
Effect, and the misrepresentation or
156
<PAGE>
Material Adverse Effect is not cured within 30 days, unless we or the
Funding Corporation, as applicable, are diligently trying to cure the
misrepresentation or Material Adverse Effect, in which case an Event of
Default will not occur for an additional 90 days; or
- we fail to perform or observe our covenant in the indenture to maintain
adequate insurance for our project; PROVIDED, HOWEVER, that we will have
five Business Days to correct or cause to be corrected any error in any
endorsement (without regard to the date that we obtained knowledge of the
error) before an Event of Default occurs; or
- either we or the Funding Corporation fail to perform or observe in any
material respect any covenant or agreement contained in the indenture
related to maintenance of existence, use of proceeds, Indebtedness, Liens,
nature of business, fundamental changes, sales of assets, investments or
additional documents, and this failure continues uncured for 30 or more
days after we or the Funding Corporation, as applicable, has knowledge of
the failure; or
- we or the Funding Corporation fail to perform or observe in any material
respect any of our or its other covenants contained in the indenture or
any other financing document and this failure is not cured within 30 days,
unless we or the Funding Corporation, as applicable, are diligently trying
to cure the failure, in which case an Event of Default will not occur for
an additional 180 days; or
- events of bankruptcy or insolvency with respect to us or the Funding
Corporation occur; or
- any Lien granted in the Security Documents ceases to be a perfected Lien
in favor of the collateral agent on any material portion, taken
individually or in the aggregate, of the collateral described in the
security documents (other than with respect to property or assets which
the terms of the financing documents permit us to convey or transfer) with
the priority purported to be created by the Security Documents; or
- any of the following circumstances (x) occurs with respect to any
Transaction Document, (y) would reasonably be expected to result in a
Material Adverse Effect and (z) is not cured within 180 days in accordance
with the terms of the indenture:
(a) a term of the Transaction Document (1) ceases to be a valid and
binding obligation of the parties to the Transaction Document or
(2) is declared unenforceable by a governmental authority; or
(b) the Transaction Document is terminated prior to its normal
expiration, which, in the case of any Power Purchase Agreement, will
be deemed to be its initial term, without giving effect to any
extension; or
(c) a Project Party denies its liability under a Project Document or
defaults on its obligation under a Project Document and any
applicable grace or cure period has expired; or
- we or the Funding Corporation fail to make any payment in respect of any
Indebtedness, including Permitted Indebtedness, having an outstanding
principal amount of more than $10,000,000 (other than any amount referred
to above) when due (after the expiration of any applicable grace period),
and a default and acceleration is declared with respect to such
Indebtedness; or
- a final and non-appealable judgment or judgments for the payment of money
in excess of $10,000,000 is rendered against us or the Funding
Corporation, and the same remains unpaid or unstayed for a period of 90 or
more consecutive days after it is due and payable; or
- LSP Batesville Holding fails to pay or cause to be paid when due any
portion of the Total Equity Amount; or
- an Event of Abandonment occurs.
157
<PAGE>
In the case of an Event of Default arising from events of bankruptcy or
insolvency with respect to us or the Funding Corporation, all outstanding bonds
will become immediately due and payable without further action or notice. In the
case of an Event of Default arising from a failure to pay principal of, premium,
if any, or interest on the bonds, holders of at least 33 1/3% in principal
amount of the then outstanding bonds may declare the bonds to be immediately due
and payable. In the case of any other Event of Default, holders of at least a
majority in principal amount of the then outstanding bonds may declare the bonds
to be immediately due and payable. However, the exercise of remedies by the
trustee or the holders following an Event of Default must be in accordance with
the provisions of the Intercreditor Agreement, which are described below under
the caption "--Intercreditor Agreement."
The holders of not less than a majority in aggregate principal amount of the
bonds outstanding may on behalf of the holders of all bonds waive any past
Default or Event of Default and its consequences, except that (1) only the
holders of all bonds affected may waive a Default or an Event of Default in the
payment of the principal of and interest on, or other amounts due under, any
outstanding bond, and (2) except as provided in clause (1), only the holders of
all outstanding bonds affected may waive a Default or an Event of Default in
respect of a covenant or provision that under the indenture cannot be modified
or amended without the consent of the holder of each outstanding bond affected.
DEFEASANCE
We and the Funding Corporation may, at any time, terminate all of our and
the Funding Corporation's obligations under the indenture, the bonds and the
other financing documents which the bonds enjoy the benefit of, and may
terminate the Liens of the Security Documents on the collateral to the extent
that the Liens run to the benefit of the trustee, the bondholders or other
agents under the indenture (a "Legal Defeasance"). In addition, we and the
Funding Corporation may terminate, at any time, our and the Funding
Corporation's obligations under any of the covenants under the indenture, the
bonds and the other financing documents which the bonds enjoy the benefit of,
and may terminate the Liens of the Security Documents on the collateral to the
extent that the Liens run to the benefit of the trustee, the bondholders or
other agents under the indenture, other than the covenants to maintain our and
the Funding Corporation's existence and to make payments on the bonds out of the
trusts described below (a "Covenant Defeasance").
Each of the Legal Defeasance or the Covenant Defeasance may be exercised
only if:
- the Funding Corporation or we have irrevocably deposited or caused to be
deposited in trust with the trustee cash, non-callable United States
government obligations or a combination of trustee cash and non-callable
United States government obligations in amounts as will be sufficient, in
the opinion of a nationally recognized firm of independent accountants, to
pay the principal of and interest on the bonds when due;
- the Funding Corporation or we have delivered to the trustee an opinion of
counsel to the effect that as of the date of the opinion, (1) the trust
funds will not be affected by the rights of holders of Indebtedness other
than the bonds and (2) other than customary assumptions and exceptions,
the trust funds will not, on the 91st day following the deposit, be
affected by any applicable bankruptcy, insolvency, reorganization or
similar law affecting creditors' rights generally;
- no Default or Event of Default has occurred and is continuing on the date
of the deposit (other than from the incurrence of debt the proceeds of
which will be used to defease the bonds);
- the Legal Defeasance or Covenant Defeasance does not result in a breach or
violation of, or constitute a default under, any material agreement or
instrument (other than the financing documents) to which we or the Funding
Corporation is a party or by which we or the Funding Corporation is bound;
158
<PAGE>
- in the case of a Legal Defeasance, the Funding Corporation or we have
delivered to the trustee an opinion of counsel confirming that (a) the
Funding Corporation or we have received from, or there has been published
by, the Internal Revenue Service a ruling or (b) since the date of the
indenture there has been a change in the applicable federal income tax
law, in either case to the effect that, and based thereon such opinion of
counsel will confirm that, the holders will not recognize income, gain or
loss for federal income tax purposes as a result of the Legal Defeasance
and will have to pay federal income tax on the same amounts, in the same
manner and at the same times as would have been the case if the Legal
Defeasance had not occurred;
- in the case of a Covenant Defeasance, the Funding Corporation or we have
delivered to the trustee an opinion of counsel confirming that the holders
of the bonds will not recognize income, gain or loss for federal income
tax purposes as a result of the Covenant Defeasance and will have to pay
federal income tax on the same amounts, in the same manner and at the same
times as would have been the case if the Covenant Defeasance had not
occurred; and
- the Funding Corporation or we have delivered to the trustee an officer's
certificate and opinion of counsel each stating that all conditions
precedent which relate to either the Legal Defeasance or the Covenant
Defeasance, as the case may be, have been complied with.
VIRGINIA POWER L/C AGREEMENT
GENERAL
We have entered into the Virginia Power L/C Agreement under which the
Virginia Power L/C Provider has issued and will issue letters of credit for our
account in favor of Virginia Power to satisfy our obligation to provide credit
support under the Virginia Power PPA. Our obligations under the Virginia Power
L/C Agreement are Senior Secured Obligations and rank equal in right of payment
with, and share equally and ratably in the collateral with, the bonds.
VIRGINIA POWER LETTERS OF CREDIT
The Virginia Power letters of credit available to us under the Virginia
Power L/C Agreement include:
- a letter of credit in an initial amount of $5,660,000 issued in favor of
Virginia Power to satisfy our obligation to provide completion security
for the generating units dedicated to Virginia Power prior to the
Commercial Operation Date for the Virginia Power dedicated units (the
"Pre-COD Virginia Power L/C");
- a letter of credit in an initial amount of $5,660,000 in favor of Virginia
Power to satisfy our obligation to provide completion security for our
replacement power obligations prior to the Commercial Operation Date for
the Virginia Power dedicated units (the "Replacement Power Virginia Power
L/C"); and
- a letter of credit in an initial amount of $5,660,000 in favor of Virginia
Power to satisfy our obligation to provide completion security for the
Virginia Power dedicated units on and after the Commercial Operation Date
for the Virginia Power dedicated units (the "Post-COD Virginia Power
L/C").
The Pre-COD Virginia Power L/C was issued on August 28, 1998 and will
terminate on the earlier of (1) June 1, 2001 and (2) the Commercial Operation
Date for the Virginia Power dedicated units. The Replacement Power Virginia
Power L/C will be available on any date on which we are obligated to provide
completion security for our replacement power obligations under the Virginia
Power PPA until the earlier of (1) June 1, 2001 and (2) the Commercial Operation
Date for the Virginia Power dedicated units. The Post-COD Virginia Power L/C
will be available on the Commercial Operation Date for the Virginia Power
dedicated units until three years after the earlier of (1) June 1, 2000 and
(2) the Commercial Operation Date for the Virginia Power dedicated units.
159
<PAGE>
REPAYMENT
Any drawings under the Pre-COD Virginia Power L/C or the Replacement Power
Virginia Power L/C will be converted to loans ("LOC Loans") made to us by the
banks under the Virginia Power L/C Agreement. We will not be required to make
principal payments on outstanding LOC Loans prior to the earlier of
(1) June 1, 2001 and (2) the Commercial Operation Date for the Virginia Power
dedicated units. On and after the earlier of those dates, we will be required to
make quarterly payments of principal and interest on each LOC Loan in 20
mortgage type installments. Each LOC Loan will bear interest on the outstanding
principal amount from the date the LOC Loan is made until the principal amount
is paid in full, at a rate per annum equal to (1) the Base Rate plus the
Applicable Margin or (2) the LIBOR Rate plus the Applicable Margin, at our
election.
The "Base Rate" will be equal to the higher of (x) the prime commercial
lending rate published in the Eastern Edition of The Wall Street Journal and
(y) the rate equal to the Federal Funds Rate plus 1/2 of 1%.
The "LIBOR Rate" will be determined by the agent under the Virginia Power
L/C Agreement and will be equal to the offered rate for deposits in U.S. dollars
in the London Interbank Market at approximately 11:00 a.m. (London time), which
appears on the Reuters Monitor Money Rates Services, two Business Days prior to
the first day of the interest period for the LIBOR Rate LOC Loan, divided by
100% minus the reserve requirement for the LIBOR Rate LOC Loan for the interest
period.
The "Applicable Margin" for Base Rate LOC Loans ranges from 0.625% to 0.875%
per annum and the "Applicable Margin" for LIBOR Rate LOC Loans ranges from 1.50%
to 1.75% per annum.
COMMON AGREEMENT
GENERAL
We entered into the Common Agreement with the administrative agent, the
collateral agent, the intercreditor agent, and the Funding Corporation on
May 21, 1999. The Common Agreement sets forth, among other things, the terms
upon which Operating Revenues, Equity Contributions and other amounts received
by us or on our behalf are disbursed to pay construction costs, operation and
maintenance costs, debt service and other amounts due from us.
DEPOSIT AND DISBURSEMENT OF FUNDS
We must deposit into the Revenue Account all Operating Revenues, all
post-completion delay damages under the Construction Contract and all other
amounts required to be transferred to the Revenue Account under the Common
Agreement or the Intercreditor Agreement. The administrative agent will disburse
funds from the Revenue Account on the 15th day of each calendar month, or, if
such day is not a business day, on the next succeeding business day (or more
frequently if necessary to pay amounts described under clauses (1) and (2) of
priority THIRD) as follows:
- FIRST:
(1) to the O&M Account in an amount sufficient to pay all O&M Costs,
other than Operator Fees, due and payable on the disbursement date or
reasonably expected to be due and payable within the next 30 days, to the
extent the O&M Costs will not be paid for with the proceeds of loans made
under the Working Capital Agreement; and
(2) at our election, to the prepayment of amounts outstanding under the
Working Capital Agreement if and to the extent that we are entitled to
re-borrow the prepaid amounts under the Working Capital Agreement;
160
<PAGE>
- SECOND, if the disbursement date occurs prior to the Completion Date, to
the Construction Account in an amount equal to all amounts then remaining
in the Revenue Account;
- THIRD:
(1) to the agent under the Virginia Power L/C Agreement in an amount
sufficient to pay all reimbursement obligations, other than reimbursement
obligations which have been converted into a term loan, then due under the
Virginia Power L/C Agreement;
(2) to the agent under any agreement providing for an Aquila Reserve L/C
(if we or the Funding Corporation are obligated for the reimbursement of any
draw under that letter of credit) in an amount sufficient to pay all
reimbursement obligations, other than reimbursement obligations which have
been converted into a term loan, then due under that agreement; and
(3) if then required under the Aquila PPA, to the Aquila PPA Reserve
Account in an amount which, together with all funds in that account and all
amounts available for drawing under any Aquila Reserve L/C, is equal to the
then current Aquila PPA Reserve Requirement;
- FOURTH, to the Debt Service Payment Account in an amount equal to the
following with respect to each credit facility (including each series of
bonds) constituting Senior Indebtedness: (1) an amount equal to the Senior
Secured Obligations Payments for such month, PLUS (2) interest, principal
and other amounts scheduled to come due on any Senior Indebtedness during
the period from and including that disbursement date through but excluding
the next disbursement date and not otherwise accounted for under
clause (1), together with any additional amount under this clause (2) as
we deem prudent to deposit in respect of Senior Indebtedness not otherwise
accounted for under this clause (2); PROVIDED, HOWEVER, that principal of
Debt Service Reserve LOC Loans will not be paid under this priority
FOURTH, but principal of Debt Service Reserve LOC Bonds will be paid under
this priority FOURTH;
- FIFTH, to the Major Maintenance Reserve Account in an amount equal to the
Major Maintenance Reserve Requirement;
- SIXTH:
(1) first to the Debt Service Reserve Account in an amount which,
together with all funds in this account and all amounts available for
drawing under any Debt Service Reserve L/C, is equal to the then current
Debt Service Reserve Requirement; and
(2) second, to the DSRA LOC Payment Account in an amount which, together
with all funds in this account, is equal to the principal amount of
outstanding Debt Service Reserve LOC Loans for which we or the Funding
Corporation are obligated;
- SEVENTH, to the operator of our project in an amount sufficient to pay the
Operator Fee then due and payable to the operator under the O&M Agreement;
and
- EIGHTH, to the Distribution Suspense Account in an amount equal to all
monies left over in the Revenue Account after application of priority
FIRST through priority SEVENTH.
161
<PAGE>
The following chart shows the priority of transfers and payments from the
Revenue Account.
[CHART]
162
<PAGE>
CONSTRUCTION ACCOUNT
We have deposited the net proceeds of the private bonds, and will deposit
all Ordinary Equity Contributions, all Net Pre-Completion Revenues and all delay
liquidated damages and similar payments received prior to Completion into the
Construction Account. Until the Completion Date, all amounts in the Construction
Account will be available for withdrawal only (1) for the payment of Project
Costs due and payable on the date of withdrawal or reasonably expected to be due
and payable within the next 30 days and (2) to make the deposit into the account
which we may establish for the benefit of the State of Mississippi and/or Panola
County, as described under the caption "Use of Proceeds".
We will be permitted to withdraw funds from the Construction Account to pay
Project Costs if we deliver the following documents to the administrative agent:
- a requisition certificate signed by one of our authorized officers which,
among other things:
(a) specifies the Project Costs that are due on the date of withdrawal or
are reasonably expected to become due within the next 30 days;
(b) certifies that construction of our power facility and the Panola
County infrastructure are proceeding in accordance with their budgets
and schedules;
(c) certifies that no Default or Event of Default has occurred and is
continuing; and
(d) certifies that the funds in the Construction Account and all other
funds available to pay Project Costs are sufficient to achieve
Completion on or prior to the Date Certain.
- a certificate of the independent engineer which, among other things:
(a) states that Completion is estimated to occur on or prior to the Date
Certain;
(b) confirms that no errors in the requisition certificate described
above have come to the attention of the independent engineer;
(c) certifies that construction of our power facility and the Panola
County infrastructure is proceeding in a workmanlike manner in
accordance with their budgets and schedules; and
(d) confirms that the funds available to pay the remaining Project Costs
are sufficient to achieve Completion on or prior to the Date Certain.
On the Completion Date, all funds in the Construction Account will first be
transferred to the Debt Service Reserve Account until the funds in that account
are equal to the Debt Service Reserve Requirement. Any remaining funds to the
Revenue Account for application in accordance with the priority of payments
described above under the caption "--Deposit and Disbursement of Funds."
O&M ACCOUNT
Amounts on deposit in the O&M Account will be available to us to pay O&M
Costs which are due and payable at the time of withdrawal, or are reasonably
expected to be due and payable within the next 30 days, other than the Operator
Fee and the major maintenance expenditures funded through the Major Maintenance
Reserve Account. The administrative agent will be required to disburse amounts
from the O&M Account upon our delivery of an officer's certificate specifying
the amount to be disbursed and the name of, and wire transfer or other payment
instructions for, each person to whom such amounts should be paid. Funds may be
disbursed from the O&M Account more often than monthly if necessary to pay O&M
Costs, other than the Operator Fee, which are due and payable on the date of
disbursement.
163
<PAGE>
DEBT SERVICE PAYMENT ACCOUNT
All amounts on deposit in the Debt Service Payment Account will be used to
pay the principal of, premium, if any, interest, fees, indemnities and other
amounts then due in respect of the bonds, the Virginia Power Letters of Credit
and the other Senior Indebtedness (but not the principal of Debt Service Reserve
LOC Loans).
DSRA LOC PAYMENT ACCOUNT
All amounts on deposit in the DSRA LOC Payment Account will be used to pay
the principal of Debt Service Reserve Loans then due.
RESERVE ACCOUNTS
DEBT SERVICE RESERVE ACCOUNT
The "Debt Service Reserve Requirement" for any disbursement date will be an
amount equal to:
(a) one-sixth of the difference between (x) (1) if the disbursement date is
not a Scheduled Payment Date for the bonds, the principal and interest which
will be due on the Senior Secured Obligations on or before the next Scheduled
Payment Date for the bonds and (2) if the disbursement date is a Scheduled
Payment Date for the bonds, the principal and interest which is due and payable
on the Senior Secured Obligations on such date and (y) the amount of funds
already on deposit in the Debt Service Reserve Account on the previous Scheduled
Payment Date for the bonds,
PLUS
(b) any shortfall in the funding of such amounts from any previous month
since the previous Scheduled Payment Date for the bonds.
We and the Funding Corporation, or any of our affiliates, may fund the Debt
Service Reserve Requirement with cash or one or more Debt Service Reserve L/Cs
as and to the extent provided under "--Letters of Credit." Funds in the Debt
Service Reserve Account will be used to pay Senior Debt Service if funds in the
Debt Service Payment Account are insufficient to make the payments. The
collateral agent will withdraw funds from the Debt Service Reserve Account and
draw on any Debt Service Reserve L/C on a pro rata basis to the extent possible.
MAJOR MAINTENANCE RESERVE ACCOUNT
The "Major Maintenance Reserve Requirement" initially will be equal to
$1,215,000 per month. We may at our option adjust the Major Maintenance Reserve
Requirement, and are required to do so if we determine that the current Major
Maintenance Reserve Requirement for each month will not provide sufficient
funding for the completion of all turbine overhauls through and including the
next major overhaul, by providing the independent engineer with a proposed new
schedule of monthly deposits to the Major Maintenance Reserve Account. The
monthly deposits reflected in this proposed schedule need not be equal, but they
must provide sufficient funds for the completion of all turbine overhauls
through and including the next major overhaul. If the independent engineer
approves this proposed schedule, then the monthly deposits reflected in the
schedule will become the Major Maintenance Reserve Requirement for each month.
Funds in the Major Maintenance Reserve Account will be used to pay the costs of
major maintenance activities for the project.
AQUILA PPA RESERVE ACCOUNT
The Aquila PPA Reserve Requirement will be equal to the amount of credit
support that the Aquila PPA requires us to provide to Aquila/UtiliCorp. We can
provide an Aquila Reserve L/C in lieu of depositing funds in the Aquila PPA
Reserve Account, or can provide an Aquila Reserve L/C in order
164
<PAGE>
to withdraw all or a portion of the funds on deposit in the Aquila PPA Reserve
Account, in each case as and to the extent provided under the caption "--Letters
of Credit." Funds in the Aquila PPA Reserve Account will be used to make
payments to Aquila as required under the Aquila PPA. If at the end of any
disbursement date, the Aquila PPA Reserve Requirement is less than the funds on
deposit in or credited to the Aquila PPA Reserve Account, all funds on deposit
in the Aquila PPA Reserve Account in excess of the Aquila PPA Reserve
Requirement will be transferred to the Revenue Account and/or we may substitute
a new Aquila Reserve L/C in a lesser amount.
LETTERS OF CREDIT
Instead of depositing cash to maintain the Debt Service Reserve Requirement
and/or the Aquila PPA Reserve Requirement, we may provide or cause to be
provided one or more irrevocable direct pay letters of credit (with respect to
the Debt Service Reserve Requirement, a "Debt Service Reserve L/C" and with
respect to the Aquila PPA Reserve Requirement, an "Aquila Reserve L/C" and,
collectively with the Debt Service Reserve L/C, the "Reserve Account L/Cs")
issued by a bank or other financial institution rated at least A- by S&P and at
least A3 by Moody's and naming the collateral agent as beneficiary. In addition,
we may provide or cause to be provided a Debt Service Reserve L/C or an Aquila
Reserve L/C in substitution for all or a portion of amounts then on deposit in
the Debt Service Reserve Account or the Aquila PPA Reserve Account, as
applicable. Provided that neither we nor the Funding Corporation has any
reimbursement or other payment obligation in respect of any such Debt Service
Reserve L/C or Aquila Reserve L/C furnished in substitution for amounts so on
deposit, such amounts will be released from the accounts and distributed to or
at the our direction without regard to any limitations on distributions
contained in the financing documents. Any Reserve Account L/C for which we or
the Funding Corporation has any reimbursement or other obligation must be issued
under a reimbursement agreement which contains terms and conditions customary
for facilities of this type. Neither we nor the Funding Corporation can be
liable for the reimbursement of any draws under, or for any other costs in
respect of, any Reserve Account L/C unless (1) the independent engineer for our
project confirms that the minimum Senior Debt Service Coverage Ratio for any
fiscal year during the remaining term of the bonds is greater than or equal to
1.45:1.00 and (2) the naming of us or the Funding Corporation, as applicable, as
the account party for the Debt Service Reserve L/C or Aquila Reserve L/C, as
applicable, will not result in a Ratings Downgrade.
Each drawing under a Debt Service Reserve L/C in respect of which we or the
Funding Corporation has responsibility for reimbursement or the payment of other
costs will be converted into a Debt Service Reserve LOC Loan. Each Debt Service
Reserve LOC Loan will mature not less than five years after the drawing giving
rise to that Debt Service Reserve LOC Loan.
The issuer of the Debt Service Reserve L/C may be permitted to convert its
Debt Service Reserve LOC Loans into a substitute loan (a "Debt Service Reserve
LOC Bond") which will amortize, will mature on the maturity date of the last
series of bonds to mature, and will bear interest at a rate to be negotiated
with the issuer of the Debt Service Reserve L/C. We will pay principal of and
interest on the Debt Service Reserve LOC Bonds on each Scheduled Payment Date
for the bonds under priority FOURTH under the caption "--Deposit and
Disbursement of Funds."
DISTRIBUTION SUSPENSE ACCOUNT
The Distribution Suspense Account will be funded with amounts remaining in
the Revenue Account after all required disbursements have been made as described
above under "--Deposit and Disbursement of Funds." On any date which is the 15th
day of the month (or, if that day is not a business day, on the next succeeding
business day) and on which the Distribution Conditions are
165
<PAGE>
satisfied, the following amount will be transferred to the "Distribution
Account" for distribution to or as directed by us:
(1) the sum of (a) the funds in the Distribution Suspense Account and
(b) the aggregate of all funds in the Debt Service Reserve Account and the
Debt Service Payment Account; less
(2) the sum of (a) the Debt Service Reserve Requirement as of the next
Scheduled Payment Date for the bonds (or, if that distribution date is a
Scheduled Payment Date for the bonds, the Debt Service Reserve Requirement
as of that date), (b) the Senior Indebtedness due and payable on the next
Scheduled Payment Date for the bonds and (c) the Senior Indebtedness due and
payable from and after the date of determination and prior to the next
Scheduled Payment Date for the bonds.
PERMITTED INVESTMENTS
Funds in the Accounts will be invested and reinvested in Permitted
Investments at our written direction, which may be in the form of a standing
instruction. However, if an Event of Default exists or we have not timely
furnished a written direction or confirmed a standing instruction to the
administrative agent, the administrative agent will invest these amounts only in
Permitted Investments with a maturity of (1) 180 days or less prior to the
Completion Date or (2) one year or less after the Completion Date. Any of our
written directions with respect to the investment or reinvestment of amounts
held in any Account must direct investment or reinvestment only in Permitted
Investments that mature in amounts and have maturity dates or can be redeemed at
the option of the holder on or prior to maturity as needed for the purposes of
the Accounts. No Permitted Investments will mature more than (1) prior to the
Completion Date, 180 days after the date acquired or (2) after the Completion
Date, one year after the date acquired. Any income or gain realized from these
investments will be deposited into the Account, or the sub-fund or sub account,
from which the amounts came.
COLLATERAL AGENCY AGREEMENT
We and Funding Corporation entered into the Collateral Agency Agreement with
the trustee, the collateral agent, the intercreditor agent, the administrative
agent, and the Virginia Power L/C Agent on May 21, 1999. In addition, we may
cause each Additional Indebtedness Agent, on behalf of each Additional
Indebtedness Holder, to become a party to the Collateral Agency Agreement.
Pursuant to the Collateral Agency Agreement, the Senior Secured Parties, or
their representatives party thereto, appoint the collateral agent to hold and
administer the collateral that secures our obligations to them and to enter into
and exercise remedies under the Security Documents on behalf of the Senior
Secured Parties.
The collateral agent will apply the proceeds of any collection, sale or
other realization of all or any part of that collateral under the Security
Documents as follows:
- FIRST, to the payment of all reasonable costs and expenses relating to the
sale of the Collateral and the collection of amounts owing under the
Collateral Agency Agreement or relating to the protection of the liens of
the Security Documents, and all liability payments covered by the
indemnity provisions of the financing documents;
- SECOND, to the payment of accrued and unpaid interest on interest that
became overdue on the Senior Secured Obligations, ratably, in an amount
necessary to make the Senior Secured Parties current on interest on
overdue interest to the same proportionate extent as the other Senior
Secured Parties are then current on interest on overdue interest due;
- THIRD, to the payment of accrued and unpaid interest on principal of the
Senior Secured Obligations that became overdue, ratably, in an amount
necessary to make the Senior Secured
166
<PAGE>
Parties current on interest on overdue principal due to the same
proportionate extent as the other Senior Secured Parties are then current
on interest on overdue principal due;
- FOURTH, to the payment of any accrued but unpaid commitment fees or other
fees for working capital facilities and letters of credit;
- FIFTH, to the payment of the remaining Senior Secured Obligations
outstanding; and
- FINALLY, to the payment to us or our successors or assigns, or as a court
of competent jurisdiction may direct, of any surplus then remaining.
INTERCREDITOR AGREEMENT
All of the existing senior secured parties, or an agent or trustee acting on
their behalf, entered into the intercreditor agreement on the closing date for
the private bonds. The existing senior secured parties include the bondholders,
the bank which issued the standby letter of credit in favor of Virginia Power,
the trustee for the bondholders, the collateral agent, the intercreditor agent
and the securities intermediary. The intercreditor agreement includes, among
other things:
- the appointment of the intercreditor agent to act on behalf of the other
senior secured parties in matters that involve more than one senior
secured party or group of senior secured parties;
- provisions regarding the sharing of the collateral among the senior
secured parties;
- the procedures for voting by the senior secured parties on matters that
involve more than one senior secured party or group of senior secured
parties;
- the percentage of senior secured parties required to exercise remedies
upon the occurrence of an event of default under a financing document; and
- the percentage of senior secured parties required to amend financing
documents under which more than one senior secured party or group of
senior secured parties has rights.
The percentages of senior secured parties required to exercise remedies and
approve amendments to the financing documents are as follows:
- the affirmative vote of persons holding at least 33 1/3% of the Senior
Secured Obligations will be required to exercise remedies upon the
occurrence of an Event of Default, or event of default under another
facility which is a Senior Secured Obligation, relating to payment;
- the affirmative vote of persons holding greater than 50% of the Senior
Secured Obligations will be required to exercise remedies upon the
occurrence of any other Event of Default, or event of default under
another facility which is a Senior Secured Obligation;
- the affirmative vote of persons holding greater than 50% of the Senior
Secured Obligations will be required to amend financing documents and
grant consents and approvals thereunder, other than with respect to
certain fundamental decisions and with respect to financing documents,
such as the indenture, specific to a particular facility constituting
Senior Secured Obligations; and
- the affirmative vote of persons holding 100% of the Senior Secured
Obligations will be required to amend financing documents and grant
consents and approvals with respect to fundamental decisions under the
financing documents, including, without limitation, amendments, consents
and approvals resulting in the release of collateral which secures the
bonds.
167
<PAGE>
EQUITY ARRANGEMENTS
EQUITY COMMITMENT OBLIGATION
Pursuant to the Equity Contribution Agreement executed by LSP Batesville
Holding on May 21, 1999 in favor of us and the collateral agent for the benefit
of the bondholders and the other Senior Secured Parties, LSP Batesville Holding
is required to make cash equity contributions to us in an aggregate amount of
$54,000,000 (the "Total Equity Amount") from time to time after depletion of the
proceeds of the bonds as requested by us to pay Project Costs.
LSP Batesville Holding is also required to make a cash equity contribution
in an amount equal to the Total Equity Amount less all previous equity
contributions upon the earliest to occur of the following events:
- an Event of Default;
- the bankruptcy or insolvency of LSP Batesville Holding;
- the withdrawal of all proceeds of the bonds from the Construction Account
and our failure to request an equity contribution within 45 days after
that withdrawal;
- the Completion Date;
- the Date Certain;
- a downgrade of the ratings of the bank providing the Equity Letter of
Credit below "A" by S&P and "A2" by Moody's and a failure by LSP
Batesville Holding to replace the Equity Letter of Credit within 30 days
of such downgrade; and
- the termination or expiration of the Equity Letter of Credit and the
failure by LSP Batesville Holding to replace the Equity Letter of Credit
within 30 days prior to that termination or expiration.
Any default equity contribution will be applied to pay Project Costs and/or
to redeem the bonds and prepay other outstanding Senior Secured Obligations as
determined by the Senior Secured Parties under the Intercreditor Agreement.
EQUITY LETTER OF CREDIT
The Equity Contribution Agreement requires LSP Batesville Holding to deliver
on May 21, 1999 a letter of credit to support its obligation to contribute
equity to us. The Equity Letter of Credit delivered on May 21, 1999 names
Cogentrix as the account party and the collateral agent as the beneficiary, and
is issued by ANZ Investment Bank, a subsidiary of Australia and New Zealand
Banking Group Limited. The collateral agent is permitted to draw on the Equity
Letter of Credit upon any failure by LSP Batesville Holding to make a required
equity contribution to us under the Equity Contribution Agreement.
168
<PAGE>
FEDERAL INCOME TAX CONSIDERATIONS
The following is a discussion of the material federal income and estate tax
considerations relevant to you if you exchange private bonds for exchange bonds.
The discussion is based upon the Internal Revenue Code of 1986, as amended,
Treasury regulations, Internal Revenue Service rulings and pronouncements, and
judicial decisions now in effect, all of which could be changed at any time by
legislative, judicial or administrative action. Any such changes may be applied
retroactively in a manner that could adversely affect tax consequences to you.
The description does not consider the effect of any applicable foreign, state,
local or other tax laws or estate or gift tax considerations.
YOU SHOULD CONSULT YOUR OWN TAX ADVISOR AS TO THE PARTICULAR TAX
CONSEQUENCES TO YOU OF EXCHANGING PRIVATE BONDS FOR EXCHANGE BONDS AND OWNING
AND DISPOSING OF THE EXCHANGE BONDS, INCLUDING THE APPLICABILITY AND EFFECT OF
ANY STATE, LOCAL OR FOREIGN TAX LAWS.
EXCHANGE OF PRIVATE BONDS FOR EXCHANGE BONDS
The exchange of private bonds for exchange bonds in the exchange offer will
not constitute a sale or an exchange for federal income tax purposes. The holder
will have a basis for the exchange bonds equal to the basis of the private bonds
and the holder's holding period for the exchange bonds will include the period
during which the private bonds were held. Accordingly, such exchange will have
no federal income tax consequences to holders of private bonds.
EXCHANGE BONDS
This discussion assumes that you hold the exchange bonds as a "capital
asset," generally, for investment, under Section 1221 of the Internal Revenue
Code of 1986, as amended (the "Code"). It does not include all of the rules
which may affect the United States tax treatment of your investment in the
exchange bonds. For example, special rules not discussed here may apply to you
if you are:
- a broker-dealer, a dealer in securities or a financial institution;
- an S corporation;
- an insurance company;
- a tax-exempt organization;
- subject to the alternative minimum tax provisions of the Code;
- holding the exchange bonds as part of a hedge, straddle or other risk
reduction or constructive sale transaction; or
- a nonresident alien or foreign corporation subject to net-basis United
States federal income tax on income or gain derived from a exchange bond
because such income or gain is effectively connected with the conduct of a
United States trade or business.
UNITED STATES HOLDERS
If you are a "United States Holder," as defined below, this section applies
to you. Otherwise, the next section, "Non-United States Holders," applies to
you.
DEFINITION OF UNITED STATES HOLDER. You are a "United States Holder" if you
hold the exchange bonds and you are:
- a citizen or resident of the United States, including an alien individual
who is a lawful permanent resident of the United States or meets the
"substantial presence" test under Section 7701(b) of the Code;
169
<PAGE>
- a corporation or partnership created or organized in the United States or
under the laws of the United States or of any political subdivision of the
United States;
- an estate the income of which is subject to United States federal income
tax regardless of its source; or
- a trust, if a United States court can exercise primary supervision over
the administration of the trust and one or more United States persons can
control all substantial decisions of the trust, or if the trust was in
existence on August 20, 1996 and has elected to continue to be treated as
a United States person.
TAXATION OF STATED INTEREST. You must generally pay federal income tax on
the interest on the exchange bonds:
- when it accrues, if you use the accrual method of accounting for United
States federal income tax purposes; or
- when you receive it, if you use the cash method of accounting for United
States federal income tax purposes.
SALE OR OTHER TAXABLE DISPOSITION OF THE EXCHANGE BONDS. You must recognize
taxable gain or loss on the sale, exchange, redemption, retirement or other
taxable disposition of an exchange bond. The amount of your gain or loss equals
the difference between the amount you receive for the exchange bond (in cash or
other property, valued at fair market value), minus the amount attributable to
accrued interest on the exchange bond, minus your adjusted tax basis in the
bond. Your initial tax basis in an exchange bond equals the price you paid for
the bond (subject to any adjustment under the market discount rules and the
acquisition premium rules discussed below).
Subject to the discussions under the market discount rules and the
acquisition premium rules discussed below, your gain or loss will generally be a
long-term capital gain or loss if you have held the exchange bond for more than
one year. Otherwise, it will be a short-term capital gain or loss. Payments
attributable to accrued interest which you have not yet included in income will
be taxed as ordinary interest income.
BOND PREMIUM AND MARKET DISCOUNT. If you purchased the private bonds at a
premium, you may make an election to treat such premium as "amortizable bond
premium." If the election is made, the amount of interest income that you must
include in its gross income with respect to the private bonds and the exchange
bonds for any taxable year will be reduced by the portion of such premium
properly allocable to such year. For this purpose, the amount of "amortizable
bond premium" will be the excess of the purchase price of the private bonds over
their principal amount payable at maturity (or, if it results in a smaller
amortizable bond premium attributable to the period of earlier call date, the
amount payable on the earlier call date). An election, once made, would apply to
all bonds (other than bonds the interest on which is excludable from gross
income) held by you at the beginning of the first taxable year to which the
election applies or which thereafter are acquired by you, and such election is
irrevocable without the consent of the IRS. If you consider such an election,
you are strongly advised to consult your own tax advisors.
Alternatively, if the purchase price of the private bonds being exchanged
for the exchange bonds was less than their principal amount (such difference
being the market discount), the private bonds and the exchange bonds may be
subject to the market discount rules. The market discount is generally deemed to
be zero if the amount of market discount is less than 0.0025 of the principal
amount multiplied by the number of complete years to maturity. If the private
bonds were purchased at a market discount, you generally would be required to
treat as ordinary income any gain recognized on the sale of the exchange bonds
to the extent of the "accrued market discount" on the exchange bonds (which will
include the market discount that accrued on the private bonds) at the time of a
disposition
170
<PAGE>
of the exchange bonds, unless you make an election to accrue market discount as
ordinary income over the term of the private bonds and the exchange bonds.
Market discount generally would be treated as accruing on a straight-line basis
over their term, or, at the holder's election, under a constant yield method. In
addition, if the private bonds were purchased at a market discount, you may be
required to defer the deduction of a portion of the interest on any indebtedness
incurred or maintained to purchase or carry the private bonds and the exchange
bonds until they are disposed of in a taxable transaction.
BACKUP WITHHOLDING. You may be subject to a 31% backup withholding tax when
you receive interest payments on the exchange bonds or proceeds upon the sale or
other disposition of an exchange bond. Certain holders (including, among others,
corporations and certain tax-exempt organizations) are generally not subject to
backup withholding. In addition, the 31% backup withholding tax will not apply
to you if you provide your taxpayer identification number ("TIN") in the
prescribed manner unless:
- the IRS notifies us or our agent that the TIN you provided is incorrect;
- you fail to report interest and dividend payments that you receive on your
tax return and the IRS notifies us or our agent that withholding is
required; or
- you fail to certify under penalties of perjury that you are not subject to
backup withholding.
If the 31% backup withholding tax does apply to you, you may use the amounts
withheld as a refund or credit against your United States federal income tax
liability as long as you provide certain information to the Internal Revenue
Service.
NON-UNITED STATES HOLDERS
DEFINITION OF NON-UNITED STATES HOLDER. A "Non-United States Holder" is any
person other than a United States Holder. Please note that if you are subject to
United States federal income tax on a net basis on income or gain with respect
to an exchange bond because such income or gain is effectively connected with
the conduct of a United States trade or business, this disclosure does not cover
the United States federal tax rules that apply to you.
INTEREST
PORTFOLIO INTEREST EXEMPTION. You will generally not have to pay United
States federal income tax on interest paid on the exchange bonds because of the
"portfolio interest exemption" if either:
- you represent that you are not a United States person for United States
federal income tax purposes and you provide your name and address to us or
our paying agent on a properly executed IRS Form W-8 (or a suitable
substitute form) signed under penalties of perjury: or
- a securities clearing organization, bank, or other financial institution
that holds customers' securities in the ordinary course of its business
holds the exchange bond on your behalf, certifies to us or our agent under
penalties of perjury that it has received IRS Form W-8 (or a suitable
substitute) from you or from another qualifying financial institution
intermediary, and provides a copy to us or our agent.
However, you will not qualify for the portfolio interest exemption described
above if:
- you own, actually or constructively, 10% or more of the total combined
voting power of all classes of our capital stock;
- you are a controlled foreign corporation with respect to which we are a
"related person" within the meaning of Section 864(d)(4) of the Code; or
- you are a bank receiving interest described in Section 881(c)(3)(A) of the
Code.
171
<PAGE>
WITHHOLDING TAX IF THE INTEREST IS NOT PORTFOLIO INTEREST. If you do not
claim, or do not qualify for, the benefit of the portfolio interest exemption,
you may be subject to a 30% withholding tax on interest payments made on the
exchange bonds. However, you may be able to claim the benefit of a reduced
withholding tax rate under an applicable income tax treaty. The required
information for claiming treaty benefits is generally submitted, under current
regulations, on Form 1001. Successor forms will require additional information,
as discussed below under the heading "--Non-United States Holders--New
Withholding Regulations."
REPORTING. We may report annually to the IRS and to you the amount of
interest paid to, and the tax withheld, if any, with respect to you.
SALE OR OTHER DISPOSITION OF THE EXCHANGE BONDS. You will generally not be
subject to United States federal income tax or withholding tax on gain
recognized on a sale, exchange, redemption, retirement, or other disposition of
an exchange bond. You may, however, be subject to tax on such gain if:
- you are an individual who was present in the United States for 183 days or
more in the taxable year of the disposition, in which case you may have to
pay a United States federal income tax of 30% (or a reduced treaty rate)
on such gain; or
- you are a United States expatriot who meets certain conditions.
UNITED STATES FEDERAL ESTATE TAXES. If you qualify for the portfolio
interest exemption under the rules described above when you die, the exchange
bonds will not be included in your estate for United States federal estate tax
purposes.
BACKUP WITHHOLDING AND INFORMATION REPORTING
PAYMENTS FROM UNITED STATES OFFICE. If you receive payments of interest or
principal directly from us or through the United States Office of a custodian,
nominee, agent or broker, there is a possibility that you will be subject to
both backup withholding at a rate of 31% and information reporting.
With respect to interest payments made on the exchange bonds, however,
backup withholding and information reporting will not apply if you certify,
generally on a Form W-8 or substitute form, that you are not a United States
person in the manner described above under the heading "--Non-United States
Holders--Interest."
Moreover, with respect to proceeds received on the sale, exchange,
redemption, or other disposition of an exchange bond, backup withholding or
information reporting generally will not apply if you properly provide,
generally on Form W-8 or a substitute form, a statement that you are an "exempt
foreign person" for purposes of the broker reporting rules, and other required
information. If you are not subject to United States federal income or
withholding tax on the sale or other disposition of an exchange bond, as
described above under the heading "--Non-United States Holder--Sale or Other
Disposition of Exchange Bonds," you will generally qualify as an "exempt foreign
person" for purposes of the broker reporting rules.
PAYMENTS FROM FOREIGN OFFICE. If payments of principal and interest are
made to you outside the United States by or through the foreign office of a
foreign custodian, nominee or other agent, or if you receive the proceeds of the
sale of an exchange bond through a foreign office of a "broker," as defined in
the pertinent United States Treasury Regulations, you will generally not be
subject to backup withholding or information reporting. You will, however, be
subject to backup withholding and information reporting if the foreign
custodian, nominee, agent or broker has actual knowledge or reason to know that
the payee is a United States person. You will also be subject to information
reporting, but not backup withholding, if the payment is made by a foreign
office of a custodian, nominee, agent or broker that is a United States person
or a controlled foreign corporation for United
172
<PAGE>
States federal income tax purposes, or that derives 50% of more of its gross
income from the conduct of a United States trade or business for a specified
three year period, unless the broker has in its records documentary evidence
that you are a Non-United States Holder and certain other conditions are met.
REFUNDS. Any amounts withheld under the backup withholding rules may be
refunded or credited against the Non-United States Holder's United States
federal income tax liability, provided that the required information is
furnished to the IRS.
NEW WITHHOLDING REGULATIONS. New regulations relating to withholding tax on
income paid to foreign persons (the "New Withholding Regulations") will
generally be effective for payments made after December 31, 2000. The New
Withholding Regulations modify and, in general, unify the way in which you
establish your status as a non-United States "beneficial owner" eligible for
withholding exemptions including the portfolio interest exemption, a reduced
treaty rate or an exemption from backup withholding. For example, the new
regulations will require new forms, which you will generally have to provide
earlier than you would have had to provide replacements for expiring existing
forms.
The New Withholding Regulations clarify withholding agents' reliance
standards. They also require additional certifications for claiming treaty
benefits. The New Withholding Regulations also provide somewhat different
procedures for foreign intermediaries and flow-through entities (such as foreign
partnerships) to claim the benefit of applicable exemptions on behalf of
non-United States beneficial owners for which or for whom they receive payments.
The New Withholding Regulations also amend the foreign broker office definition
as it applies to partnerships.
The New Withholding Regulations provide that certifications satisfying the
requirements of the New Withholding Regulations will be deemed to satisfy the
requirements of the Treasury Regulations now in effect. In any case, you will
generally be required to provide certifications that comply with the provisions
of the New Withholding Regulations, where required, not later than December 31,
2000, if you remain as a holder of the exchange bonds on that date, unless you
receive payments on the bonds through a qualified intermediary (as defined in
the New Withholding Regulations) that has provided a proper certification on
your behalf. If you are a Non-United States Holder claiming benefit under an
income tax treaty (and not relying on the portfolio interest exemption), you
should be aware that you may be required to obtain a taxpayer identification
number and to certify your eligibility under the applicable treaty's limitations
on benefits article in order to comply with the New Withholding Regulations'
certification requirements.
THE NEW WITHHOLDING REGULATIONS ARE COMPLEX AND THIS SUMMARY DOES NOT
COMPLETELY DESCRIBE THEM. PLEASE CONSULT YOUR TAX ADVISOR TO DETERMINE HOW THE
NEW WITHHOLDING REGULATIONS WILL AFFECT YOUR PARTICULAR CIRCUMSTANCES.
173
<PAGE>
PLAN OF DISTRIBUTION
Each broker-dealer that receives exchange bonds for its own account in the
exchange offer must acknowledge that it will deliver a prospectus for any resale
of those exchange bonds. This prospectus, as it may be amended or supplemented
from time to time, may be used by a broker-dealer for resales of exchange bonds
received in exchange for private bonds where the private bonds were acquired as
a result of market making activities or other trading activities. We have agreed
that this prospectus, as it may be amended or supplemented from time to time,
may be used by a participating broker-dealer for resales of exchange bonds for a
period ending 120 days after the registration statement of which this prospectus
is a part has been declared effective, subject to extension, or, if earlier,
when all exchange bonds have been disposed of by the participating
broker-dealer.
We will not receive any proceeds from any sale of exchange bonds by
broker-dealers or any other persons. Exchange bonds received by broker-dealers
for their own account in the exchange offer may be sold from time to time in one
or more transactions in the over-the-counter market, in negotiated transactions,
through the writing of options on the exchange bonds or a combination of those
methods of resale, at market prices prevailing at the time of resale, at prices
related to prevailing market prices or negotiated prices. Any such resale may be
made directly to purchasers or to or through brokers or dealers who may receive
compensation in the form of commissions or concessions from any broker-dealer
and/or the purchasers of any of those exchange bonds. Any broker-dealer that
resells exchange bonds that were received by it for its own account in the
exchange offer and any broker or dealer that participates in a distribution of
those exchange bonds may be deemed to be an "underwriter" within the meaning of
the Securities Act and any profit on any such resale of exchange bonds and any
commissions or concessions received by any such persons may be deemed to be
underwriting compensation under the Securities Act. The letter of transmittal
accompanying this prospectus states that by acknowledging that it will deliver
and by delivering a prospectus, a broker-dealer will not be deemed to admit that
it is an "underwriter" within the meaning of the Securities Act.
We have agreed to pay all expenses incident to our performance of, or
compliance with, the registration rights agreement and will indemnify the
holders of private bonds, including any broker-dealers, and certain parties
related to such holders, against certain liabilities, including liabilities
under the Securities Act.
174
<PAGE>
VALIDITY OF THE EXCHANGE BONDS
The validity of the exchange bonds offered in this prospectus will be passed
upon by Latham & Watkins, our counsel and the Funding Corporation's counsel.
EXPERTS
The financial statements of LSP Batesville Funding Corporation as of
December 31, 1999 and 1998 and for year ended December 31, 1999 and the period
from inception (August 3, 1998) to December 31, 1998, and of LSP Energy Limited
Partnership (a Delaware limited partnership in the development stage) as of
December 31, 1999 and 1998, and for each of the years ended December 31, 1999,
1998 and 1997, and for the period from inception (February 7, 1996) to
December 31, 1999 and the balance sheets of LSP Energy, Inc. as of December 31,
1999 and 1998, have been included herein and in the registration statement in
reliance upon the report of KPMG LLP, independent certified public accountants,
appearing elsewhere herein, and upon the authority of KPMG LLP as experts in
accounting and auditing.
INDEPENDENT ENGINEER
R.W. Beck, Inc. prepared the independent engineer's report included as Annex
B to this prospectus. We include that report in this prospectus in reliance upon
R.W. Beck's conclusions and their experience in the review of the design,
development, construction and operation of cogeneration facilities. You should
read the R.W. Beck report in its entirety for information with respect to our
power facility and the related subjects discussed in the R.W. Beck report.
INDEPENDENT ELECTRICITY MARKET AND FUEL CONSULTANT
C.C. Pace Consulting, L.L.C. prepared the independent electricity market and
fuel consultant's report included as Annex C to this prospectus. We include that
report in this prospectus in reliance upon C.C. Pace's conclusions and their
experience in analyzing power markets and fuel supply and transportation
arrangements for independent power projects. You should read the C.C. Pace
report in its entirety for information with respect to the southeastern power
market and the availability of fuel supply and transportation arrangements to
serve our power facility.
AVAILABLE INFORMATION
We have filed with the Commission a Registration Statement on Form S-4 under
the Securities Act with respect to the exchange bonds offered hereby. As
permitted by the rules and regulations of the Commission, this prospectus omits
certain information, exhibits and undertakings contained in the registration
statement. For further information with respect to us, the Funding Corporation
and the exchange bonds offered hereby, reference is made to the registration
statement, including the exhibits and the financial statements, notes and
schedules filed as a part of the registration statement of which this prospectus
is a part. As a result of the exchange offer, we will become subject to the
informational requirements of the Exchange Act. The registration statement (and
the exhibits and schedules thereto), as well as the periodic reports and other
information filed by us and the Funding Corporation with the Commission, may be
inspected and copied at the Public Reference Section of the Commission at Room
1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 and at the
regional offices of the Commission located at Room 1400, 75 Park Place, New
York, New York 10007 and Suite 1400, Northwestern Atrium Center, 500 West
Madison Street, Chicago, Illinois 6061-2511. Information on the operation of the
Public Reference Room may be obtained by calling the Commission at
1-800-SEC-0330. Copies of such materials may be obtained from the Public
Reference Section of the Commission, Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, and its public reference facilities in New
York, New York and Chicago, Illinois at the prescribed rates. The
175
<PAGE>
Commission maintains a web site (http://www.sec.gov), that contains periodic
reports, proxy and information statements and other information regarding
registrants that file documents electronically with the Commission.
Pursuant to the indenture, we have agreed to furnish to the trustee and to
registered holders of the exchange bonds, without cost to the trustee or those
registered holders, copies of all reports and other information that would be
required to be filed by us and the Funding Corporation with the Commission under
the Securities Exchange Act of 1934 (and, with respect to the annual information
only, a report thereon by our and the Funding Corporation's certified
independent accountants), whether or not we or the Funding Corporation are then
required to file reports with the Commission. As a result of this exchange
offer, we will become subject to the periodic reporting and other informational
requirements of the Exchange Act. In the event that we cease to be subject to
the informational requirements of the Exchange Act, we have agreed that, so long
as any bonds remain outstanding, we will file with the Commission (but only if
the Commission at such time is accepting such voluntary filings) and distribute
to holders of the private bonds or the exchange bonds, as applicable, copies of
the financial information that would have been contained in such annual reports
and quarterly reports that would have been required to be filed with the
Commission under the Exchange Act. We will also furnish such other reports as we
may determine or as may be required by law.
176
<PAGE>
INDEX TO THE FINANCIAL STATEMENTS
Our audited financial statements, and those of the Funding Corporation and
LSP Energy and the related information listed below are set forth on pages F-2
through F-48 of this prospectus.
<TABLE>
<CAPTION>
TITLE PAGE
- ----- --------
<S> <C>
LSP Batesville Funding Corporation:
Report of Independent Auditors............................ F-2
Balance Sheets as of December 31, 1999 and 1998........... F-3
Statements of Operations for the year ended December 31,
1999 and for the period from Inception (August 3, 1998)
to December 31, 1998.................................... F-4
Statements of Changes in Stockholder's Equity for the year
ended December 31, 1999 and for the period from
Inception (August 3, 1998) to December 31, 1998......... F-5
Statements of Cash Flows for the year ended December 31,
1999 and for the period from Inception (August 3, 1998)
to December 31, 1998.................................... F-6
Notes to Financial Statements............................. F-7
LSP Energy Limited Partnership:
Report of Independent Auditors............................ F-11
Balance Sheets as of December 31, 1999, and 1998.......... F-12
Statements of Operations for the years ended December 31,
1999, 1998 and 1997 and for the period from inception
(February 7, 1996) to December 31, 1999................. F-13
Statements of Changes in Partners' Capital (Deficit) for
the years ended December 31, 1999, 1998 and 1997 and for
the period from inception (February 7, 1996)
to December 31, 1999.................................... F-14
Statements of Cash Flows for the years ended December 31,
1999, 1998 and 1997 and for the period from inception
(February 7, 1996) to December 31, 1999................. F-15
Notes to Financial Statements............................. F-16
LSP Energy, Inc.
Report of Independent Auditors............................ F-41
Balance Sheets as of December 31, 1999 and 1998........... F-42
Notes to Financial Statement.............................. F-43
</TABLE>
F-1
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors
LSP Batesville Funding Corporation:
We have audited the accompanying balance sheets of LSP Batesville Funding
Corporation as of December 31, 1999 and 1998 and the related statements of
operations, changes in stockholder's equity (deficit) and cash flows for the
year ended December 31, 1999 and the period from inception (August 3, 1998) to
December 31, 1998. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with 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 audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of LSP Batesville Funding
Corporation as of December 31, 1999 and 1998, and the results of its operations
and its cash flows for the year ended December 31, 1999 and the period from
inception (August 3, 1998) to December 31, 1998 in conformity with generally
accepted accounting principles.
KPMG LLP
Billings, Montana
February 7, 2000
F-2
<PAGE>
LSP BATESVILLE FUNDING CORPORATION
BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
ASSETS
Current Asset--Cash......................................... $1,000 $1,000
====== ======
</TABLE>
<TABLE>
<S> <C> <C>
LIABILITY AND STOCKHOLDER'S EQUITY (DEFICIT)
Liability--Due to LSP Energy Limited Partnership............ $ 5,960 $ --
------- ------
Common stock, $.01 par value, 1,000 shares authorized, 100
shares issued and outstanding............................. 1 1
Additional paid-in-capital.................................. 999 999
Accumulated Deficit......................................... (5,960) --
------- ------
Total Stockholder's Equity (Deficit)........................ (4,960) 1,000
------- ------
Total Liability and Stockholder's Equity (Deficit).......... $ 1,000 $1,000
======= ======
</TABLE>
See accompanying notes to financial statements.
F-3
<PAGE>
LSP BATESVILLE FUNDING CORPORATION
STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999 AND
PERIOD FROM INCEPTION (AUGUST 3, 1998) TO DECEMBER 31, 1998
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
Revenues.................................................... $ -- $ --
General and administrative expenses......................... 5,960 --
------- ----
Net loss................................................ $(5,960) $ --
======= ====
</TABLE>
See accompanying notes to financial statements.
F-4
<PAGE>
LSP BATESVILLE FUNDING CORPORATION
STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (DEFICIT)
YEAR ENDED DECEMBER 31, 1999
AND PERIOD FROM INCEPTION (AUGUST 3, 1998) TO DECEMBER 31, 1998
<TABLE>
<CAPTION>
ADDITIONAL ACCUMULATED
COMMON STOCK PAID-IN-CAPITAL DEFICIT TOTAL
------------ --------------- ----------- --------
<S> <C> <C> <C> <C>
Balance at inception.......................... $ -- $ -- $ -- $ --
Issuance of common stock...................... 1 999 -- 1,000
---- ---- ------- -------
Balance at December 31, 1998.................. $ 1 $999 $ -- $ 1,000
Net loss...................................... -- -- (5,960) (5,960)
---- ---- ------- -------
Balance at December 31, 1999.................. $ 1 $999 $(5,960) $(4,960)
==== ==== ======= =======
</TABLE>
See accompanying notes to financial statements.
F-5
<PAGE>
LSP BATESVILLE FUNDING CORPORATION
STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, 1999
AND PERIOD FROM INCEPTION (AUGUST 3, 1998) TO DECEMBER 31, 1998
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
Cash Flows from Operating Activities:
Net loss.................................................. $(5,960) $ --
Adjustments to reconcile net loss to cash provided by
operating activities:
Increase in due to LSP Energy Limited Partnership......... 5,960 --
------- -------
Cash provided by (used in) operating activities............. -- --
------- -------
Cash Flows from Investing Activities........................ -- --
------- -------
Cash Flows from Financing Activities:
Issuance of common stock.................................... -- 1,000
------- -------
Cash provided by financing activities....................... -- 1,000
------- -------
Increase in cash............................................ -- 1,000
Cash, beginning of period................................... 1,000 --
------- -------
Cash, end of period......................................... $ 1,000 $ 1,000
======= =======
</TABLE>
See accompanying notes to financial statements.
F-6
<PAGE>
LSP BATESVILLE FUNDING CORPORATION
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION
LSP Batesville Funding Corporation ("Funding") was established on August 3,
1998. Funding's business purpose is limited to maintaining its organization and
activities necessary to facilitate the acquisition of financing by LSP Energy
Limited Partnership ("the Partnership") from the institutional debt market and
to offering debt securities. Funding is wholly owned by LSP Batesville Holding,
LLC ("Holding"), a Delaware limited liability company.
Holding was established on July 29, 1998 for the purpose of owning and
managing the limited partnership interests of the Partnership, the common stock
of LSP Energy, Inc., the general partner of the Partnership, and the common
stock of Funding.
The Partnership is a Delaware limited partnership formed in February 1996 to
develop, finance, construct, own and operate a gas-fired electric generating
facility with a design capacity of approximately 837 megawatts to be located in
Batesville, Mississippi (the "Facility"). The Partnership has been in the
development stage since its inception and is not expected to generate any
operating revenues until the Facility achieves commercial operations. As with
business ventures of this size and nature, the ultimate construction and
operation of the Facility could be affected by many factors. Construction of the
Facility is expected to be completed in the year 2000.
Due to the insignificance of income tax effects applicable to Funding, the
accompanying financial statements do not reflect any income tax effects.
2. FINANCING
Effective August 28, 1998, the Partnership entered into agreements with a
financial institution (the "Bank"), that provided for financing in the amount of
$180,000,000 (the "Tranche A Credit Facility"). Borrowings from this financing
were used for the development and construction of the Facility. The agreements
also contemplated circumstances under which Funding and Holding would enter into
agreements whereby they would issue bonds in the amounts of $100,000,000 (the
"Tranche B Bond Facility") and $50,000,000 (the "Tranche C Bond Facility"),
respectively, in order to further finance the construction of the Facility. The
terms and conditions of the Tranche B Bond Facility and Tranche C Bond Facility
were set forth in a letter agreement (the "Letter Agreement") entered into among
the Partnership, Holding and Funding (collectively, the "Borrowers") and the
Bank. Bonds under the Tranche B Bond Facility and Tranche C Bond Facility were
never issued.
Pursuant to the Letter Agreement, the Borrowers and the Bank, as
underwriter, also agreed to pursue a capital markets offering during the last
quarter of 1998. However, due to unfavorable capital markets conditions the
capital markets offering was not completed. Alternatively, on December 15, 1998
the Partnership amended and restated the financing agreements entered into on
August 28, 1998. The amended and restated agreements provided for financing in
the amount of $305,000,000. The new financing consisted of a $305,000,000
three-year loan facility (the "Bank Credit Facility") entered into among the
Partnership and a consortium of banks.
The aggregate principal amount of all loans under the Bank Credit Facility
could not exceed $305,000,000. The maturity date of loans outstanding under the
Bank Credit Facility was the earlier of (a) December 15, 2001 and (b) the
commitment termination date, as defined. At December 31, 1998, the Partnership
had $78,000,000 of LIBOR loans outstanding under the Bank Credit Facility.
Interest rates on the outstanding loans at December 31, 1998 ranged from 6.355%
to 6.505%.
F-7
<PAGE>
LSP BATESVILLE FUNDING CORPORATION
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
2. FINANCING (CONTINUED)
Loans made under the Bank Credit Facility were secured by all of the assets
and contract rights of the Partnership. In addition, each of the partners of the
Partnership pledged its respective partnership interest in the Partnership.
A common agreement (the "Common Agreement") tied all of the financing
agreements together and set forth, among other things: (a) terms and conditions
upon which loans and disbursements could be made under the Bank Credit Facility;
(b) the mechanism for which loan proceeds, operating revenues, equity
contributions and other amounts received by the Partnership were disbursed to
pay construction costs, operations and maintenance costs, debt service and other
amounts due from the Partnership; (c) the conditions which had to be satisfied
prior to making distributions from the Partnership; and (d) the covenants and
reporting requirements the Partnership was required to be in compliance with
during the term of the Common Agreement.
The Common Agreement prohibited the Partnership from making distributions to
its partners while loans made under the Bank Credit Facility were outstanding.
The Common Agreement required compliance with covenants, including, among
other things, compliance with reporting requirements and limitations or
restrictions relating to the use of the proceeds under the Bank Credit Facility,
additional indebtedness, and disposition of assets. The Common Agreement also
described events of default which included, among others, failure to make
payments in accordance with the terms of the Bank Credit Facility and failure to
comply with agreements entered into by the Partnership.
On May 21, 1999, the Partnership and Funding issued two series of Senior
Secured Bonds (the "Bonds") in the following total principal amounts:
$150,000,000 7.164% Series A Senior Secured Bonds due 2014 and $176,000,000
8.160% Series B Senior Secured Bonds due 2025. Interest is payable semiannually
on each January 15 and July 15, commencing January 15, 2000 to the holders of
record on the immediately preceeding January 1 and July 1. On January 15, 2000,
the Partnership made interest payments aggregating approximately $16,320,000.
Interest on the Bonds accrues from the most recent date to which interest has
been paid or, if no interest has been paid, from the date of original issuance.
Interest is computed on the basis of a 360-day year consisting of twelve 30-day
months. The interest rate on the Bonds may be increased under the circumstances
described below.
A portion of the proceeds from the issuance of the Bonds was used to repay
the $136,600,000 of outstanding loans under the Bank Credit Facility. The
remaining proceeds from the issuance of the Bonds are being used to pay a
portion of the costs of completing the Facility.
Principal payments are payable on each January 15 and July 15, commencing on
July 15, 2001. Scheduled maturities of the Bonds are as follows:
<TABLE>
<S> <C>
1999.......................................... $ --
2000.......................................... $ --
2001.......................................... $ 4,125,000
2002.......................................... $ 7,575,000
2003.......................................... $ 7,125,000
Thereafter.................................... $307,175,000
------------
Total......................................... $326,000,000
============
</TABLE>
F-8
<PAGE>
LSP BATESVILLE FUNDING CORPORATION
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
2. FINANCING (CONTINUED)
The Bonds are secured by substantially all of the personal property and
contract rights of the Partnership and Funding. In addition, Holding and LSP
Energy, Inc. have pledged all of their interests in the Partnership, and Holding
has pledged all of the common stock of LSP Energy, Inc. and all of the common
stock of Funding.
The Bonds are senior secured obligations of the Partnership and Funding,
rank equivalent in right of payment to all other senior secured obligations of
the Partnership and Funding and rank senior in right of payment to all existing
and future subordinated debt of the Partnership and Funding.
The Bonds are redeemable, at the option of the Partnership and Funding, at
any time in whole or from time to time in part, on not less than 30 nor more
than 60 days' prior notice to the holders of that series of Bonds, on any date
prior to its maturity at a redemption price equal to 100% of the outstanding
principal amount of the Bonds being redeemed, plus accrued and unpaid interest
on the Bonds being redeemed and a make-whole premium. In no event will the
redemption price ever be less than 100% of the principal amount of the Bonds
being redeemed plus accrued and unpaid interest thereon.
The Bonds are redeemable at the option of the bondholders if funds remain on
deposit in the distribution account for at least 12 months in a row, and the
Partnership and Funding cause the bondholders to vote on whether the Partnership
and Funding should use those funds to redeem the Bonds, and holders of at least
66 2/3% of the outstanding Bonds vote to require the Partnership and Funding to
use those funds to redeem the Bonds. If the Partnership and Funding are required
to redeem Bonds with those funds, then the redemption price will be 100% of the
principal amount of the Bonds being redeemed plus accrued and unpaid interest on
the Bonds being redeemed. In addition, if LS Power, LLC, Cogentrix Energy, Inc.
and/or any qualified transferee collectively cease to own, directly or
indirectly, at least 51% of the capital stock of LSP Energy, Inc. (unless any or
all of them maintain management control of the Partnership), or LS Power, LLC,
Cogentrix Energy, Inc. and/or any qualified transferee collectively cease to
own, directly or indirectly, at least 10% of the ownership in the Partnership,
then the Partnership and Funding must offer to purchase all of the Bonds at a
purchase price equal to 101% of the outstanding principal amount of the Bonds
plus accrued and unpaid interest unless the Partnership and Funding receive a
confirmation of the then current ratings of the Bonds or at least 66 2/3% of the
holders of the outstanding Bonds approve the change in ownership.
The Trust Indenture for the Bonds (the "Trust Indenture") entered into among
the Partnership, Funding and the Bank of New York, as Trustee (the "Trustee")
contains covenants including, among others, limitations and restrictions
relating to additional debt other than the Bonds, Partnership distributions, new
and existing agreements, disposition of assets, and other activities. The Trust
Indenture also describes events of default which include, among others, events
involving bankruptcy of the Partnership or Funding, failure to make any payment
of interest or principal on the Bonds and failure to perform or observe in any
material respect any covenant or agreement contained in the Trust Indenture.
Effective May 21, 1999, the Common Agreement was amended and restated (the
"Amended and Restated Common Agreement"). The Amended and Restated Common
Agreement sets forth, among other things; (a) the mechanism by which Bond
proceeds, operating revenues, equity contributions and other amounts received by
the Partnership are disbursed to pay construction costs, operations and
F-9
<PAGE>
LSP BATESVILLE FUNDING CORPORATION
NOTES TO FINANCIAL STATEMENTS (CONCLUDED)
2. FINANCING (CONTINUED)
maintenance costs, debt service and other amounts due from the Partnership and
(b) the conditions which must be satisfied prior to making distributions from
the Partnership.
The Amended and Restated Common Agreement provides that the following
conditions must be satisfied before making distributions from the Partnership to
its partners: (1) the Partnership must have made all required disbursements to
pay operating and maintenance expenses, management fees and expenses and debt
service; (2) the Partnership must have set aside sufficient reserves to pay
principal and interest payments on the Bonds and its other senior secured debt;
(3) there cannot exist any default or event of default under the Trust Indenture
for the Bonds; (4) the Partnership's historical and projected debt service
coverage ratios must equal or exceed the required levels; (5) the Partnership
must have sufficient funds in its accounts to meet its ongoing working capital
needs; (6) the Facility must be complete; and (7) the distributions must be made
after the last business day of September 2000.
The Amended and Restated Common Agreement requires that the Partnership set
aside reserves for: (1) payments of scheduled principal and interest on the
Bonds and the other senior secured debt of the Partnership and Funding; (2) the
cost of performing periodic major maintenance on the Facility, including turbine
overhauls; and (3) the credit support, if any, that the Partnership is required
to provide to one of the Partnership's power purchasers.
Under the terms and conditions of the Trust Indenture, the Partnership and
Funding have agreed to file a registration statement with the Securities and
Exchange Commission (the "SEC") for a registered offer to exchange the Bonds for
two series of debt securities (the "Exchange Bonds") which are in all material
respects substantially identical to the Bonds. Upon such registration being
effective, the Partnership and Funding will offer the Exchange Bonds in return
for surrender of the Bonds. Interest on each Exchange Bond will accrue from the
last date on which interest was paid on the Bond so surrendered or, if no
interest has been paid, since the date of the issuance of the Bonds.
If the Partnership and Funding do not begin the exchange offer or the SEC
does not declare the registration effective within 270 days of May 21, 1999, the
respective interest rates on the Bonds will increase by one-half of one percent
effective on the 271st day following May 21, 1999. Such increase will remain in
effect until the date on which the Partnership and Funding begin the exchange
offer.
F-10
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Partners
LSP Energy Limited Partnership:
We have audited the accompanying balance sheets of LSP Energy Limited
Partnership (a Delaware limited partnership in the development stage) as of
December 31, 1999 and 1998, and the related statements of operations, changes in
partners' capital (deficit) and cash flows for each of the years in the
three-year period ended December 31, 1999 and for the period from inception
(February 7, 1996) to December 31, 1999. 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 audits.
We conducted our audits 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 audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of LSP Energy Limited
Partnership (a Delaware limited partnership in the development stage) as of
December 31, 1999 and 1998, and the results of its operations and its cash flows
for each of the years in the three-year period ended December 31, 1999 and for
the period from inception (February 7, 1996) to December 31, 1999, in conformity
with generally accepted accounting principles.
KPMG LLP
Billings, Montana
February 7, 2000
F-11
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
<TABLE>
<CAPTION>
1999 1998
------------ -----------
<S> <C> <C>
ASSETS
Current assets:
Cash...................................................... $ 202,924 $ 83,866
Investments held by Trustee, at amortized cost which
approximates fair value................................. 53,547,410 --
Spare parts inventory..................................... 733,462 --
Other current assets...................................... 174,174 57,067
------------ -----------
Total Current Assets.................................... 54,657,970 140,933
Property and construction in progess........................ 296,509,139 83,429,694
Debt issuance and financing costs, net of accumulated
amortization of $4,046,139 in 1999 and $233,505 in 1998... 10,099,017 10,531,773
------------ -----------
Total Assets............................................ $361,266,126 $94,102,400
============ ===========
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT)
Current liabilities:
Accounts payable.......................................... $ 9,923,894 $13,507,883
Contract retainage payable................................ 11,944,208 --
Accrued interest payable.................................. 15,345,443 154,898
------------ -----------
Total Current Liabilities............................... 37,213,545 13,662,781
Contract retainage payable.................................. -- 2,882,344
Bonds payable............................................... 326,000,000 --
Loans payable............................................... -- 78,000,000
------------ -----------
Total Liabilites........................................ 363,213,545 94,545,125
Commitments and contingencies
Partners' Capital (Deficit)................................. (1,947,419) (442,725)
------------ -----------
Total Liabilities and Partners' Capital (Deficit)....... $361,266,126 $94,102,400
============ ===========
</TABLE>
See accompanying notes to financial statements.
F-12
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
INCEPTION
YEAR ENDED DECEMBER 31, (FEBRUARY 7, 1996)
------------------------------------ TO
1999 1998 1997 DECEMBER 31, 1999
----------- --------- ---------- ------------------
<S> <C> <C> <C> <C>
Revenues.................................. $ -- $ -- $5,224,084 $5,382,289
Expenses:
Operations and maintenance expenses..... 918,782 -- -- 918,782
Project management expenses............. 367,277 142,122 -- 509,399
General and administrative expenses..... 218,635 301,603 4,205 528,187
----------- --------- ---------- ----------
Total expenses............................ 1,504,694 443,725 4,205 1,956,368
----------- --------- ---------- ----------
Net income (loss)..................... $(1,504,694) $(443,725) $5,219,879 $3,425,921
=========== ========= ========== ==========
</TABLE>
See accompanying notes to financial statements.
F-13
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (DEFICIT)
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
FOR THE PERIOD FROM INCEPTION (FEBRUARY 7, 1996)
TO DECEMBER 31, 1999
<TABLE>
<CAPTION>
LIMITED PARTNER GENERAL PARTNER
LIMITED PARTNER ----------------- ---------------
LSP BATESVILLE GRANITE POWER LSP ENERGY,
HOLDING, LLC PARTNERS II, L.P. INC. TOTAL
--------------- ----------------- --------------- -----------
<S> <C> <C> <C> <C>
Balance at December 31, 1996.......... $ -- $ 44,017 $ 444 $ 44,461
Net income............................ -- 5,167,680 52,199 5,219,879
Distribution to partners.............. -- (5,211,697) (52,643) (5,264,340)
----------- ---------- -------- -----------
Balance at December 31, 1997.......... $ -- $ -- $ -- $ --
Capital contributions................. -- 990 10 1,000
Transfer of partnership interests..... 990 (990) -- --
Net loss.............................. (439,288) -- (4,437) (443,725)
----------- ---------- -------- -----------
Balance at December 31, 1998.......... $ (438,298) $ -- $ (4,427) $ (442,725)
----------- ---------- -------- -----------
Net loss.............................. (1,489,647) -- (15,047) (1,504,694)
----------- ---------- -------- -----------
Balance at December 31, 1999.......... (1,927,945) -- (19,474) (1,947,419)
=========== ========== ======== ===========
Balance at inception.................. $ -- $ -- $ -- $ --
Capital contributions................. -- 990 10 1,000
Transfer of partnership interests..... 990 (990) -- --
Net income (loss)..................... $(1,928,935) 5,320,597 34,259 3,425,921
Distributions to partners............. -- (5,320,597) (53,743) (5,374,340)
----------- ---------- -------- -----------
Balance at December 31, 1999.......... $(1,927,945) $ -- $(19,474) $(1,947,419)
=========== ========== ======== ===========
</TABLE>
See accompanying notes to financial statements.
F-14
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
INCEPTION
(FEBRUARY 7,
YEAR ENDED DECEMBER 31, 1996)
------------------------------------------ TO DECEMBER 31,
1999 1998 1997 1999
------------- ------------ ----------- ---------------
<S> <C> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss)..................................... $ (1,504,694) $ (443,725) $ 5,219,879 $ 3,425,921
Adjustments to reconcile net income (loss) to cash
provided by (used in) operating activities:
Decrease in interest receivable net of accretion of
purchase discount on escrow funds................. -- -- 44,461 --
Increase in spare parts inventory................... (733,462) -- -- (733,462)
Increase in other current assets.................... (117,107) (57,067) -- (174,174)
Increase (decrease) in accounts payable............. (3,583,989) 13,507,883 -- 9,923,894
Increase (decrease) in accrued interest on loans
payable........................................... (154,898) 154,898 -- --
------------- ------------ ----------- -------------
Cash provided by (used in) operating activities......... (6,094,150) 13,161,989 5,264,340 12,442,179
------------- ------------ ----------- -------------
Cash Flows from Investing Activities:
Investments held by Trustee........................... (183,648,081) -- -- (183,648,081)
Investments drawn for property and construction in
progress............................................ 147,526,874 -- -- 147,526,874
Payments on property and construction in progress..... (202,285,707) (80,313,845) -- (282,599,552)
------------- ------------ ----------- -------------
Cash used in investing activities....................... (238,406,914) (80,313,845) -- (318,720,759)
------------- ------------ ----------- -------------
Cash Flows from Financing Activities:
Debt issuance and financing costs..................... (3,379,878) (10,765,278) -- (14,145,156)
Proceeds from issuance of loans....................... 58,600,000 78,000,000 -- 136,600,000
Repayment of loans.................................... (136,600,000) -- -- (136,600,000)
Proceeds from issuance of bonds....................... 326,000,000 -- -- 326,000,000
Capital contributions................................. -- 1,000 -- 1,000
Distributions to partners............................. -- -- (5,264,340) (5,374,340)
------------- ------------ ----------- -------------
Cash provided by (used in) financing activities......... 244,620,122 67,235,722 (5,264,340) 306,481,504
------------- ------------ ----------- -------------
Increase in cash........................................ 119,058 83,866 -- 202,924
Cash, beginning of period............................... 83,866 -- -- --
------------- ------------ ----------- -------------
Cash, end of period..................................... $ 202,924 $ 83,866 $ -- $ 202,924
============= ============ =========== =============
RECONCILIATION OF CHANGES IN PROPERTY AND CONSTRUCTION
IN PROGRESS:
Increase in property and construction in progress....... $(213,079,445) $(83,429,694) $ -- $(296,509,139)
Increase in contract retainage payable.................. 9,061,864 2,882,344 -- 11,944,208
Investment income on investments held by Trustee........ (3,148,444) -- -- (3,148,444)
Reimbursement received from the State of Mississippi.... (14,277,759) -- -- (14,277,759)
Amortization of debt issuance and financing costs....... 3,812,634 233,505 -- 4,046,139
Increase in accrued interest payable on bonds........... 15,345,443 -- -- 15,345,443
------------- ------------ ----------- -------------
Payments on property and construction in progress....... $(202,285,707) $(80,313,845) $ -- $(282,599,552)
============= ============ =========== =============
</TABLE>
See accompanying notes to financial statements.
F-15
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(a Delaware Limited Partnership in the Development Stage)
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND BUSINESS
LSP Energy Limited Partnership (the "Partnership") is a Delaware limited
partnership formed in February 1996 to develop, construct, own and operate a
gas-fired electric generating facility with a design capacity of approximately
837 megawatts to be located in Batesville, Mississippi (the "Facility"). The 1%
general partner of the Partnership is LSP Energy, Inc. ("Energy"). Granite Power
Partners II, L.P. ("Granite") was the original 99% limited partner of the
Partnership. The current 99% limited partner of the Partnership is LSP
Batesville Holding, LLC ("Holding"), a Delaware limited liability company
established on July 29, 1998. Granite is a Delaware limited partnership formed
to develop independent power projects throughout the United States. The general
partner of Granite is LS Power, LLC ("LS Power"), a Delaware limited liability
company.
Granite and Cogentrix/Batesville, LLC ("Cogentrix"), a Delaware limited
liability company, entered into an operating agreement dated as of August 28,
1998 which was amended and restated on both December 15, 1998 and May 19, 1999
(as amended, the "Operating Agreement"). Pursuant to the Operating Agreement,
Granite contributed to Holding its 99% limited partnership interest in the
Partnership and all of the common stock of Energy, and Cogentrix agreed to
contribute to Holding $54,000,000 of equity. Granite received an initial 47.85%
membership interest in Holding and Cogentrix received an initial 52.15%
membership interest in Holding.
Pursuant to the Operating Agreement, Granite's and Cogentrix's membership
interest may be adjusted to insulate Cogentrix's economic return from events,
including: (i) a refinancing of the project debt, (ii) deviations of market
prices from the market prices projected as of the closing date, (iii) an
increase in debt service as a result of a draw on the Virginia Electric and
Power Company ("VEPCO") completion security (see Note 4), (iv) inability to post
a debt service letter of credit and distribute cash from the debt service
reserve account to Cogentrix, by a certain date, due to insufficient cash
funding of the debt service reserve account and (v) a termination by VEPCO of
the VEPCO power purchase agreement (see Note 4). On the 25th anniversary of the
delivery start date as defined in the VEPCO power purchase agreement Cogentrix's
membership interest shall be reduced to 2%.
Under the terms of the Operating Agreement, the issuance of two series of
Senior Secured Bonds by the Partnership and LSP Batesville Funding Corporation
on May 21, 1999 (see Note 5) resulted in a recalculation of the Granite and
Cogentrix membership interests in Holding. Effective May 21, 1999 the revised
Granite and Cogentrix membership interests were adjusted to 48.63% and 51.37%,
respectively.
Cogentrix's equity contribution to Holding will be contributed to the
Partnership and used for the development and construction of the Facility.
Cogentrix's equity contribution commitment is supported by an irrevocable letter
of credit.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
The Partnership has been in the development stage since its inception and is
not expected to generate any operating revenues until the Facility achieves
commercial operations. Revenues in 1997 primarily represent a $5,000,000 option
payment received by the Partnership under an option purchase agreement (the
"Option Purchase Agreement") entered into in 1996 with a third party. Under the
terms of the Option Purchase Agreement, the third party had the option to
purchase 750 megawatts of
F-16
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
capacity and dispatchable energy for a defined term from the Partnership.
Effective November 1, 1997, the Option Purchase Agreement expired unexercised.
The Partnership has no continuing financial commitments under the Option
Purchase Agreement and all funds earned under the Option Purchase Agreement were
distributed to the partners of the Partnership prior to December 31, 1997.
As with any new business venture of this size and nature, the ultimate
operation of the Facility could be affected by many factors. Construction of the
Facility is expected to be completed in 2000.
PROJECT DEVELOPMENT COSTS
On April 3, 1998, the AICPA Accounting Standards Executive Committee issued
Statement of Position 98-5, REPORTING ON THE COSTS OF START-UP ACTIVITIES ("SOP
98-5"). SOP 98-5 requires that costs incurred during start-up activities,
including organization costs, be expensed as incurred. Generally, all start-up
costs incurred that are not directly related to the acquisition or construction
of long-lived tangible assets will be expensed.
The Partnership adopted SOP 98-5 during 1998 and accordingly has expensed
all start-up costs in the accompanying 1999 and 1998 statements of operations.
INVESTMENTS HELD BY TRUSTEE
At December 31, 1999, Investments Held by Trustee referred to in Note 5,
consists of commercial paper with original maturities primarily of 90 days or
less. All such commercial paper at December 31, 1999 matures prior to January
31, 2000. The Partnership acquired and classified these debt securities as
held-to-maturity because of its intent and ability to hold them to maturity. At
December 31, 1999, the fair value of each of these investment securities
approximated its amortized cost.
Held-to-maturity securities are carried at amortized cost, adjusted for
amortization of premiums or accretion of discounts. Such amortization and
accretion is included in interest income. Interest income is recognized when
earned. Realized gains and losses, and declines in value judged to be
other-than-temporary, are included in investment securities gains (losses).
There were no sales of investment securities during 1999. Maturities of
investment securities are reflected as investments drawn for property and
construction in progress on the statement of cash flows.
A trustee holds all of these investments and the use of the proceeds from
maturities is restricted to payment of project costs.
CONSTRUCTION IN PROGRESS
All costs directly related to the acquisition and construction of long-lived
assets are capitalized. Interest costs (including amortization of debt issuance
and financing costs), net of interest income on excess proceeds from loans and
bonds is capitalized during construction. As of December 31, 1999 and
December 31, 1998, capitalized interest including amortization of debt issuance
and financing costs was approximately $20,823,000 and $1,815,000, respectively,
($16,777,000 and $1,581,000, respectively, before amortization). Cash paid for
interest was approximately $3,172,000 and $1,426,000 for the years ended
December 31, 1999 and 1998, respectively, and approximately $4,598,000 for the
period February 7, 1996 (inception) to December 31, 1999.
F-17
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
DEBT ISSUANCE AND FINANCING COSTS
The Partnership amortizes deferred debt issuance and financing costs over
the expected term of the related debt using the effective interest method.
Amortization of deferred financing costs is capitalized as part of construction
in progress in the accompanying financial statements.
ACCOUNTS PAYABLE
As of December 31, 1999 and 1998, substantially all accounts payable were
considered project costs and were eligible for payment from funds held by the
trustee and unadvanced loan proceeds.
USE OF ESTIMATES
Management makes a number of estimates and assumptions relating to the
reporting of assets and liabilities and revenues and expenses and the disclosure
of contingent assets and liabilities to prepare financial statements in
conformity with generally accepted accounting principles. Actual results could
differ from those estimates.
INCOME TAXES
Since the Partnership is not an income tax paying entity, the accompanying
financial statements do not reflect any income tax effects.
3. PROPERTY AND CONSTRUCTION IN PROGRESS
Property and construction in progress consist of the following at:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1999 1998
------------- ------------
<S> <C> <C>
Land and easements (see Note 4)............................. $ 673,558 $ 1,398,071
Construction in progress.................................... 295,835,581 82,031,623
------------ -----------
$296,509,139 $83,429,694
============ ===========
</TABLE>
4. FACILITY CONTRACTS
On May 18, 1998, the Partnership entered into a Power Purchase Agreement
("VEPCO PPA") with Virginia Electric and Power Company ("VEPCO"). Under the
terms of the VEPCO PPA, the Partnership is obligated to sell and VEPCO is
obligated to purchase approximately 558 megawatts of electrical capacity and
dispatchable energy to be generated from two of the three Combined Cycle Units
("Unit" or "Units") at the Facility at prices set forth in the VEPCO PPA. The
initial term of the VEPCO PPA is thirteen years, beginning on the earlier of
commencement of commercial operations or June 1, 2000, which date may be
extended by a force majeure event or a delivery excuse. VEPCO has the option of
extending the term of the VEPCO PPA for an additional twelve years by providing
the Partnership written notice at least two years prior to the expiration of the
initial term. The extended term may be terminated at any time by VEPCO with
18 months prior notice to the Partnership.
F-18
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
The VEPCO PPA is subject to specified construction and energy delivery
milestone deadlines, including achieving commercial operations of the VEPCO
Units by June 1, 2000, which date may be extended by a force majeure event or a
delivery excuse.
In the event the commercial operation date of the VEPCO units is delayed
beyond June 1, 2000, which date may be extended by a force majeure event or
delivery excuse, the Partnership may be responsible for replacement power during
the period of delay, subject to a maximum of $20 per kilowatt of committed
capacity from each VEPCO Unit. VEPCO may terminate the VEPCO PPA if the
commercial operation date is not achieved by June 1, 2001, which date may be
extended by a force majeure event or a delivery excuse.
The terms of the VEPCO PPA require VEPCO to make payments to the Partnership
including a reservation payment, an energy payment, a start-up payment, system
upgrade payments and a guaranteed heat rate payment.
The reservation payment is a monthly payment based on the tested capacity of
each VEPCO Unit adjusted to specific ambient conditions and the applicable
reservation charge. The standard capacity reservation charge is $5.00 per
megawatt per month, $6.00 per megawatt per month, and $4.50 per megawatt per
month for contract years 1-5, 6-13, and 14-25, respectively. The supplemental
(or augmented) capacity reservation charge is $3.25 per megawatt per month,
$3.50 per megawatt per month, and $3.00 per megawatt per month for contract
years 1-5, 6-13, and 14-25, respectively. The reservation payment may be
adjusted downward due to low Unit reliability or availability. However, in the
event of an extended forced outage the Partnership may elect to pay for or
provide VEPCO with replacement power and, thereby, avoid a reduction in the
reservation payment due to reduced availability.
The energy payment is a monthly payment based on the amount of electricity
delivered to VEPCO and an energy rate. The energy rate is $1.00 per
megawatt-hour escalated by 3% per year. The start-up payment is a monthly
payment based on the number of starts for a VEPCO Unit in excess of 250 per year
and a start-up charge. The start charge is equal to $5,000 per Unit per start in
excess of 250 per year.
The system upgrade payment is a monthly payment based on VEPCO's receipt of
a credit or discount for transmission service from the Tennessee Valley
Authority ("TVA") and Entergy Mississippi, Inc. ("Entergy") due to the
Partnership's payment for system upgrades on TVA's or Entergy's transmission
systems. The system upgrade payment is due only to the extent that VEPCO
receives such transmission service credit or discount.
The guaranteed heat rate payment is a monthly payment based on the
difference between the actual operating efficiency of the VEPCO Units and the
operating efficiency that the Partnership has guaranteed. If the actual
operating efficiency of the VEPCO Units is higher than the operating efficiency
that the Partnership has guaranteed, VEPCO is required to pay the Partnership
the fuel cost savings that resulted from such higher efficiency. If the actual
operating efficiency of the VEPCO Units is lower than the operating efficiency
that the Partnership has guaranteed, the Partnership is required to pay VEPCO
the fuel cost expense that resulted from such lower efficiency.
F-19
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
The VEPCO PPA requires the Partnership and VEPCO to work together to develop
an annual schedule for the maintenance based upon VEPCO's projected dispatch
schedule. The Partnership has agreed not to schedule maintenance during the
months of June, July, August, September, January and February without VEPCO's
consent.
The VEPCO PPA requires the Partnership to own, operate, maintain and control
all of the electrical interconnection facilities up to the point of
interconnection of the Facility with Entergy's and TVA's transmission systems.
VEPCO is responsible for obtaining and paying for the provision of transmission
services and any ancillary or control area services required beyond the
interconnection points between the Facility and the TVA and Entergy transmission
systems.
The Partnership is required to obtain all governmental approvals required
for the ownership, construction, operation and maintenance of the lateral
natural gas pipeline. The Partnership is also required to construct, operate and
maintain the lateral natural gas pipeline.
Under the VEPCO PPA either party is excused from performing its obligations
due to force majeure events or events that are not in its reasonable control.
The Partnership is not liable for or deemed in breach of the VEPCO PPA to the
extent performance of its obligations is delayed or prevented by circumstances
due to the non-performance of VEPCO. The VEPCO PPA is a tolling arrangement,
whereby VEPCO is obligated to supply natural gas to each VEPCO Unit. VEPCO is
obligated to arrange, procure, nominate, balance, transport and deliver to the
Facility's lateral pipeline the amount of fuel necessary for each VEPCO Unit to
generate its net electrical output.
VEPCO is required to file reports and other information with the Securities
and Exchange Commission. These materials are available on the Securities and
Exchange Commission's web site, which can be accessed at HTTP://WWW.SEC.GOV.
The following summarized balance sheets and income statements of VEPCO at
September 30, 1999 and December 31, 1998 were obtained from the Securities and
Exchange Commission's web site.
The summarized condensed financial information should be read in conjunction
with the complete financial statements for the periods presented herein, the
related notes to such financial statements and the respective independent
auditors' report. The summarized condensed financial information also may not be
indicative of the entity's ability to fulfill its obligations under the power
purchase agreement.
F-20
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
CONDENSED BALANCE SHEETS (IN THOUSANDS) (UNAUDITED)
The summarized condensed financial information should be read in conjunction
with the complete financial statements for the periods presented herein, the
related notes to such financial statements and the respective independent
auditors' report. The summarized condensed financial information also may not be
indicative of the entity's ability to fulfill its obligations under the power
purchase agreement.
<TABLE>
<CAPTION>
ASSETS 09/30/1999 12/31/1998
- ------ ----------- -----------
<S> <C> <C>
Cash........................................................ $ 115,100 $ 49,600
Other Current Assets........................................ 1,615,900 1,420,700
----------- -----------
Current Assets.............................................. 1,731,000 1,470,300
Property, Plant & Equipment, Net............................ 9,007,400 9,081,900
Other Non-Current Assets.................................... 1,116,900 1,432,700
----------- -----------
Non-Current Assets.......................................... 10,124,300 10,514,600
----------- -----------
TOTAL ASSETS................................................ $11,855,300 $11,984,900
=========== ===========
LIABILITIES & EQUITY
- ------------------------------------------------------------
Accounts Payable............................................ $ 620,100 $ 566,500
Other Current Liabilities................................... 1,488,200 1,208,100
----------- -----------
Current Liabilities......................................... 2,108,300 1,774,600
Long Term Debt.............................................. 3,486,700 3,464,700
Other Long-Term Liabilities................................. 1,937,600 2,123,900
----------- -----------
Long-Term Liabilities....................................... 5,424,300 5,588,600
----------- -----------
TOTAL LIABILITIES........................................... 7,532,600 7,363,200
----------- -----------
Stockholders' Equity........................................ 4,322,700 4,621,700
----------- -----------
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY.................... $11,855,300 $11,984,900
=========== ===========
CONDENSED INCOME STATEMENT (IN THOUSANDS) (UNAUDITED)
<CAPTION>
NINE
MONTHS YEAR
ENDED ENDED
09/30/1999 12/31/1998
----------- -----------
<S> <C> <C>
Sales....................................................... $ 3,615,000 $ 4,284,600
Operating Expenses.......................................... (2,726,100) (3,598,800)
----------- -----------
Operating Income............................................ 888,900 685,800
Other Income/(Expense)...................................... 21,300 18,000
----------- -----------
Interest Expense............................................ (220,500) (316,600)
Income Taxes................................................ (241,300) (157,300)
----------- -----------
NET INCOME BEFORE EXTRAORDINARY ITEM........................ 448,400 229,900
Extraordinary Item.......................................... (254,800) 0
----------- -----------
NET INCOME.................................................. $ 193,600 $ 229,900
=========== ===========
</TABLE>
F-21
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
On May 21, 1998, the Partnership entered into a Power Purchase Agreement
("Aquila PPA") with Aquila Power Corporation ("Aquila") and UtiliCorp
United, Inc. ("Utilicorp"). Under the terms of the Aquila PPA, the Partnership
is obligated to sell and Aquila is obligated to purchase approximately 279
megawatts of electrical capacity and dispatchable energy to be generated from
one of the three Units at the Facility at prices set forth in the Aquila PPA.
UtiliCorp has appointed Aquila as its agent under the Aquila PPA. The initial
term of the Aquila PPA is fifteen years and seven months, beginning on June 1,
2000, which date may be extended by a force majeure event or a delivery excuse.
Aquila has the option of extending the term of the Aquila PPA for an additional
five years by providing the Partnership written notice by the later of
July 2013 or twenty-nine months prior to the expiration of the initial term.
The Aquila PPA is subject to an energy delivery milestone deadline of
June 1, 2000, which deadline may be extended by a force majeure event or a
delivery excuse. In the event that commercial operation of the Aquila Unit is
not achieved by such deadline, the Partnership may elect to incur an adjustment
to the reservation payment to be received under the Aquila PPA or to be
responsible for replacement power during the period of delay. Aquila may
terminate the Aquila PPA if commercial operations of the Aquila Unit is not
achieved by the first anniversary of the energy delivery milestone deadline,
which deadline may be extended for up to one year by a force majeure event or
delivery excuse.
The terms of the Aquila PPA require Aquila to make payments to the
Partnership including a reservation payment, an energy payment, a start-up
payment, system upgrade payments and a guaranteed heat rate payment.
The reservation payment is a monthly payment based on the tested capacity of
each Aquila Unit adjusted to specific ambient conditions and the applicable
reservation charge. The capacity reservation charge for all capacity up to
267-megawatts is $4.90 per megawatt per month for the first 60 months and $5.00
per megawatt per month thereafter. The capacity reservation charge for all
capacity in excess of 267-megawatts is $2.50 per megawatt per month through the
term of the Aquila PPA. The reservation payment may be adjusted downward due to
low Unit reliability or availability. However, in the event of an extended
forced outage the Partnership may elect to pay for or provide Aquila with
replacement power and, thereby, avoid a reduction in the reservation payment due
to reduced availability.
The energy payment is a monthly payment based on the amount of electricity
delivered to Aquila and an energy rate. The energy rate is $1.00 per
megawatt-hour escalated by the rate of change in the gross domestic product
implicit price deflator index. The start-up payment is a monthly payment based
on the number of starts for the Aquila Unit in excess of 200 per year and a
start charge. The start charge is equal to $5,000 per Unit per start.
The system upgrade payment is a monthly payment based on Aquila's receipt of
a credit or discount for transmission service from TVA or Entergy due to the
Partnership's payment for system upgrades on TVA's or Entergy's transmission
systems. The system upgrade payment is due only to the extent that Aquila
receives such transmission service credit or discount.
F-22
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
The guaranteed heat rate payment is a monthly payment based on the
difference between the actual operating efficiency of the Aquila Unit and the
operating efficiency that the Partnership has guaranteed. If the actual
operating efficiency of the Aquila Unit is higher than the operating efficiency
that the Partnership has guaranteed, Aquila is required to pay the Partnership
the fuel cost savings that resulted from such higher efficiency. If the actual
operating efficiency of the Aquila Unit is lower than the operating efficiency
that the Partnership has guaranteed, the Partnership is required to pay Aquila
the fuel cost expense that resulted from such lower efficiency.
The Aquila PPA requires the Partnership and Aquila to work together to
develop an annual schedule for the maintenance of the Aquila Unit based upon
Aquila's projected dispatch schedule. The Partnership has agreed not to schedule
maintenance during the period from June 15 through September 15 without Aquila's
consent.
The Aquila PPA requires the Partnership to own, operate, maintain and
control all of the electrical interconnection facilities up to the point of
interconnection of the Facility with Entergy's and TVA's transmission systems.
Aquila is responsible for obtaining and paying for the provision of transmission
services and any ancillary or control area services required beyond the
interconnection points between the Facility and the TVA and Entergy transmission
systems.
The Partnership is required to obtain all governmental approvals required
for the ownership, construction, operation and maintenance of the lateral
natural gas pipeline. The Partnership is also required to construct and operate
and maintain the lateral natural gas pipeline.
Under the Aquila PPA either party is excused from performing its obligations
due to force majeure events or events that are not in its reasonable control.
The Partnership is not liable for or deemed in breach of the Aquila PPA to the
extent performance of its obligations is delayed or prevented by circumstances
due to the non-performance of Aquila. The Aquila PPA is a tolling arrangement,
whereby Aquila is obligated to supply natural gas to the Aquila Unit. Aquila is
obligated to arrange, procure, nominate, balance, transport and deliver to the
Facility's lateral pipeline the amount of fuel necessary for the Aquila Unit to
generate its net electrical output. The Partnership is obligated to administer
gas imbalances on the Facility's lateral pipeline among all parties using the
Facility's lateral pipeline.
Utilicorp is required to file reports and other information with the
Securities and Exchange Commission. These reports include information about
Aquila because it is a wholly-owned subsidiary of UtiliCorp. The reports and
other information filed by UtiliCorp are available on the Securities and
Exchange Commission's web site, which can be accessed at HTTP://WWW.SEC.GOV.
The following summarized condensed balance sheets and income statements of
Utilcorp United Inc. at September 30, 1999 and December 31, 1998 were obtained
from the Securities and Exchange Commission's web site. The summarized condensed
financial information should read in conjunction with the complete financial
statements for the periods presented herein, the related notes to such financial
statements and the respective independent auditors' report. The summarized
condensed financial information also may not be indicative of the entity's
ability to fulfill its obligations under the power purchase agreement.
F-23
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
CONDENSED BALANCE SHEETS (IN THOUSANDS) (UNAUDITED)
The summarized condensed financial information should be read in conjunction
with the complete financial statements for the periods presented herein, the
related notes to such financial statements and the respective independent
auditors' report. The summarized condensed financial information also may not be
indicative of the entity's ability to fulfill its obligations under the power
purchase agreement.
<TABLE>
<CAPTION>
ASSETS 09/30/1999 12/31/1998
- ------ ----------- -----------
<S> <C> <C>
Cash........................................................ $ 181,200 $ 120,500
Other Current Assets........................................ 3,120,800 1,784,300
----------- -----------
Current Assets.............................................. 3,302,000 1,904,800
Property, Plant & Equipment, Net............................ 3,672,000 3,313,900
Other Non-Current Assets.................................... 1,523,600 912,200
----------- -----------
Non-Current Assets.......................................... 5,195,600 4,226,100
----------- -----------
TOTAL ASSETS................................................ $ 8,497,600 $ 6,130,900
=========== ===========
LIABILITIES & EQUITY
- ------------------------------------------------------------
Accounts Payable............................................ $ 2,854,600 $ 1,415,300
Other Current Liabilities................................... 655,400 815,900
----------- -----------
Current Liabilities......................................... 3,510,000 2,231,200
Long-Term Debt.............................................. 2,234,200 1,376,600
Other Long-Term Liabilities................................. 895,800 976,800
----------- -----------
Long-Term Liabilities....................................... 3,130,000 2,353,400
----------- -----------
TOTAL LIABILITIES........................................... 6,640,000 4,584,600
----------- -----------
Shareowners' Equity......................................... 1,857,600 1,546,300
----------- -----------
TOTAL LIABILITIES & SHAREOWNERS' EQUITY..................... $ 8,497,600 $ 6,130,900
=========== ===========
CONDENSED INCOME STATEMENT (IN THOUSANDS) (UNAUDITED)
<CAPTION>
NINE
MONTHS YEAR
ENDED ENDED
09/30/1999 12/31/1998
----------- -----------
<S> <C> <C>
Sales....................................................... $14,235,400 $12,563,400
Cost of Sales............................................... (13,390,200) (11,596,000)
----------- -----------
Gross Margin................................................ 845,200 967,400
Operating Expenses.......................................... (577,100) (726,600)
----------- -----------
Operating Income............................................ 268,100 240,800
Other Income/(Expense)...................................... 43,700 110,600
Interest Expense............................................ (134,200) (132,600)
Income Taxes................................................ (58,400) (86,600)
----------- -----------
NET INCOME.................................................. $ 119,200 $ 132,200
=========== ===========
</TABLE>
F-24
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
On July 22, 1998, the Partnership entered into a $240 million fixed price
Turnkey Engineering, Procurement and Construction Contract ("Construction
Agreement") with BVZ Power Partners--Batesville ("BVZ"), a joint venture formed
by H.B. Zachary Company and a subsidiary of Black & Veatch, LLP. The obligations
of BVZ are guaranteed by Black & Veatch, LLP and the entire Construction
Agreement is backed by a performance bond. Under the terms of the Construction
Agreement, BVZ has committed to develop and construct the Facility subject to
the terms, deadlines and conditions set forth in the Construction Agreement. In
the event the construction and start-up to specified performance levels of the
two VEPCO Units and the Aquila Unit has not occurred on or prior to July 16,
2000, July 26, 2000 and July 31, 2000, as adjusted under the terms of the
Construction Agreement ("Guaranteed Completion Dates"), respectively, then BVZ
will be required under the contract to pay liquidated damages, subject to
limits. In the event the construction and start-up of the entire Facility to
specified performance levels occurs prior to the last Guaranteed Completion
Date, then BVZ will be entitled to receive a bonus for early completion.
At various times during the period between January 8, 1999 and January 15,
1999, BVZ's access to the construction site was limited as a result of the
failure of the temporary access road. Due to delays in construction progress
experienced by BVZ during this period, the Partnership and BVZ entered into a
change order to the Construction Agreement to extend the Guaranteed Completion
Dates by 7 days. This extension is reflected in the Guaranteed Completion Dates
above.
The Partnership received a force majeure notice from BVZ and the
manufacturer of the steam turbine generators with respect to delays incurred
during the transportation of one of the VEPCO Unit's steam turbine generator to
the Facility. The Partnership requested that BVZ and the manufacturer provide
additional information to support the claim of force majeure. In response to our
request, the manufacturer has recently provided information indicating a total
of 21 days of delay and an 18 day claim of force majeure for delay in the
delivery of the steam turbine generator. The Partnership does not believe that
the delays in transportation of the steam turbine generator constitute a force
majeure event. BVZ has stated that it is working extra hours, multiple shifts
and weekends in an attempt to meet its originally projected target completion
dates. If it is determined that the delay in the delivery of the steam turbine
constitutes a force majeure event under the BVZ Construction Agreement, BVZ
would be entitled to a day for day extension of the guaranteed completion date
with respect to that VEPCO Unit. We have informed VEPCO of the occurrence of a
potential force majeure event as a result of a delay in the delivery of the
VEPCO Unit's steam turbine generator that was beyond our reasonable control and
without our fault or negligence. If it is determined that the delay in the
delivery of the steam turbine constitutes a force majeure event under the VEPCO
PPA agreement, the date that we are required to deliver power under the VEPCO
PPA agreement would be extended day for day for the number of days of the force
majeure event. A final resolution of the issue has not yet occurred.
A gap of 46 to 61 days currently exists between the Guaranteed Completion
Dates and the guaranteed delivery start dates of June 1, 2000 under the
VEPCO PPA and the Aquila PPA. This gap may be increased if BVZ is successful in
its claim that the steam turbine delay constitutes a force majeure event and we
are unsuccessful in our claim that the steam turbine delay constitutes a force
majeure event under the VEPCO PPA agreement. This gap and any further delay in
construction and start-up of the Facility beyond June 1, 2000, may obligate the
Partnership to: (i) provide replacement
F-25
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
power to VEPCO or reimburse VEPCO for any incremental replacement power cost
during the period of delay, up to a maximum of $11,320,000 and (ii) elect to, at
the option of the Partnership, provide replacement power to Aquila, reimburse
Aquila for any incremental replacement power cost during the period of delay, or
elect to incur an adjustment to the reservation payment to be received under the
Aquila PPA. The current construction schedule provided to the Partnership by BVZ
anticipates that the construction and start-up of the two VEPCO Units and the
Aquila Unit will occur on May 10, 2000, June 5, 2000 and June 27, 2000,
respectively. The Partnership has notified both VEPCO and Aquila of these
revised dates. Based upon the estimated completion date of June 5, 2000 for one
of the VEPCO Units the Partnership will be obligated for the cost of replacement
power for the period from June 1, 2000 to June 5, 2000. The Partnership has
notified Aquila that it will elect to incur an adjustment to the reservation
payment to be received for the period from June 1, 2000 to June 27, 2000 under
the Aquila PPA. The estimated liability that may result from this period of
delay, if any, cannot presently be determined.
While BVZ will be obligated to pay liquidated damages for any failure to
complete the construction and start-up of the Facility on or prior to one day
after the Guaranteed Completion Dates, no delay damages will be due from BVZ
with respect to any Unit during the respective gap periods described above.
Because the delay liquidated damages are subject to limits, there can be no
assurance that such liquidated damages will fully compensate the Partnership for
replacement power costs or other costs associated with delays for which BVZ is
responsible. The ultimate liability that would result from this delay, if any,
cannot presently be determined.
In accordance with the terms of the Construction Agreement, Granite made
payments aggregating $1,742,500 during the months of July 1998 and August 1998,
on behalf of the Partnership. Granite was reimbursed for these payments by the
Partnership on August 28, 1998. As of December 31, 1999 and 1998, engineering,
procurement and construction was estimated to be approximately 93% and 26%
complete, respectively, and total costs incurred to date under the Construction
Agreement were approximately $222,664,000 and $61,754,000, respectively,
including retainage. At December 31, 1999 and December 31, 1998, the Partnership
had retained construction contract payments under the Construction Agreement
totaling approximately $11,091,000 and $2,882,000, respectively.
The Partnership has entered into a contract with Kruger, Inc. ("Kruger")
dated September 15, 1999 for the supply of water pretreatment system equipment.
The lump sum price for this contract is approximately $415,000, which includes
all costs associated with the engineering, manufacturing and delivery of the
water pretreatment system equipment. As of December 31, 1999, approximately
$166,000 of the contract had been completed and invoiced to the Partnership,
including approximately $8,300 of retainage. During January 2000, all major
equipment was delivered to the Facility. The obligations of Kruger are secured
by a performance bond and a payment bond.
The Partnership entered into a contract with Lauren Constructors, Inc.
("Lauren") dated October 19, 1999 for the engineering, procurement and
construction of a water pretreatment system. The water pretreatment system will
operate to help ensure that water supplied to the Facility is of the quality
specified in the Construction Agreement with BVZ. The lump sum price for this
contract is approximately $1,703,000. As of December 31, 1999, approximately
$207,000 of the contract had been completed and invoiced to the Partnership
including approximately $10,400 of retainage.
F-26
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
Lauren must pay the Partnership $5,000 per day for each day substantial
completion of the water treatment system is delayed beyond April 7, 2000. The
obligations of Lauren are secured by a performance bond and a payment bond.
The Partnership has entered into electrical interconnection agreements with
Tennessee Valley Authority (the "TVA Interconnection Agreement") and with
Entergy Mississippi, Inc. (the "Entergy Interconnection Agreement" and together
with the TVA Interconnection Agreement, the "Interconnection Agreements").
The TVA Interconnection Agreement has a term of thirty-five years, subject
to certain amendments for regulatory conformance on a non-discriminatory basis,
which amendments could be proposed by the Tennessee Valley Authority at any time
after five years from commencement of commercial operations. If the Partnership
and TVA fail to reach agreement on such amendment within six months, TVA may
terminate the TVA Interconnection Agreement upon giving the Partnership one
years' notice.
The TVA Interconnection Agreement provides for the cost of the
interconnection facilities of approximately $4,000,000 and system upgrades of
approximately $9,500,000 to be paid by the Partnership. As of December 31, 1999,
total costs incurred under the TVA Interconnection Agreement were approximately
$12,556,000. The partnership is entitled to receive system upgrade credits in
the amount of incremental revenue received by Tennessee Valley Authority for
future transmission services procured for the delivery of energy from the
Facility. The amount of such credits, if any, may not exceed the total cost of
the system upgrades paid for by the Partnership.
The TVA Interconnection Agreement does not cover transmission service. Under
our power purchase agreements with VEPCO and Aquila, the power purchasers are
responsible for arranging transmission services across TVA's system for the term
of the power purchase agreements. To the extent energy produced by the Facility
is transmitted over TVA's transmission system, the transmission service will be
purchased at the rates established by TVA's tariff.
TVA must prepare and submit to the Partnership a written voltage schedule
which shall be coordinated and be consistent with the voltage schedules provided
by Entergy. The Partnership must comply with the schedule and install, operate
and maintain the equipment needed for compliance. If energy produced by the
Facility is transmitted across the TVA system, an appropriate adjustment for
reactive supply and voltage control will be made to reflect the contribution to
reactive supply and voltage support made by the Facility.
On a daily basis, the Partnership must inform TVA as to the forecasted
hourly generation levels of the Facility for the following day, including any
anticipated outages. The Partnership must take all actions to assure that during
each hour the amount of designated output is equal to or greater than the
schedule of energy delivered by TVA to third parties. In the event a difference
occurs between the scheduled amount and the designated output, the Partnership
will be required to pay the appropriate charges or other compensation applied to
the difference, which charges or compensation will be consistent with the
charges or compensation applied to similar power production facilities, under
comparable circumstances, located in the TVA control area.
F-27
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
The Entergy Interconnection Agreement has a term of thirty-five years from
the date when the interconnection facilities have been completed, automatically
extending for subsequent five-year periods.
The Entergy Interconnection Agreement provides for the cost of the
interconnection facilities of approximately $1,100,000 and system upgrades of
approximately $7,100,000 to be paid by the Partnership. As of December 31, 1999,
total costs incurred under the Entergy Interconnection Agreement were
approximately $6,286,000. The Partnership is entitled to receive system upgrade
credits in the amount of incremental revenue received by Entergy for future
transmission services procured for the delivery of energy from the Facility. The
amount of such credits, if any, may not exceed the total cost of the system
upgrades paid for by the Partnership.
The Entergy Interconnection Agreement does not cover transmission service.
Under our power purchase agreements with VEPCO and Aquila, the power purchasers
are responsible for arranging transmission services across Entergy's system for
the term of the power purchase agreements. To the extent energy produced by the
Facility is transmitted over Entergy's transmission system, the transmission
service will be purchased at the rates established by Entergy's tariff.
The Partnership must operate the facility to meet the voltage schedules
designated by Entergy, which must be within the normal operating range of the
Facility and consistent with voltage schedules provided by TVA, which shall be
coordinated and be consistent with the voltage schedules provided by Entergy.
The Partnership must comply with the schedule and install, operate and maintain
the equipment needed for compliance. If energy produced by the Facility is
transmitted across the Entergy system, an appropriate adjustment for reactive
supply and voltage control will be made to reflect the contribution to reactive
supply and voltage support made by the Facility.
The Partnership entered into an interconnection agreement with ANR Pipeline
Company ("ANR") dated July 29, 1998 to establish an interconnection between the
ANR interstate natural gas pipeline system and the Partnership's lateral natural
gas pipeline. Each party must design, engineer, and construct its portion of the
interconnection, own title to its interconnection and is responsible for
insuring those interests.
Under the terms of the interconnection agreement the Partnership is required
to reimburse ANR for all reasonable costs, up to $250,000, incurred by ANR with
respect to the design, engineering, construction, testing and placing in service
of the ANR interconnection facilities. The Partnership may also be required to
reimburse ANR for, and hold ANR harmless against, any incremental federal taxes
that will be due by ANR if the costs of the ANR interconnection facilities are
deemed to be a contribution in aid of construction under the Internal Revenue
Code. ANR must use commercially reasonable efforts to minimize such costs.
Each party is generally responsible for the operation, repair and
replacement of its portion of the interconnection facilities, and for all
associated cost, expense and risk. ANR will operate and perform minor
maintenance within the capability of ANR's technicians on the gas measurement
equipment, operate, but not maintain, that portion of the Partnership's
interconnection facilities located on ANR owned land, and, in the case of an
emergency involving the Partnership's interconnection facilities, take such
steps and incur such expense as ANR determines are necessary to abate the
emergency and to
F-28
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
safeguard life and property. The Partnership will reimburse ANR for all costs
and expenses incurred by ANR with respect to such emergencies.
All gas delivered by ANR to the Partnership at the interconnection
facilities will conform to specifications set forth in ANR's tariff and will be
delivered at ANR's prevailing line pressure. The Partnership and ANR will each
make reasonable efforts to control their respective prevailing line pressure to
permit gas to enter the Partnership's lateral pipeline.
Custody of the gas will transfer from ANR to the Partnership or the
Partnership's power purchasers after it passes through the custody transfer
point. The custody transfer point is located where the ANR interconnection
facilities and the Partnership's interconnection facilities are connected. The
actual quantity of gas delivered by ANR to the Partnership will be determined
using the recorded meter information at this custody transfer point.
The ANR interconnection agreement is in full force and effect until
terminated by the mutual agreement of both parties or the Partnership's final
removal and/or abandonment of the Partnership's interconnection facilities. Upon
notice, either party may terminate the ANR interconnection agreement if the
other party materially breaches it obligation.
The Partnership entered into a facilities agreement with Tennessee Gas
Pipeline Company ("Tennessee Gas") dated June 23, 1998 to establish tap
facilities and connecting facilities for an interconnection between the
Tennessee Gas natural gas pipeline system and the Partnership's lateral natural
gas pipeline. Tennessee Gas must design, engineer, install, construct, inspect,
test and own the tap facilities. The Partnership must design, install, construct
and test the connecting facilities. Tennessee Gas has the right of access to the
connecting facilities installed by the Partnership to install tap facilities and
to inspect, test and witness the Partnership's testing of the connecting
facilities. Each party must ensure its work under the facilities agreement is in
accordance with Tennessee Gas's design specifications, sound and prudent gas
industry practice and applicable laws.
Under the terms of the facilities agreement the Partnership is required to
reimburse Tennessee Gas for all costs incurred by Tennessee Gas with respect to
the design, engineering, installation construction, and testing of the tap
facilities and any expenses incurred by Tennessee Gas with respect to the
installation of the connecting facilities. As of November 30, 1999, Tennessee
Gas provided notification that anticipated the total facilities cost may exceed
the estimated cost of $231,000 by more than 20%.
Tennessee Gas is responsible for the operation, repair, replacement and
maintenance of the tap facilities, and for all associated cost, expense and
risk. The Partnership will provide support for any regulatory authorization or
permitting requirements for the tap facilities. Tennessee Gas has the right to
inspect the connecting facilities at all reasonable times to ensure that the
facilities are installed, operated and maintained correctly.
The Tennessee Gas interconnection agreement is in full force and effect
until the final removal and/or abandonment of the tap facilities and connecting
facilities, unless terminated by the Partnership or by Tennessee Gas as a result
of the Partnership's failure to make timely payments, if gas has not flowed
through the connecting facilities for the previous period of 12 consecutive
months or in the event the Partnership has caused the connecting facilities to
be disconnected or removed. Tennessee
F-29
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
Gas cannot cause the final removal and/or abandonment of the tap facilities and
connecting facilities without approval of the Federal Regulatory Commission.
The Partnership entered into a contract with Black & Veatch, LLP dated as of
July 24, 1998 for the engineering services related to construction of the
Infrastructure and the Project's electrical substation and transmission lines.
Under the terms of the contract, Black & Veatch, LLP developed the conceptual
design and the bid packages for these facilities and developed the conceptual
design for the interconnection of these facilities provided under each of the
other construction contracts to the Facility. For the years ended December 31,
1999 and 1998, Black & Veatch had billed the Partnership for approximately
$269,000 and $258,000, respectively, under the engineering services contract.
The Partnership has entered into three contracts aggregating approximately
$9,200,000 for the design and construction of an electrical substation and
transmission line system (the "Partnership's Interconnection Facilities"). The
Partnership's Interconnection Facilities are required to enable the Partnership
to deliver the output of the Facility to the Tennessee Valley Authority and
Entergy Mississippi, Inc. interconnection facilities. The Partnership will
design, construct, own and operate the Partnership's Interconnection Facilities
at its own expense.
The Partnership entered into another contract with Lauren
Constructors, Inc. ("Lauren") dated January 13, 1999 for the design,
engineering, procurement, construction and testing of electrical substation and
transmission lines that will interconnect to the TVA and Entergy transmission
systems. The lump sum price for this contract is approximately $4,714,000
including change orders. As of December 31, 1999 approximately $4,671,000 of the
contract had been completed and invoiced to the Partnership, including retainage
of approximately $228,000. The obligations of Lauren are secured by a
performance bond and a payment bond.
The Partnership has entered into a contract with North American
Transformer, Inc. ("North American") dated as of January 13, 1999 for the supply
of four single phase transformers to be incorporated into our electrical
substation. The lump sum price for this contract is approximately $3,683,000. As
of December 31, 1999 the total contract had been invoiced to the Partnership
including retainage of approximately $368,000. The obligations of North American
are secured by a performance bond and a payment bond.
The Partnership has entered into a contract with Siemens Power Transmission
and Distribution, LLC ("Siemens") dated as of January 13, 1999 for the supply of
thirteen circuit breakers to be incorporated into the Partnership's electrical
substation. The lump sum price for this contract is approximately $722,000. As
of December 31, 1999 the total contract had been invoiced to the Partnership,
including retainage of approximately $72,000. The obligations of Siemens are
secured by a performance bond and a payment bond.
The Partnership entered into three contracts aggregating approximately
$18,350,000 for the construction of the Facility's gas lateral pipeline and the
pipelines through which the Facility will receive water and dispose of waste
water (collectively the "Infrastructure"). These contracts were subsequently
transferred to Panola County, Mississippi ("Panola County"). The Partnership has
leased the Infrastructure under terms which provide the Partnership with the
operational control and responsibility for the Infrastructure, and with the use
of the Infrastructure for the full projected requirements of the Facility.
F-30
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
The Partnership has entered into a contract with Robinson Mechanical
Contractors, Inc. ("Robinson") dated as of January 13, 1999 for the design,
engineering, procurement, construction and testing of intake facilities that
will withdraw water from Enid Lake and pump it to the Facility. The lump sum
price for this contract is approximately $5,256,000 including change orders.
Robinson is obligated to pay $5,000 for each day that completion of the water
intake infrastructure is delayed beyond November 1, 1999. As of December 31,
1999 approximately $4,080,000 of the contract had been invoiced to the
Partnership. As of December 31, 1999, the Partnership had outstanding accounts
payable to Robinson of approximately $150,000. The obligations of Robinson are
secured by a performance bond and a payment bond. Pursuant to a change order
effective November 1, 1999, the Partnership transferred the water intake
contract to Panola County; therefore, the Partnership is no longer entitled to
receive liquidated damages under this contract.
The Partnership has entered into a contract with Garney Companies, Inc.
("Garney") dated as of March 1, 1999 for the design, engineering, procurement,
construction and testing of a water supply pipeline to transport water from Enid
Lake to the Facility and a wastewater discharge pipeline to transport wastewater
from the Facility to the Little Tallahatchie River. The lump sum price for this
contract is approximately $4,528,000 including change orders. Garney is
obligated to pay $5,000 for each day that final completion is delayed beyond
November 1, 1999. As of December 31, 1999 the total contract had been invoiced
to the Partnership. As of December 31, 1999, the Partnership had outstanding
accounts payable to Garney of approximately $20,000. The obligations of Garney
are secured by a performance bond and a payment bond. Pursuant to a change order
effective November 1, 1999, the Partnership transferred the water supply and
waste water pipeline contract to Panola County; therefore, the Partnership is no
longer entitled to receive liquidated damages under this contract.
The Partnership has entered into a contract with Big Warrior Corporation
("Big Warrior") dated as of February 4, 1999 for the design, engineering,
procurement, construction and testing of a lateral gas pipeline and related
facilities to transport natural gas from two interstate gas pipelines to the
Partnership's Facility. The lump sum price for this contract is approximately
$8,565,000 including change orders. Big Warrior is obligated to pay $5,000 for
each day that initial operation of the gas pipeline is delayed beyond
October 1, 1999 and $10,000 for each day that final completion is delayed beyond
November 1, 1999. As of December 31, 1999 approximately $8,450,000 of the
contract had been completed and invoiced to the Partnership. As of December 31,
1999, the Partnership had no outstanding accounts payable to Big Warrior. The
obligations of Big Warrior are secured by a performance bond and a payment bond.
Pursuant to a change order effective November 1, 1999, the Partnership
transferred the lateral gas pipeline contract to Panola County; therefore, the
Partnership is no longer entitled to receive any liquidated damages under this
contract.
The Partnership has entered into five agreements with State of Mississippi
governmental entities. Under an "Inducement Agreement," the State of Mississippi
agreed to issue general obligations bonds (the "Municipal Bonds") to finance the
Infrastructure, Panola County (and ultimately the Industrial Development
Authority of Panola County) agreed to assume ownership of the Infrastructure,
and the Partnership agreed to operate and maintain both the Facility and the
Infrastructure. As contemplated by the Inducement Agreement, the Partnership has
transferred to Panola County the construction contracts relating to the
Infrastructure and its title to the Infrastructure already completed or under
F-31
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
construction, together with permanent easements and real estate rights relating
to the Infrastructure sites. The Partnership paid the cost of constructing the
Infrastructure until the State of Mississippi issued the Municipal Bonds to
finance the Infrastructure and these transfers had been made. The State of
Mississippi has reimbursed the Partnership for the costs that it incurred for
development and easement acquisition activities and for the construction of the
Infrastructure after April 11, 1999 and will pay any remaining costs due under
the Infrastructure contracts up to a maximum aggregate amount of approximately
$17,000,000. The Partnership has received approximately $14,278,000 of these
funds as a reimbursement. This reimbursement has been reflected as a reduction
in land and easements and construction in progress of approximately $899,000 and
$13,379,000, respectively, in the accompanying financial statements.
Under the Inducement Agreement, the Partnership has promised to maintain the
Facility and to keep it capable of being operated other than during periods when
the Facility is not available because of maintenance or repair or for reasons
beyond the Partnership's control, and to perform the Partnership's obligations
under the other Infrastructure agreements. In the event the Partnership fails to
do so, the Partnership would be responsible for paying to the State an amount
equal to (1) the outstanding principal amount of the Municipal Bonds times a
fraction the numerator of which is the number of months remaining in the term of
these bonds and the denominator of which is the original number of months in the
term of these bonds plus (2) accrued interest on that principal amount plus
(3) the costs of redeeming these bonds.
The Partnership has entered into agreements with the County and the IDA that
will allow the Partnership to use the Infrastructure. The Partnership has
entered into one agreement with respect to the natural gas lateral pipeline and
one with respect to the water supply and wastewater discharge systems. Each of
these agreements is in the form of a lease each with an initial term of
30 years. In return for the Partnership's use of the Infrastructure, the
Partnership promises to operate and maintain, or arrange for the operation and
maintenance of, the Infrastructure and to pay for all operation and maintenance
expenses. The Partnership currently expects that the operation and maintenance
of the natural gas lateral pipeline will be performed by the Operator or another
experienced gas pipeline operator, and that operation and maintenance of the
water supply and wastewater discharge systems will be performed by the Operator.
The Partnership also currently expects that the City of Batesville, Mississippi
will be an additional user of the capacity of the natural gas lateral pipeline
which is in excess of the capacity required to operate the Facility. The
Partnership currently expects that there may be additional users in the future
of the water supply and wastewater discharge systems. In the case of any such
additional user of the water infrastructure, the Partnership has approval rights
over the terms and conditions (including cost sharing, indemnification and any
restrictions resulting from regulatory limitations) pursuant to which such
additional users will be provided access to use the water infrastructure.
In consideration for the approval to locate a portion of the Infrastructure
in Yalobusha County, Mississippi and the Coffeeville School District, the
Partnership has entered into an agreement with Yalobusha County, Mississippi,
and the Coffeeville School District to pay them an aggregate amount equal to
$1,500,000. This payment will be due on or before the first day of February
following the first full calendar year after the year in which the Facility is
certified substantially complete. This payment will constitute a credit against
the amount, if any, of any ad valorem real and/or personal property
F-32
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
taxes assessable against and leviable on or with respect to the assessable
interest of the Partnership in the water intake Infrastructure. The Partnership
estimates that this payment will be made in 2002.
Finally, in consideration for its use of the Infrastructure, the Partnership
has entered into an agreement with and has promised to pay Panola Partnership,
Inc. (a County governmental entity) a yearly payment equal to $300,000, which
escalates annually, so long as the Inducement Agreement and the use agreements
described above remain in effect and are not terminated, other than as a result
of a default by the Partnership.
As with any major construction effort, construction of the facility involves
many risks, including shortages of labor, work stoppages, labor disputes,
weather interferences, engineering, environmental permitting or geological
problems and unanticipated cost increases for reasons beyond the control of BVZ
and the other contractors, the occurrence of which could give rise to delays,
cost overruns or performance deficiencies, or otherwise adversely affect the
design or operation of the Facility.
The Partnership entered into a water supply storage agreement with the
United States of America ("the Government"), represented by the District
Engineer of the Vicksburg District of the United States Army Corps of Engineers
(the "District Engineer"), that provides for storage in Enid Lake of the
Partnership's industrial water supply. Enid Lake is approximately 15 miles south
of the site of the Facility. The United States Army Corps of Engineers pursuant
to the Flood Control Act of March 28, 1928, as amended, constructed and now
operates the lake to control flooding in the region.
The Water Supply Storage Agreement continues for the life of the
Government's Enid Lake project. In the event the Government no longer operates
Enid Lake, the Partnership's rights associated with storage may continue subject
to the execution of a separate agreement or additional supplemental agreement
with the new operator.
The Partnership has an undivided 7.8% of the storage space in Enid Lake that
is estimated to contain 4,500 acre-feet after adjustments for sediment deposits.
The Partnership may withdraw water from Enid Lake to the extent that its storage
space allows and the Partnership may construct any required works, plants and
pipelines necessary for diverting or withdrawing such water. The Government must
reserve 4,500 acre-feet of storage for the Partnership for up to 24 months while
the Partnership designs and constructs the water intake storage structure. If
the Partnership cannot complete construction within that time, the Partnership
may terminate this agreement.
For the period of up to 24 months that the Partnership uses the Government
reserved 4,500 acre-feet of storage while its water intake structure is designed
and constructed, the Partnership must pay to the Government $1.00 per acre-foot
per year for the use of the Government reserved 4,500 acre-feet storage.
The Partnership must pay to the Government an amount equal to the cost
allocated to the water storage rights acquired by the Partnership, which is 7.8%
of the water storage rights at Enid Lake. The Partnership's cost is estimated to
be $1,100,000, subject to adjustments for the year the initial payment is made.
This cost is payable over the life of the Enid Lake flood control project, but
not to exceed 30 years from the due date of the first annual payment. The first
payment must be made the earlier of 30 days after the Partnership's initial use
of the storage or within 24 months after the Partnership's notification by the
District Engineer that this water supply storage agreement is effective.
F-33
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
4. FACILITY CONTRACTS (CONTINUED)
The unpaid balance of the Partnership's storage cost will accrue interest at
a rate determined pursuant to Section 932 of the 1986 Water Resources
Development Act. In 1998, the rate was 6.75%. At this interest rate the
Partnership's combined yearly principal and interest payments would total
approximately $81,800, with the first payment to be applied solely against the
principal. The interest rate will be adjusted prior to the first payment to
reflect the appropriate interest rate. Thereafter, the interest rate will be
adjusted at five year intervals.
In addition to the annual water storage cost, the Partnership must pay,
annually, 0.682% of (i) the costs of any repair, rehabilitation or replacement
of Enid Lake features as a result of any joint use with another entity utilizing
Enid Lake and (ii) the annual joint use operation and maintenance expenses.
The Partnership entered into an Ad Valorem Tax Contract dated as of
August 28, 1998, with the County of Panola, Mississippi, the City of Batesville,
Mississippi, the Mississippi Department of Economic and Community Development
acting for and on behalf of the State of Mississippi and the Panola County Tax
Assessor/Collector (the "Government Entities"). The Government Entities granted
to the Partnership several tax reductions and incentives to construct the
Facility in Batesville. The Government Entities have agreed that the Partnership
is eligible for a fee-in-lieu-of-taxes of not less than one-third of the
Partnership's state and local taxes.
The fee-in-lieu-of-taxes amount which the Partnership must pay equals
one-third of the taxes assessed against the Partnership, the Facility,
inventories and any assessable interest of the industrial water supply system,
the wastewater disposal system, the fire protection system and the lateral gas
pipeline, provided that the fee-in-lieu-of-taxes amount will never be less than
$1,900,000 per year. The fee-in-lieu-of-taxes is also subject to all millage
changes.
The fee-in-lieu-of-taxes is for a 10 year period beginning on the first
January 1st after the Facility has been substantially completed and the
Partnership has spent at least $100,000,000 on the construction of the Facility.
However, if both of these events occur between January 1st and March 1st of the
same year then the term will commence on January 1st of that year. To the extent
lawfully available, the Government Entities will apply this agreement to any
expansions, improvements or equipment replacements provided that the Partnership
complies with its material obligations under this ad valorem tax agreement.
The Partnership must maintain the Facility and keep it capable of being
operated other than during periods when the Facility is not available because of
maintenance or repair or for reasons beyond the Partnership's control. If the
Partnership fails to do so, this agreement will terminate on the January 1st
following the Partnership's failure.
These and other contracts and activities incident to the construction and
ultimate operation of the Facility require various other commitments and
obligations by the Partnership. Additionally, the contracts contain various
restrictive covenants, which allow the contracted party to terminate the
contract upon the occurrence of specified events or, in certain cases, default
under other contractual commitments.
F-34
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
5. FINANCING
Effective August 28, 1998, the Partnership entered into agreements with a
financial institution (the "Bank"), that provided for financing in the amount of
$180,000,000 (the "Tranche A Credit Facility"). Borrowings from this financing
were used for the development and construction of the Facility. These agreements
also contemplated circumstances under which LSP Batesville Funding Corporation
("Funding") and Holding would enter into agreements whereby they would issue
bonds in the amounts of $100,000,000 (the "Tranche B Bond Facility") and
$50,000,000 (the "Tranche C Bond Facility"), respectively, in order to further
finance the construction of the facility. The terms and conditions of the
Tranche B Bond Facility and Tranche C Bond Facility were set forth in a letter
agreement (the "Letter Agreement") entered into among the Partnership, Holding
and Funding (collectively, the "Borrowers") and the Bank. Bonds under the
Tranche B Bond Facility and Tranche C Bond Facility were never issued.
Pursuant to the Letter Agreement, the Borrowers and the Bank, as
underwriter, also agreed to pursue a capital markets offering during the last
quarter of 1998. However, due to unfavorable capital markets conditions the
capital markets offering was not completed. Alternatively, on December 15, 1998
the Partnership amended and restated the financing agreements entered into on
August 28, 1998. The amended and restated agreements provided for financing in
the amount of $305,000,000. The new financing consisted of a $305,000,000
three-year loan facility (the "Bank Credit Facility") entered into among the
Partnership and a consortium of banks.
A common agreement (the "Common Agreement") tied all of the financing
agreements together and set forth, among other things: (a) terms and conditions
upon which loans and disbursements were to be made under the Bank Credit
Facility; (b) the mechanism for which loan proceeds, operating revenues, equity
contributions and other amounts received by the Partnership were disbursed to
pay construction costs, operations and maintenance costs, debt service and other
amounts due from the Partnership; (c) the conditions which had to be satisfied
prior to making distributions from the Partnership; and (d) the covenants and
reporting requirements the Partnership was required to be in compliance with
during the term of the Common Agreement.
The Common Agreement prohibited the Partnership from making any
distributions to its partners while loans made under the Bank Credit Facility
were outstanding.
The Common Agreement also required the Partnership to set aside reserves for
the cost of performing periodic major maintenance on the Facility, including
turbine overhauls, and the credit support, if any, that the Partnership is
required to provide to Aquila under the Aquila PPA.
The aggregate principal amount of all loans under the Bank Credit Facility
could not exceed $305,000,000. The maturity date of loans outstanding under the
Bank Credit Facility was the earlier of (a) December 15, 2001 and (b) the
commitment termination date, as defined.
During the period from December 15, 1998 through May 21, 1999, interest
rates on amounts outstanding, based on loan amounts designated by the
Partnership, were (i) .125% above the higher of the Prime Rate or .50% above the
Federal Funds Rate (collectively the "Base Rate") or (ii) 1.125% above the
selected London Interbank Offered Rate ("LIBOR") term, not to exceed one year.
Interest payments on Base Rate loans were payable quarterly. Interest
payments on LIBOR loans were payable on the last day of the LIBOR loan term, or
if the LIBOR loan term maturity was longer
F-35
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
5. FINANCING (CONTINUED)
than three months, every three months after the date of such LIBOR loan. At
December 31, 1998, the Partnership had $78,000,000 of LIBOR loans outstanding
under the Bank Credit Facility. Interest rates on the outstanding loans at
December 31, 1998 ranged from 6.355% to 6.505%.
A quarterly commitment fee of .375% was incurred on the daily average
unadvanced and available commitment under the Bank Credit Facility.
The Partnership entered into a Letter of Credit and Reimbursement Agreement
(the "LOC Agreement") with the Bank that provides for letter of credit
commitments aggregating $16,980,000. The LOC Agreement provides for the Bank to
issue three separate letters of credit ("Letter of Credit A", "Letter of Credit
B" and "Letter of Credit C"). The letters of credit will be used to provide
security in favor of VEPCO to support the Partnership's obligations under the
VEPCO PPA. The LOC Agreement requires the Partnership to pay commitment fees
quarterly in arrears, at varying rates on each letter of credit commitment until
the expiration of each letter of credit commitment. The Partnership is required
to reimburse the Bank for any drawings made by VEPCO under the letters of
credit.
On August 28, 1998, the Bank issued Letter of Credit A in the amount of
$5,660,000 as security for the Partnership's replacement power obligation under
the VEPCO PPA until the earlier of June 1, 2001 and the commercial operations
date.
On December 15, 1998, the Partnership and the Bank amended the LOC Agreement
to conform its terms and conditions to the amended and restated Bank Credit
Facility and Common Agreement.
Loans made under the Bank Credit Facility were secured by all of the assets
and contract rights of the Partnership. In addition, each of the partners had
pledged its respective partnership interest in the Partnership as security for
these loans.
On May 21, 1999, the Partnership and Funding issued two series of Senior
Secured Bonds (the "Bonds") in the following total principal amounts:
$150,000,000 7.164% Series A Senior Secured Bonds due 2014 and $176,000,000
8.160% Series B Senior Secured Bonds due 2025. Interest is payable semiannually
on each January 15 and July 15, commencing January 15, 2000, to the holders of
record on the immediately preceeding January 1 and July 1. On January 15, 2000,
the Partnership made interest payments aggregating approximately $16,320,000.
Interest on the Bonds will accrue from the most recent date to which interest
has been paid or, if no interest has been paid, from the date of original
issuance. Interest will be computed on the basis of a 360-day year consisting of
twelve 30-day months. The interest rate on the Bonds may be increased under the
circumstances described below.
A portion of the proceeds from the issuance of the Bonds was used to repay
the $136,600,000 of outstanding loans under the Bank Credit Facility. The
remaining proceeds from the issuance of the Bonds will be used to pay a portion
of the costs of completing the Facility.
F-36
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
5. FINANCING (CONTINUED)
Principal payments are payable on each January 15 and July 15, commencing on
July 15, 2001. Scheduled maturities of the Bonds are as follows:
<TABLE>
<S> <C>
1999........................................................ $ --
2000........................................................ --
2001........................................................ 4,125,000
2002........................................................ 7,575,000
2003........................................................ 7,125,000
Thereafter.................................................. 307,175,000
------------
Total....................................................... $326,000,000
============
</TABLE>
The Bonds are secured by substantially all of the personal property and
contract rights of the Partnership and Funding. In addition, Holding and Energy
have pledged all of their interests in the Partnership, and Holding has pledged
all of the common stock of Energy and all of the common stock of Funding.
The Bonds are senior secured obligations of the Partnership and Funding,
rank equivalent in right of payment to all other senior secured obligations of
the Partnership and Funding and rank senior in right of payment to all existing
and future subordinated debt of the Partnership and Funding.
The Bonds are redeemable, at the option of the Partnership and Funding, at
any time in whole or from time to time in part, on not less than 30 nor more
than 60 days' prior notice to the holders of that series of Bonds, on any date
prior to its maturity at a redemption price equal to 100% of the outstanding
principal amount of the Bonds being redeemed, plus accrued and unpaid interest
on the Bonds being redeemed and a make-whole premium. In no event will the
redemption price ever be less than 100% of the principal amount of the Bonds
being redeemed plus accrued and unpaid interest thereon.
The Bonds are redeemable at the option of the bondholders if funds remain on
deposit in the distribution account for at least 12 months in a row, and the
Partnership and Funding cause the bondholders to vote on whether the Partnership
and Funding should use those funds to redeem the Bonds, and holders of at least
66 2/3% of the outstanding Bonds vote to require the Partnership and Funding to
use those funds to redeem the Bonds. If we are required to redeem Bonds with
those funds, then the redemption price will be 100% of the principal amount of
the Bonds being redeemed plus accrued and unpaid interest on the Bonds being
redeemed. In addition, if LS Power, LLC, Cogentrix Energy, Inc. and/or any
qualified transferee collectively cease to own, directly or indirectly, at least
51% of the capital stock of Energy (unless any or all of them maintain
management control of the Partnership), or LS Power, LLC, Cogentrix Energy, Inc.
and/or any qualified transferee collectively cease to own, directly or
indirectly, at least 10% of the ownership in the Partnership, then the
Partnership and Funding must offer to purchase all of the Bonds at a purchase
price equal to 101% of the outstanding principal amount of the Bonds plus
accrued and unpaid interest unless the Partnership and Funding receive a
confirmation of the then current ratings of the Bonds or at least 66 2/3% of the
holders of the outstanding Bonds approve the change in ownership.
F-37
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
5. FINANCING (CONTINUED)
The Trust Indenture for the Bonds (the "Trust Indenture") entered into among
the Partnership, Funding and the Bank of New York, as Trustee (the "Trustee")
contains covenants including, among others, limitations and restrictions
relating to additional debt other than the Bonds, Partnership distributions, new
and existing agreements, disposition of assets, and other activities. The Trust
Indenture also describes events of default which include, among others, events
involving bankruptcy of the Partnership or Funding, failure to make any payment
of interest or principal on the Bonds and failure to perform or observe in any
material respect any covenant or agreement contained in the Trust Indenture.
Effective May 21, 1999, the Common Agreement was amended and restated (the
"Amended and Restated Common Agreement"). The Amended and Restated Common
Agreement sets forth, among other things: (a) the mechanism by which Bond
proceeds, operating revenues, equity contributions and other amounts received by
the Partnership are disbursed to pay construction costs, operations and
maintenance costs, debt service and other amounts due from the Partnership and
(b) the conditions which must be satisfied prior to making distributions from
the Partnership.
The Amended and Restated Common Agreement provides that the following
conditions must be satisfied before making distributions from the Partnership to
its partners: (1) the Partnership must have made all required disbursements to
pay operating and maintenance expenses, management fees and expenses and debt
service; (2) the Partnership must have set aside sufficient reserves to pay
principal and interest payments on the Bonds and its other senior secured debt;
(3) there cannot exist any default or event of default under the Trust Indenture
for the Bonds; (4) the Partnership's historical and projected debt service
coverage ratios must equal or exceed the required levels; (5) the Partnership
must have sufficient funds in its accounts to meet its ongoing working capital
needs; (6) the Facility must be complete; and (7) the distributions must be made
after the last business day of September 2000.
The Amended and Restated Common Agreement requires that the Partnership set
aside reserves for: (1) payments of scheduled principal and interest on the
Bonds and the other senior secured debt of the Partnership and the Funding
Corporation; (2) the cost of performing periodic major maintenance on the
Facility, including turbine overhauls; and (3) the credit support, if any, that
the Partnership is required to provide to Aquila under the Aquila PPA.
The Partnership and Funding have agreed to file a registration statement
with the Securities and Exchange Commission (the "SEC") for a registered offer
to exchange the Bonds for two series of debt securities (the "Exchange Bonds")
which are in all material respects substantially identical to the Bonds. Upon
such registration being effective, the Partnership and Funding will offer the
Exchange Bonds in return for surrender of the Bonds. Interest on each Exchange
Bond will accrue from the last date on which interest was paid on the Bond so
surrendered or, if no interest has been paid, since the date of the issuance of
the Bonds.
If the Partnership and Funding do not begin the exchange offer within
270 days of May 21, 1998, the respective interest rates on the Bonds will
increase by one-half of one percent effective on the 271st day following
May 21, 1998. Such increase will remain in effect until the date on which the
Partnership and Funding begin the exchange offer.
F-38
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
6. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of the Partnership's cash, investments held by Trustee,
accounts payable and contract retainage payable approximate fair value because
of the short maturities of these instruments. The estimated fair value of the
Partnership's bonds payable at December 31, 1999, is approximately $16,111,000
lower than the historical carrying value of $326,000,000. The estimated fair
value of outstanding loans payable at December 31, 1998 approximate their
carrying value since the interest rates are variable.
7. PARTNERS' CAPITAL
The amended and restated partnership agreement of the Partnership provides
that profits and losses are generally allocated between the Partnership's
partners, Energy and Holding, in proportion to the partners' respective
partnership interests. Accordingly, 1% of the profits and losses of the
Partnership are allocated to Energy and 99% of the profits and losses of the
Partnership are allocated to Holding. Regular distributions made by the
Partnership with available funds are first used to repay loans made by the
partners to the Partnership and are then paid to the partners in proportion to
their respective partnership interests. Any amounts available for distribution
which are comprised of (1) the excess of (x) the net proceeds of the Bonds and
committed equity contributions to the Partnership over (y) the aggregate of the
project costs for the Facility, or (2) funds released from the debt service
reserve account to the Partnership upon the posting of a letter of credit for
that account, will be distributed to or as directed by Holding. The Amended and
Restated Common Agreement includes conditions that the Partnership must satisfy
before making distributions to its partners (see Note 5).
8. RELATED PARTY TRANSACTIONS
All costs incurred through August 28, 1998 to develop the Facility,
consisting principally of site development costs, engineering fees, legal and
consulting fees, permitting costs, and LS Power employee and office costs have
been expended by Granite. These costs were reimbursed and a development fee of
$11,000,000 was paid to Granite on completion of construction financing on
August 28, 1998 (see Note 5). The aggregate payment to Granite on August 28,
1998 was approximately $13,500,000. In addition, concurrent with the issuance of
the Bonds, the Partnership paid a development fee of $3,000,000 to Granite.
LS Power Management, LLC ("LSP Management"), a wholly owned subsidiary of LS
Power, provides certain management services to the Partnership pursuant to a
management services agreement. Under this management services agreement, LSP
Management manages the business affairs of the Partnership during construction
and operation of the Facility. LSP Management is reimbursed for its reasonable
and necessary expenses incurred in performing its services, including salaries
of its personnel, other than executive officers, to the extent related to
services provided under the management services agreement. LSP Management will
also receive a monthly management fee of approximately $33,300 during the
construction and operation of the Facility. This management fee will be adjusted
annually based on published indices. Management fee payments began during the
third quarter of 1999. For the years ended December 31, 1999 and 1998, LSP
Management billed the Partnership approximately $1,043,000 and $368,000,
respectively, under the management services agreement.
F-39
<PAGE>
LSP ENERGY LIMITED PARTNERSHIP
(A DELAWARE LIMITED PARTNERSHIP IN THE DEVELOPMENT STAGE)
NOTES TO FINANCIAL STATEMENTS (CONCLUDED)
8. RELATED PARTY TRANSACTIONS (CONTINUED)
The Facility is operated and maintained under a long-term operations and
maintenance agreement with Cogentrix Batesville Operations, LLC (the
"Operator"). The initial term of the operations and maintenance agreement is
twenty-seven years. The Partnership has the option of extending the term of the
agreement for successive two-year terms with one hundred and eighty days notice.
Under the terms of the agreement the Partnership is required to pay the Operator
a fixed fee of $390,000, payable in ten monthly installments, for services
provided during construction of the Facility and a fixed monthly fee of
approximately $42,000 during operation of the Facility. The Partnership is also
required to reimburse the Operator for all labor costs, including payroll and
taxes, subcontractor costs and other costs deemed reimbursable by the
Partnership. The management fee will be adjusted annually based on published
indices. For the year ended December 31, 1999 Cogentrix billed the Partnership
approximately $984,000 under the operations and maintenance agreement.
9. DEPENDENCE ON THIRD PARTIES
The Partnership is highly dependent on BVZ for the construction of the
Facility, contractors for the construction of the interconnection facilities and
the Operator for the operation and maintenance of the Facility. During the terms
of the VEPCO PPA and Aquila PPA, the Partnership will be highly dependent on two
utilities for the purchase of electric generating capacity and dispatchable
energy from their respective Units at the Facility. Any material breach by any
one of these parties of their respective obligations to the Partnership could
affect the ability of the Partnership to make payments under the various
financing agreements. In addition, bankruptcy or insolvency of other parties or
default by such parties relative to their contractual or regulatory obligations
could adversely affect the ability of the Partnership to make payments under the
various financing agreements. If an agreement were to be terminated due to a
breach of such agreement, the Partnership's ability to enter into a substitute
agreement having substantially equivalent terms and conditions, or with an
equally creditworthy third party, is uncertain and there can be no assurance
that the Partnership will be able to make payments under the various financing
agreements.
F-40
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Stockholder
LSP Energy, Inc.:
We have audited the accompanying balance sheets of LSP Energy, Inc. as of
December 31, 1999 and 1998. This financial statement is the responsibility of
the Company's management. Our responsibility is to express an opinion on this
financial statement based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the balance sheet is free of material
misstatement. An audit of a balance sheet includes examining, on a test basis,
evidence supporting the amounts and disclosures in that balance sheet. An audit
of a balance sheet also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
balance sheet presentation. We believe that our audits of the balance sheets
provide a reasonable basis for our opinion.
In our opinion, the balance sheets referred to above present fairly, in all
material respects, the financial position of LSP Energy, Inc. as of
December 31, 1999 and 1998, in conformity with generally accepted accounting
principles.
KPMG LLP
Billings, Montana
February 7, 2000
F-41
<PAGE>
LSP ENERGY, INC.
BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
ASSETS
ASSETS:
Cash...................................................... $ 990 $ 990
-------- --------
Total Assets............................................ $ 990 $ 990
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY (DEFICIT)
LIABILITIES:
Due to Granite Power Partners II, L.P..................... $ 7,357 $ 7,357
Due to LSP Energy Limited Partnership..................... 5,001 --
Equity in LSP Energy Limited Partnership deficit.......... 19,474 4,427
-------- --------
Total Liabilities....................................... 31,832 11,784
-------- --------
STOCKHOLDER'S DEFICIT
Common stock, $.01 par value, 1,000 shares authorized, 20
shares issued and outstanding........................... 1 1
Additional paid-in-capital................................ 999 999
Accumulated deficit....................................... (31,842) (11,794)
-------- --------
Total stockholder's equity (deficit).................. (30,842) (10,794)
-------- --------
Total Liabilities and Stockholder's Equity (Deficit).... $ 990 $ 990
======== ========
</TABLE>
See accompanying notes to financial statement.
F-42
<PAGE>
LSP ENERGY, INC.
NOTES TO FINANCIAL STATEMENT
1. ORGANIZATION
LSP Energy, Inc. (the "Company"), a Delaware corporation, is the general
partner of a development stage limited partnership, LSP Energy Limited
Partnership (the "Partnership"). The Company has a 1% general partnership
interest in the Partnership. The Partnership is a Delaware limited partnership
formed in February 1996 to develop, construct, own and operate a gas-fired
electric generating facility with a design capacity of approximately 837
megawatts to be located in Batesville, Mississippi (the "Facility").
The Company was originally wholly owned by Granite Power Partners II, L.P.
("Granite"). Granite also originally held a 99% limited partnership interest in
the Partnership. Granite is a Delaware limited partnership formed to develop
independent power projects throughout the United States. The general partner of
Granite is LS Power, LLC ("LS Power"), a Delaware limited liability company.
LSP Batesville Holding, LLC ("Holding"), a Delaware limited liability
company, was established on July 29, 1998 for the purpose of owning the limited
partnership interests of the Partnership, the common stock of the Company and
the common stock of LSP Batesville Funding Corporation ("Funding"). Funding was
established on August 3, 1998. Funding's business purpose is limited to
maintaining its organization and activities necessary to facilitate the
acquisition of financing by the Partnership from the institutional debt market
and to offering debt securities.
Granite and Cogentrix/Batesville, LLC ("Cogentrix"), a Delaware limited
liability company, entered into an operating agreement dated as of August 28,
1998 which was amended and restated on both December 15, 1998 and May 19, 1999
(as amended, the "Operating Agreement"). Pursuant to the Operating Agreement,
Granite contributed to Holding its 99% limited partnership interest in the
Partnership and all of the common stock of Energy and Cogentrix agreed to
contribute to Holding $54,000,000 of equity. Granite received an initial 47.85%
membership interest in Holding and Cogentrix received an initial 52.15%
membership interest in Holding.
Under the terms of the Operating Agreement, the issuance of two series of
Senior Secured Bonds by the Partnership and Funding on May 21, 1999 resulted in
a recalculation of the Granite and Cogentrix membership interests in Holding.
Effective May 21, 1999 the revised Granite and Cogentrix membership interests
were adjusted to 48.63% and 51.37%, respectively.
Cogentrix's equity contribution to Holding will be contributed to the
Partnership and used for the development and construction of the Facility.
Cogentrix's equity contribution commitment is supported by an irrevocable letter
of credit.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
The Company's investment in the Partnership is accounted for under the
equity method of accounting. Under the equity method, the investment is recorded
at cost and adjusted by the Company's share of undistributed earnings and losses
of the Partnership.
By definition, the Company is liable for the obligations of the Partnership
and as such records its equity in Partnership losses in excess of its
investment. The Company will also record losses otherwise allocable to the
limited partner of the Partnership if it is probable that Holding will be unable
to bear their share of losses. At December 31, 1999, Holding has obtained an
irrevocable letter of credit from an "A" S&P rated bank for the benefit of the
Partnership for its $54,000,000 equity commitment. As
F-43
<PAGE>
LSP ENERGY, INC.
NOTES TO FINANCIAL STATEMENT (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
such, the Company will not record the losses allocable to Holding until its
allocable losses exceed its investment and collateralized guarantee.
FEDERAL AND STATE INCOME TAXES
Due to the insignificance of income tax effects applicable to the Company,
the accompanying financial statements do not reflect any income tax effects.
USE OF ESTIMATES
Management makes a number of estimates and assumptions relating to the
reporting of assets and liabilities and the disclosure of contingent assets and
liabilities to prepare financial statements in conformity with generally
accepted accounting principles. Actual results could differ from those
estimates.
3. INVESTMENT
The Company's investment in the Partnership is accounted for under the
equity method of accounting.
The Partnership has been in the development stage since its inception and is
not expected to generate any operating revenues until the Facility achieves
commercial operation, which is projected to occur during the second quarter of
2000. The Partnership has recorded net income of $3,425,921 for the period
February 7, 1996 (inception) through December 31, 1999. Partnership net income
consists primarily of a $5,000,000 option payment received by the Partnership
under an option purchase agreement (the "Option Purchase Agreement") entered
into in 1996 with a third party. Under the terms of the Option Purchase
Agreement, the third party had the option to purchase 750 megawatts of capacity
and dispatchable energy for a defined term from the Partnership. Effective
November 1, 1997, the Option Purchase Agreement expired unexercised. The
Partnership has no continuing financial commitments under the Option Purchase
Agreement and all funds earned under the Option Purchase Agreement were
distributed to the partners prior to December 31, 1997.
The Company's share of such distributions was $52,643, which represented its
1% managing general partnership interest.
As with any new business venture of this size and nature, the ultimate
construction and operation of the Facility could be affected by many factors.
F-44
<PAGE>
LSP ENERGY, INC.
NOTES TO FINANCIAL STATEMENT (CONTINUED)
3. INVESTMENT (CONTINUED)
The Partnership's balance sheets and statements of operations at
December 31, 1999 and 1998, were as follows:
BALANCE SHEETS
<TABLE>
<CAPTION>
1999 1998
------------ -----------
<S> <C> <C>
ASSETS
Cash.............................................. $ 202,924 $ 83,866
Investments held by Trustee....................... 53,547,410 --
Spare parts inventory............................. 733,462 --
Other assets...................................... 174,174 57,067
Property and construction in progress............. 296,509,139 83,429,694
Debt issuance and financing costs, net............ 10,099,017 10,531,773
------------ -----------
Total Assets.................................... $361,266,126 $94,102,400
============ ===========
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT)
Accounts payable and contract retainage payable... $ 21,868,102 $16,390,227
Accrued interest payable.......................... 15,345,443 154,898
Bonds payable..................................... 326,000,000 --
Loans payable..................................... -- 78,000,000
------------ -----------
Total Liabilities............................... 363,213,545 94,545,125
Partners' capital (deficit)....................... (1,947,419) (442,725)
------------ -----------
Total Liabilities and Partners' Capital
(Deficit)....................................... $361,266,126 $94,102,400
============ ===========
</TABLE>
STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
1999 1998
----------- ---------
<S> <C> <C>
Revenues............................................. $ -- $ --
Operations and maintenance expenses.................. 918,782 --
Project management expenses.......................... 367,277 142,122
General and administrative expenses.................. 218,635 301,603
----------- ---------
Net loss........................................... $(1,504,694) $(443,725)
=========== =========
</TABLE>
On May 18, 1998, the Partnership entered into a Power Purchase Agreement
("VEPCO PPA") with Virginia Electric and Power Company ("VEPCO"). Under the
terms of the VEPCO PPA, the Partnership is obligated to sell and VEPCO is
obligated to purchase approximately 558 megawatts of electrical capacity and
dispatchable energy to be generated from two of the three Combined Cycle Units
("Unit" or "Units") at the Facility at prices set forth in the VEPCO PPA. The
initial term of the VEPCO PPA is thirteen years, beginning on the earlier of
commencement of commercial operations or June 1, 2000, which date may be
extended by a force majeure event or a delivery excuse. VEPCO has the option of
extending the term of the VEPCO PPA for an additional twelve years by providing
the Partnership written notice at least two years prior to the expiration of the
initial term. The extended term may be terminated at any time by VEPCO with
18 months prior notice to the Partnership.
F-45
<PAGE>
LSP ENERGY, INC.
NOTES TO FINANCIAL STATEMENT (CONTINUED)
3. INVESTMENT (CONTINUED)
The VEPCO PPA is subject to specified construction and energy delivery
milestone deadlines, including achieving commercial operations of the VEPCO
Units by June 1, 2000, which date may be extended by a force majeure event or a
delivery excuse.
In the event the commercial operation date of the VEPCO units is delayed
beyond June 1, 2000, which date may be extended by a force majeure event or
delivery excuse, the Partnership may be responsible for replacement power during
the period of delay, subject to a maximum of $20 per kilowatt of committed
capacity from each VEPCO Unit. VEPCO may terminate the VEPCO PPA if the
commercial operation date is not achieved by June 1, 2001, which date may be
extended by a force majeure event or a delivery excuse.
The terms of the VEPCO PPA require VEPCO to make payments to the Partnership
including a reservation payment, an energy payment, a start-up payment, system
upgrade payments and a guaranteed heat rate payment.
On May 21, 1998, the Partnership entered into a Power Purchase Agreement
("Aquila PPA") with Aquila Power Corporation ("Aquila") and UtiliCorp United,
Inc. ("Utilicorp"). Under the terms of the Aquila PPA, the Partnership is
obligated to sell and Aquila is obligated to purchase approximately
279 megawatts of electrical capacity and dispatchable energy to be generated
from one of the three Units at the Facility at prices set forth in the
Aquila PPA. UtiliCorp has appointed Aquila as its agent under the Aquila PPA.
The initial term of the Aquila PPA is fifteen years and seven months, beginning
on June 1, 2000, which date may be extended by a force majeure event or a
delivery excuse. Aquila has the option of extending the term of the Aquila PPA
for an additional five years by providing the Partnership written notice by the
later of July 2013 or twenty-nine months prior to the expiration of the initial
term.
The Aquila PPA is subject to an energy delivery milestone deadline of
June 1, 2000, which deadline may be extended by a force majeure event or a
delivery excuse. In the event that commercial operation of the Aquila Unit is
not achieved by such deadline, the Partnership may elect to incur an adjustment
to the Reservation payment to be received under the Aquila PPA or to be
responsible for replacement power during the period of delay. Aquila may
terminate the Aquila PPA if commercial operations of the Aquila Unit is not
achieved by the first anniversary of the energy delivery milestone deadline,
which deadline may be extended for up to one year by a force majeure event or
delivery excuse.
The terms of the Aquila PPA require Aquila to make payments to the
Partnership including a reservation payment, an energy payment, a start-up
payment, system upgrade payments and a guaranteed heat rate payment.
On July 22, 1998, the Partnership entered into a $240 million fixed price
Turnkey Engineering, Procurement and Construction Agreement ("Construction
Agreement") with BVZ Power Partners & Batesville ("BVZ"), a joint venture formed
by H.B. Zachary Company and a subsidiary of Black & Veatch, LLP. The obligations
of BVZ are guaranteed by Black & Veatch, LLP and the entire Construction
Agreement is backed by a performance bond. Under the terms of the Construction
Agreement, BVZ has committed to develop and construct the Facility subject to
the terms, deadlines and conditions set forth in the Construction Agreement. In
the event the construction and start-up to specified performance levels of the
two VEPCO Units and the Aquila Unit has not occurred on or prior to July 16,
2000, July 26, 2000 and July 31, 2000, as adjusted under the terms of the
Construction
F-46
<PAGE>
LSP ENERGY, INC.
NOTES TO FINANCIAL STATEMENT (CONTINUED)
3. INVESTMENT (CONTINUED)
Agreement ("Guaranteed Completion Dates"), respectively, then BVZ will be
required under the contract to pay liquidated damages, subject to limits. In the
event the construction and start-up of the entire Facility to specified
performance levels occurs prior to the last Guaranteed Completion Date, then BVZ
will be entitled to receive a bonus for early completion.
At various times during the period between January 8, 1999 and January 15,
1999, BVZ's access to the construction site was limited as a result of the
failure of the temporary access road. Due to delays in construction progress
experienced by BVZ during this period, the Partnership and BVZ entered into a
change order to the Construction Agreement to extend the Guaranteed Completion
Dates by 7 days. This extension is reflected in the Guaranteed Completion Dates
above.
The Partnership received a force majeure notice from BVZ and the
manufacturer of the steam turbine generators with respect to delays incurred
during the transportation of one of the VEPCO Unit's steam turbine generator to
the Facility. The Partnership requested that BVZ and the manufacturer provide
additional information to support the claim of force majeure. In response to our
request, the manufacturer has recently provided information indicating a total
of 21 days of delay and an 18 day claim of force majeure for delay in the
delivery of the steam turbine generator. The Partnership does not believe that
the delays in transportation of the steam turbine generator constitute a force
majeure event. BVZ has stated that it is working extra hours, multiple shifts
and weekends in an attempt to meet its originally projected target completion
dates. If it is determined that the delay in the delivery of the steam turbine
constitutes a force majeure event under the Construction Agreement, BVZ would be
entitled to a day for day extension of the Guaranteed Completion Date with
respect to that VEPCO unit. The Partnership has informed VEPCO of the occurrence
of a potential force majeure event as a result of a delay in the delivery of the
VEPCO unit's steam turbine generator that was beyond the Partnership's
reasonable control and without the Partnership's fault or negligence. If it is
determined that the delay in the delivery of the steam turbine constitutes a
force majeure event under the VEPCO PPA, the date that the Partnership is
required to deliver power under the VEPCO PPA would be extended day for day for
the number of days of the force majeure event. A final resolution of the issue
has not yet occurred.
A gap of 46 to 61 days currently exists between the Guaranteed Completion
Dates and the guaranteed delivery start date, which is June 1, 2000. Under the
VEPCO PPA and Aquila PPA, this gap may be increased if BVZ is successful in its
claim that the steam turbine delay constitutes a force majeure event and the
Partnership is unsuccessful in our claim that the steam turbine delay
constitutes a force majeure event under the VEPCO PPA. This gap and any delay in
construction and start-up of the Facility beyond June 1, 2000, may obligate the
Partnership to: (i) provide replacement power to VEPCO or reimburse VEPCO for
any incremental replacement power cost during the period of delay, up to a
maximum of $11,320,000 and (ii) elect to, at the option of the Partnership,
provide replacement power to Aquila, reimburse Aquila for any incremental
replacement power cost during the period of delay, or elect to incur an
adjustment to the capacity payment to be received under the Aquila PPA.
The current construction schedule provided to the Partnership by BVZ
anticipates that the construction and start-up of the two VEPCO Units and the
Aquila Unit will occur on May 10, 2000, June 5, 2000 and June 27, 2000,
respectively. The Partnership has notified both VEPCO and Aquila of these
revised dates. Based upon the estimated completion date of June 5, 2000 for one
of the VEPCO Units the Partnership will be obligated for the cost of replacement
power for the period from June 1,
F-47
<PAGE>
LSP ENERGY, INC.
NOTES TO FINANCIAL STATEMENT (CONCLUDED)
3. INVESTMENT (CONTINUED)
2000 to June 5, 2000. The Partnership has notified Aquila that it will elect to
incur an adjustment to the capacity payment to be received for the period from
June 1, 2000 to June 22, 2000 under the Aquila PPA. The estimated liability that
may result from this period of delay, if any, cannot presently be determined.
While BVZ will be obligated to pay liquidated damages for any failure to
complete the construction and start-up of the Facility on or prior to one day
after the Guaranteed Completion Dates, no delay damages will be due from BVZ
with respect to any Unit during the respective gap periods. Because the delay
liquidated damages are subject to limits, there can be no assurance that such
liquidated damages will fully compensate the Partnership for replacement power
costs or other costs associated with delays for which BVZ is responsible. The
ultimate liability that would result from this delay, if any, cannot presently
be determined.
On May 21, 1999, the Partnership and Funding issued two series of Senior
Secured Bonds (the "Bonds") in the following total principal amounts:
$150,000,000 7.164% Series A Senior Secured Bonds due 2014 and $176,000,000
8.160% Series B Senior Secured Bonds due 2025. Interest is payable semiannually
on each January 15 and July 15, commencing January 15, 2000, to the holders of
record on the immediately preceeding January 1 and July 1. Interest on the Bonds
will accrue from the most recent date to which interest has been paid or, if no
interest has been paid, from the date of original issuance. Interest will be
computed on the basis of a 360-day year consisting of twelve 30-day months.
The Bonds are secured by substantially all of the personal property and
contract rights of the Partnership and Funding. In addition, Holding and Energy
have pledged all of their interests in the Partnership, and Holding has pledged
all of the capital stock of Energy and all of the capital stock of Funding.
F-48
<PAGE>
ANNEX A
DEFINITIONS
"Acceptable PPA" means any of the Virginia Power PPA, the Aquila PPA or a
Replacement PPA.
"Acceptable Replacement Power Arrangement" means an agreement for the
purchase of Replacement Power entered into or arranged for by us:
(1) that would not reasonably be expected to result in a Material
Adverse Effect or a material adverse effect on the operation of the project
(as certified by us);
(2) (a) the counterparty of which or the credit support provider for
such counterparty (including any parent of such counterparty which
guarantees such counterparty's obligations) is rated at least "BBB-" by S&P
or at least "Baa3" by Moody's, provided that such counterparty or such
credit support provider, as applicable, will not be required to satisfy such
rating standard if such counterparty has dedicated existing generating
assets and capacity for the provision of such Replacement Power and such
generating assets have a proven track record for satisfying the obligation
to provide all of such Replacement Power,
and
(b) that has a term not exceeding 45 days; or
(3) (a) the counterparty of which is reasonably experienced in the
business of providing power for similar sized obligations and has a proven
track record for satisfying the obligation to provide all of such
Replacement Power
and
(b) that has a term not exceeding 48 hours.
"Account Balance Amount" means the sum of
(1) the funds in the Distribution Suspense Account
and
(2) the aggregate of all funds in the Debt Service Reserve Account and
the Debt Service Payment Account.
"Account Reserve Requirement" means, as of any date of determination, the
sum of
(1) the Debt Service Reserve Requirement as of the next Scheduled
Payment Date for the bonds (or, if the date of determination is a Scheduled
Payment Date for the bonds, the Debt Service Reserve Requirement as of such
date),
(2) the Senior Indebtedness due and payable on the next Scheduled
Payment Date for the bonds
and
(3) the Senior Indebtedness due and payable from and after the date of
determination and prior to the next Scheduled Payment Date for the bonds.
"Accounts" means, collectively, the Construction Account, the Revenue
Account, the O&M Account, the Debt Service Payment Account, the DSRA LOC Payment
Account, the Debt Service Reserve Account, the Major Maintenance Reserve
Account, the Aquila PPA Reserve Account, the Distribution Suspense Account and
any other accounts as may be established pursuant to the Common Agreement.
A-1
<PAGE>
"Additional Indebtedness" means Indebtedness incurred in respect of Required
Modifications, Optional Modifications or Expansion Modifications.
"Additional Indebtedness Agent" means any agent, trustee or similar
representative for the Additional Indebtedness Holders under an Additional
Indebtedness Agreement.
"Additional Indebtedness Agreement" means an agreement among us, an
Additional Indebtedness Agent and Additional Indebtedness Holders pursuant to
which the Additional Indebtedness Holders agree to provide Additional
Indebtedness to the Partnership on the terms and conditions set forth therein
and in accordance with the Financing Documents.
"Additional Indebtedness Holders" means the financial institutions from time
to time party to an Additional Indebtedness Agreement.
"Additional Project Document" means any material contract or undertaking to
which we are a party relating to the development, construction, operation,
administration or maintenance of the project entered into after May 21, 1999,
but excluding any Financing Document.
"Aquila PPA" means the Power Purchase Agreement, dated May 21, 1998, by and
among us, Aquila and UtiliCorp, as amended by (1) the Letter Agreement, dated
July 16, 1998, by and among us, Aquila and UtiliCorp, and (2) the Letter
Agreement, dated August 28, 1998, by and among us, Aquila and UtiliCorp.
"Aquila PPA Reserve Account" means the account with this name established
pursuant to the Common Agreement.
"Aquila Reserve L/C" means any letter of credit provided by or on behalf of
us to the administrative agent to satisfy the Aquila PPA Reserve Requirement as
described under the caption "Description of Principal Financing
Documents--Common Agreement--Reserve Accounts--Letters of Credit."
"Aquila Reserve L/C Agreement" means any agreement providing for the
issuance of an Aquila Reserve L/C.
"Bonds" means the private bonds and the exchange bonds.
"Bondholder" means a person in whose name a private bond or an exchange bond
is registered in the security register.
"Bonding Arrangements" means surety bonds, performance bonds or similar
arrangements with third-party sureties or indemnitors or similar persons.
"Btu" means British Thermal unit, the amount of heat required to raise the
temperature of 1 pound of pure water 1 degree F from 59 degrees F to 60 degrees
F at a constant pressure of 14.73 pounds per square inch absolute.
"Cash Available for Debt Service" means, for any period, Operating Revenues
(excluding any receipts derived from the sale of any property pertaining to the
project) for that period, minus (1) all O&M Costs for such period and (2) all
deposits, if any, into the Major Maintenance Reserve Account for that period.
"Casualty Event" means an event that causes all or a portion of the project
to be damaged, destroyed or rendered unfit for normal use for any reason
whatsoever, other than an Expropriation Event.
"Casualty Proceeds" means all insurance proceeds or other amounts actually
received on account of a Casualty Event, except proceeds of delayed opening or
business interruption insurance.
A-2
<PAGE>
"Change of Control" means:
(1) LS Power, Cogentrix and/or any Qualified Transferee collectively
cease to own, directly or indirectly, at least 51% of the capital stock of
our general partner (unless any or all of them maintain management control
of us); or
(2) LS Power, Cogentrix and/or any Qualified Transferee collectively
cease to own, directly or indirectly, at least 10% of the ownership and
economic interests in us;
PROVIDED that none of the events described in clauses (1) or (2) above will
be deemed a "Change of Control" if (x) they will not result in a Rating
Downgrade or (y) they are approved by Holders holding at least 66 2/3% in
aggregate principal amount of the outstanding bonds.
"Closing Date" means May 21, 1999.
"Collateral" means all assets, rights, interests and other property in or
upon which a security interest or Lien is or is purported to be granted to the
Collateral Agent for the benefit of the Senior Secured Parties pursuant to the
Security Documents.
"Commercial Operation Date" means the later to occur of the Commercial
Operation Date under the Virginia Power PPA and the Commercial Operation Date
under the Aquila PPA.
"Commercially Feasible Basis" means that, following a Casualty Event, an
Expropriation Event or a Title Event:
(1) the Casualty Proceeds, the Expropriation Proceeds or the Title
Proceeds, as the case may be, together with any other amounts that we or our
the partners are irrevocably committed to contribute pursuant to support
arrangements to Restore all or a portion, as the case may be, of our
project, will be sufficient to permit such Restoration of our project;
(2) the sum of (a) the proceeds of the business interruption insurance,
(b) the monies available in the Construction Account and the O&M Account,
(c) any amounts that we or our partners are irrevocably committed to
contribute pursuant to support arrangements (without duplication of such
amounts referred to in clause (1) above) and (d) the anticipated Operating
Revenues during the estimated period of Restoration will be sufficient to
pay all Senior Debt Service and O&M Costs (taking into account the
limitation on the use of such funds set forth in the Common Agreement)
during the estimated period of Restoration;
(3) our project upon being Restored can be reasonably expected to
produce Operating Revenues adequate to maintain (x) a Projected Senior Debt
Service Coverage Ratio, for the period of four of our consecutive complete
fiscal quarters commencing with our fiscal quarter beginning on or most
recently after the projected date of Restoration, equal to or greater than
1.3 to 1 during the 100% PPA Period and the Two-Thirds PPA Period and 1.75
to 1.0 during the One-Third PPA Period and the Merchant Period, and (y) a
Projected Senior Debt Service Coverage Ratio, for each complete Fiscal Year
commencing with the Fiscal Year beginning on or most recently after the
projected date of Restoration, equal to or greater than 1.4 to 1 during the
100% PPA Period and the Two-Thirds PPA Period and 2.0 to 1.0 during the
One-Third PPA Period and the Merchant Period, in each case taking into
account any change in projected operating results due to the impairment of
any portion of our project and any reduction in Senior Debt Service due to
any partial redemption of the bonds pursuant to the Indenture or any partial
prepayment of the amounts outstanding under the Virginia Power L/C
Agreement; and
(4) we reasonably believe that our project can be operated in accordance
with the provisions of the Project Documents that are then in effect or that
are expected to be in effect after the completion of the Restoration.
"Commission" means the United States Securities and Exchange Commission.
A-3
<PAGE>
"Common Facilities Agreement" means an agreement between us and an Expansion
Party which provides for the sharing of transmission lines, interconnections,
utilities and other facilities among the first three units of our project and
any Expansion.
"Completion" means that:
(1) Substantial Completion (as defined in the Construction Contract) of
our power facility (as defined the Construction Contract) has occurred and
been accepted under the Construction Contract, that all work necessary to
achieve Substantial Completion under the Construction Contract has been
performed in accordance with the Construction Contract and the requirements
of all applicable governmental approvals, and that all liquidated damages
then due and payable under the Construction Contract have been paid in full
(other than those that are subject to a Good Faith Contest);
(2) commercial operation under any Infrastructure Contracts has occurred
and been accepted under these Infrastructure Contracts, that all work
necessary to achieve completion under these Infrastructure Contracts has
been performed in accordance with these Infrastructure Contracts and the
requirements of all applicable governmental approvals;
(3) the Commercial Operation Date has occurred; and
(4) the independent engineer for our project has confirmed each of the
events described in clauses (1) through (3) above.
"Completion Date" means the date on which our project achieves Completion.
"Construction Account" means the account with this name established pursuant
to the Common Agreement.
"Construction Contract" means the Turnkey Engineering, Procurement and
Construction Agreement dated as of July 22, 1998 between us and BVZ Power
Partners.
"Date Certain" means June 1, 2001.
"Debt Service Payment Account" means the account with this name established
pursuant to the Common Agreement.
"Debt Service Reserve Account" means the account with this name established
pursuant to the Common Agreement.
"Debt Service Reserve L/C" means any letter of credit provided by or on
behalf of us to the administrative agent to satisfy the Debt Service Reserve
Requirement as described under the caption "Description of Principal Financing
Documents--Common Agreement--Reserve Accounts--Letters of Credit."
"Debt Service Reserve L/C Agreement" means any agreement providing for the
issuance of a Debt Service Reserve L/C.
"Debt Service Reserve LOC Loans" means any loans made to us or the Funding
Corporation under a Debt Service Reserve L/C Agreement.
"Default" means any occurrence, circumstance or event, or any combination
thereof, which, with the lapse of time and/or the giving of notice, would
constitute an Event of Default.
"Default Equity Contribution" means an equity contribution made to us when
an Event of Default or a bankruptcy event has occurred.
"Distributable Amount" means the Account Balance Amount less the Account
Reserve Requirement.
A-4
<PAGE>
"Distribution Suspense Account" means the account with this name established
pursuant to the Common Agreement.
"DSRA LOC Payment Account" means the account with this name established
pursuant to the Common Agreement.
"Easements" means the easements appurtenant, easements in gross, license
agreements and other rights running in favor of us and/or appurtenant to the
Site, including the easements and licenses described in the Title Policy.
"Eligible Facility" means an "eligible facility" as that term is defined in
15 U.S.C. Section 79z-5a(a-2).
"Equity Documents" means the Equity Contribution Agreement and the Equity
Letter of Credit.
"Event of Abandonment" means:
(1) prior to the Completion Date,
(a) the cessation or deferral of all or substantially all construction
or completion of our project for more than 120 consecutive days, as this
period may be extended on a day for day basis corresponding with the
occurrence and continuance of any event of force majeure, as defined in any
of the Project Documents, so long as we are diligently proceeding to
mitigate the consequences of the event, other than by reason of a Casualty
Event or an Expropriation Event, or
(b) the announcement by the Partnership of a decision to permanently
cease or indefinitely defer the construction or completion of our project;
or
(2) after the Completion Date,
(a) the suspension for more than 120 consecutive days, as this period
may be extended on a day for day basis corresponding with the occurrence and
continuance of any event of force majeure, as defined in any of the Project
Documents so long as we are diligently proceeding to mitigate the
consequences of the event of all or substantially all operation of our
project, other than (1) by reason of the failure to be dispatched or (2) by
reason of the occurrence of a Casualty Event or an Expropriation Event, or
(b) the announcement by us of a decision to permanently cease operation
of our project.
"EWG" or "Exempt Wholesale Generator" means an "exempt wholesale generator,"
as that term is defined in 15 U.S.C. Section79z-5a(a-1).
"Expansion" means the improvements resulting from an Expansion Modification.
"Expansion Modifications" means modifications or improvements to our project
that are designed to materially increase the net generating capacity of our
power facility, including without limitation the addition of a fourth
combined-cycle generating unit at the Site. Expansion Modifications do not
include modifications that are either Required Modifications or Optional
Modifications.
"Expansion Party" means any third person owning and otherwise responsible
for the development, construction and operation of an Expansion.
"Expropriation Event" means any compulsory transfer or taking or transfer
under threat of compulsory transfer or taking of a material part of the
Collateral by any Governmental Authority unless such transfer or taking is the
subject of a Good Faith Contest.
"Expropriation Proceeds" means all insurance proceeds or other amounts,
including instruments, actually received on account of an Expropriation Event
unless such transfer or taking is the subject of a Good Faith Contest, after
deducting all reasonable expenses incurred in litigating, arbitrating,
A-5
<PAGE>
compromising, settling or consenting to the settlement of any claims against the
appropriate Governmental Authority.
"Financing Documents" means, collectively, the Indenture, the supplemental
indentures for the initial two series of bonds, the bonds, the Virginia Power
L/C Agreement, any Working Capital Agreement, when entered into, any Debt
Service Reserve L/C Agreement, to the extent we or the Funding Corporation is
the account party to the Debt Service Reserve L/C issued thereunder, when
entered into, any Aquila Reserve L/C Agreement, to the extent we or the Funding
Corporation is the account party to the Aquila Reserve L/C issued thereunder,
when entered into, any Additional Indebtedness Agreement, when entered into, the
Security Documents and the Equity Documents.
"Fiscal Year" means our accounting year commencing each year on January 1
and ending on December 31 or any other period adopted by us as an accounting
year.
"Good Faith Contest" means the contest of an item if
(1) the item is diligently being contested in good faith by appropriate
proceedings timely instituted,
(2) adequate reserves are established in accordance with generally
accepted accounting principles with respect to the contested item and held
in cash or Permitted Investments, if the contested item individually or when
taken together with all other contested items for which reserves are not at
the time being held in cash or Permitted Investments could reasonably be
expected to result in liability to us and the Funding Corporation in excess
of $1,000,000,
(3) during the period of such contest, the enforcement of any contested
item is effectively stayed, unless such enforcement would not reasonably be
expected to result in a Material Adverse Effect,
(4) any Lien filed in connection therewith will have been removed from
the record by Bonding Arrangements by a reputable surety company, or title
insurance or cash deposits are otherwise provided to assure the discharge of
the Funding Corporation's or our obligation in connection therewith,
provided that such cash deposits, in the aggregate, will not exceed
$2,000,000,
(5) the payment for any Tax, Lien or claim will have been made as is
necessary to prevent the recordation of a tax deed or other similar
instrument conveying our property or any portion thereof,
(6) the failure to pay or comply with the contested item during the
period of such Good Faith Contest would not reasonably be expected to result
in a Material Adverse Effect and
(7) neither we nor the Funding Corporation has knowledge of any actual
or proposed deficiency or additional assessment in connection with the
contest not otherwise satisfying the requirements of clauses (1) through
(6).
"Governmental Authority" means any government, governmental department,
ministry, commission, board, bureau, agency, regulatory authority,
instrumentality of any government (central or state), judicial, legislative or
administrative body, federal, state or local, having jurisdiction over the
matter or matters in question.
"Heat rate" means a measure of generating station thermal efficiency,
generally expressed in Btu per net kilowatt-hour. It is computed by dividing the
total Btu content of fuel burned for electric generation by the resulting net
kilowatt-hour generation.
"Heating value" means the amount of heat produced by the complete combustion
of a unit quantity of fuel. The gross or higher heating value is that which is
obtained when all of the products of
A-6
<PAGE>
combustion are cooled to the temperature existing before combustion, the water
vapor formed during combustion is condensed and all the necessary corrections
have been made. The net or lower heating value is obtained by subtracting the
latent heat of vaporization of the water vapor, formed by the combustion of the
hydrogen in the fuel, from the gross or higher heating value.
"Indebtedness" of any person at any date means, without duplication,
(1) all obligations of that person for borrowed money,
(2) all obligations of that person evidenced by bonds, debentures, notes
or other similar instruments,
(3) all obligations of that person to pay the deferred purchase price of
property or services, except trade accounts payable arising in the ordinary
course of business,
(4) all obligations of that person under leases which are or should be,
in accordance with generally accepted accounting principles, recorded as
capital leases for which that person is liable,
(5) all obligations of that person under interest rate or currency
protection agreements or other hedging instruments,
(6) all obligations of that person to purchase securities (or other
property) which arise out of or in connection with the sale of the same or
substantially similar securities (or property),
(7) all deferred obligations of that person to reimburse any bank or
other person for amounts paid or advanced under a letter of credit or other
instrument,
(8) all Indebtedness of others secured by a Lien on any asset of that
person, whether or not that Indebtedness is assumed by that person, and
(9) all Indebtedness of others guaranteed directly or indirectly by that
person or as to which that person has an obligation substantially the
economic equivalent of a guarantee or other arrangement to assure a creditor
against loss.
"Independent Consultants" means the independent engineer and the independent
electricity market and fuel consultant.
"Inducement Agreement" means the Inducement Agreement entered into by and
among the Authority, Panola County, the Industrial Development Authority and us.
"Infrastructure Contracts" means the construction contracts between us and
each of Robinson Mechanical Contracts, Inc., Big Warrior Corporation and Garney
Companies, Inc., which are described under the caption "Description of the
Principal Project Documents--Other Construction and Engineering Contracts." We
have assigned our interests under these contracts to Panola County.
"Infrastructure Financing Documents" means the Use Agreements and the
Inducement Agreement.
A-7
<PAGE>
"Initial Purchasers" means Credit Suisse First Boston Corporation, Scotia
Capital Markets (USA) Inc., and TD Securities (USA) Inc.
"Institutional Accredited Investors" means an institution that is an
"accredited investor" as defined in Rule 501(a)(1), (2), (3) or (7) under the
Securities Act, who are not also Qualified Institutional Buyers.
"Involuntary PPA Buy-Out" means any buy-out of a Power Purchase Agreement
that is not voluntarily sought by us, but into which we are legally or
practically required to enter by force or law or regulation, or by any actual or
threatened Expropriation Event, or by an actual or threatened bankruptcy
proceeding or other action adverse to the material rights and benefits granted
to us under the Power Purchase Agreement on the part of, or an actual or
threatened termination of the Power Purchase Agreement by, the purchaser of
electricity under the Power Purchase Agreement.
"Kilowatt" or "kW" means 1,000 watts.
"Lien" means, with respect to any asset, any mortgage, deed of trust, lien,
pledge, charge, security interest, or easement or encumbrance of any kind in
respect of such asset, whether or not filed, recorded or otherwise perfected or
effective under applicable law, as well as the interest of a vendor or lessor
under any conditional sale agreement, capital lease or other title retention
agreement relating to the asset.
"Loss Event" means a Casualty Event, an Expropriation Event or a Title
Event.
"Make-Whole Premium" means an amount equal to the Discounted Present Value
calculated for any bond subject to redemption less the unpaid principal amount
of that bond; provided that the Make-Whole Premium shall not be less than zero.
For purposes of this definition, the "Discounted Present Value" of any bond
subject to redemption is equal to the discounted present value of all principal
and interest payments scheduled to become due in respect of that bond after the
date of the redemption, calculated using a discount rate equal to the sum of
(1) the yield to maturity on the United States treasury security having
an average life equal to the remaining average life of that bond and trading
in the secondary market at the price closest to par
and
(2) 30 basis points in the case of the series C bonds and 50 basis
points in the case of the series D bonds;
PROVIDED, HOWEVER, that if there is no United States treasury security
having an average life equal to the remaining average life of the bond, the
discount rate will 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 United States treasury securities
having average lives most closely corresponding to the remaining average life of
the bond and trading in the secondary market at the price closest to par.
"Material Adverse Effect" means:
(1) a material adverse change in the status of our business, operations,
property or financial condition or the business, operations, property or
financial condition of the Funding Corporation; or
(2) any event or occurrence of whatever nature which materially
adversely affects (a) our or the Funding Corporation's ability to perform
our or its obligations under any Transaction Document or (b) the perfection,
validity or priority of the Senior Secured Parties' security interests in
the Collateral.
A-8
<PAGE>
"Merchant Period" means any period during which less than 33% of the then
current capacity of our power facility is to be sold or otherwise disposed of
under an Acceptable PPA.
"Moody's" means Moody's Investors Service, Inc.
"Mortgage Estate" means the mortgage on and security interest in all our
real property interests, including leasehold interests and easement interests,
in the Site and all fixtures, equipment and improvements thereon granted by us
to a trustee for the benefit of the collateral agent, acting on behalf of the
Senior Secured Parties.
"O&M Account" means the account with this name established pursuant to the
Common Agreement.
"O&M Costs" means all actual cash maintenance and operation costs incurred
and paid for our project in any particular calendar or fiscal year or period to
which the term is applicable, PROVIDED that if we elect to accrue property taxes
or any other annual cost on a monthly basis and the property taxes and/or other
annual costs are shown as a separate line item in the annual operating budget,
the property taxes and/or such other annual costs will be factored into the
calculation of Cash Available for Debt Service as accrued instead of according
to when the property taxes and/or other annual costs are actually paid,
including:
- payments for fuel and/or tracking account payments made by us under the
Power Purchase Agreements,
- fuel costs incurred under Power Purchase Agreements other than the
Virginia Power PPA or the Aquila PPA or when no Power Purchase Agreements
are in effect,
- additives or chemicals and transportation costs related thereto,
- taxes other than those based upon our income,
- insurance,
- consumables,
- payments under any lease,
- payments pursuant to the O&M Agreement, other than the Operator Fee, the
Parts Agreement and the Management Services Agreement,
- legal fees and expenses paid by us in connection with the management,
maintenance or operation of our project,
- fees paid in connection with obtaining, transferring, maintaining or
amending any Governmental Approvals and reasonable general and
administrative expenses,
but exclusive in all cases of non-cash charges, including depreciation or
obsolescence charges or reserves therefor, amortization of intangibles or other
bookkeeping entries of a similar nature, and also exclusive of all interest
charges and charges for the payment or amortization of principal of our
indebtedness;
PROVIDED that O&M Costs do not include
(1) major maintenance expenditures to the extent paid with funds on
deposit in the Major Maintenance Reserve Account,
(2) distributions of any kind to us or our affiliates, other than
payments under the Management Services Agreement and the O&M Agreement,
except for the Operator Fee,
(3) depreciation,
A-9
<PAGE>
(4) capital expenditures, other than those included in and approved as
part of the annual operating budget or
(5) payments made for Restoration of our project in accordance with the
applicable provisions of the Common Agreement.
"100% PPA Period" means any period during which 100% of the then current
capacity of our power facility is to be sold or otherwise disposed of under an
Acceptable PPA.
"One-Third PPA Period" means any period during which at least 33% but less
than 66 2/3% of the then current capacity of our power facility is to be sold or
otherwise disposed of under an Acceptable PPA.
"Operating Revenues" means all of the following, without duplication,
received by us:
(1) all payments received by us under the Power Purchase Agreements,
including with respect to fuel;
(2) proceeds of any business interruption insurance;
(3) income derived from the sale or use of electric capacity or energy
produced, transmitted or distributed by our project;
(4) all other revenues from the operation of our project together with
any receipts derived from the sale of any property pertaining to our project
or incidental to the operation of our project, including, without
limitation, transmission system upgrade credits;
(5) the investment income on amounts in the Accounts, but solely to the
extent deposited from time to time in the Revenue Account; and
(6) all other deposits into the Revenue Account not included in clauses
(1) through (5) above, including transfers from the Debt Service Reserve
Account,
all as determined in conformity with cash accounting principles and excluding
any payments received in connection with any buy-out of a Power Purchase
Agreement.
"Operator Fee" means the "Management Fee" due and payable to Cogentrix
Batesville Operations pursuant to the O&M Agreement.
"Optional Modifications" means discretionary modifications or improvements
to the project other than Required Modifications or Expansion Modifications.
"Ordinary Equity Contributions" means, all equity contributions other than
Default Equity Contributions.
"NOx" means oxides of nitrogen.
"Panola Partnership Agreement" means the Agreement to be entered into by and
between Panola Partnership, Inc. and us.
"Performance Liquidated Damages" means the performance liquidated damages
payable by BVZ Power Partners pursuant to the Construction Contract, in an
amount and to the extent payable pursuant to the Construction Contract.
"Permitted Investments" means
(1) securities issued or directly and fully guaranteed or insured by the
United States of America or any agency or instrumentality thereof, provided
that the full faith and credit of the United States of America is pledged in
support thereof, having a maturity not exceeding
A-10
<PAGE>
(x) 180 days, prior to the Completion Date or (y) 364 days after the
Completion Date, from the date of issuance;
(2) time deposits and certificates of deposit having a maturity not
exceeding (a) 180 days, prior to the Completion Date or (b) 364 days, after
the Completion Date, of any domestic commercial bank of recognized standing
having capital and surplus in excess of $100,000,000;
(3) commercial paper issued by the parent corporation of any domestic
commercial bank of recognized standing having capital and surplus in excess
of $100,000,000 and commercial paper of any domestic corporation 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, in each case, having a maturity not exceeding
(x) 180 days, prior to the Completion Date, or (y) 364 days, after the
Completion Date, from the date of acquisition;
(4) fully secured repurchase obligations for underlying securities of
the types described in clause (1) above entered into with any bank meeting
the qualifications established in clause (2) above or any financial
institution having long term unsecured debt securities rated "A" or better
by S&P or "A2" or better by Moody's, in connection with which such
underlying securities are held in trust by a third party custodian;
(5) high-grade corporate bonds rated at least "A" or the equivalent
thereof by S&P or at least "Aa3" or the equivalent thereof by Moody's and
having a maturity not exceeding (x) 180 days, prior to the Completion Date
or (y) 364 days, after the Completion Date, and
(6) money market funds having a rating in the highest investment
category granted thereby by a Rating Agency at the time of acquisition,
including any fund for which the trustee or an affiliate of the trustee
serves as an investment advisor, administrator, shareholder, servicing
agent, custodian or subcustodian, notwithstanding that (a) the trustee or an
affiliate of the trustee charges and collects fees and expenses from these
funds for services rendered (provided that the charges, fees and expenses
are on terms consistent with terms negotiated at arm's-length) and (b) the
Trustee charges and collects fees and expenses for services rendered
pursuant to the Indenture.
"Power Purchase Agreements" means the Aquila PPA, the Virginia Power PPA and
any other agreement for the sale of all or a portion of the net electric
capacity and generation from our power facility entered into by us from time to
time.
"PPA Buy-Outs" means a Voluntary PPA Buy-Out or an Involuntary PPA Buy-Out.
"Project Costs" means the costs associated with the development, financing,
design, engineering, acquisition, equipping, construction, assembly, inspection,
testing, completion and start-up of our project, including the Panola County
infrastructure. Project Costs include, without limitation, amounts advanced or
payable under the Infrastructure Financing Documents, including any retention
relating to construction costs paid or payable by us whenever due, management
fees, including under the management services agreement, and Operator Fees
payable prior to the commercial operation of the project and a development fee
in the amount of $3,000,000 payable to one of our affiliates on May 21, 1999.
"Project Documents" means the Construction Contract, Construction Contract
Guarantee, the Infrastructure Contracts (until any such contract is transferred
by us), the Power Purchase Agreements, the Fuel Interconnection Agreements, the
Electric Interconnection Agreements, the Water Supply Storage Agreement, the O&M
Agreement, the Partnership Agreement, the Consents, the Engineering Services
Agreement, the Parts Agreement, the Management Services Agreement, the Ad
Valorem Tax Agreement and, when entered into, any Additional Project Document.
A-11
<PAGE>
"Project Party" means any party to any Project Document other than us.
"Projected Senior Debt Service Coverage Ratio" means, for any period, the
ratio of
(a) the aggregate of all Cash Available for Debt Service for that period
to
(b) the aggregate of all Senior Debt Service for that period, in each
case calculated on a projected basis, using,
(1) if the period in question is the 100% PPA Period, projections of
Cash Available for Debt Service based on projected sales under the Power
Purchase Agreements or Replacement PPAs, as applicable,
(2) if the period in question is the Merchant Period, projections of
Cash Available for Debt Service based on projected merchant sales, and
(3) if the period in question is the One-Third PPA Period or the
Two-Thirds PPA Period, projections of Cash Available for Debt Service
based on the appropriate combination of projected sales under the Power
Purchase Agreements or Replacement PPAs, as applicable, and projected
merchant sales,
and confirmed by the independent engineer for our project.
"Qualified Institutional Buyer" means "qualified institutional buyer" as
defined in Rule 144A under the Securities Act.
"Qualified Transferee" means any person that acquires after May 21, 1999
interests in us or our general partner so long as:
(1) that person is, or is controlled by a person that is, reasonably
experienced in the business of owning and operating facilities similar to
our project;
(2) that acquisition is in compliance with law and after giving effect
to that acquisition (a) we will not as a result of such acquisition be in
violation of any Applicable Laws, including, without limitation, all
Governmental Approvals, the compliance with which is necessary to permit us
to conduct our business in accordance with the Project Documents and to
maintain our status as an Exempt Wholesale Generator and our project's
status as an Eligible Facility, if we and our project were certified as such
at the time of such acquisition, and the trustee has received opinions of
counsel to that person and counsel to us to that effect, (b) no Default or
Event of Default has occurred and be continuing and (c) that acquisition
would not reasonably be expected to result in a Material Adverse Effect; and
(3) to the extent relevant to that acquisition, the collateral agent has
received a pledge of and lien on our general partnership interests or shares
of capital stock of LSP Energy so acquired and we have furnished to the
trustee, the collateral agent and the administrative agent those documents,
certificates and opinions from counsel to that person and us as the trustee,
the collateral agent and the administrative agent have reasonably required.
"Rating Agency" means S&P or Moody's.
"Rating Downgrade" means a downgrade in the then current ratings of the
bonds by a Rating Agency either within a particular category or from one
category to another.
"Replacement Power" has the meaning given such term in the Power Purchase
Agreements.
A-12
<PAGE>
"Replacement PPA" means a power purchase agreement in respect of which or
that
(1) the Rating Agencies confirm in writing that no downgrade of the
ratings for the bonds will occur solely as a result of that Replacement PPA,
or
(2) (a) the counterparty of which or the credit support provider for
that counterparty, including any parent of that counterparty which
guarantees that counterparty's obligations, is rated at least BBB- by S&P
and at least Baa3 by Moody's,
(b) has a minimum term of one year and
(c) the pricing and commercial terms of which are, as a whole,
equivalent to or better than the pricing and commercial terms under the
Power Purchase Agreement being replaced, as confirmed by the independent
engineer for our project.
"Required Modifications" means
(1) those modifications or improvements reasonably necessary for us to
maintain our status as an Exempt Wholesale Generator or our project to
maintain its status as an Eligible Facility or for our project to remain in
compliance with all applicable laws and governmental approvals and
(2) those modifications or improvements reasonably necessary to achieve
Completion after the application of all Ordinary Equity Contributions.
"Required Ratio" means
(1) with respect to the 100% PPA Period, 1.20/1.00,
(2) with respect to the Two-Thirds PPA Period, 1.35/1.00,
(3) with respect to the One-Third PPA Period, 1.55/1.00, and
(4) with respect to the Merchant Period, 1.70/1.00.
"Restoration" or "Restoring" means repairing, rebuilding or otherwise
restoring our project due to the occurrence of a Casualty Event or an
Expropriation Event or, with respect to any Title Event, curing such Title
Event.
"Revenue Account" means the account with this name established pursuant to
the Common Agreement.
"S&P" means Standard & Poor's Ratings Group.
"Scheduled Payment Date" means
(a) with respect to any bond or additional bond issued under the
indenture governing the bonds, January 15 and July 15, and
(b) with respect to any other amortizing Senior Secured Obligation, the
date on which any principal is scheduled to become due, which will be on
April 15, July 15, October 15 and January 15.
"Security Documents" means the documents pursuant to which the Liens on the
Collateral are pledged to the collateral agent.
"Senior Debt Service" means, for any period, without duplication, (1) the
aggregate of all fees payable to the Secured Parties during that period, plus
(2) the aggregate of all interest, principal and other amounts payable in
respect of the Senior Secured Obligations during that period, but not including
any interest during construction or other similar payments which are pre-funded
with the proceeds of a debt issuance or otherwise.
A-13
<PAGE>
"Senior Debt Service Coverage Ratio" means for any period, the ratio of
(1) the aggregate of all Cash Available for Debt Service for that period
to
(2) all Senior Debt Service for that period.
"Senior Indebtedness" means the Senior Secured Obligations, together with
our and the Funding Corporation's other Permitted Indebtedness, other than
subordinated Indebtedness.
"Senior Secured Obligations" means, collectively, without duplication:
(1) all of our and the Funding Corporation's Indebtedness, financial
liabilities and obligations of whatsoever nature and howsoever evidenced,
including principal, interest, fees, reimbursement obligations, penalties,
indemnities and legal and other expenses, whether due after acceleration or
otherwise, to the Senior Secured Parties under or pursuant to the Indenture,
the bonds, any Working Capital Agreement, any Debt Service Reserve L/C
Agreement, the Virginia Power L/C Agreement, any Aquila Reserve L/C
Agreement, any Additional Indebtedness Agreement, the Security Documents,
the Equity Documents, any other Financing Document or any other agreement,
document or instrument evidencing, securing or relating to that
indebtedness, financial liabilities or obligations, in each case, direct or
indirect, primary or secondary, fixed or contingent, now or hereafter
arising out of or relating to any such agreements;
(2) any and all sums advanced by the collateral agent in order to
preserve the Collateral or preserve its security interest in the Collateral;
and
(3) in the event of any proceeding for the collection or enforcement of
the obligations described in clauses (1) and (2) above, after an Event of
Default has occurred and is continuing and unwaived, the expenses of
retaking, holding, preparing for sale or lease, selling or otherwise
disposing of or realizing on the Collateral, or of any exercise by the
collateral agent of its rights under the Security Documents, together with
reasonable attorneys' fees and court costs.
"Senior Secured Obligations Payments" means, on any monthly disbursement
date, for any given facility constituting a series of Senior Secured
Obligations, including the bonds, an amount equal to:
(1)(a) a fraction the numerator of which is the number of months from
and including the disbursement date to but excluding the immediately
preceding Scheduled Payment Date for that facility constituting or series of
Senior Secured Obligations and the denominator of which is the number of
months from but excluding the immediately preceding Scheduled Payment Date
to and including the next succeeding Scheduled Payment Date for that
facility constituting or series of Senior Secured Obligations, or, if the
disbursement date is on a Scheduled Payment Date for such facility
constituting or series of Senior Secured Obligations, the Scheduled Payment
Date
MULTIPLIED BY
(b) principal, interest and other amounts due or coming due in respect
of those Senior Secured Obligations on the next succeeding Scheduled Payment
Date therefor, or, if the disbursement date is on a Scheduled Payment Date
for that facility constituting or series of Senior Secured Obligations, the
Scheduled Payment Date,
MINUS
(2) the funds then on deposit in or credited to the Debt Service Payment
Account in respect of the issuance or series of Senior Secured Obligations.
"Senior Secured Parties" means
(1) the bondholders,
A-14
<PAGE>
(2) the trustee,
(3) the Securities Intermediary,
(4) the Virginia Power L/C Banks, the Virginia Power L/C Issuer and the
Virginia Power L/C Agent,
(5) any Working Capital Bank and any Working Capital Agent,
(6) any Additional Indebtedness Holder and any Additional Indebtedness
Agent,
(7) to the extent we or the Funding Corporation is the account party to
any letter of credit related thereto, any Debt Service Reserve L/C Bank, any
Debt Service Reserve L/C Issuer and any Debt Service Reserve L/C Agent,
(8) to the extent we or the Funding Corporation is the account party to
any letter of credit related thereto, any Aquila Reserve L/C Bank, any
Aquila Reserve L/C Issuer and any Aquila Reserve L/C Agent,
(9) the collateral agent,
(10) the intercreditor agent and
(11) the administrative agent, in each case to the extent such party is,
or pursuant to the Intercreditor Agreement, it (or an agent on its behalf)
becomes, a party to the Intercreditor Agreement.
"Site" means the approximately 60 acre parcel of land located near
Batesville, Mississippi on which our power facility will be located.
"Test Period" means, for any distribution date, the period beginning one
year prior to that distribution date and ending one year after that distribution
date; PROVIDED that if we have received written notice from Virginia Power that
Virginia Power has elected not to extend the Virginia Power PPA beyond the
Initial Term, as defined in the Virginia Power PPA, the "Test Period" for any
distribution date through the expiration of the Virginia Power PPA will be the
period beginning one year prior to such distribution date and ending two years
after that distribution date.
"Therm" means a unit of heating value equivalent to 100,000 British thermal
units (Btu).
"Title Event" means the existence of any defect of title or lien or
encumbrance on the Mortgage Estate, other than Permitted Liens in effect on
May 21, 1999, that entitles the collateral agent to make a claim under the Title
Policy.
"Title Insurer" means First American Title Insurance Company.
"Title Proceeds" means all amounts and proceeds actually received under any
title insurance policy on account of a Title Event.
"Title Policy" means the policy of title insurance issued by the Title
Insurer dated as of May 21, 1999, including all amendments thereto, endorsements
thereof and substitutions or replacements therefor.
"Total Equity Amount" means $54,000,000.
"Transaction Documents" means the Project Documents and the Financing
Documents.
"Two-Thirds PPA Period" means any period during which at least 66 2/3% but
less than 100% of the then current capacity of our power facility is to be sold
or otherwise disposed of under an Acceptable PPA.
A-15
<PAGE>
"Use Agreements" means, collectively, the Infrastructure Use Agreement
(Water Supply System and Wastewater Disposal System) to be entered into by and
among the Authority, the Mississippi Department of Economic and Community
Development, Panola County, the Industrial Development Authority, and us and the
Infrastructure Use Agreement (Lateral Pipeline) to be entered into by and among
the Authority, the Mississippi Department of Economic and Community Development,
Panola County, the Industrial Development Authority, the City of Batesville and
us, the Panola Partnership Agreement and any other agreements that may be
entered into by us pursuant to the terms of these agreements.
"Virginia Power L/C Agent" means, initially, Credit Suisse First Boston, and
any Person appointed as a substitute or replacement facility agent under the
Virginia Power L/C Agreement.
"Virginia Power L/C Agreement" means the Letter of Credit Agreement, dated
as of August 28, 1998, as amended, among us, the Virginia Power L/C Agent, the
Virginia Power L/C Issuer and the Virginia Power L/C Banks.
"Virginia Power L/C Banks" mean the financial institutions from time to time
party to the Virginia Power L/C Agreement.
"Virginia Power L/C Provider" means Credit Suisse First Boston and any other
issuer of a Virginia Power Letter of Credit.
"Virginia Power Letter of Credit" means any letter of credit issued under
the Virginia Power L/C Agreement.
"Virginia Power PPA" means the Power Purchase Agreement, dated as of
May 18, 1998, between us and Virginia Power, as amended by the First Amendment
to Power Purchase Agreement, dated as of July 22, 1998 and as amended by the
Second Amendment to Power Purchase Agreement, dated as of August 11, 1998,
between us and Virginia Power.
"Voluntary PPA Buy-Outs" means any buy-out of a Power Purchase Agreement
that is not an Involuntary PPA Buy-Out.
"Watt" means the electric unit of real power or rate of doing work. The rate
of energy transfer equivalent to one ampere flowing due to an electrical
pressure of one volt at unity power factor.
"Working Capital Agent" means any agent for the Working Capital Banks under
a Working Capital Agreement.
"Working Capital Agreement" means an agreement among us, the Working Capital
Agent and the Working Capital Banks pursuant to which the Working Capital Banks
agree to make working capital loans to us on the terms and conditions set forth
in that agreement and in accordance with the Financing Documents; PROVIDED that
any Working Capital Agreement must require that no working capital loans be
outstanding for a period of at least ten days per year.
"Working Capital Banks" means the financial institutions from time to time
party to a Working Capital Agreement.
A-16
<PAGE>
ANNEX B
INDEPENDENT ENGINEER'S REPORT
We have included this independent engineer's report prepared by R.W. Beck,
Inc. in order to provide investors with an independent third-party analysis of,
among other things:
- the ability of the major project participants, including the construction
contractor and the operator, to perform their obligations under the
project contracts;
- the feasibility of the technology to be used in our power facility;
- the projected output of electricity from our power facility and the
projected efficiency of our power facility;
- the projected useful life of our power facility;
- the environmental permits required for the construction and operation of
our power facility and our power facility's ability to comply with these
permits; and
- the ability of our power facility to generate revenues which are
sufficient for us to make payments on the bonds.
We retained R.W. Beck, Inc. as an independent consultant in connection with
the offering of the private bonds. R.W. Beck, Inc. is not an employee, affiliate
or agent of us, and does not have any relationship to us other than as an
independent consultant. We paid R.W. Beck, Inc. a fee for the consulting
services provided to us in connection with the issuance of the private bonds.
B-1
<PAGE>
ANNEX B
INDEPENDENT ENGINEER'S REPORT
LSP ENERGY LIMITED PARTNERSHIP
BATESVILLE COMBINED-CYCLE PROJECT
R W Beck
[LOGO]
<PAGE>
[THIS PAGE INTENTIONALLY LEFT BLANK]
<PAGE>
ANNEX B
INDEPENDENT ENGINEER'S REPORT
LSP ENERGY LIMITED PARTNERSHIP
BATESVILLE COMBINED-CYCLE PROJECT
TABLE OF CONTENTS
Page
PROJECT PARTICIPANTS.........................................................B-2
The Partnership............................................................B-6
The Contractor.............................................................B-6
The Operator...............................................................B-6
THE FACILITY.................................................................B-6
Introduction...............................................................B-6
The Site...................................................................B-6
Site Access and Description..............................................B-6
Site Arrangement.........................................................B-7
Subsurface Conditions....................................................B-9
Environmental Site Assessment...........................................B-10
Site Summary............................................................B-10
Description of Facility...................................................B-11
Mechanical Equipment and Systems........................................B-11
Fuel Supply.............................................................B-12
Environmental Control Equipment.........................................B-12
Structural..............................................................B-13
Civil/Structural Design Criteria........................................B-13
Electrical System and Control...........................................B-13
Off-Site Requirements...................................................B-15
Review of Technology......................................................B-16
Combustion Turbine......................................................B-16
Heat Rate...............................................................B-19
Summary.................................................................B-20
Reliability and Availability..............................................B-20
Estimated Useful Life of Facility.........................................B-21
Construction Status and Schedule..........................................B-21
Performance Guarantees and Acceptance Tests...............................B-22
Performance Guarantees..................................................B-22
Acceptance Tests........................................................B-23
Status of Permits and Approvals...........................................B-25
THE FINANCING OF THE PROJECT................................................B-27
Facility Construction Cost................................................B-27
Sources and Uses of Funds.................................................B-27
PROJECTED OPERATING RESULTS.................................................B-28
Annual Operating Revenues.................................................B-28
Revenues from the Sale of Electricity to Virginia Power.................B-28
B-i
<PAGE>
ANNEX B
INDEPENDENT ENGINEER'S REPORT
LSP ENERGY LIMITED PARTNERSHIP
BATESVILLE COMBINED CYCLE PROJECT
TABLE OF CONTENTS (Continued)
Page
----
Revenues from the Sale of Electricity to Aquila/UtiliCorp...............B-30
Revenues from the Sale of Electricity to the Market.....................B-32
Interest Income.........................................................B-32
Annual Operating Expenses.................................................B-33
Fuel Costs..............................................................B-33
Operation and Maintenance...............................................B-33
Annual Debt Service.......................................................B-33
Debt Service Coverage.....................................................B-34
Sensitivity Analyses......................................................B-34
Summary Comparison of Projected Operating Results.........................B-35
Liquidated Damages Analyses...............................................B-35
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
IN THE PROJECTION OF OPERATING RESULTS......................................B-35
CONCLUSIONS.................................................................B-37
EXHIBITS....................................................................B-40
EXHIBIT B-1 Base Case Projected Operating Results.......................B-40
EXHIBIT B-2 Sensitivity Case A - Reduced Availability...................B-48
EXHIBIT B-3 Sensitivity Case B - Increased Heat Rate....................B-55
EXHIBIT B-4 Sensitivity Case C - Increased Operating Expenses...........B-62
EXHIBIT B-5 Sensitivity Case D - Increased Inflation (4%)...............B-69
EXHIBIT B-6 Sensitivity Case E - Increased Inflation (6%)...............B-76
EXHIBIT B-7 Sensitivity Case F - Increased Gas Escalation...............B-83
EXHIBIT B-8 Sensitivity Case G - Reduced Market Prices..................B-90
EXHIBIT B-9 Sensitivity Case H - Reduced Market Prices, No Power
Purchase Agreements Renewals ...............................B-97
EXHIBIT B-10 Sensitivity Case I - No Power Purchase Agreements
Renewals ..................................................B-104
Copyright (C) 1999, R. W. Beck, Inc.
All Rights Reserved
B-ii
<PAGE>
[LETTERHEAD OF R W BECK]
May 13, 1999
LSP Energy Limited Partnership
c/o LS Energy, Inc.
Two Tower Center, 10th Floor
East Brunswick, New Jersey 08816
Credit Suisse First Boston
Eleven Madison Avenue
New York, NY 10010
Ladies and Gentlemen:
Subject: Independent Engineer's Report on
Batesville Combined-Cycle Project
Presented herein is the report (the "Report") of our review and
analyses of an 837 megawatt ("MW") combined-cycle plant under construction
primarily in Batesville, Mississippi (the "Facility"). The Facility sponsor is
LS Power, LLC ("LS Power"). The Facility will be owned by LSP Energy Limited
Partnership (the "Partnership"), a Delaware limited partnership.
The Facility is being designed and constructed by BVZ Power
Partners-Batesville (the "Contractor") under a Turnkey Engineering, Procurement
and Construction Agreement with the Partnership dated as of July 22, 1998, as
amended, and the Notice To Proceed, dated August 28, 1998 (the "Construction
Contract"), with the exception of certain infrastructure related to the
Facility, including lateral gas pipelines, water intake structure and pipelines,
transmission lines, and the electrical substation, which are the responsibility
of the Partnership. This infrastructure is being designed and constructed under
separate agreements between the Partnership and various contractors.. The
Facility will be operated by CEI Batesville Operations, LLC (the "Operator"),
pursuant to the Operation and Maintenance Agreement with the Partnership dated
August 24, 1998 (the "O&M Agreement").
A major portion of the costs of acquisition, design, and
construction of the Facility is being provided for through the issuance of
$150,000,000 of 7.164% Senior Secured Bonds due January 15, 2014 (the "Series A
Bonds") and $176,000,000 of 8.160% Senior Secured Bonds due July 15, 2025 (the
"Series B Bonds" and, together with the Series A Bonds, the "Bonds"). A portion
of the proceeds of the Bonds has been allocated in the construction budget for
payment of interest accruing on the Bonds through June 1, 2000, to fund a debt
service reserve fund equal to the next six months of principal and interest, and
to pay transaction costs.
The Facility and its related components are being constructed on a
60-acre parcel located in Batesville, Mississippi (the "Site"), as shown in
Figure B-1. The Partnership purchased the Site from the Industrial Development
Authority of the second Judicial District of Panola County, Mississippi (the
"IDA") on August 28, 1998.
The major equipment being incorporated into the Facility are: (1)
three thermal-cycle combustion turbine generators ("CTGs"), Model 501F,
manufactured by Westinghouse Power Generation ("Westinghouse"); (2) three heat
recovery steam generators ("HRSGs") manufactured by Nooter/Eriksen; and (3)
three steam turbine generators ("STGs") manufactured by ABB Power Generation
("ABB"). Control of oxides of nitrogen ("NOX") is to be achieved by equipping
the CTGs with Dry Low NOX ("DLN") combustors.
B-1
<PAGE>
Pursuant to the Construction Contract, the Contractor has
agreed to design and construct the Facility to generate a guaranteed
Maximum Unit Power Output, guaranteed Unit Power Output, and a guaranteed
Unit Heat Rate as summarized in the "Performance Guarantees and Acceptance
Tests" section of this Report. Electrical capacity and energy produced by
the Facility will be sold to: (1) Virginia Electric and Power Company
("Virginia Power") pursuant to a Power Purchase Agreement with the
Partnership dated May 18, 1998, as amended by the First Amendment to Power
Purchase Agreement dated as of July 22, 1998 and the Second Amendment to
Power Purchase Agreement dated as of August 11, 1998 (the "Virginia Power
Purchase Agreement"), and (2) Aquila Energy Marketing Corporation and
UtiliCorp United, Inc. (collectively, "Aquila/UtiliCorp") pursuant to a
Power Purchase Agreement with the Partnership dated May 21, 1998 (the
"Aquila/UtiliCorp Power Purchase Agreement" and, together with the
Virginia Power Purchase Agreement, the "Power Purchase Agreements").
Natural gas fuel for the Project will be supplied by each power purchaser
under tolling arrangements contained in the above-referenced respective
Power Purchase Agreements.
During the preparation of this Report, we have reviewed the executed
agreements related to the development of the Facility to which the Partnership
is a party. The executed agreements 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.
In addition we have reviewed: (1) the Contractor's Scope of Services
and Scope of Supply (the "Design Criteria"), which is an exhibit to the
Construction Contract, and preliminary general engineering plans and
specifications for the Facility; (2) the construction costs and schedule; (3)
the separate agreements for the construction of certain infrastructure related
to the Facility for the limited purpose of their consistency with the overall
construction schedule and the inclusion of these costs in the overall
construction costs; (4) the status of permits and approvals; and the
environmental site assessment reports; (5) the Preliminary Site Investigation
Report and the Subsurface Investigation Data Report; (6) the projected levels of
production of the Facility; (7) the projected heat rate; (8) the projected
operation and maintenance expenses; and (9) the projected revenues. Based on our
review, we have prepared a projection of revenues, expenses, and debt service
coverage ratios for the Facility (the "Projected Operating Results").
During the course of our review, we have visited and made general
field observations of the 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 Site and were not in the detail which would be
necessary to reveal conditions with respect to safety; geological or
environmental conditions; or the conformance with agreements, codes, permits,
rules, or regulations of any party having jurisdiction with respect to the
Facility or the Site.
Certain analyses relied upon for the purposes of this Report,
specifically those related to the price of fuel and the market clearing price of
electricity, were performed by others and relied upon by us. The projections of
(1) fuel pricing for the purposes of projecting fuel-related components of the
energy payments under the Power Purchase Agreements and during the merchant
plant period of operation, and (2) the market clearing price of electricity for
the term of the Bonds were estimated by C.C. Pace Consulting, L.L.C. ("C.C.
Pace").
PROJECT PARTICIPANTS
Those partners, contractors, vendors and other service providers
responsible for the development, design, construction, and operation of the
Facility are discussed below. Construction is being performed pursuant to the
Construction Contract with the Contractor. Under the terms of the Construction
Contract, the Contractor is responsible for the performance of all
subcontractors and all vendors providing equipment for the Facility, with the
exception of the contracts for the construction of certain infrastructure
related to the Facility. Under the O&M Agreement, the Operator is responsible
for the performance of all subcontractors which it engages related to the
operation of the Facility. We are of the opinion that the Contractor and the
Operator have previously demonstrated the capability to perform their
responsibilities under the Construction Contract and the O&M Agreement,
respectively.
B-2
<PAGE>
The Partnership
The Partnership was formed to develop, design, construct, finance,
own, operate, and maintain the Facility. The general and limited partners in the
Partnership are LSP Energy, Inc. and LSP Batesville Holding, LLC. These entities
are affiliates of LS Power and Cogentrix Energy, Inc. ("CEI").
LS Power is a privately-owned independent power producer that
develops, finances, owns, and manages cogeneration and independent power
projects. Since 1990, LS Power and its affiliates have completed development of
over 2,000 MW of power generation capacity with approximately 1,400 MW of
additional capacity under development.
Cogentrix Energy, Inc is an independent power producer that
acquires, develops, owns and operates electric generating facilities,
principally in the United States. Cogentrix has net ownership interest in 26
facilities comprising approximately 2,110 MW.
The Contractor
The Contractor is responsible for the Construction Contract, which
includes the design, engineering, procurement, construction, start-up, and
testing of the Facility in accordance with the Construction Contract. The
Contractor was formed as a partnership in 1994 between Black & Veatch and H.B.
Zachry Company, both of which independently have extensive experience on similar
projects, to engineer, procure, and construct power plant projects. The
Contractor has experience on similar projects both domestically and
internationally. H. B. Zachry Company reports that total contracts in hand
exceed one billion dollars. Black and Veatch reports that since 1990 it has
completed, or has in progress, EPC projects totaling over 9 billion dollars and
from 1987 to 1996 it was awarded 62,530 MW in new power plant projects.
Included in the Contractor's design-construct portfolio is: (1) the
Tenaska IV Partners, Ltd. Plant, a 258 MW gas-fired combined cycle cogeneration
facility in Cleburne, Texas, which has Westinghouse 501F CTGs, three pressure
level, supplementary fired HRSGs, and a Westinghouse reheat steam turbine; and
(2) the E.I. Mid-Georgia Kathleen Project, a 250 MW combined cycle cogeneration
facility in Georgia which has two Westinghouse 501D5A combustion turbines with
dry low NOX combustors, a 100 MW non-reheat MHI steam turbine generator and two
Nooter/Erikson HRSGs.
The Operator
The O&M Agreement is based on compensation and reimbursement to the
Operator, a subsidiary of CEI, for all reimbursable costs, services and
management fees. In accordance with the O&M Agreement, CEI has commenced
Pre-Commencement Phase Services for the Facility.
CEI has both owned and operated fossil fuel facilities since 1985.
CEI owns and operates ten coal and four natural gas facilities, which generate
approximately 1,864 MW of electricity for sale. Two of the facilities utilize
Westinghouse 501F machines and one facility utilizes a General Electric 7FA
machine.
CEI has more than 400 employees with direction for safety and other
programs provided from its Charlotte, NC operations division. To emphasize focus
for its personnel, CEI reports it offers an incentive program based on
pre-determined goals for plant output, efficiency and performance. Each employee
is paid a bonus based on the output and efficiency relative to the
pre-determined goals.
CEI has developed its own computer-based maintenance management
system that incorporates areas of preventive maintenance, corrective maintenance
and maintenance history. Plant performance testing is used to complement
predictive maintenance measures. CEI has reported an operating record of over 95
percent availability for electric capacity.
B-3
<PAGE>
Figure B-1
Batesville Combined-Cycle Project
Site Location
[GRAPHIC OMITTED]
B-4
<PAGE>
Figure B-2
Batesville Combined-Cycle Project
Off-Site Requirements
[GRAPHIC OMITTED]
B-5
<PAGE>
THE FACILITY
Introduction
This section describes the Site and the environmental site
assessments for the Facility, the equipment and systems, the technology, the
reliability and availability, the estimated useful life, the construction status
and schedule, the performance guarantees and tests, and the status of permits
and approvals of the Facility.
The Facility is a combined-cycle electric generating facility being
designed to produce approximately 837 MW of electricity. The Facility is under
construction on an approximately 60-acre parcel of land located within the
Batesville Industrial Park in the City of Batesville, Mississippi, as shown on
Figure B-1, Site Location.
Major components of the Facility will include three power trains
that can be operated independently. Each train consists of a CTG, a HRSG, and a
STG. The CTGs and the duct burners incorporated in the HRSGs will only fire
natural gas.
Off-site connections are shown on Figure B-2, Off-Site Requirements.
The electrical interconnection will be via a new switchyard on the project site
and high voltage connections to the Batesville Substation along approximately
1,500 feet of Project-owned property, and along the transmission line right of
way. The Batesville Substation is shared between TVA and Entergy allowing for
direct access to either transmission system through interconnection points with
each utility. The Facility, through interstate gas pipeline connections with ANR
Pipeline Company ("ANR") and Tennessee Gas Pipeline Company ("TGPL"), will have
access to multiple supply basins in the United States and Canada plus indirect
access to two other pipeline systems (Texas Gas and Trunkline Gas). Procurement
and delivery of fuel will be performed by the power purchasers during the terms
of the Power Purchase Agreements, and may be the responsibility of the
Partnership after the expiration of the Power Purchase Agreements.
The Facility's potable water needs will be supplied by a permanent
connection to the Batesville municipal water system which has a potable water
main adjacent to the Site. Sanitary waste will be disposed of by a connection to
the Batesville sanitary sewer system. As of the date of this Report the Facility
is being served by temporary connections to the Batesville potable water and
sewer lines. The Facility's process water needs will be obtained from Enid Lake
pursuant to a Water Supply Storage Agreement between the Partnership and the US
Army Corps of Engineers dated June 8, 1998, and the State of Mississippi
Department of Environmental Quality Office of Land and Water Resources Permit
issued November 25, 1997. Process wastewater, after treatment on site, will be
discharged to the Little Tallahatchie River northwest of the site via a
pipeline. Stormwater runoff from the Site will be discharged to an unnamed
tributary of the Little Tallahatchie River in accordance with the Facility's
National Pollution Discharge Elimination System ("NPDES") permit for stormwater
discharge.
The Site
The main portion of the Facility is being constructed on property
located in the Batesville Industrial Park in the City of Batesville,
Mississippi. The Partnership purchased the Site from the IDA on August 28, 1998.
The deed is subject to restrictive covenants which govern the development of the
land, and the Partnership is currently working with the IDA toward a waiver of
ambiguous items and acknowledgment of compliance with the terms of the
covenants. The Facility also requires easements for construction of one or more
gas pipeline connections, a process water supply pipeline, a wastewater
discharge pipeline, and the electrical transmission line connections (the
"Easements"). The Site is described below, and the Easements are described under
the Off-Site Requirements section.
Site Access and Description
Vehicle access to the Site is relatively convenient over federal,
state and local roads. From the north, starting at the nearest international
airport in Memphis Tennessee, Interstate Highway 55 South provides access to
Mississippi State Route 35 ("Rt. 35") south and a two lane paved road named
Brewer Road (shown as Keating or Ballentine Road on some maps) currently
provides access east from Rt. 35 to the Site in the Batesville Industrial Park.
Portions of the industrial park border the east side of Rt. 35 and a new two
lane paved access road is to be constructed into the industrial park. The main
access to the Site will be from this new access road. From the
B-6
<PAGE>
south, the Site is accessible via Interstate 55 north to Mississippi State Route
6 ("Rt. 6") West into Batesville and then Rt. 35 north (or Rt. 51 north to Rt.
35) to the Batesville Industrial Park. There is already some industrial
development at the industrial park. The park is serviced by the surrounding
roadways.
The main line of the Illinois Central Gulf Railroad runs along the
west side of Rt. 35 and passes approximately 1,000 feet to the northwest of the
Site. The Mississippi River, accessible approximately 38 miles from the site, is
the closest navigable waterway. Due to the distance to the river, water-borne
deliveries of equipment and materials are not practical.
The main components of the Facility are being constructed on the
Site, which consists of approximately 60 acres of property within an
approximately 200-acre addition to the existing Batesville Industrial Park. The
Site is located in Panola County, Mississippi in portions of both the NW quarter
of Section 3 and the NE quarter of Section 4, Township 9S, Range 7W. The Site is
bordered to: (1) the north by vacant land in the Batesville Industrial Park and
the existing Harmon Industrial Park; (2) the east by vacant land in the
Batesville Industrial Park; (3) the south by Brewer Road, beyond which is vacant
land, a portion of which is currently planned for a commercial/residential
development; and (4) the west by Tri Star Mechanical Contractors ("Tri Star"),
Serta Mattress Company ("Serta"), Rt. 35, and Thermos ("Thermos") Manufacturing
Company (west of Rt. 35). The northern two-thirds of the Site is relatively
level while the southern third of the site slopes gradually upward. Site
elevation varies from approximately 215 to 260 feet above mean sea level. The
Site is mostly clear of large vegetation and has no known above- or below-grade
structures, with the exception of the existing electric transmission lines and
natural gas pipeline that cross the southern portion of the site. Former use of
the land was limited to agriculture. The existing drainage pattern runs to the
North by Northeast towards the unnamed tributary of the Little Tallahatchie
River, which crosses the northeast corner of the Site. A Preliminary Site
Investigation report, covering the entire Batesville Industrial Park site, was
prepared by Allan & Hoshall and dated March 1991. This report states that "the
Federal Emergency Management Agency's ("FEMA") Flood Insurance Rate Map for the
Batesville area does not indicate any floodplains or floodway areas on the
Industrial Park Site".
Site Arrangement
Based on information provided by the Contractor, the main power
block (the "Power Block"), including the generation area, multi-purpose
building, parking, storage tanks for various fluids, cooling tower, switchyard,
and substation areas comprises approximately 30 acres. The remaining Site area
is available for laydown, construction office space, and open area. As shown on
Figure B-3, Site Arrangement, the Power Block is located towards the northern
side of the Site, adjacent to the new Industrial Park Access Road that is to be
constructed from Rt. 35, and is also approximately centered on the Site in the
east-west direction. Access to the Site is currently provided by a temporary
road constructed by the Partnership from Rt. 35.
The three CTG and HRSG trains are oriented north-to-south with the
HRSGs on the north end. The three STGs are located east of each CTG. The
switchyard and substation are located on the south end of the CTGs, and the
multi-purpose building, storage tanks and parking lot are located north of the
HRSGs. The cooling tower is located to the east, with its axis oriented
north-south. The gas pipeline interconnection enters the Site from the west, the
process water supply pipeline enters from the east and the potable water and
sewer interconnections are to the south. The process wastewater discharge
pipeline leaves the Site via an easement to the northwest.
A plant access road system is to be provided consisting of a loop
around the Power Block area with connecting roadways to serve all of the major
equipment, the parking area and the multi-purpose building. Access to the Power
Block area will be through two gates from the new Industrial Park access road.
The area inside the loop road, around the CTGs, HRSGs and STGs, is to be
surfaced with crushed stone and will provide an additional means of temporary
access if required.
B-7
<PAGE>
Figure B-3
Batesville Combined-Cycle Project
Site Arrangement
[GRAPHIC OMITTED]
B-8
<PAGE>
Subsurface Conditions
A preliminary subsurface exploration for the Batesville Industrial
Park was performed by Professional Service Industries, Inc. ("PSI") in
connection with a preliminary investigation of the proposed Batesville
Industrial Park site. PSI's report was included in the Preliminary Site
Investigation report prepared by Allan & Hoshall and dated March 1991. This
investigation included information applicable to the Site.
A more specific subsurface investigation for the Site was recently
performed by PSI under the direction of the Contractor. The data collected
during this recent investigation is presented in a report prepared by the
Contractor and dated July 1998 (the "Subsurface Investigation Data Report").
The work documented in the Preliminary Site Investigation Report
included a limited boring program of 10 borings, with a maximum depth of 20.5
feet, spread across the industrial park property. Two of these borings were
located within the limits of the Site. Generally, the soils encountered were
composed of an upper stratum of fine-grained soils (silt or clay) underlain by a
lower stratum of sand or clayey sand. The upper stratum ranged from 8 to 15.5
feet thick. The Preliminary Site Investigation Report noted that the
fine-grained soils in the upper stratum are likely to be very sensitive to
changes in moisture content and that isolated areas of wet and soft soils should
be undercut and replaced with properly compacted fill. During the preliminary
investigation, ground water was found at depths ranging from 3.3 to 18.5 feet in
four of the borings, while the other six borings were dry.
The investigation documented in the Subsurface Investigation Data
Report was more detailed and Site specific than the Preliminary Site
Investigation Report data, and included 14 soil borings ranging in depth from 18
feet to 65 feet below ground surface, installation of 3 piezometers to monitor
groundwater elevations, 4 soil resistivity tests, and laboratory tests on
selected samples. The boring location plan included with the Subsurface
Investigation Data Report indicates that these 14 borings provide good coverage
of the area of the Site where the major portions of the Facility will be
constructed. The borings confirm an upper subsurface stratum of fine grained
soils including clayey silts, sandy silts and silty sands, and an underlying
stratum of layers of sands, silty sands and silty clays, including a dense sand
layer. The top elevation of the dense sand layer varies across the site, but was
located at 25 to 35 feet below grade in most of the borings. Groundwater levels
at the Site were measured during the field testing and one week after the
testing at the sites of the 3 piezometers and were found to be approximately 10
feet below grade at two locations, but varied from 10 feet just after drilling
to less than one foot below grade a week later at the location of piezometer
PZ-9. No notation was made in the report as to the possible reasons for this
high apparent water table.
The Preliminary Site Investigation Report states that subsurface
conditions encountered during the exploration appear to be adequate to support
foundations required by typical one, or two story industrial buildings using
typical shallow foundation construction, and provides a range of allowable soil
bearing capacities for design. This implies that the Facility's lightly loaded
structures can be supported on shallow spread footing or mats. The Preliminary
Site Investigation Report also states that these soils will adequately support
typical roadway and parking area pavements. The Subsurface Investigation Data
Report contains only factual data as determined by the field investigation and
laboratory test program and indicates that no analysis, engineering or reduction
of data was performed and no conclusions or recommendations for site-work and
foundation design are presented. However, the Design Criteria in the
Construction Contract indicate that "Based on the Subsurface Investigation Data
Report included in Attachment I-1, auger cast piling for heavily loaded
foundations such as the CTG, STG, HRSG and Step up transformer is included". No
criteria for the diameter, capacity, or length of the piling, or for the
allowable bearing capacity of shallow foundations is provided in the Design
Criteria. This indicates that analysis, engineering and reduction of the data
presented in the Subsurface Investigation Data Report, and development of
conclusions and recommendations (detailed design criteria) for site-work and
foundation design must be completed by the Contractor during the detailed design
of the Facility. The contract wording is similar to that we have seen in
contracts for similar projects, the Site Conditions clause of the Construction
Contract appears to properly assign the subsurface risk to the Contractor and
indicates that the only exceptions, or basis for change orders, will be the
discovery of pre-existing hazardous materials, archaeological remains or
artifacts.
B-9
<PAGE>
Environmental Site Assessment
We have reviewed the Phase I Environmental Site Assessment ("ESA"),
dated May 20, 1998, for the power plant site and associated right-of-ways
prepared by ECO-Systems, Inc., for the Partnership. The properties included in
the environmental site assessment are the power plant site, the transmission
line right-of-way, the wastewater pipeline right-of-way, and the water supply
pipeline right-of-way. The properties mostly lie within Panola County with
portions of the right-of-ways and water intake structure extending into
Yalobusha County, Mississippi. The objective of the environmental site
assessment was to discover readily-identifiable environmental impacts and
liabilities associated with the subject property. Specifically, the
environmental site assessment included: (1) a records review; (2) site
reconnaissance; (3) interviews with personnel knowledgeable about the property;
and (4) the preparation of a report with the findings of the environmental site
assessment.
The power plant site consists of approximately 60 acres of cleared
woods and former farmland which is part of a 200 acre addition to an existing
industrial park. The right-of-ways (the wastewater pipeline route is one mile,
the water supply route is 13.5 miles, and the transmission line properties are
seven acres) consist of primarily open pasture farmland, and undeveloped areas.
The subject properties are also bordered by certain industries located in the
industrial park.
The power plant site environmental site assessment report concludes
that based on the database search, no historical records contained in the
database appear to have identified an area of concern with the potential to have
impacted the properties. Furthermore, the assessment did not reveal evidence of
recognized environmental conditions in connection with the properties
investigated.
We have also reviewed another environmental site assessment, dated
June 9, 1998, for the natural gas pipeline right-of-way and associated easements
prepared by ECO-Systems, Inc., for the Partnership. The properties included in
this environmental site assessment are a 14-mile stretch extending from the Site
to the ANR Pipeline Company Sardis Station. The properties lie within Panola
County, Mississippi. The objective of the environmental site assessment was to
discover readily-identifiable environmental impacts and liabilities associated
with the subject property. Specifically, the environmental site assessment
included: (1) a records review; (2) site reconnaissance; (3) interviews with
personnel knowledgeable about the property; and (4) the preparation of a report
with the findings of the environmental site assessment.
The natural gas pipeline right-of-way environmental site assessment
report concludes that based on the database search, no historical records
contained in the database appears to have identified an area of concern with the
potential to have impacted the properties. Furthermore, the assessment did not
reveal evidence of recognized environmental conditions in connection with the
properties investigated.
Site Summary
Based on our review, we are of the opinion that sufficient data has
been gathered at the Site to perform the geotechnical analysis, engineering, and
reduction of data required to provide the geotechnical recommendations and
detailed site-work and foundation design criteria needed to properly complete
the Facility design. With proper foundation design, and adequate construction
controls to minimize the change in moisture content of the Site soils, the Site
should be suitable for construction and operation of the Facility.
Based on our review of the environmental site assessments for the
power plant site, the transmission line right-of-way, the wastewater pipeline
right-of-way, the water supply pipeline right-of-way, and the natural gas
pipeline right-of-way, we are of the opinion that there are no significant risks
identified regarding environmental contamination at the Site and that there are
no Site contamination issues that require substantial investigations or
significant allocation of funds.
Description of Facility
Mechanical Equipment and Systems
Each of the three natural gas fired 501F CTGs, nominally rated at
185,000 kW each, exhaust into a three-pressure, reheat HRSG with supplemental
firing for increased steam generation. The CTGs are equipped with DLN combustors
for emissions control. Combustion air conditioning consists of pulse-type,
self-cleaning air filters as well as evaporative coolers to reduce the inlet air
temperature for increased CTG
B-10
<PAGE>
performance during times of high ambient temperature. The CTGs are also equipped
for steam injection to augment power production. Each CTG is capable of starting
up by electricity being backfed from the utility grid. An on-line and off-line
compressor water wash system is also provided.
The three-pressure HRSGs will generate high pressure ("HP"),
intermediate pressure ("IP") and low pressure ("LP") steam at pressures and
temperatures of 1676 psia/1052(0)F, 382 psia/578(0)F and 54 psia/561(0)F,
respectively when not using duct burners for supplemental firing and at 59(0)F
ambient temperature. In addition, the design reheat outlet conditions are 350
psia/997(0)F under these conditions. The HRSGs are equipped with duct burners
located at the gas inlet to the HRSGs. These duct burners will allow
supplemental firing of gas to increase the temperature of the CTG exhaust gas
flow to the HRSG. Increasing the temperature of the gas flow increases steam
generation in the HRSG. At maximum load the duct burner will use approximately
12 percent of the total fuel consumption of the Facility. When using the duct
burners for supplemental firing, the HP steam flow increases from approximately
422,400 lb/hr to 575,400 lb/hr with pressures increasing and temperatures
decreasing. The HP steam outlet conditions change to 2,080 psia/1027(0)F. A
portion of this increased steam flow using duct burners is used for injection
into the CTGs for power augmentation. The HRSG is also equipped with a Selective
Catalytic Reduction ("SCR") system to limit NOX emissions. The HRSGs also have
provisions to allow the future installation of a catalyst to reduce carbon
monoxide ("CO") if required. The HRSGs utilize a cascading blowdown system along
with drum chemicals to control boiler water chemistry. Each HRSG has an HP, IP
and a LP economizer section.
The STGs are reheat units with axial exhaust, each nominally rated
at 92,000 kW. The exhaust of each steam turbine is directed to its own
water-cooled condenser. Circulating water from each condenser is routed to a
common forced-draft cooling tower. The cooling tower is positioned so as to be
oriented in the direction of the prevailing wind and to minimize the length of
the circulating water pipe. The condenser is a shell-and-tube type deaerating
condenser with the ability to operate with 100 percent of the HRSG output
(without duct burners) bypassing the steam turbine and being sent to the
condenser. Each condenser is equipped with a steam jet air removal system.
The HP steam from each HRSG is sent to its associated STG. The IP
steam from each HRSG is combined with the cold reheat steam coming from the STG.
This combined cold reheat/IP steam is reheated in the HRSG and sent to the STG
for admission to an intermediate pressure stage in the turbine. The LP steam
from each HRSG is also sent to the STG for admission to a low-pressure stage in
the turbine. When steam is injected to the CTG for power augmentation, a portion
of the cold reheat steam is used for this purpose. Each power train will utilize
two 50 percent condensate pumps and two 50 percent feedwater pumps, with an
uninstalled spare of each type of pump providing redundancy for all three power
trains. The common circulating water system will have three one-third capacity
pumps. The cooling tower will also provide auxiliary cooling water for equipment
cooling via two 100-percent cooling water pumps.
Raw water required by the Facility for cooling tower make-up, boiler
make-up and fire protection will be pumped to the 640,000 gallon raw water
storage tank at the site via a new 14-mile water supply pipeline from Enid Lake.
It has been recently determined that lake water sample analyses provided to the
Contractor prior to the NTP are not representative of actual conditions. The
Contractor, Partnership and Operator agree that pretreatment of the raw water is
required before the water can be used in the cooling tower and other equipment.
The Contractor and Partnership are in the process of developing an appropriate
pretreatment system. Wastewater will be treated and eventually disposed of in
the Tallahatchie River. These systems are further described in the section
entitled "Off-Site Requirements".
The demineralized boiler feedwater make-up system consists of two 50
percent capacity demineralizer trains. These two demineralizer trains provide
enough demineralized water to allow operation with continuous steam injection to
the CTGs. The system also has an 800,000 gallon demineralized water storage
tank.
The fire protection system is supplied with water from two 100
percent fire pumps, one motor-driven pump and one diesel engine-driven pump.
These pumps take suction from the 640,000 gallon raw water storage tank, which
is configured to provide 200,000 gallons of water dedicated to the fire
protection system. A fire main with hydrants serves the site and buildings.
Sprinkler systems protect the transformers, STG bearings and lube oil
reservoirs. The cooling tower is protected by a dry pipe sprinkler system.
B-11
<PAGE>
Natural gas is to be supplied to the site boundary via a new gas
supply line, which is further discussed in the section entitled "Off-Site
Requirements". Each CTG will have a gas scrubber to remove small amounts of
particulate matter and liquids.
The instrument and service air needs are supplied by two
50-percent-capacity rotary screw compressors. The instrument air will be
conditioned by passing through two 100-percent-capacity coalescing filters, one
100-percent regenerative dual tower desiccant-type air dryer and after filters.
The dryer and filters produce instrument air with a dewpoint of -40(degree)F. A
five-minute compressed air storage tank provides surge capacity. Backup air is
provided by an air bleed from the CTG compressors.
Fuel Supply
Under the terms of the Virginia Power Purchase Agreement and the
Aquila/UtiliCorp Power Purchase Agreement, Virginia Power and Aquila/UtiliCorp
are responsible for the procurement, payment, transportation and delivery to the
fuel metering points of the natural gas fuel required for the dispatch of the
respective Dedicated Units. Information provided by the Partnership regarding
the historical fuel quality of the gas in the ANR and Tennessee pipelines
indicates that this natural gas has met the pressure and quality requirements of
the CTG manufacturer's specifications.
Environmental Control Equipment
Air Pollution Control
The three Westinghouse 501F CTGs are to be equipped with DLN
combustors, a technology that has been developed by Westinghouse and its
alliance partners over several years. The CTGs are designed to utilize water or
steam injection while firing natural gas. NOX Emissions control is provided by
DLN combustors and Selective Catalytic Reduction ("SCR") systems. The
Construction Contract guarantees NOX emissions to 9 ppmvd, corrected to 15
percent oxygen when firing natural gas. Emissions are measured at the stack. The
Westinghouse Warranty Data Sheet indicates emissions from the CTGs prior to the
SCR. The sheet indicates a NOX guarantee of 25 ppmvd from base load to 70
percent and 45 ppmvd from 70 percent to 50 percent .
Emissions of other pollutants from operation of the Facility are to
be controlled primarily by burning clean fuels, by the inherently high
combustion efficiency of the CTGs and the use of SCR. We can identify no reason
why the emissions guarantees of the Construction Contract and the emissions
limitations of the applicable air permits cannot be met by the Facility provided
the SCR systems are properly designed and sized.
A continuous emission monitoring system ("CEMS") to measure the
concentrations of NOX, CO, and O2 will be installed.
Wastewater Disposal
Facility wastewater will be pre-treated utilizing an oil-water
separator and pH control and pumped to the Little Tallahatchie River. Sanitary
waste will be delivered to the municipal sewer system. Wastewater effluent
quality to the Partnership is guaranteed under the Construction Contract.
Noise Control
The Construction Contract requires that the Facility will be
designed to meet the near field sound levels recommended by OSHA for plant
equipment at base load operation, exclusive of transients, start-up and
shut-down, and off normal and emergency conditions.
The far field sound level has been guaranteed in the Construction
Contract, Attachment 1, Exhibit A. The near field sound level has been
guaranteed in the Construction Contract in accordance with OSHA. Sound shrouds
may be furnished by the Contractor to meet OSHA requirements.
Structural
Because the Facility is essentially an outdoor installation,
buildings are limited. The CTGs, and STGs are to be set on reinforced concrete
foundations with pilings and furnished with walk-in enclosures which will
B-12
<PAGE>
provide for weather protection and reduction of noise but still allow regular
maintenance. As specified in the Design Criteria included in the Construction
Contract the Facility will have one large Multi-purpose Building. The
Multi-purpose Building is to house the water treatment equipment, the control
room, control and electrical equipment, warehouse space (minimum 2,000 square
feet), repair shops (minimum 2,000 square feet), and an operator's
administration area (minimum 3,000 square feet) consisting of air conditioned
and heated offices, conference/training room, locker rooms, showers and sanitary
facilities. The building is to be an insulated pre-engineered metal building
approximately 100 foot by 160 foot in plan with an 18-foot eave height and
concrete foundations and floor slab. The control room, locker rooms, offices,
kitchen/lunch room and conference room are to be air-conditioned.
The remainder of the equipment and facilities will be located
outside on concrete foundations.
Civil/Structural Design Criteria
We have reviewed civil/structural provisions of the Design Criteria
included in the Construction Contract and find that they provide detailed
recommendations for design and construction and references to local, state and
national building codes and standards.
Electrical System and Control
The electrical and control system of the Facility is designed to
generate power in six generators, transfer the power to the transmission systems
of both TVA and Entergy, power the auxiliary electrical equipment associated
with the generators and the balance of the plant, and to control the processes
required to operate all the facilities. The six generators include three with an
output voltage of 18 kV associated with three combustion turbine units and three
with an output voltage of 13.8 kV associated with three steam turbines. All
generators will be rated for the full output of the prime mover to which they
are connected. All six generators are individually connected to a 161 kV
switchyard via isolated phase bus duct and generator step-up transformers which
raise the generator output voltage to the switchyard voltage which matches that
of the transmission system. In the unit connected configuration, the circuit
breaker(s) in the switchyard provide isolation and protection of the
generator(s) and the generator step up transformer(s). The transformers are
indicated to be sized for the maximum output of the generators. The bus duct
conductor material will be either aluminum or copper.
There is no black start capability. Normally auxiliary power will be
delivered from the switchyard via two unit auxiliary power transformers.
Start-up power will be purchased from TVA or Entergy. Prior to completion of the
substation and interconnection with TVA and Entergy, startup power is expected
to be taken from a temporary connection off the TVA Oxford transmission line to
an auxiliary power transformer. Each of these transformers reported to be
sufficient to allow either transformer to carry the entire Facility load in the
event of a failure of one of these units. The two unit auxiliary transformers
are connected to a double ended lineup of 4.16 kV switchgear which serves as the
main distribution center for electric power in the Facility. The lineup includes
a main circuit breaker for each of the transformers, a bus tie breaker, medium
voltage motor starters for motors greater than 250HP and feeder circuit breakers
to provide power to four 4.16 kV-480V transformers to supply the 480V system.
The 4.16 kV-480V transformers are used to feed two double ended 480V unit
substations. Each of the unit substations is fed by two of the transformers,
which are individually rated to carry the entire unit substation. These unit
substations are designed with two main circuit breakers and a bus tie circuit
breaker, to allow one or both of the connected transformers to carry the load on
the substation, and feeder circuit breakers to distribute power to motor control
centers ("MCC") throughout the plant. The MCC contain motor starters to feed
motors up to 200HP, as well as circuit breakers to feed lighting and panelboards
via small dry-type step down transformers as required.
There are appropriate protective relaying systems included in the
design of the Facility to limit the impact of electrical equipment faults to the
immediate area of the failed piece of equipment. The Facility design includes a
125Vdc system consisting of a station battery and dual redundant chargers to
provide switchgear control power, power to the STG and CTG shut-down systems and
other essential control and instrumentation systems. The 125Vdc system also
supplies the Uninterruptible Power Supply system ("UPS") which converts the
125Vdc to 120Vac upon loss of normal power supply in the plant to operate the
DCS and other control functions. The Facility design also includes lighting,
grounding, lightning protection, cathodic protection (if required) and other
electrical equipment and systems typically included in a project of this type.
B-13
<PAGE>
The Facility uses a distributed control system ("DCS") to integrate
the overall operation of the various systems and equipment within the plant. The
DCS will directly process most of the balance of plant instrument and control
loops and also communicate directly with the control systems provided with the
combustion and steam turbine-generator packages. It will also communicate with
the interconnected utilities' system operations centers for load control and
other data related to the dispatch of the Facility. The DCS is provided with
multiple workstations for operator interface and the level of redundancy, in
terms of power supply, processors and input/output ("I/O"), that would be
expected for reliable operation of a plant of this type.
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
organizations like the Partnership in several ways. First, it could impact the
financial records of the Partnership; second, it could impact the operating data
of the Facility; and third, it could impact the instruments and controls of the
Facility. Although the Y2K Issue has received considerable publicity as it
relates to computer information systems such as billing and financial systems,
the problems regarding process control or embedded systems in operational
equipment have received limited attention. This includes instrument and control
systems for power plants and SCADA systems for substation, transmission and
distribution facilities. The potential problems with these operating facilities
are significant as is the effort required to identify and correct the problems.
Additionally, the Y2K Issue has the potential to affect other
organizations, whose continued performance could be critical to the operation of
the Facility. These other organizations may be located either "upstream" or
"downstream" of the Facility.
We have reviewed this matter with the management of the Partnership
and they have advised that the Construction Contract requirement that the
Facility be "Year 2000 Compliant" is considered sufficient, and is the
responsibility of the Contractor per the Construction Contract. The Construction
Contract defines "Year 2000" Compliant" to mean, with respect to the Work,
including without limitation any computer hardware, software and firmware
supplied by Contractor or its Subcontractors, that such Work, without any
operator intervention, will operate accurately and, without interruption,
accept, process and in all manner retain full functionality when referring to,
or involving, any year or date in the twentieth or twenty-first centuries.
Evaluation of the actual status of the 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 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
Water Supply
The potable water requirements of the Facility will be served by a
new 8-inch line, approximately 1,500 feet long, which will tie into the
municipal water system. The new 8-inch line will be installed by the Partnership
or the municipality. The process water needs of the Facility will be serviced by
the raw water system. The raw water system will transport water from Enid Lake
to the Facility through a dedicated water line. The raw water system will
consist of three 50-percent pumps at a new intake structure at Enid Lake and
approximately 13.5 miles of 24-inch diameter pipe to convey the water to the
Facility. At the site the water will be received by the
B-14
<PAGE>
640,000-gallon raw water storage tank. Both the intake structure and pipeline
are currently being constructed by the Partnership.
Enid Lake was formed by the U.S. Army Corps of Engineers by
constructing the 85 ft high, 8,400 ft long Enid Dam on the Yocona River in 1952.
The flood control lake contains drainage from 560 square miles and has between
65 miles and 220 miles of shoreline, depending on its fluctuating level. The
level rises from el. 230, its lowest level, to el. 268, its flood control pool
level.
The raw water line right-of-way ("ROW") is approximately 13.5 miles
long by 25 feet wide and extends from the northwest end of Enid Lake at the
water intake structure location, north/northwestward toward Interstate 55
("I-55") near the Yalobusha/Panola county line. The raw water line ROW turns
north and follows the east side of Leslie Road before following an existing
Entergy electrical transmission right-of-way to approximately one-half mile
south of McNeely Road where the raw water line ROW begins to follow Johnson
Creek. The raw water line ROW proceeds along Johnson Creek to approximately
one-quarter mile north of McNeely Road where it begins to follow Hurt Creek. The
raw water line ROW follows Hurt Creek until it reaches Shiloh Road where it
again begins to follow the Entergy right-of-way lying just east of I-55.
Approximately one-half mile north of Shiloh Road, the raw water line ROW begins
to run 25 feet east of I-55, north to Brewer Road. The raw water line ROW then
crosses I-55 and proceeds westward on the north side of Brewer Road to the Site.
The Corps of Engineer's Report ("COE Report") which recommended the
reallocation of water from Enid Lake to the Facility also considered alternative
water supplies for the Facility. There were two alternatives in the COE Report
that were technically viable, but had higher evaluated costs than the
recommended reallocation from Enid Lake. One alternative was a new groundwater
wellfield in the Mississippi River Valley Alluvium aquifer located approximately
11 miles west of the Site. The other alternative was the damming of a creek and
the creation of a new single purpose water supply located approximately 10 miles
to the southeast of the Site.
Wastewater Disposal
Process wastewater is collected and treated by the Facility, as
described in the "Environmental Control Systems" Section of this Report. The
wastewater will be discharged to the Little Tallahatchie River. The wastewater
pipeline is currently being installed by the Partnership. The sanitary wastes
will be discharged to the municipal sewer system via a new 2,500-foot sewer
line.
The wastewater line ROW is one mile long by 25 feet wide and extends
from the Site to the Little Tallahatchie River. This tract of land is almost
entirely wooded and parallels a small, unnamed creek running from the Industrial
Park to the river. The ROW is bordered to the southwest by Thermos as it crosses
Rt. 35; to the north and to the east by more variably wooded terrain; and, to
the south by Rt. 35 and Illinois Central Gulf Railroad, across from which lies
the north corner of the cleared Industrial Park site.
Electrical Interconnection
A substation adjacent to the Site is currently being designed and
installed by the Partnership, which will serve to integrate the output of the
six generators, the input to the two station auxiliary transformers and the
transmission lines which tie the Facility to the Entergy and TVA portions of the
Batesville Substation approximately one-half mile from the site. Based on the
information contained in the Interconnection Agreements between the Partnership
and both TVA and Entergy the substation will operate at 161 kV and include
circuit breakers, switches, protective relaying, metering and other equipment
necessary to meet the utility grade requirements for a substation acceptable and
subject to the approval of both of the utilities. In addition, there will be a
161-230 kV step-up transformer to raise the voltage on the tie line to the
Entergy facilities at the Batesville Substation, which is operated at 230 kV.
The construction of the interconnecting substation also includes the tie lines
to the Batesville Substation.
In addition, there are system improvements on both the TVA and
Entergy systems in terms of both equipment replacement and transmission line
upgrades that are required to allow the Facility to transmit power through the
utility systems without overloading. These improvements are being made by the
utilities and paid for by the Partnership.
The transmission line ROW consists of approximately seven acres of
open farmland with small patches of trees. This property lies to the southwest
of the Site. It is bordered to the west by Rt. 35; to the north by
B-15
<PAGE>
Serta and Tri Star; to the east and south by pasture/rural land; and to the
southwest by the TVA and Entergy electrical substations to which the
transmission line ROW connects.
Natural Gas Interconnection
The Facility will be interconnected to the interstate natural gas
pipeline system through a new 20-inch diameter line that is currently being
installed by the Partnership. This 14.6-mile natural gas line runs from ANR's
existing Sardis Compressor Station located near Delta, Mississippi to the Site.
The gas interconnection pipeline ROW is 25 feet wide and runs from the Sardis
Compressor Station along Silo Road then southeast along Sandbed Road and across
Peach Creek. The easement then runs southeast, paralleling the Mississippi Power
& Light ("MP&L") transmission line ROW, crossing the MC/VOR Drainage Canal and
Amistead Creek. At the point where it crosses the TGPL's ROW, taps off of two
TGPL lines will join the interconnection line as it continues along the MP&L
ROW. The gas interconnection ROW turns east along the north bank of the Little
Tallahatchie River, crosses U.S. Rt. 51 and then turns south alongside a second
MP&L ROW and crosses the Little Tallahatchie River. The gas interconnection ROW
continues south along the MP&L ROW, turns southeast, crosses the Illinois
Central Gulf Railroad ROW and state Rt. 35. The gas interconnection ROW then
turns east terminating at the Site.
The interconnection agreements with ANR and TGPL both provide for
interconnection facilities with the capability of flowing up to 216 million
standard cubic feet per day of gas, which provides fully independent sourcing
capabilities. Gas metering stations will be located at the Sardis Compressor
Station and at the tap location on the TGPL pipelines.
Review of Technology
Combustion Turbine
The Facility is based on a combined-cycle technology, a technology
which has many years experience in cogeneration applications and the independent
power industry. This section comprises a discussion of the combustion turbine.
In general, the Facility will utilize equipment common in the
industry and with substantial operating history. However, the Westinghouse CTG
model 501F equipped with the DLN combustion system (the "501F-DLN") is a
relatively new application in the marketplace. Therefore, to aid in the
assessment of technology risk, the development and risk of the 501F-DLN is
addressed in this section. Our assessment of the 501F-DLN and its suitability
for the Facility is based on discussions with Westinghouse and published
literature provided by Westinghouse, discussions with the owners of other
Westinghouse CTGs, and information gathered during our review of other
Westinghouse based facilities.
The 501F is a 3,600 rpm heavy duty combustion turbine designed to
serve the 60 Hertz ("Hz") power generation needs for utility and industrial
service. The 501F was jointly developed by Westinghouse and Mitsubishi Heavy
Industries, Ltd. ("MHI") and is the fifth generation of Westinghouse combustion
turbine engines. This edition, the "F" technology, includes increases in air
flow and firing temperature, improved component efficiencies, and advances in
materials and turbine cooling.
To verify the basic design concepts of the 501F, full load shop
tests were completed at MHI's Takasago Machinery Works in the summer of 1989.
After the 1989 tests, several design enhancements were made and further testing
was conducted in 1991. Tests included starting and acceleration evaluations,
loading and unloading evaluations, cooling circuit flow modulation, part load
and full load performance, emissions testing of both the conventional "wet"
system combustors and the DLN systems combustors, and various system
evaluations. The design tested in 1991 was the basis for the production model of
the 501F. There are currently thirty 501Fs and one 701F (a 50 Hz model of the
501F) manufactured by Westinghouse in operation worldwide, as shown in Table 1.
B-16
<PAGE>
Table 1
Projects Utilizing the 501F or 701F
<TABLE>
<CAPTION>
Westinghouse Operation
Commercial Customer Station Country Quantity/Model Date
------------------- ------- ------- -------------- ---------
<S> <C> <C> <C> <C>
MHI/K-Point Station K-Point Japan (1) 701F 1992
Florida Power & Light Co. Lauderdale USA (4) 501F 1993
Kyushu Electric Power Co. Shinohita (1) Japan (4) 501F 1994
Kansai Electric Power Co. Himeji I (1) Japan (3) 501F 1994
Chubu Electric Power Co. Chita (1) Japan (2) 501F
Chubu Electric Power Co. Kawagoe (1) Japan (7) 501F
Korea Electric Power Co. Ulsan (1) Korea (4) 501F 1996
Tenaska IV Brazos USA (1) 501F 1997
LS Power Whitewater (1) USA (1) 501F 1997
LS Power Cottage Grove (1) USA (1) 501F 1997
Empire State Line Unit 2 (1) USA (1) 501F 1997
Termoflores Las Flores 3 (1) Colombia (1) 501F 1997
Calpine Pasadena (1) USA (1) 501F 1997
Termovalle Termovalle (1) Colombia (1) 501F 1998
Termomerilelectrica Merilelectrica (1) Colombia (1) 501F 1998
InterGen TermoEmcali (1) Colombia (1) 501F 1998
CFE El Sauz (1) Mexico (1) 501F 1998
CFE Hermosillo (1) Mexico (1) 501F 1998
CFE Huinala (1) Mexico (1) 501F 1998
AES Americas Uruguaiana (1) Brazil (2) 501F 1998
Thai Oil Refinery (1) Thailand (2) 701F 1998
KMR Power TermoCandelaria (1) Colombia (2) 501F 1999
Enron Penuelas (1) Puerto Rico (2) 501F 1999
PREPA Abengoa Puerto Rico (2) 501F 1999
El Dorado Energy El Dorado (1) USA (2) 501F 1999
AES Merida Mexico (2) 501F 2000
Nova Chemical (1) Canada (2) 501F 2000
CLECO (1) USA (3) 501F 2000
ENRON (1) USA (2) 501F 2000
</TABLE>
- ----------
(1) Denotes Plants with DLN combustion systems.
In addition, Westinghouse reports and Table 1 shows, twenty-five
additional 501F CTGs and two 701F CTGs that are expected to be in operation
prior to, or concurrent with, the start-up of the Facility. These 501F CTGs will
include a rotor inlet temperature and compressor ratio similar to that proposed
for the Facility. Westinghouse 501F CTGs began commercial operation in 1993 and
have 250,000 hours of operating history.
While the 501F has a reasonably long operating history, the
Westinghouse model 501F when used with the DLN combustion system (the
"501F-DLN"), which is to be used on the Facility, is still relatively new in the
marketplace. There are nine units currently in operation utilizing this specific
configuration. The following section contains a discussion of the 501F-DLN
combustion turbine and the problems which were encountered during start-up and
early operation at two (the "Early Plants") of these nine operating units. Since
the commissioning of the Early Plants, three 501F-DLN based simple cycle units
have been commissioned, two in Colombia (the "Colombian Plants") and one other
unit located in the United States. There were also three combined-cycle units,
with two in Colombia and one in the United States.
Performance and Emissions Issues
The Westinghouse 501F-DLN combustion turbine performance and
emissions deficiencies are similar at each of the Early Plants, each of which is
a dual fuel unit. At the Early Plants , the heat rate on natural gas was 2-3
percent above the construction contract performance guarantees while combustion
turbine NOX emissions were higher than expected. At this time, Westinghouse has
developed a number of modifications to address the performance and emissions
problems of the 501F-DLN combustion turbine at the Early Plants. Westinghouse
implemented these modifications on the combustion turbines at the Early Plants
during late 1998 and conducted
B-17
<PAGE>
further tuning and performance re-testing by the end of 1998. One installation,
with four 501F-DLN Combined Cycle units, was commissioned prior to the Early
Plants and Westinghouse reports that it operated within expected emission
limits. The remaining six 501F-DLN installations have come on line in recent
years and Westinghouse reports that they operated within the expected emissions
limits.
Like the Facility, each of the two Colombian Plants is equipped to
burn only natural gas. During performance testing and early operation,
Westinghouse reports neither of the Colombian Plants has experienced the same
problems with heat rate and power output. These Colombian Plants have reportedly
met contract performance guarantees and NOX emission limits. Westinghouse
reports that the commissioning and early operation of the Colombian Plants shows
that the heat rate and power output problems experienced at the Early Plants did
not recur. Under the terms of the Construction Contract, the Contractor has
guaranteed that the NOX emissions from the power trains would not exceed 9 ppm.
In addition, given the expected NOX emissions at the outlet of the CTG, the SCR
technology expected to be utilized at the Facility can be capable, if properly
designed with adequate margin, of achieving the level of NOX reduction required
with NOX inlet levels consistent with NOX levels observed in currently operating
501F-DLN combustion turbines.
A summary of the combined stack emissions guarantees contained
within the Construction Contract is indicated in Table 2 below.
Table 2
Summary of Construction Contract Combined Stack Emissions Guarantees
<TABLE>
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Steam Injection Maximum Maximum None None
- ----------------------------------------------------------------------------------------------------
Duct Firing Maximum None None None
- ----------------------------------------------------------------------------------------------------
CTG Load CTG at Full CTG at Full CTG from 75% CTG from 50%
Load Load to 100% Load to 75% Load
- ----------------------------------------------------------------------------------------------------
Pollutants
- ----------------------------------------------------------------------------------------------------
Nitrogen Oxides ("NOX") 9.0 ppmvd 9.0 ppmvd 9.0 ppmvd 9.0 ppmvd
@ 15% O2 @ 15% O2 @ 15% O2 @ 15% O2
- ----------------------------------------------------------------------------------------------------
Carbon Monoxide ("CO") 30.3 ppmvd 30.3 ppmvd 30.3 ppmvd 200 ppmvd
- ----------------------------------------------------------------------------------------------------
Volatile Organic Compounds ("VOC") 9.3 ppmvd 9.3 ppmvd 9.3 ppmvd 20 ppmvd
- ----------------------------------------------------------------------------------------------------
Opacity 20% 20% 20% 20%
- ----------------------------------------------------------------------------------------------------
Ammonia ("NH4") Slip 20.0 ppmvd 20.0 ppmvd 20.0 ppmvd 20.0 ppmvd
- ----------------------------------------------------------------------------------------------------
</TABLE>
Blade Cracking Issues
The Westinghouse 501F-DLN combustion turbines at the Early Plants
have experienced power turbine blade cracking in two areas. In the first area,
the cracks were occurring at the roots of the first stage blades where the
rotating blades fit into the turbine shaft. Investigation showed that the blades
were fitted too tightly into the rotating shaft such that during start-up, the
blades were thermally expanding faster than the shaft itself. Westinghouse
machined more space between the blades to allow for adequate differential
expansion between the relatively hotter blades and the relatively cooler shaft.
This work has been completed and there is no sign of additional problems in this
regard. Westinghouse is continuing to monitor the issue by means of frequent
boroscope inspections. Blade cracking has the potential to affect plant
operation.
While the blade root cracking problem appears to have been resolved,
boroscope inspections have recently revealed new blade cracking in a different
area on the power turbine blades. Westinghouse has investigated the problem and
found that the new cracks are not in a critical, highly stressed area of the
blades. Westinghouse does not consider these cracks to be a threat to the
integrity of the machines at this time; however, Westinghouse is continuing to
monitor the cracks for further growth and may take further action if deemed
necessary to assure that summer availability goals will be achieved.
Should these problems occur on the Facility, the Construction
Contract contains warranty provisions requiring the Contractor to correct them.
In addition, the number of 501F-DLN units planned to be
B-18
<PAGE>
commissioned prior to the commissioning of the Facility suggests that
Westinghouse has sufficient time to identify and correct such problems, should
they occur, before the commissioning of the Facility.
Based on the foregoing, we believe that the technology risk at the
Facility is mitigated by: (1) the fact that the 501F-DLN at the Facility is a
single fuel, rather than a dual fuel design; (2) Westinghouse's ability to make
on-going adjustments and design refinements to the 501F-DLN based on the
experience at other facilities scheduled to reach commissioning prior to the
completion of the Facility; and (3) the capability of a properly designed SCR
system to maintain Facility NOX emissions at or below allowed levels while
accommodating CTG outlet NOX emissions levels that are comparable to facilities
which have experienced the emissions problems described herein.
Heat Rate
The Construction Contract Unit Heat Rate guarantee is stated on a
gross reading at the high side of the generator step-up transformer basis,
rather than on a "net plant" basis, and is 6,769 Btu/kWh higher heating value
("HHV") at 95(Degree)F, 60 percent relative humidity, 14.577 psia, and 0.90
generator power factor. This gross heat rate is guaranteed for the unfired,
non-power augmented case. No gross or net heat rate guarantee for the
supplementary-fired, power augmented case was required by the Construction
Contract.
There is a fixed commercial tolerance, or deadband, of plus or minus
1.25 percent on the Construction Contract heat rate guarantee. Accounting for
the potential impact of the 1.25 percent tolerance and adjusting for the
guaranteed auxiliary load of 15,300 kW for the unfired, non-power augmented
condition, the equivalent net plant heat rate is 7,000 Btu/kWh HHV at
95(Degree)F.
The net plant heat rate for the supplemental fired, power augmented
condition, with adjustments for the maximum guaranteed auxiliary load of 18,900
kW and the commercial tolerance band is 7,397 Btu/kWh (HHV) at 95(degree)F.
Adjusting the equivalent net plant heat rate at 95(Degree)F for
recoverable/operational degradation (fouling), short-term test vs. long term
commercial operating conditions, non-recoverable equipment degradation, upside
tuning potential, average annual ambient conditions, and the expected dispatch
scenario developed by C. C. Pace, we have projected the levelized annual average
net plant heat rate to be approximately 7,050 Btu/kWh (HHV).
Summary
Based on our review, we are of the opinion that the proposed method
of design, construction, operation, and maintenance of the Facility has been
developed in accordance with generally acceptable industry practice and has
taken into consideration the current environmental, license and permit
requirements that the Facility must meet.
After consideration of the emissions and blade cracking issues
experienced with the two dual-fuel installations of the 501F-DLN type of
combustion turbine being installed at the Facility as described herein, and the
effect that single-fuel firing, higher allowable NOX emission limits, and the
other mitigating factors described herein have on these emissions and blade
cracking issues, we are of the opinion that the combined-cycle technology
proposed for the Facility is a sound, proven method of energy generation and
recovery.
Based on our review, we are of the opinion that if designed,
constructed, operated, and maintained as currently proposed by the Partnership,
the Contractor, and the Operator, the Facility should be capable of passing the
Acceptance Tests pursuant to the Construction Contract and satisfying the
current environmental, license, and permit requirements which the Facility must
meet.
Based on our review, we are of the opinion that if designed,
constructed, operated and maintained as currently proposed and dispatched as
projected by C. C. Pace, the Facility should be capable of achieving an average
annual output of 806,100 kW and an average annual net plant heat rate of 7,050
Btu/kWh (HHV).
B-19
<PAGE>
Reliability and Availability
For the purposes of estimating energy delivered by the Facility,
plant availability was projected on an average annual basis based on indices as
defined by the North American Electric Reliability Council ("NERC"), modified as
necessary to conform to the Power Purchase Agreements. Our opinions regarding
average annual outage rates and availability factors are based on the assumption
that all annual scheduled maintenance outages will be scheduled and performed
during the Off-Peak periods, as required by the Power Purchase Agreements.
We have assembled statistical information on the historical
availability of combined-cycle plants and have researched a variety of published
reports and studies regarding gas turbine plant availability by vendors,
operators and engineering firms and commercially available databases, such as
those published by the NERC and Strategic Power Systems. The data we have
reviewed represents the experience of both utility and non-utility owned
facilities, aeroderivative and heavy-duty industrial frame-type gas turbine
plants. Our review of the data indicates that non-utility owned combined-cycle
plants in full dispatch service on average achieve annual availabilities,
calculated using generally accepted methods, which include the allowance for
scheduled and forced outages in the range of 88 percent to 96 percent, with the
average being 92 percent.
Under the terms of the Power Purchase Agreements, the Facility is
allowed specified amounts of forced outage hours. If these forced outage
allowances are exceeded, reservation payments will be reduced. Under the terms
of the Virginia Power Purchase Agreement, capacity payments are reduced if the
equivalent forced outage hours exceed 369 hours through May 31, 2001 and 245
hours per year thereafter. This is equivalent to a forced outage rate of 2.8
percent, which is also equivalent to a contract availability of 97.2 percent.
Under the terms of the Aquila/UtiliCorp Power Purchase Agreement, capacity
payments are reduced in the event that the annual contract availability, which
excludes forced outages, is less than 97 percent. The Power Purchase Agreements
contain notice provisions which can, in some circumstances, allow the
Partnership to effectively take deferrable forced outages as scheduled outages.
In addition, the Partnership is allowed to purchase replacement power to avoid
being charged for a forced outage hour. Based on this flexibility allowed by the
Power Purchase Agreements, we believe that the Facility should be capable of
achieving a forced outage rate of 2.8 percent per year.
Based on our review, we are of the opinion that the Facility should
be capable of achieving a contract availability under the Power Purchase
Agreements with Virginia Power and Aquila/UtiliCorp required to avoid reductions
in the reservation payments under those agreements.
The stipulated average availability factors represent the projected
average availabilities expected of the Facility over the term of the Bonds.
There may be years when the actual availability factors are above or below the
average availability factors stipulated herein. However, for the purpose of the
Projected Operating Results, we have utilized this average annual availability
factor.
Estimated Useful Life of Facility
Based on our review, we are of the opinion that assuming: (1) the
Facility is designed, constructed, operated, and maintained as proposed by the
Partnership, the Contractor, and the Operator; (2) all equipment is operated in
accordance with manufacturers' recommendations; (3) all required repairs,
refurbishments 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, then the Facility will have a useful life extending beyond
the term of the Bonds.
Construction Status and Schedule
The Contractor commenced mobilization at the Site in October 1998.
The Contractor has provided summary and look ahead schedules as of March 31,
1999. As of that date, the Contractor reported focusing on engineering, design,
procurement, planning/scheduling and construction activities. As of the end of
March, engineering is reported to be approximately 59 percent complete with
procurement approximately 70 percent complete, based on the value of equipment
purchased, and construction is 7 percent complete. Overall the Project is
reported to be approximately 62 percent complete. Construction staffing is
increasing and as of March 31, the Contractor reports 221 were working at the
Site. The Contractor's schedule is based on working five ten-hour days a week
with spot overtime and makeup time as required to meet the schedule.
Construction work currently is concentrated on underground piping and electrical
conduit, and preparation of foundations. In March, the first
B-20
<PAGE>
sections of the Unit 1 HRSG were delivered to the Site and erection commenced.
CTGs are currently scheduled to commence shipment on June 15, 1999 and STGs on
August 16, 1999. On April 28, 1999, the Contractor submitted a Force Majeure
Event Notification to the Partnership because of a strike that began on April
26, 1999 at the Westinghouse manufacturing facility, which is manufacturing the
generators for the combustion turbines. The Partnership reports that
Westinghouse has verbally informed them that the strike has been settled in a
manner that should not adversely impact its schedule for completing the
generators for the Facility.
The Contractor has guaranteed completion by July 16, 2000 for Unit
1, July 26, 2000 for Unit 2 and July 31, 2000 for Unit 3. The Contractor's
schedule is based on a target completion date that is earlier than the
contractually guaranteed completion date. The schedule provides the Contractor's
planned completion of the Project based on the Target Operation of the Unit 1 on
March 16, 2000, the Target Operation of Unit 2 on April 1, 2000 and the Target
Operation of Unit 3 on May 1, 2000. The early completion bonus provisions of the
Construction Contract provide the Contractor financial incentive to attempt to
achieve early completion.
The Partnership is responsible for completion of the Infrastructure
Work such that it supports the planned completion and start-up of the Facility
by the Contractor per Exhibit R, Owner's Obligations, to the Construction
Contract. The Partnership is responsible for prosecution of the infrastructure
utility work required by the Project. This work includes the supply of potable
water and connection of the site sanitary sewer system to the City of Batesville
systems; installation of the raw water supply system from Enid Lake to the Site;
installation of the waste-water discharge pipeline; installation of a natural
gas lateral pipeline interconnecting the Facility to two interstate natural gas
pipelines; and finally, installation of the electrical interconnection systems
required to connect the Facility to two electrical transmission grid systems
(collectively, the "Infrastructure Work").
The infrastructure contracts for which the Partnership is
responsible have all been executed. The water supply and wastewater pipelines
are being laid and are scheduled to be completed by July 17, 1999. The water
intake structure at Lake Enid is expected to be completed by October 31, 1999.
Completion of the water intake by October 31, 1999 does not meet the
Partnership's obligation to the Contractor to have raw water supply available
for the demineralizer system to be placed in service by September 22, 1999. The
Contractor has expressed its willingness to accept potable water instead. The
Partnership is currently planning to increase the size of the potable water line
to the Facility to provide the flow rate required.
The fuel gas pipeline contractor has ordered pipe and is scheduled
to mobilize in May 1999, is scheduled for initial operation by September 23,
1999, and to be completed by October 15, 1999. The electrical contractor
constructing the electrical substation/interconnection facilities has mobilized
at the Site and is scheduled to be completed on December 1, 1999. TVA and
Entergy are scheduled to have their system upgrades and interconnections
completed by November 19, 1999 and December 20, 1999, respectively.
Neither the substation/interconnection facilities nor the TVA and
Entergy upgrades and interconnections are scheduled to be completed in time to
energize the step-up transformers and supply backfeed power to the Facility by
September 1, 1999 as required by the Construction Contract. The Partnership is
therefore arranging to have TVA provide a temporary 161 kV power supply to one
of the Facility's auxiliary transformers from the TVA Oxford transmission line.
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 hazardous materials or waste not previously
known or other abnormal events that are prejudicial to normal construction or
installation, and although the construction contracts that the Partnership has
entered into for the electrical substation, transmission lines, and water
infrastructure do not provide for the facilities to be completed by the dates by
which the Contractor needs electrical backfeed and water in order to conduct
certain tests, we are of the opinion that commercial operation of the Facility
by June 1, 2000 is achievable and within the previously demonstrated
capabilities of the Contractor and the Partnership using generally accepted
construction and project management practices. It should be noted that the
Partnership will not receive any liquidated damages for delays until the day
following the guaranteed completion dates under the Construction Contract.
If Substantial Completion of a unit has not occurred on or prior to
the unit's Guaranteed Completion Date, then liquidated damages (a) in an amount
of $43,333 per unit per day in the months of May
B-21
<PAGE>
through September and (b) in an amount of $33,333 per unit in the months of
October through April, shall be paid by the Contractor to the Partnership.
In the event Substantial Completion of three units occurs prior to
the Guaranteed Completion Date, then $50,000 per day shall be paid by the
Partnership to the Contractor, but not to exceed $3,000,000.
Performance Guarantees and Acceptance Tests
Performance Guarantees
Under the terms of the Construction Contract, the Contractor
guarantees the thermodynamic performance of the Facility with respect to: (1)
gross electrical power output per unit with duct firing and power augmentation
in service ("Maximum Unit Power Output"); (2) gross electrical power output per
unit without duct firing and power augmentation in service ("Unit Power
Output"); (3) gross plant heat rate without duct firing and power augmentation
in service ("Unit Heat Rate"), (4) total auxiliary power load for all three
units with duct firing and power augmentation in service ("Maximum Auxiliary
Load"); and (5) total auxiliary power load for all three units without duct
firing and power augmentation in service ("Auxiliary Load"). These performance
guarantees and the conditions under which they are guaranteed, are summarized in
Table 3 below:
Table 3
Performance Guarantees
Maximum Unit Power Output (fired) 285,400 kW (gross, per unit)
Unit Power Output (unfired) 248,290 kW (gross, per unit)
Unit Heat Rate (unfired) 6,769 Btu/kWh HHV (gross)
Maximum Auxiliary Load (fired) 18,890 kW (total 3 units)
Auxiliary Load (unfired) 15,300 kW (total 3 units)
Ambient Dry Bulb Temperature 95(degree)F
Relative Humidity 60 Percent
Barometric Pressure 14.577 psia
Fuel Natural Gas (per spec.)
Generator Power Factor 0.90 lagging
Evaporative Cooler(s) In Service
HRSG Blowdown 0% (isolated)
Emissions Compliance Per CEMS or alternate
The Maximum Unit Power Output and the Unit Power Output guarantees
are subject to fixed commercial tolerances of 0.75 percent. The Unit Heat Rate
guarantee is subject to a fixed commercial tolerance of 1.25 percent. The
Contractor is also entitled to degradation credits after more than 400 CTG fired
hours or 250 equivalent starts at the time of initial testing. CTG degradation
credits are capped at 2.5 Percent for CTG gross power. CTG heat rate degradation
credits are to be two-thirds of the percentage calculated for power.
We have received and reviewed heat balance data and preliminary
major equipment performance data from the Contractor. We have not reviewed
performance information covering all individual equipment components and piping
systems, however, the performance levels represented in the heat balance data
sheets were generally found to be within the ranges we have seen specified or
demonstrated on comparable equipment of similar size and type. The heat balances
data and equipment data reviewed, while preliminary and subject to modification,
appear to support the overall plant thermodynamic performance guarantees stated
above.
Additional plant and equipment guarantees related to initial
reliability, long-term dispatch availability, stack emissions, sound level,
start-up durations, and various plant equipment capabilities are included in the
Construction Contract and are discussed below under the applicable Acceptance
Tests.
Acceptance Tests
In order to demonstrate that the Facility meets or exceeds the
Performance Guarantees, the Construction Contract requires the Contractor to
successfully complete certain performance, reliability, emissions,
B-22
<PAGE>
and demonstration-type tests (collectively, the "Acceptance Tests"). The
Acceptance Tests are required to be conducted and passed, at Performance
Minimums where applicable, as a requirement of Substantial Completion, except as
otherwise noted below.
The Performance Minimums are defined as follows: Maximum Unit Power
Output Test, 94.25 percent of guarantee; Unit Power Output Test, 96.25 percent
of guarantee; and Unit Heat Rate Test, 104.25 percent of guarantee. Performance
Minimums are calculated without the benefit of commercial tolerances.
The Acceptance Tests include the following:
o Maximum Unit Power Output Test - 4 continuous hours within an
8-hour period
o Unit Power Output Test - 4 continuous hours within an 8-hour
period
o Unit Heat Rate Test - 4 continuous hours within an 8-hour
period
o Maximum Auxiliary Load Test - 4 continuous hours within an
8-hour period
o Auxiliary Load Test - 4 continuous hours within an 8-hour
period
o Reliability Test - 96-hour test with duct firing and power
augmentation with 99 percent Equivalent Availability Factor
for 88 hours, 70 percent unfired output minimum, and no
trips allowed
o Availability Test - rolling 480-hour test with 95 percent
Availability Factor (required for Final Completion only)
o Stack Emissions Test - emissions per contract (required for
Final Completion only)
o Sound Level Test - sound levels per contract (required for
Final Completion only)
o Cold Start-up Duration Test - 210 minutes maximum
o Hot Start-up Duration Test - 130 minutes maximum
o Cooling Tower
o Test Capability Tests (see below)
o CTG Benchmark Test
Capability Tests include the following Substantial Completion
Capability Tests; the Ramp Rate Test and the Minimum Load Operation. Capability
Tests also include the following Final Completion Capability Tests; Duct Burner
Capacity Test, Water/Steam Purity Test, Steam Turbine Bypass Test, Facility
Backup Power Transfer Test, Boiler Feed Pump Trip Test, Wastewater Discharge
Test, Demineralizer Capacity Demonstration Test, and Power Factor Test.
Utility Tests described in the Power Purchase Agreements are not
currently included in the scope of the Construction Contract and will need to be
conducted by the Partnership.
Various liquidated damages are available under the Construction
Contract. The liquidated damage calculations include allowances for commercial
tolerance bands. The tolerances are 0.75 percent with respect to Unit Power
Output and Maximum Unit Power Output, and 1.25 percent with respect to Unit Heat
Rate and are based on assumed accuracies, or uncertainty. Both tolerance
allowances are subject to adjustment if the actual accuracy of either the
Partnership's electrical meter or the fuel supply meter is such that the
uncertainty of either is higher than assumed. The various liquidated damages are
as follows:
(1) If the Unit Power Output is below guaranteed output, the
Contractor shall pay $800 per kW of shortfall.
(2) If the Maximum Unit Power Output exceeds the guaranteed
output, the Partnership shall pay $400 per kW of excess.
(3) If the Unit Heat Rate is greater than guaranteed, the
Contractor shall pay $67,200 per Btu/kWh.
(4) If the Auxiliary Load is greater than guaranteed, the
Contractor shall pay $800 per kW.
If the Auxiliary Load is less than guaranteed, the Partnership
shall pay $800 per kW plus $200 per kW times the difference
between the adjusted auxiliary load kW credit minus the
facility power shortfall.
B-23
<PAGE>
If the auxiliary load heat rate is greater than guaranteed,
the Contractor shall pay $201,600 per Btu/kWh times the
auxiliary load exceedance. If the auxiliary load heat rate is
less than guaranteed, the Partnership shall pay $201,600 per
Btu/kWh times the lesser if the auxiliary load heat rate
credit and the facility heat rate exceedance.
(5) If the Maximum Auxiliary Load is greater than guaranteed, the
Contractor shall pay $400 per kW. If the Maximum Auxiliary
Load is less than guaranteed, the Partnership shall pay $400
per kW times the lesser of the Maximum Auxiliary Load kW
credit and the Maximum Unit Output shortfall.
(6) If the cooling tower performance is poorer than guaranteed,
the Contractor shall pay $800 per kW by which amount the Unit
Power Output is less; and shall pay $67,200 per Btu/kWh by
which the Unit Heat Rate exceeds the Unit Heat Rate guarantee;
and shall pay $400 per kW by which amount the Maximum Unit
Power Output is less than guaranteed.
The aggregate of schedule and performance bonuses the Contractor may
earn shall not exceed $5,000,000. The aggregate of Contractor liquidated damages
liability shall not exceed 30 percent of the Construction Contract price.
Based on our review, we are of the opinion that the scope and
duration of the Acceptance Tests included in the Construction Contract are
similar to the tests of other projects with which we are familiar and should be
adequate to verify the guarantees in accordance with the Construction Contract.
Status of Permits and Approvals
The Facility must be designed, constructed, and operated in
accordance with applicable environmental laws, regulations, policies, codes and
standards. Based on 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 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.
The status of the key permits and approvals required for
construction and operation of the Facility is presented in Table 4, which is
based on our review of documents including permit applications, permits
received, and related agency correspondence provided by the Partnership.
B-24
<PAGE>
The DEQ co-issued both a Prevention of Significant Deterioration
Permit To Construct ("PSD Permit") and an Air Permit To Operate ("Air Permit")
on November 25, 1997. The permits were modified on July 14, 1998. The permits
limit oil firing to 876 hours per year (i.e., 10 percent maximum annual use),
which allows the Facility to be defined a "Gas-Fired Unit" under applicable
federal regulations.
On July 14, 1998, the DEQ modified both the PSD Permit and Air
Permit to incorporate a change in project design as requested by the Partnership
on July 13, 1998. These permit modifications included changing the CTGs to
Westinghouse Model 501-F units with a corresponding decrease in unit electric
output to 185,000 kW and increasing the supplemental duct firing fuel input rate
of the HRSGs to 268.0 MMBtu/hr. No other Permit changes appear to have been
made.
Table 4
Status of Key Permits and Approvals
<TABLE>
<CAPTION>
====================================================================================================================================
TYPE OF
AGENCY PERMIT ACTION REASON FOR ACTION STATUS
- ------------------------------------------------------------------------------------------------------------------------------------
FEDERAL/STATE
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
FERC Exempt Wholesale FERC Required for status as an exempt wholesale Notice in Federal Register 63
Generator Status Certification generator of electricity pursuant to the FR 16, 489
Public Utilities Holding Company Act Authorized by FERC: April 28,
1998
Docket # EG98-59-000
- ------------------------------------------------------------------------------------------------------------------------------------
Department of Certification Self-Certification Required for energy facilities that will Self-Certification submitted to
Energy Alternate Fuel burn fossil fuels other than coal. DOE on March 19, 1998
Capability Compliance with Industrial Fuel Use Act
- ------------------------------------------------------------------------------------------------------------------------------------
EPA & DEQ NPDES - runoff Notice of Required for runoff control from the Received October 23, 1998
during Intent under site(s) during construction
construction General Permit
Program
- ------------------------------------------------------------------------------------------------------------------------------------
EPA & DEQ PSD Permit to Permit Required for the construction of an air PSD Permit # 2100-00054
Construct emissions source under Prevention of Issued: November 25, 1997;
Significant Deterioration Program of the Modified: July 14, 1998
Clean Air Act
- ------------------------------------------------------------------------------------------------------------------------------------
EPA & DEQ Air Permit to Permit Required for the operation of an air PSD Permit # 2100-00054
Operate emissions source under Prevention of Issued: November 25, 1997;
Significant Deterioration of the Clean Air Modified: July 14, 1998
Act and the Mississippi Air and Water
Pollution Control Law
- ------------------------------------------------------------------------------------------------------------------------------------
DEQ Title V - Permit Permit Required for the air emission source To be obtained by the
to Operate Partnership; application must
be submitted within 12 months
of commencing operation
- ------------------------------------------------------------------------------------------------------------------------------------
DEQ Title IV - Acid Permit Required for the air emission source prior To be obtained by the
Rain Permit to start of operations Partnership; application was
submitted on June 2, 1998. The
DEQ indicates separate issuance
by end of 1998 and then to be
rolled up into Title V Permit
when issued
- ------------------------------------------------------------------------------------------------------------------------------------
EPA Spill Prevention Self-Certification Required for Oil Pollution Prevention To be prepared by the
Control and Regulations (40 CFR 112) for facilities Partnership within six months
Countermeasure meeting certain requirements, including after start of operations
Plan oil storage in electrical transformers
- ------------------------------------------------------------------------------------------------------------------------------------
EPA Hazardous Waste Registration Required if hazardous wastes are to be To be obtained, if required by
Identification generated or stored at the site the Partnership
Number
- ------------------------------------------------------------------------------------------------------------------------------------
Department of Nationwide Permit Required for construction of intake Nationwide Permits #7, 12, 14,
the Army Permits and structure, water supply and discharge 25 & 26 General Permit # 22,
General Permit pipeline, outfall pipe(s), access road(s), Authorization #144 Issued:
tower footing(s), and fill in waterways December 4, 1997
areas
- ------------------------------------------------------------------------------------------------------------------------------------
Department of Permit for Gas Permit(s) Required for construction of gas pipeline Nationwide Permit #12
the Army Transmission Line
- ------------------------------------------------------------------------------------------------------------------------------------
Federal Notice of Permit Required for construction of exhaust Notified by the Partnership on
Aviation Proposed stack, the three electric transmission May 12, 1998
Administration Construction lines, and temporary construction cranes
- ------------------------------------------------------------------------------------------------------------------------------------
DEQ Water Use Permit Permit Required to divert or withdraw water for Permit # MS-SW-02744
the Facility from public waters, Issued: November 25, 1997;
specifically Enid Lake Expires: November 25, 2007
Limited to 12,300 acre-feet per
year and 7,600 gallons per
minute
- ------------------------------------------------------------------------------------------------------------------------------------
Public Service Order Granting Docket Order Required to authorize the Partnership to Docket No. 97-UA-513
Commission Certificate of acquire, install, construct, own, operate, Ordered: December 12, 1997;
Public and maintain certain electric generation No expiration
Convenience and equipment
Necessity
- ------------------------------------------------------------------------------------------------------------------------------------
LOCAL
- ------------------------------------------------------------------------------------------------------------------------------------
City of Zoning Approval Approval Required for construction and operation of Issued: April 24, 1997
Batesville Facility in a Heavy Industrial Zone
- ------------------------------------------------------------------------------------------------------------------------------------
Local Building Building Permit Permit Required for compliance with local Permit number
Department building codes and standards issued September 9, 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Local Building Certificate of Certificate Required to demonstrate project completion To be obtained by the
Department Occupancy Contractor at project
completion
- ------------------------------------------------------------------------------------------------------------------------------------
Local Fire Safety Approval Approval Required to demonstrate compliance with To be obtained by the
Marshall fire safety regulations Contractor
====================================================================================================================================
</TABLE>
B-25
<PAGE>
THE FINANCING OF THE PROJECT
Facility Construction Cost
The Construction Contract includes a fixed price, including change
orders, of approximately $239,967 (the "Construction Contract Price"). The
Contractor's estimates which serve as the basis of the Construction Contract
Price are based on the requirements as stated in the Partnership's request for a
proposal, design drawings, site plans and general arrangement drawings, quotes
obtained from manufacturers, suppliers, vendors and subcontractors with whom the
Contractor is familiar and from in-house knowledge and experience gained by the
Contractor on other similar projects.
The Partnership has estimated other construction costs of
$71,345,000 (the "Other Construction Costs"), which are based on the aggregate
of $5,273,000 for start-up and spare parts, $2,466,000 for contractor's fee,
$1,987,000 for construction management, $27,669,000 for
infrastructure-gas/water/electrical system costs, $21,859,000 for electrical
interconnection costs, $1,442,000 for land and easements costs, and $10,649,000
for project contingency (the "Project Contingency"). The Project Contingency
equates to approximately 5.8 percent of the aggregate of the expected balance of
the Construction Contract Price of $144,281,000, $24,703,000 for gas, water, and
electrical infrastructure work, and the Partnership's estimate of $15,458,000
for electrical interconnection costs. The Project Contingency is consistent with
other projects at a similar stage of completion with which we are familiar. The
aggregate of the Other Construction Costs of $71,345,000 and the Construction
Contract Price of $239,967,000 is $311,312,000 (the "Total Construction Cost").
Table 6
Total Construction Costs
($000)
Total(1) Remaining
-------- ---------
Construction Contract Price $239,967 $144,281
Other Construction Costs
Start-up and Spare Parts 5,273 5,273
Contractor's Fee 2,466 1,944
Construction Management 1,987 1,419
Infrastructure - Gas/Water/Electrical 27,669 24,703
Electrical Interconnection 21,859 15,458
Land and Easements 1,442 0
Project Contingency 10,649 10,649
-------- --------
Subtotal - Other Construction Costs 71,345 59,446
Total Construction Cost $311,312 $203,727
(1) - Total cost of construction from Notice-to-Proceed, as
estimated by the Partnership.
B-26
<PAGE>
Based on our review, we are of the opinion that the estimates which
serve as the basis for the Construction Contract Price and the Total
Construction Cost were prepared in accordance with generally accepted
engineering and estimating practices and methods. The Construction Contract
Price and the Total Construction Cost, including the Project Contingency, are
comparable to the costs and contingency of similar projects at a similar stage
of completion and 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, as estimated by the Partnership, are set forth in
Table 7.
Table 7
Estimated Sources and Uses of Funds (1)
($000)
Sources of Funds
The Bonds $326,000
Partner Equity Contributions 54,000
--------
Total Sources of Funds $380,000
========
Uses of Funds
Term and Construction Loan Payment $136,600
Remaining Construction Cost 203,727
Financing and Development Fees 5,392
Debt Service Reserve 12,551
Net Interest During Construction 21,730
--------
Total Uses of Funds $380,000
========
(1) - As estimated by the Partnership.
Based upon the interest and reinvestment rates as estimated by
Credit Suisse First Boston (the "Initial Purchasers") and the total uses of
funds as estimated by the Partnership, we are of the opinion that the principal
amount of the Bonds, when combined with the $54,000,000 of equity that the
Partnership expects will be contributed by its parent and interest income during
the construction period, should be sufficient to fund the Total Construction
Cost and interest on the Bonds through June 1, 2000.
PROJECTED OPERATING RESULTS
We have reviewed estimates and projections of electrical generating
capacity, fuel consumption, and capital and operating costs of the Facility made
available to us by the Partnership and the Operator. On the basis of our review
of such data, we have prepared the Project Operating Results. For purposes of
preparing the Projected Operating Results we have assumed that the Facility will
be fully operational by June 1, 2000. The Projected Operating Results are
presented herein for each year ending December 31, beginning June 1, 2000
through July 1, 2025, the date upon which the final deposit to the Trustee is
due on the Bonds. Revenues will be derived from the sale of electricity from the
three generating units, which comprise the Facility. The electric output of one
of the generating units is dedicated to Aquila/UtiliCorp and the output of the
other two generating units is dedicated to Virginia Power pursuant to the Power
Purchase Agreements. At the termination of each of the Power Purchase
Agreements, revenues will be derived from the sale of power from the units to
the market over the remaining term of the Bonds. Revenues will also be derived
to a lesser extent, from the interest income on certain funds created pursuant
to the Bonds. Expenses will consist of the cost of fuel based on a unit fuel
cost estimated by C.C. Pace, operations and maintenance expenses, property
taxes, replacement power, general and administrative expenses, as estimated by
the Partnership and debt service on the Bonds, as estimated by the Initial
Purchasers. The Projected Operating Results are set forth in Exhibits B-1 to
B-10. 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.
B-27
<PAGE>
Annual Operating Revenues
Revenues from the Sale of Electricity to Virginia Power
Commencing with the commercial operation date, scheduled for June 1,
2000, the Partnership shall receive from Virginia Power monthly reservation,
energy, replacement power fuel, excess start-up, tracking account, and
transmission system upgrade credit payments. The initial term of the Virginia
Power Purchase Agreement is 13 years from the commercial operation date.
The term of the Virginia Power Purchase Agreement may be extended
for an additional 12 years (the "Extended Term"), provided that Virginia Power
requests in writing an extension of the Virginia Power Purchase Agreement not
less than two years prior to expiration of the initial 13-year term. For
purposes of the Base Case Projected Operating Results, it has been assumed that
Virginia Power will choose the Extended Term because the projected market prices
are higher than Virginia Power's cost under the Virginia Power Purchase
Agreement.
Reservation Payment
Reservation payments are based on Summer Condition Standard Capacity
and Summer Condition Supplemental Capacity for the dedicated Virginia Power
units. The Summer Condition Standard Capacity and Summer Condition Supplemental
Capacity will be based on performance tests performed in each 12-month period
after commercial operation. Summer Condition Standard Capacity will be measured
as the generating capacity of the unit at full combustion turbine output without
duct firing or steam injection at 95(Degree)F and 60 percent relative humidity.
Summer Condition Supplemental Capacity will be measured as the additional
generating capacity derived from duct firing and steam injection. In no event
can the sum of the Summer Condition Standard Capacity and the Summer Condition
Supplemental Capacity be greater than 283 MW or less than 241 MW. The
reservation charge is $5.00 per kW-month for Summer Condition Standard Capacity
for the first 5 years following commercial operation, $6.00 per kW-month for the
next 8 years and $4.50 per kW-month for the 12-year extension term. The
reservation charge is $3.25 per kW-month for Summer Condition Supplemental
Capacity for the first five years, $3.50 per kW-month for the next eight years,
and $3.00 per kW-month for the 12-year extension term. The capacity charge is
the product of the Summer Condition Capacity and the appropriate reservation
charge. The reservation payment is determined by multiplying the sum of the
Summer Condition Standard Capacity charge and the Summer Condition Supplemental
Capacity Charge by the Availability Adjustment Factor. Pursuant to the Virginia
Power Purchase Agreement, the Availability Adjustment Factor is equal to 1.0 in
the event that the Facility's equivalent forced outage hours are less than 369
in the first twelve months and 245 hours per year thereafter. The Availability
Adjustment Factor is equivalent to the ratio of 8,760 hours less the equivalent
forced outage hours divided by 8,760 hours less the allowance for forced outage
hours. If the annual equivalent forced outage hours exceed 1,752 hours or 2,628
hours, the amount by which equivalent forced outage hours exceed these levels
are increased by 25 percent and 40 percent, respectively, thereby creating a
further Availability Adjustment Factor penalty.
For the purpose of estimating the capacity for the reservation
payment under the Virginia Power Purchase Agreement, we have assumed: (1) a
Summer Condition Standard Capacity and Summer Condition Supplemental Capacity,
after allowing for degradation and expected actual operation condition, of
473,000 kW and 69,800 kW, respectively; (2) an Availability Adjustment Factor of
1.0, based on an annual contract availability, which excludes scheduled
maintenance, of 95.8 percent during the first twelve months and 97.2 percent
thereafter; and (3) Virginia Power will exercise its option to extend the
Virginia Power Purchase Agreement for the Extended Term.
The Energy Policy Act of 1992 (the "Act") fundamentally changed the
Federal regulation of the electric utility industry. The Act provides for, among
other matters, open access to transmission facilities for transactions involving
sales of electric energy for subsequent resale by a receiving entity, or
"wholesale sales". This is changing the level of control that a utility owning
transmission facilities has over its facilities and is changing the arrangements
between parties for transmission services. The authority for retail wheeling,
which allows a customer located in one utility's service area to obtain power
from another utility or non-utility source, is specifically excluded from the
enhanced authority granted to the FERC under the Act. This leaves authority for
retail wheeling with individual state legislative and regulatory bodies. Several
states are now receiving and considering requests to facilitate retail wheeling.
Federal legislation has also been introduced which, if passed, would extend
retail wheeling to all states. One potential effect of the proposed changes is
that utilities or electric service providers with low-cost
B-28
<PAGE>
power may be better able to compete for new customers and retain existing ones.
Future legislative and regulatory actions will likely continue to affect
developments related to both wholesale and retail wheeling. At this time we
cannot predict what impact changes in legislation, regulation or market
conditions will have on the ability or willingness of Virginia Power and
Aquila/UtiliCorp to pay the stipulated capacity costs contained in the Power
Purchase Agreements. Accordingly, we have therefore assumed that the capacity
pricing provisions contained in the Power Purchase Agreements will remain
effective throughout the term of the Power Purchase Agreements.
Energy Payment and Tracking Account
The energy payment is equal to the product of: (1) the sum of the
energy generated by the unit dedicated to Virginia Power and the energy supplied
as replacement power which is delivered to Virginia Power at the interconnection
point, and (2) $1.00 per MWh, escalated at a contractually fixed escalation rate
of 3.0 percent per year commencing on June 1, 2000.
The tracking account payment or credit is equal to the monthly
summation of the product of the hourly delivered cost of fuel and the hourly
difference determined by the actual amount of fuel required to produce the net
output delivered to Virginia Power less the fuel amount estimated to produce
such output based on the guaranteed heat rate under the Virginia Power Purchase
Agreement. Pursuant to the Virginia Power Purchase Agreement, the guaranteed
heat rate is a function of the hourly energy dispatched from the unit divided by
the Standard Capacity taking into account ambient conditions when the energy
dispatched in an hour is less than the Standard Capacity. The guaranteed heat
rate associated with energy dispatched above Standard Capacity is based on a
formula also set forth in the Virginia Power Purchase Agreement.
For purposes of estimating the energy payments from Virginia Power,
we have assumed: (1) an annual average net capacity of 537,400 kW; (2) capacity
factors as projected by C.C. Pace adjusted for our availability assumptions; (3)
a resulting guaranteed heat rate under the Virginia Power Purchase Agreement of
approximately 7,105 Btu/kWh over the period 2000-2025; (4) an actual Facility
heat rate of 7,050 Btu/kWh; and (5) an annual average delivered cost of fuel, as
estimated by C.C. Pace, of $2.30/MMBtu in 1998 dollars escalated at 0.5 percent
above the assumed general inflation rate. The guaranteed heat rate under the
Virginia Power Purchase Agreement was estimated based upon a net capacity at
95(Degree)F without augmentation of 473,000 kW and a supplemental capacity at
95(Degree)F due to augmentation of 69,800 kW, which have been adjusted for
assumed actual ambient conditions and dispatch of the Facility as projected by
C.C. Pace. The dispatch of the unit at various ambient conditions was based on
information from C.C. Pace.
Replacement Power Fuel Payment
The replacement power fuel payment is based on the product of the
delivered cost of fuel, the guaranteed heat rate, and the amount of energy
supplied as replacement power by the Partnership. The Partnership has the option
of having Virginia Power provide replacement power, or being penalized by the
availability adjustment factor. If replacement power is provided by Virginia
Power, the Partnership must pay Virginia Power the positive difference, if any
between replacement power cost and contract energy cost. For purposes of the
Projected Operating Results, no replacement power was assumed.
Excess Start-up Payment
The Facility will receive excess start-up payments for start-ups in
the event the number of start-ups for a unit exceeds 250 per contract year.
Virginia Power will pay the Partnership the amount of $5,000 for each excess
start-up. For the purposes of the Projected Operating Results, no excess
start-ups were assumed.
System Upgrade Credits
Based on the installation of the electrical infrastructure, the
Partnership will receive a system upgrade credit based on the amount of payment,
credit or discount received by Virginia Power under its transmission service
agreement with Entergy and TVA as described in the Interconnection Agreement
between TVA and the Partnership, and the Interconnection and Operating Agreement
between the Partnership and Entergy, and the Power Purchase Agreements. The
total amount is not to exceed two-thirds of the total reimbursable transmission
system upgrade cost, which is currently estimated by the Partnership to be
approximately $20,000,000. The annual system upgrade credit has been included
based on two-thirds of the total system upgrade credit estimate prepared by C.C.
Pace of $3,400,000 per year until the balance is repaid in the sixth year of
operation.
B-29
<PAGE>
Revenues from the Sale of Electricity to Aquila/UtiliCorp
Commencing with the commercial operation date, scheduled for June 1,
2000, the Partnership receives from Aquila/UtiliCorp monthly reservation,
energy, replacement power fuel, excess start-up, tracking account; and
transmission system upgrade credit payments. The initial term of the
Aquila/UtiliCorp Power Purchase Agreement is 15 years, 7 months from the
commercial operation date. The Aquila/UtiliCorp Power Purchase Agreement may be
extended an additional 5 years at Aquila/UtiliCorp's option, provided that
Aquila/UtiliCorp notifies the Partnership by the later of July 31, 2013 or
twenty-nine (29) months prior to the expiration of the initial term. For
purposes of Projected Operating Results, it was assumed that Aquila/UtiliCorp
would extend the term of the Aquila/UtiliCorp Power Purchase Agreement because
the projected market prices are higher than Aquila/UtiliCorp's cost under the
Aquila/UtiliCorp Power Purchase Agreement.
Reservation Payment
Reservation payments are based on Standard Capacity, Supplemental
Capacity and Surplus Supplemental Capacity. The Standard Capacity, Supplemental
Capacity and Surplus Supplemental Capacity will be based on performance tests
performed in each 12-month period after commercial operation. Standard Capacity
will be measured as the generating capacity of the unit at full combustion
turbine output without duct firing or steam injection at 95(Degree)F and 60
percent relative humidity. Supplemental Capacity will be measured as the
additional amount of capacity with duct firing and steam injection, up to
267,000 kW. Surplus Supplemental Capacity is equal to the total capacity above
267 MW at 95(Degree)F and 60 percent relative humidity. The reservation payment
is equal to $4.90 per kW-month for Standard Capacity and Supplemental Capacity
for the first 60 months following commercial operation, and $5.00 per kW-month
for the remainder of the initial term and extension period. The reservation
payment is $2.50 per kW-month for Surplus Supplemental Capacity for the initial
term and the extension period. The reservation payment is subject to a monthly
and annual adjustment for availability. Reservation payments are reduced if the
monthly availability excluding periods of force majeure and Delivery Excuse on a
cumulative weighted average is less than 96 percent, or if the annual
availability excluding periods of force majeure and Delivery Excuse is less than
97 percent. In the event that the availability is less than the contractual
requirements, the reservation payment is multiplied by an availability
adjustment factor equal to the ratio of the actual contract availability and the
appropriate monthly or annual availability criteria.
For the purpose of estimating the capacity for the reservation
payment under the Aquila/UtiliCorp Power Purchase Agreement, we have assumed:
(1) a Summer Condition Standard Capacity, Summer Condition Supplemental
Capacity, and Surplus Supplemental Capacity, after allowing for degradation and
expected actual operation condition, of 236,500 kW, 30,500 kW, and 4,400 kW,
respectively; (2) an annual availability adjustment factor of 1.0, based on an
annual contract availability, which excludes scheduled maintenance, of 97.2
percent; and (3) Aquila/UtiliCorp will exercise its option to extend the
Aquila/UtiliCorp Power Purchase Agreement.
Energy Payment and Tracking Account
The Energy Payment is equal to the product of: (1) the sum of the
energy generated by the unit and the energy supplied as replacement power which
is delivered to Aquila/UtiliCorp at the interconnection point, and (2) $1.00 per
MWh, escalated at the ratio of the current Gross Domestic Product Implicit Price
Deflator ("GDP-IPD") to the January 1, 1997 GDP-IDP of 110.95.
The tracking account payment or credit is equal to the monthly
summation of the product of the hourly delivered cost of fuel and the hourly
difference determined by the actual amount of fuel required to produce the net
output delivered to Aquila/UtiliCorp less the fuel amount estimated to produce
such output based on the heat rate guaranteed under the Aquila/UtiliCorp Power
Purchase Agreement. Pursuant to the Aquila/UtiliCorp Power Purchase Agreement,
the guaranteed heat rate is a function of the hourly energy dispatched from the
unit divided by the Standard Capacity taking into account ambient conditions
when the energy dispatched in an hour is less than the Standard Capacity. The
guaranteed heat rate associated with energy dispatched above Standard Capacity
is based on a formula also set forth in the Aquila/UtiliCorp Power Purchase
Agreement.
For purposes of estimating the energy payments from
Aquila/UtiliCorp, we have assumed: (1) an annual average net capacity 268,700
kW; (2) capacity factors as projected by C.C. Pace and adjusted for our
availability assumptions; (3) a resulting guaranteed heat rate under the
Aquila/UtiliCorp Power Purchase Agreement of approximately 7,040 Btu/kWh over
the period 2000-2020; (4) an actual Facility heat rate of 7,050 Btu/kWh; and
B-30
<PAGE>
(5) an annual average delivered cost of fuel, as estimated by C.C. Pace, of
$2.30/MMBtu in 1998 dollars escalated at 0.5 percent above the assumed general
inflation rate. The guaranteed heat rate under the Aquila/UtiliCorp Power
Purchase Agreement was estimated based upon a net capacity at 95(Degree)F
without augmentation of 236,500 kW and a supplemental capacity at 90(Degree)F
due to augmentation of 34,900 kW, which have been adjusted for assumed actual
ambient conditions and dispatch of the Facility as projected by C.C. Pace. The
dispatch of the unit at various ambient conditions was based on information from
C.C. Pace.
Replacement Power Fuel Payment
The replacement power fuel payment is based on the product of the
Delivered Cost of Fuel, the guaranteed heat rate, and the amount of energy
supplied as replacement power by the Partnership. During a forced outage the
Partnership has the option of providing replacement power or being penalized
through the availability adjustment factor. If replacement power is provided,
Aquila/UtiliCorp will pay the Partnership replacement power fuel payments in an
amount per MWh which is equal to the delivered cost of fuel times the guaranteed
heat rate. For purposes of the Projected Operating Results, no replacement power
was assumed.
Excess Start-up Payment
The Facility will receive excess start-up payments for start-ups in
the event the number of start-ups for a unit exceeds 200 per contract year.
Aquila/UtiliCorp will pay the Seller the amount of $5,000 for each excess
start-up. The payment will be made monthly as each additional excess start-up
occurs. For the purposes of the Projected Operating Results, no excess start-ups
were assumed.
System Upgrade Credits
Based on the installation of the electrical infrastructure, the
Partnership will receive a system upgrade credit based on the amount of payment,
credit or discount received by Aquila/UtiliCorp under its transmission service
agreement with Entergy and TVA as described in the Interconnection Agreement
between TVA and the Partnership, and the Interconnection and Operating Agreement
between the Partnership and Entergy, and the Power Purchase Agreements. The
total amount is not to exceed one-third of the total reimbursable transmission
system upgrade cost, which is currently estimated by the Partnership to be
approximately $20,000,000. The annual system upgrade credit has been included
based on one-third of the total system upgrade credit estimate prepared by C.C.
Pace of $3,400,000 per year until the balance is repaid in the sixth year of
operation.
Revenues from the Sale of Electricity to the Market
After the termination of the Power Purchase Agreements with
Aquila/UtiliCorp and Virginia Power which are assumed to be December 31, 2020
and May 31, 2025, respectively, the Partnership has projected that the available
output which would no longer be dedicated to the purchasers, will be sold to the
market at the forecasted market clearing price. For purposes of the Projected
Operating Results we have assumed the market clearing price forecast prepared by
C.C. Pace. The dispatch of the units in the market was based on capacity factors
also provided by C.C. Pace. The projected revenues are assumed to be the product
of the net output of the non-dedicated units at the assumed capacity factor
multiplied by the forecast average market-based revenues projected by C.C. Pace.
Interest Income
Pursuant to the Indenture, a debt service reserve fund will be
created for the Bonds (the "Debt Service Reserve Account"). We have included
interest income on the Debt Service Reserve Account at a rate, as estimated by
the Initial Purchasers, of 5.5 percent per year. The initial deposit to the Debt
Service Reserve Account is $12,551,000. The annual Debt Service Reserve Account
requirement is assumed to be equal to the next semi-annual debt service payment.
Any required additions to the Debt Service Reserve Account are to be made from
funds available after the payment of debt service. Interest income and excess
funds in the Debt Service Reserve Account are to be transferred to the Revenue
Account and will be available to pay debt service.
The Major Maintenance Reserve Account is to be funded through annual
deposits which were based on a schedule projected by the Partnership based on
the base case dispatch estimated by C.C. Pace. Deposits to the Major Maintenance
Reserve Account will be made after the payment of debt service on the Bonds. We
have
B-31
<PAGE>
included interest income on the Major Maintenance Reserve Account at a
reinvestment rate, as estimated by the Initial Purchasers, of 5.5 percent per
year. Interest income on the Major Maintenance Reserve Account has been assumed
to be retained in the Major Maintenance Reserve Account.
Annual Operating Expenses
Fuel Costs
We have reviewed the potential for the Facility to experience an
increase in net plant heat rate, therefore the potential for an increase in fuel
costs, over the term of the Bonds. The adjustment to the net plant heat rate, to
reflect average annual operations, part-load conditions, and ambient conditions
was assumed to be 4.2 percent above the guaranteed net plant heat rate at 95oF,
60 percent relative humidity. This adjustment reflected the assumed dispatch
estimated by C.C. Pace. Fuel prices were based on an assumed gas price of
$2.30/MMBtu in 1998, including transportation, and an assumed escalation of 0.5
percent above inflation as provided by C.C. Pace. During the term of the Power
Purchase Agreements, fuel will be provided and paid for by Aquila/UtiliCorp and
Virginia Power under a tolling arrangement. After the term of the Power Purchase
Agreements, the Partnership is assumed to procure and pay for fuel.
Operation and Maintenance
The Partnership's estimate of operating and maintenance expenses
includes provision for labor, repair and maintenance, including renewals and
replacements, utilities, and consumables. The Partnership has estimated that the
Operator will receive an annual fee of $500,000 in the first year of operation,
escalating at the rate of change in the GDP-IPD thereafter. Pursuant to the
Financing Documents and the O&M Agreement, the Operator's fee is subordinated to
all debt service and reserve fund obligations.
We have included deposits to the Major Maintenance Reserve Account
as required pursuant to the Financing Documents based on a schedule of deposits
projected by the Partnership based on the base case dispatch estimated by C.C.
Pace. The cost of overhauls which is to be funded from the Major Maintenance
Reserve Fund is based on information provided by the Partnership based on an
inflation rate of 2.6 percent. Based upon an assumed rate of inflation of 2.6
percent per year, the deposits to the Major Maintenance Reserve Account as shown
in the Projected Operating Results are estimated to be sufficient to fund the
projected major maintenance costs in all years.
Based on our review, we are of the opinion that the basis for the
Partnership's estimates of the cost of operating and maintaining the Facility,
including provision for major maintenance, is reasonable.
The Partnership has also estimated general and administrative
expenses, property taxes, insurance, site use fee, corps of engineers' fees,
lateral pipeline operations and maintenance, electrical transmission operations
and maintenance, backup power expenses, trustee and rating agency fees, and
other expenses, all of which are assumed to increase at the projected rate of
change in inflation of 2.6 percent per year, with the exception of Panola fees,
property taxes, corps of engineers' fees, trustee and rating agency fees, and
the site use fees, which were based on the estimates provided by the
Partnership. The Partnership's local counsel has stated that the first property
taxes are expected to be due in year 2002.
Annual Debt Service
Based on information provided by the Initial Purchasers, we have
included debt service payments based on the principal amount of the Bonds of
$326,000,000 at a weighted average interest rate of approximately 7.70 percent,
as reported by the Initial Purchasers. Semi-annual principal payments are due
each January 15 and July 15. Monthly deposits to the Trustee are assumed to be
made on the first of each month prior to the due dates. Interest is assumed to
be paid from the proceeds of the Bonds through the June 1, 2000 deposit. The
Indenture defines Debt Service to include Letter-of-Credit fees. The Initial
Purchasers have estimated the Letter-of-Credit fees to be $92,000 per year for
the first five years of operation and $64,000 per year thereafter.
Debt Service Coverage
The debt service coverage ratio has been calculated as the Cash
Available for Debt Service divided by the Debt Service (the "Debt Service
Coverage Ratio"). The Indenture defines Cash Available for Debt Service to
exclude the deposits to the Major Maintenance Reserve Account, although the
deposits to the Major Maintenance
B-32
<PAGE>
Reserve Account are subordinate to the payment of Debt Service. 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, which assumes the extension of the Virginia Power and the
Aquila/UtiliCorp Power Purchase Agreements, the projected revenues from the sale
of electricity are adequate to pay annual operating and maintenance expenses
(including deposits to the Major Maintenance Reserve Account), fuel expense, and
other operating expenses and to provide an annual Debt Service Coverage Ratio of
at least 1.42 in each year during the term of the Bonds and a weighted average
Debt Service Coverage Ratio of 1.63 over the term of the Bonds. The average
coverage has been calculated as the total net operating revenues divided by the
total Debt Service over the term of the Bonds. Annual Debt Service Coverage
Ratios 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 impacts
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: and (a) the Facility contract availability is
reduced by 5 percentage points from the Base Case; (b) the Facility heat rate is
5 percent higher than that assumed in the Base Case; (c) the Facility non-fuel
operating expenses are 10 percent higher than that assumed in the Base Case; (d)
the rate of general inflation is 4.0 percent per year, or 1.4 percent above the
Base Case assumption, which also increases the natural gas escalation rate to
4.5 percent per year, (e) the rate of general inflation is 6.0 percent per year,
or 3.4 percent above the Base Case assumption, which also increases the natural
gas escalation rate to 6.5 percent per year; (f) escalation for natural gas fuel
expense for the Facility increases to 1.0 percent above inflation while market
prices are assumed to remain the same as the Base Case; (g) average market
energy prices are equal to the Downside Case prepared by C.C. Pace; (h) average
market energy prices are equal to the Downside Case prepared by C.C. Pace and
the Power Purchase Agreements are not renewed; and (i) the Power Purchase
Agreements are not renewed. The sensitivity analyses are presented as Exhibits
B-2 through B-9 to this Report. In preparing these sensitivity analyses, we have
assumed that there would be no liquidated damage payments made by the Contractor
under the Construction Contract. For the purposes of sensitivity case (a), we
have not taken into consideration any potential reduction in major maintenance
costs resulting from lower levels of operation. For the purposes of sensitivity
cases (a) and (b), C.C. Pace has estimated that it is reasonable to assume that
the dispatch and market prices would not change from the Base Case. For the
purposes of sensitivity cases (d) and (e), the Initial Purchasers have estimated
that the reinvestment rate on the Debt Service Reserve Account and Major
Maintenance Reserve Account would be equal to 6.5 and 8.5 percent per year,
respectively. In addition, the Partnership has provided additional projections
of deposits to the Major Maintenance Reserve Account for sensitivity cases (d)
and (e).
Sensitivity case (h) includes a combination of certain other
sensitivity case assumptions. The particular combination is not intended to
present a combination of events that would cause the most significant impact to
the Facility, nor does it represent the only possible combinations of variables
that could simultaneously occur.
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
8.
B-33
<PAGE>
Table 8
Projected Debt Service Coverage
<TABLE>
<CAPTION>
Base Case Sensitivity Cases
--------- -----------------
A D C D E F G H I
No Renewal
of PPAs &
Year Increased Increased Increased Increased Reduced Reduced No
Ending Reduced Increased Operating Inflation Inflation Gas Market Market PPA
Dec 31 Availability Heat Rate Expenses (4%) (6%) Escalation Prices Prices Renewal
------ ------------ --------- -------- ---- ---- ---------- ------ ------ -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000 1.45 1.37 1.29 1.38 1.76 1.74 1.45 1.44 1.44 1.45
2001 1.43 1.36 1.31 1.40 1.41 1.38 1.43 1.42 1.42 1.43
2002 1.43 1.35 1.30 1.39 1.40 1.37 1.43 1.42 1.42 1.43
2003 1.43 1.35 1.30 1.39 1.40 1.37 1.43 1.42 1.42 1.43
2004 1.43 1.35 1.29 1.39 1.40 1.37 1.43 1.42 1.42 1.43
2005 1.42 1.34 1.29 1.38 1.39 1.36 1.42 1.41 1.41 1.42
2010 1.43 1.34 1.28 1.39 1.35 1.27 1.43 1.41 1.41 1.43
2015 1.50 1.39 1.27 1.43 1.41 1.24 1.50 1.47 2.97 3.40
2020 1.92 1.78 1.57 1.81 1.69 1.32 1.93 1.90 5.70 6.66
Minimum 1.42 1.33 1.24 1.36 1.35 1.24 1.42 1.41 1.41 1.42
Average 1.63 1.52 1.45 1.57 1.67 1.78 1.60 1.57 2.39 2.66
</TABLE>
Liquidated Damages Analyses
We have performed a series of analyses to estimate the impact on the
average debt service coverage ratio if the Facility 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 Contractor the total damages payment
will be used to redeem the principal of the Bonds on a pro rata basis. These
analyses have been performed to demonstrate the sufficiency of the performance
liquidated damages for the Maximum Unit Power Output, Unit Power Output, and
Unit Heat Rate to maintain debt service coverage at the level projected in the
Base Case Projected Operating Results. Under the terms of the Construction
Contract, the Facility must meet Performance Minimums equivalent to a deficiency
in Maximum Unit Power Output of 5.75 percent, in Unit Power Output of 3.75
percent, and in Unit Heat Rate of 4.25 percent. These analyses assume that: (1)
only one type of performance deficiency would occur at a time; (2) the
deficiency would exist in all units; and (3) that the maximum liquidated damages
of 30 percent of the Construction Contract Price would be available to pay the
damages associated with that deficiency.
Based on these analyses, we are of the opinion that, if the
Contractor pays the Partnership performance liquidated damages due to a failure
to achieve the Maximum Unit Power Output, Unit Power Output, or Unit Heat Rate,
then the weighted average Debt Service Coverage Ratio over the term of the Bonds
is projected to remain at the same level as in the Base Case Projected Operating
Results for a deficiency consistent with the Performance Minimums for Maximum
Unit Power Output, Unit Power Output, and Unit Heat Rate set forth in the
Construction Contract.
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
IN THE PROJECTION OF OPERATING RESULTS
In the preparation of this Report and the opinions that follow, we
have made certain assumptions with respect to conditions which may exist or
events which may occur in the future. While we believe these assumptions to be
reasonable for the purpose of this Report, they are dependent upon future events
and actual conditions may differ from those assumed. In addition, we have used
and relied upon certain information provided to us by sources which we believe
to be reliable. While we believe the use of such information and assumptions to
be reasonable for the purposes of our Report, we offer no other assurances 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.
B-34
<PAGE>
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 Facility 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. The Construction Contract will be implemented as described to us
by the Partnership and the Contractor.
3. The Contractor has taken into account the information in the
Preliminary Site Investigation report and the Subsurface Investigation
Data Report; complete the geotechnical analysis, engineering, and
reduction of data required to provide the geotechnical recommendations and
detailed site-work and foundation design criteria; and take into account
those recommendations during the design and construction of the Facility.
4. The Contractor and the Operator will construct and operate the
Facility as currently proposed in the Construction Contract and the O&M
Agreement.
5. The Contractor will undertake generally accepted project
management techniques to closely monitor construction and will react in a
timely fashion to lagging performance such that the Facility will be
constructed in accordance with the construction schedule developed by the
Contractor.
6. The Operator will maintain the Facility in accordance with
generally accepted industry practices, make all required renewals and
replacements in a timely manner, and will not operate the equipment to
cause it to exceed the equipment manufacturers' recommended maximum
ratings.
7. The Operator will employ qualified and competent personnel who
will properly operate and maintain the equipment in accordance with the
manufacturers' recommendations and generally accepted engineering practice
and will generally operate the Facility in a sound and businesslike
manner.
8. Inspections, overhauls, repairs, and modifications will be
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.
9. The design parameters and delivery dates of the major equipment
incorporated in the Facility will conform to performance and design data
in the Construction Contract and the construction schedule submitted by
the Contractor.
10. The three units will meet the emission guarantees in the
Construction Contract. Any exceedances will be resolved by the Contractor
in a manner which does not increase the Total Construction Cost, the
construction schedule, Facility availability, or Facility operating and
maintenance costs.
11. All permits and approvals necessary to construct and operate the
Facility will be obtained on a timely basis and any changes in required
permits and approvals will not require changes in design resulting in
either material delays in the scheduled Commercial Operation Date of the
Facility or in significant increases in the costs of the Facility.
12. There will be no increases in the Construction Contract Price
and the Other Construction Costs of the Facility that are greater than the
funded Project Contingency.
13. There will be no excess start-ups as defined in the Power
Purchase Agreement.
14. The market clearing price used for projecting the sales revenue
received by the Partnership after the termination of the Power Purchase
Agreements will be as estimated by C.C. Pace. The capacity factors of the
Facility and associated market-based revenues assuming an economic
dispatch in a market environment will be as estimated by C.C. Pace.
B-35
<PAGE>
15. Upon commercial operation, the Debt Service Reserve Account will
earn interest at a rate of 5.5 percent, as estimated by the Initial
Purchasers. The Major Maintenance Reserve Fund will earn interest at a
rate of 5.5 percent, as estimated by the Initial Purchasers.
16. The Virginia Power letters of credit will not be drawn upon.
17. The GDP-IPD and general inflation will escalate at a rate of 2.6
percent per year, and the average 1998 natural gas Price will be
$2.30/MMBtu and will escalate at a rate of 0.5 percent per year above
inflation, as estimated by C.C. Pace.
18. The non-fuel operating and maintenance expenses of the Facility,
including the cost of overhauls, will be equal to those estimated by the
Partnership, and will increase at a rate of 2.6 percent per year, except
for property taxes, corps of engineer's fees, trustee and rating agency
fees and site use fees, which were based on estimates prepared by the
Partnership. Deposits to the Major Maintenance Reserve Fund will be as
estimated by the Partnership. The cost of major maintenance will be as
estimated by the Partnership as adjusted for the assumed rate of change in
general inflation.
19. The principal amount of the Bonds will be $326,000,000.
20. The annual interest rate on the Series A and Series B Bonds
outstanding upon commencement of commercial operation will be 7.164 and
8.16 percent, respectively, as reported by the Initial Purchasers.
Interest will be funded from the proceeds of the Bonds through the June 1,
2000 deposit to the Trustee.
21. The amortization schedule of the Bonds will be as estimated by
the Initial Purchasers.
22. If performance liquidated damages are paid to the Partnership by
the Contractor, the total damages payment will be paid on the Substantial
Completion Date and will be used to repay 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 forth in
this Report, we are of the opinion that:
1. The Contractor and the Operator have previously demonstrated the
capability to perform their responsibilities under the Construction
Contract and the O&M Agreement, respectively.
2. Sufficient data has been gathered at the Site to perform the
geotechnical analysis, engineering, and reduction of data required to
provide the geotechnical recommendations and detailed site-work and
foundation design criteria needed to properly complete the Facility
design. With proper foundation design, and adequate construction controls
to minimize the change in moisture content of the Site soils, the Site
should be suitable for construction and operation of the Facility.
3. Based upon our review of the environmental site assessments for
the power plant site, the transmission line right-of-way, the wastewater
pipeline right-of-way, the water supply pipeline right-of-way, and the
natural gas pipeline right-of-way:
o there are no significant risks identified regarding
environmental contamination at the Site; and
o there are no Site contamination issues that require
substantial investigations or significant allocation of
funds.
4. The proposed method of design, construction, operation, and
maintenance of the Facility has been developed in accordance with
generally acceptable industry practice and has taken into consideration
the current environmental, license and permit requirements that the
Facility must meet.
B-36
<PAGE>
5. After consideration of:
o the emissions and blade cracking issues experienced with
the two dual-fuel installations of the 501F-DLN type of
combustion turbine being installed at the Facility as
described herein, and
o the effect that single-fuel firing, higher allowable NOX
emission limits, and the other mitigating factors
described herein have on these emissions and blade
cracking issues,
the combined-cycle technology proposed for the Facility is a sound, proven
method of energy generation and recovery.
6. If designed, constructed, operated, and maintained as currently
proposed by the Partnership, the Contractor, and the Operator, the
Facility should be capable of passing the Acceptance Tests included in the
Construction Contract and satisfying the current environmental, license,
and permit requirements which the Facility must meet.
7. If designed, constructed, operated and maintained as currently
proposed and dispatched as projected by C. C. Pace, the Facility should be
capable of achieving:
o an average annual output of 806,100 kW; and
o an average annual net plant heat rate of 7,050 Btu/kWh
(HHV).
8. The Facility should be capable of achieving a contract
availability under the Power Purchase Agreements with Virginia Power and
Aquila/UtiliCorp required to avoid reductions in the reservation payments
under those agreements.
9. Assuming:
o the Facility is designed, constructed, operated, and
maintained as proposed by the Partnership, the
Contractor, and the Operator;
o all equipment is operated in accordance with
manufacturers' recommendations;
o all required repairs, refurbishments and replacements
are made on a timely basis; and
o natural gas and water used by the Facility are within
the expected range with respect to quantity and quality,
then the Facility will have a useful life extending beyond the term of the
Bonds.
10. Assuming the absence of events such as:
o delivery delays;
o labor difficulties;
o unusually adverse weather conditions;
o force majeure events;
o the discovery of hazardous materials or wastes not
previously known; or
o other abnormal events prejudicial to normal construction
or installation,
and although the construction contracts that the Partnership has
entered into for the electrical substation, transmission lines, and
water infrastructure do not provide for the facilities to be
completed by the dates by which the Contractor needs electrical
backfeed and water in order to conduct certain tests, commercial
operation of the Facility by June 1, 2000 is achievable and within
the previously demonstrated capabilities of the Contractor and the
Partnership using generally accepted construction and project
management practices.
11. The scope and duration of the Acceptance Tests included in the
Construction Contract are similar to the tests of other projects with
which we are familiar and should be adequate to verify the performance
guarantees in accordance with the Construction Contract.
12. 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.
13. The estimates which serve as the basis for the Construction
Contract Price and the Total Construction Cost were prepared in accordance
with generally accepted engineering and estimating practices and methods.
The Construction Contract Price and the Total Construction Cost, including
the
B-37
<PAGE>
Project Contingency, are comparable to the costs and contingency of
similar projects at a similar stage of completion and utilizing similar
technologies with which we are familiar.
14. 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
$54,000,000 of equity that the Partnership expects will be contributed by
its parent and interest income during the construction period, should be
sufficient to fund the Total Construction Cost and interest on the Bonds
through June 1, 2000.
15. The basis for the Partnership's estimates of the cost of
operating and maintaining the Facility, including provision for major
maintenance, is reasonable.
16. For the Base Case Projected Operating Results, which assumes the
extension of the Virginia Power and the Aquila/UtiliCorp Power Purchase
Agreements, the projected revenues from the sale of electricity are
adequate:
o to pay annual operating and maintenance expenses
(including deposits to the Major Maintenance Reserve
Account), fuel expense, and other operating expenses;
and
o to provide an annual Debt Service Coverage Ratio of at
least 1.42 in each year during the term of the Bonds and
a weighted average Debt Service Coverage Ratio of 1.63
over the term of the Bonds.
17. If the Contractor pays the Partnership performance liquidated
damages due to a failure to achieve the Maximum Unit Power Output, Unit
Power Output or Unit Heat Rate, then the weighted average Debt Service
Coverage Ratio over the term of the Bonds is projected to remain at the
same level as in the Base Case Projected Operating Results for a
deficiency consistent with the Performance Minimums for Maximum Unit Power
Output, Unit Power Output, and Unit Heat Rate set forth in the
Construction Contract.
Respectfully submitted,
/s/ R. W. BECK, INC.
B-38
<PAGE>
[THIS PAGE INTENTIONALLY LEFT BLANK]
B-39
<PAGE>
Exhibit B-1
Batesville Project
Projected Operating Results
Base Case
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005 2006
- ------------------------ ------- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 66.71% 63.73% 63.73% 63.29% 62.85% 62.04% 61.23%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,832,000 3,000,000 3,000,000 2,979,300 2,958,700 2,920,700 2,882,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 916,000 1,500,000 1,500,000 1,489,700 1,479,300 1,460,300 1,441,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 19,379 31,734 31,734 31,515 31,297 30,895 30,493
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $57.30 57.30 57.30 57.30 57.30 63.62 68.14
Energy Rate ($/MWh)(13) $1.18 1.20 1.24 1.27 1.31 1.36 1.39
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $58.33 58.33 58.33 58.33 58.33 59.51 59.51
Energy Rate ($/MWh)(15) $1.09 1.12 1.15 1.18 1.21 1.24 1.27
Market Electricity Rates (16) $34.55 35.56 36.59 37.95 39.36 40.54 41.75
Natural Gas Price ($/MMBtu)(17) $2.445 2.521 2.599 2.679 2.762 2.848 2.936
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $18,143 31,102 31,102 31,102 31,102 34,535 36,988
Energy $1,832 3,060 3,150 3,218 3,284 3,359 3,402
Tracking Account Payment $322 544 561 575 588 599 609
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267 678
Aquila/UtiliCorp
Capacity $9,235 15,832 15,832 15,832 15,832 16,152 16,152
Energy $980 1,647 1,690 1,722 1,754 1,777 1,799
Tracking Account Payment $20 34 35 36 37 37 38
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133 339
Market $0 0 0 0 0 0 0
Interest Income (19) $403 917 864 863 861 944 951
------- ------ ------ ------ ------ ------ ------
Total Operating Revenues $32,919 56,536 56,634 56,747 56,858 60,803 60,956
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0 0
Labor $963 1,693 1,737 1,782 1,829 1,876 1,925
Deposits to Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525 4,525
Corps of Engineers $64 111 111 111 111 111 111
Subcontractor $115 203 208 214 219 225 231
Lateral Pipeline O&M $10 18 19 19 20 20 21
Back Up Power $158 279 286 294 302 309 317
Balance of Plant Parts $231 387 396 407 413 421 424
Equipment and Materials $173 293 302 304 311 315 320
Water Treatment Chemicals $98 164 168 171 175 177 179
SCR Chemicals $77 126 131 134 138 136 138
Supply/Waste Water Pumping Costs $102 171 176 179 182 184 186
Electrical Transmission O&M $6 10 10 11 11 11 12
Insurance $346 609 625 641 658 675 692
Administrative & General $462 812 833 855 877 900 923
Property Taxes (22) $0 0 1,900 1,900 1,900 1,900 1,900
Panola Partnership / Inducement A Payments $175 306 312 318 325 331 338
Trustee & Rating Agency Fees $54 93 93 93 93 93 93
------- ------ ------ ------ ------ ------ ------
Total Operating Expenses $11,534 9,800 11,832 11,958 12,089 12,209 12,335
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $21,385 46,736 44,802 44,789 44,769 48,594 48,621
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700 108,300
Principal $0 8,250 6,900 7,350 7,800 11,400 12,450
Interest $6,269 10,598 10,031 9,529 8,994 8,371 7,536
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75 64
------- ------ ------ ------ ------ ------ ------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208 34,411
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0 371
ANNUAL DEBT SERVICE COVERAGE (26) 1.45 1.43 1.43 1.43 1.43 1.42 1.42
AVERAGE DEBT COVERAGE (27) 1.63
MINIMUM SENIOR DEBT COVERAGE 1.42
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117 (371)
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285 16,914
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525 4,525
Major Overhaul Expenses (29) $0 5,850 0 2,821 11,768 0 3,047
Major Maintenance Reserve Balance (30) $8,500 7,643 12,588 14,984 8,565 13,561 15,785
<CAPTION>
Year Ending December 31, 2007 2008
- ------------------------ ---- ----
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 60.91% 60.58%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 2,867,300 2,852,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 1,433,700 1,426,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 30,331 30,168
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 68.14 68.14
Energy Rate ($/MWh)(13) 1.43 1.47
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51
Energy Rate ($/MWh)(15) 1.31 1.34
Market Electricity Rates (16) 42.82 43.92
Natural Gas Price ($/MMBtu)(17) 3.027 3.121
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 36,988 36,988
Energy 3,469 3,565
Tracking Account Payment 625 641
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152
Energy 1,836 1,874
Tracking Account Payment 39 40
Transmission (18) 0 0
Market 0 0
Interest Income (19) 930 918
------ ------
Total Operating Revenues 60,039 60,178
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0
Labor 1,975 2,026
Deposits to Major Maintenance Reserve (21) 4,525 4,975
Corps of Engineers 111 111
Subcontractor 237 243
Lateral Pipeline O&M 21 22
Back Up Power 325 333
Balance of Plant Parts 434 441
Equipment and Materials 327 334
Water Treatment Chemicals 183 187
SCR Chemicals 142 145
Supply/Waste Water Pumping Costs 189 193
Electrical Transmission O&M 12 12
Insurance 710 729
Administrative & General 947 972
Property Taxes (22) 1,900 1,900
Panola Partnership / Inducement A Payments 345 351
Trustee & Rating Agency Fees 93 93
------ ------
Total Operating Expenses 12,476 13,067
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 47,563 47,111
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 95,850 83,250
Principal 12,600 13,050
Interest 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000
Principal 0 0
Interest 14,362 14,362
Letter-of-Credit Fees 64 64
------ ------
Total Debt Service 33,667 33,206
TRANSFERS FROM DSRA (25) 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.42 1.43
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (226) (242)
Debt Service Reserve Account Balance (28) 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 4,525 4,975
Major Overhaul Expenses (29) 3,126 0
Major Maintenance Reserve Balance (30) 18,052 24,020
</TABLE>
B-40 & B-41
<PAGE>
Exhibit B-1
Batesville Project
Projected Operating Results
Base Case
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014 2015
- ------------------------ ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 60.08% 59.58% 59.05% 58.53% 57.81% 57.10% 56.02%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,828,300 2,804,700 2,780,000 2,755,300 2,721,700 2,688,000 2,637,300
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,414,200 1,402,300 1,390,000 1,377,700 1,360,800 1,344,000 1,318,700
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 29,918 29,668 29,407 29,146 28,790 28,434 27,898
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $68.14 68.14 68.14 68.14 58.54 51.69 51.69
Energy Rate ($/MWh)(13) $1.52 1.57 1.62 1.66 1.71 1.76 1.82
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 59.51 59.51 59.51 59.51
Energy Rate ($/MWh)(15) $1.38 1.41 1.45 1.49 1.53 1.57 1.61
Market Electricity Rates (16) $45.31 46.74 48.69 50.71 52.36 54.07 56.68
Natural Gas Price ($/MMBtu)(17) $3.218 3.318 3.421 3.527 3.636 3.749 3.865
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $36,988 36,988 36,988 36,988 31,777 28,055 28,055
Energy $3,649 3,730 3,809 3,885 3,946 4,005 4,061
Tracking Account Payment $655 670 685 700 712 725 734
Transmission (18) $0 0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 16,152 16,152 16,152 16,152
Energy $1,906 1,940 1,973 2,006 2,033 2,060 2,074
Tracking Account Payment $41 42 43 44 45 45 46
Transmission (18) $0 0 0 0 0 0 0
Market $0 0 0 0 0 0 0
Interest Income (19) $904 894 900 869 749 651 650
------- ------ ------ ------ ------ ------ ------
Total Operating Revenues $60,294 60,416 60,549 60,643 55,414 51,694 51,772
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0 0
Labor $2,079 2,133 2,189 2,246 2,304 2,364 2,425
Deposits to Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000 5,375
Corps of Engineers $111 111 111 111 111 111 111
Subcontractor $249 256 262 269 276 283 291
Lateral Pipeline O&M $22 23 24 24 25 26 26
Back Up Power $343 351 361 370 379 389 399
Balance of Plant Parts $450 459 463 471 478 484 487
Equipment and Materials $339 345 350 355 359 367 368
Water Treatment Chemicals $190 193 196 200 202 205 207
SCR Chemicals $148 151 154 157 159 161 162
Supply/Waste Water Pumping Costs $195 202 204 207 208 214 214
Electrical Transmission O&M $12 13 13 13 14 14 15
Insurance $748 767 787 808 829 850 872
Administrative & General $997 1,023 1,050 1,077 1,105 1,134 1,163
Property Taxes (22) $1,900 1,900 1,900 4,438 4,386 4,489 4,358
Panola Partnership / Inducement A Payments $359 366 373 380 388 396 404
Trustee & Rating Agency Fees $93 93 93 93 93 93 93
------- ------ ------ ------ ------ ------ ------
Total Operating Expenses $13,583 14,135 14,710 17,863 18,458 16,580 16,970
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $46,711 46,281 45,839 42,780 36,956 35,114 34,802
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0 0
Principal $13,500 14,100 15,300 15,300 12,000 0 0
Interest $4,787 3,809 2,778 1,682 645 0 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000 166,672
Principal $0 0 0 0 0 9,328 10,032
Interest $14,362 14,362 14,362 14,362 14,362 14,171 13,396
Letter-of-Credit Fees $64 64 64 64 64 64 64
------- ------ ------ ------ ------ ------ ------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563 23,492
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29 409
ANNUAL DEBT SERVICE COVERAGE (26) 1.43 1.43 1.43 1.43 1.43 1.49 1.50
AVERAGE DEBT COVERAGE (27) 1.63
MINIMUM SENIOR DEBT COVERAGE 1.42
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29) (409)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816 11,407
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000 5,375
Major Overhaul Expenses (29) $19,843 10,269 0 6,447 21,249 0 5,091
Major Maintenance Reserve Balance (30) $10,846 6,923 13,484 14,423 1,109 6,170 6,793
<CAPTION>
Year Ending December 31, 2016 2017
- ------------------------ ---- ----
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 54.95% 54.17%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 2,586,700 2,550,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 1,293,300 1,275,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 27,362 26,974
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 51.69
Energy Rate ($/MWh)(13) 1.88 1.93
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51
Energy Rate ($/MWh)(15) 1.65 1.69
Market Electricity Rates (16) 59.38 61.45
Natural Gas Price ($/MMBtu)(17) 3.985 4.108
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 28,055
Energy 4,113 4,157
Tracking Account Payment 742 754
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152
Energy 2,087 2,111
Tracking Account Payment 46 47
Transmission (18) 0 0
Market 0 0
Interest Income (19) 627 619
------ ------
Total Operating Revenues 51,822 51,895
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0
Labor 2,488 2,553
Deposits to Major Maintenance Reserve (21) 5,778 6,211
Corps of Engineers 111 111
Subcontractor 298 306
Lateral Pipeline O&M 27 28
Back Up Power 409 421
Balance of Plant Parts 493 497
Equipment and Materials 369 375
Water Treatment Chemicals 208 210
SCR Chemicals 163 164
Supply/Waste Water Pumping Costs 217 218
Electrical Transmission O&M 15 15
Insurance 895 918
Administrative & General 1,193 1,224
Property Taxes (22) 4,239 4,180
Panola Partnership / Inducement A Payments 412 420
Trustee & Rating Agency Fees 93 93
------ ------
Total Operating Expenses 17,408 17,944
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 34,414 33,951
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 156,640 146,608
Principal 10,032 10,560
Interest 12,577 11,748
Letter-of-Credit Fees 64 64
------ ------
Total Debt Service 22,673 22,372
TRANSFERS FROM DSRA (25) 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 1.52 1.54
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (145) (607)
Debt Service Reserve Account Balance (28) 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 5,778 6,211
Major Overhaul Expenses (29) 0 4,040
Major Maintenance Reserve Balance (30) 12,945 15,828
</TABLE>
B-42 & B-43
<PAGE>
Exhibit B-1
Batesville Project
Projected Operating Results
Base Case
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023 2024
- ------------------------ ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 53.39% 53.11% 52.82% 52.04% 50.26% 49.41% 48.50%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,513,300 2,500,000 2,486,700 2,450,000 2,366,000 2,326,000 2,283,300
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,256,700 1,250,000 1,243,300 0 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 1,225,000 1,183,000 1,163,000 1,141,700
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 26,586 26,445 26,304 25,916 25,028 24,604 24,153
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $51.69 51.69 51.69 51.69 51.69 51.69 51.69
Energy Rate ($/MWh)(13) $1.98 2.04 2.10 2.17 2.23 2.31 2.38
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 0.00 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $1.74 1.78 1.83 0.00 0.00 0.00 0.00
Market Electricity Rates (16) $63.59 65.17 66.79 70.04 71.91 73.50 76.13
Natural Gas Price ($/MMBtu)(17) $4.236 4.367 4.502 4.642 4.786 4.934 5.087
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $28,055 28,055 28,055 28,055 28,055 28,055 28,055
Energy $4,222 4,325 4,426 4,508 4,472 4,536 4,589
Tracking Account Payment $766 786 806 819 815 826 836
Transmission (18) $0 0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 0 0 0 0
Energy $2,134 2,178 2,223 0 0 0 0
Tracking Account Payment $48 49 50 0 0 0 0
Transmission (18) $0 0 0 0 0 0 0
Market $0 0 0 85,799 85,070 85,481 86,918
Interest Income (19) $586 616 463 746 715 677 780
------- ------ ------ ------- ------- ------- -------
Total Operating Revenues $51,963 52,161 52,176 119,927 119,127 119,575 121,179
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 40,098 39,924 40,465 40,956
Labor $2,619 2,688 2,757 2,829 2,903 2,978 3,056
Deposits to Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586 525
Corps of Engineers $111 111 111 111 111 111 111
Subcontractor $314 322 331 339 348 357 366
Lateral Pipeline O&M $28 29 30 31 31 32 33
Back Up Power $432 442 454 465 478 490 503
Balance of Plant Parts $501 514 522 529 525 530 534
Equipment and Materials $377 386 395 397 394 398 401
Water Treatment Chemicals $213 217 221 224 222 224 225
SCR Chemicals $166 169 172 173 174 174 175
Supply/Waste Water Pumping Costs $222 225 231 232 231 234 233
Electrical Transmission O&M $16 16 17 17 17 18 18
Insurance $942 967 992 1,018 1,044 1,071 1,099
Administrative & General $1,256 1,289 1,322 1,357 1,392 1,428 1,465
Property Taxes (22) $4,065 3,965 4,124 4,244 4,331 4,161 3,921
Panola Partnership / Inducement A Payments $428 437 446 455 464 473 483
Trustee & Rating Agency Fees $93 93 93 93 93 93 93
------- ------ ------ ------- ------- ------- -------
Total Operating Expenses $18,460 19,048 19,935 60,907 61,599 62,823 54,197
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $33,503 33,113 32,241 59,020 57,528 56,752 66,982
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0 0
Principal $0 0 0 0 0 0 0
Interest $0 0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816 49,808
Principal $10,208 12,144 7,568 18,480 18,832 19,008 24,288
Interest $10,893 10,021 9,123 8,283 6,768 5,228 3,569
Letter-of-Credit Fees $64 64 64 64 64 64 64
------- ------ ------ ------- ------- ------- -------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300 27,921
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.58 1.61 1.92 2.22 2.27 2.34 2.40
AVERAGE DEBT COVERAGE (27) 1.63
MINIMUM SENIOR DEBT COVERAGE 1.42
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864 12,385
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176 26,561
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586 525
Major Overhaul Expenses (29) $21,486 0 10,061 0 14,894 0 17,861
Major Maintenance Reserve Balance (30) $1,890 9,172 7,332 16,030 10,935 21,122 4,948
<CAPTION>
Year Ending December 31, 2025(1)
- ------------------------ -------
<S> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100
Availability Factor (%)(3) 92.00%
Capacity Factor (4) 47.19%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800
Contract Availability (%)(6) 97.20%
Energy Sales (MWh) 925,600
Contract Heat Rate (Btu/kWh)(7) 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700
Standard Capacity (kW)(5) 236,500
Supplemental Capacity (kW)(5) 30,500
Surplus Supplemental Capacity (kW)(8) 4,400
Contract Availability (%)(6) 97.20%
Energy Sales (MWh) 0
Contract Heat Rate (Btu/kWh)(9) 7,061
Market Energy Sales 740,400
Heat Rate (Btu/kWh)(10) 7,052
Fuel Consumption (BBtu) 11,749
COMMODITY PRICES
General Inflation (%)(11) 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 43.07
Energy Rate ($/MWh)(13) 2.45
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00
Energy Rate ($/MWh)(15) 0.00
Market Electricity Rates (16) 78.65
Natural Gas Price ($/MMBtu)(17) 5.245
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 11,688
Energy 1,916
Tracking Account Payment 350
Transmission (18) 0
Aquila/UtiliCorp
Capacity 0
Energy 0
Tracking Account Payment 0
Transmission (18) 0
Market 58,232
Interest Income (19) 730
------
Total Operating Revenues 72,916
OPERATING EXPENSES ($000)(20)
Fuel Expense 27,384
Labor 1,567
Deposits to Major Maintenance Reserve (21) 282
Corps of Engineers 55
Subcontractor 188
Lateral Pipeline O&M 17
Back Up Power 359
Balance of Plant Parts 267
Equipment and Materials 200
Water Treatment Chemicals 112
SCR Chemicals 88
Supply/Waste Water Pumping Costs 117
Electrical Transmission O&M 9
Insurance 564
Administrative & General 752
Property Taxes (22) 1,795
Panola Partnership / Inducement A Payments 246
Trustee & Rating Agency Fees 46
------
Total Operating Expenses 34,048
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 38,868
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0
Principal 0
Interest 0
Series B Bonds
Balance Outstanding 25,520
Principal 25,520
Interest 1,041
Letter-of-Credit Fees 32
------
Total Debt Service 26,593
TRANSFERS FROM DSRA (25) 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 2.46
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (26,561)
Debt Service Reserve Account Balance (28) 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 282
Major Overhaul Expenses (29) 0
Major Maintenance Reserve Balance (30) 5,366
</TABLE>
B-44 & B-45
<PAGE>
Footnotes to Exhibit B-1
1. Represents six months of operation for 1999 based on a Commercial
Operation Date of June 1, 2000, and six months of operation for 2025 based
on the months during which deposits to the Trustee will be required for
the final amortization of the Bonds on July 15, 2025.
2. Plant output for purposes of determining the energy output based on three
(3) units with a total net capacity of 268,700 kW per unit, based on
guaranteed gross capacity adjusted for allowed measurement margin,
auxiliary loads, degradation and adjustments, and normal operating
conditions.
3. Annual average availability estimate includes allowances for scheduled
maintenance, major overhauls and forced outages.
4. The capacity factor is based on the typical dispatch projected by C.C.
Pace adjusted to reflect R. W. Beck availability assumptions.
5. Pursuant to the Aquila/UtiliCorp and Virginia Power Purchase Agreements,
capacity ratings are based on test conditions and do not include
adjustments for normal operating conditions. Under the Aquila/UtiliCorp
Power Purchase Agreement, Supplemental Capacity is limited to the
additional capacity up to a total capacity of 267,000 kW.
6. Based on availability including unscheduled forced outage hours, but
excluding scheduled maintenance.
7. Estimated based on the terms of the Virginia Power Purchase Agreement and
the dispatch projected by C.C. Pace.
8. Pursuant to the Aquila/UtiliCorp Power Purchase Agreement, Surplus
Supplemental Capacity is the amount by which the sum of standard and
supplemental capacity exceed 267,000 kW adjusted to ambient conditions of
95oF and 60 percent relative humidity.
9. Estimated based on the terms of the Aquila/UtiliCorp Power Purchase
Agreement and the dispatch projected by C.C. Pace.
10. Net heat rate based on gross guaranteed heat rate adjusted for allowed
test margin, auxiliary energy requirements, degradation and adjustments,
and seasonality and part-load operating conditions. The adjustment for
seasonality and part-load operating conditions was based on projected
dispatch provided by C.C. Pace.
11. General inflation and the GDP-IPD assumed to increase at a rate of 2.6
percent per year.
12. The capacity rates pursuant to the Virginia Power Purchase Agreement are
equal to the sum of the Summer Condition Standard Capacity charge and the
Summer Condition Supplemental Capacity charge times the Availability
Adjustment Factor. The Summer Condition Standard Capacity charge is equal
to $5.00 per kW-month for the first 60 months following commercial
operation, and $6.00 next 8 years and $4.50/kW-month for the remainder of
the term, if extended. The Summer Condition Supplemental Capacity charge
is equal to $3.25 per kW-month for the first five years, $3.50 per
kW-month for the next eight years, and $3.00 per kW-month for the
remainder of the term, if extended. The Availability Adjustment Factor is
equal to 1.0 unless the contract availability is less than 97.2 percent.
13. The energy rate pursuant to the Virginia Power Purchase Agreement is equal
to the sum of the energy payment, fuel expense, and the Tracking Account
payment divided by energy sales to Virginia Power. The energy payment is
equal to a rate of $1.0 per MWh escalated at the GDP-IPD index from June
1, 2000. The fuel expense is assumed to be the actual fuel expense based
on an assumed average annual net heat rate of 7,050 Btu/kWh. The Tracking
Account payment reflects the difference in fuel cost between actual fuel
expense and the fuel expense based on the guaranteed heat rate.
14. The capacity rates pursuant to the Aquila/UtiliCorp Purchase Power
Agreement are equal to the sum of the reservation charge and the Surplus
Supplemental Capacity charge times the Availability Adjustment Factor. The
reservation charge, which is applicable to the first 267,000 kW of
capacity is equal to $4.90 per kW-month for the first 60 months following
commercial operation, $5.00 per kW-month for the reminder of the initial
term of 15 years, 7 months and the extended term of five years. The
Surplus Supplemental Capacity charge, which is applicable to capacity
above 267,000 kW, is equal to $2.50 per kW-month for the 15-year, 7-month
and the extended term of five years. The availability adjustment factor is
equal to 1.0 unless the contract availability is less than 97 percent.
15. The energy rate pursuant to the Aquila/UtiliCorp Power Purchase Agreement
is presented as the sum of the energy expense, fuel expense, and the
Tracking Account payment divided by energy sales to Aquila/UtiliCorp. The
energy payment is equal to the product of energy sales and a rate of $1.0
per MWh escalated at the GDP-IPD index from January 1, 1997. The fuel
expense is assumed to be the actual fuel expense based on an assumed
average annual net heat rate of 7,050 Btu/kWh. The Tracking Account
payment reflects the difference in fuel cost between actual fuel expense
and the fuel expense based on the guaranteed heat rate.
16. Market electricity rates as estimated by C.C. Pace adjusted to reflect the
assumed general escalation rate of 2.6 percent per year.
17. Natural gas prices have been estimated by C.C. Pace and are based on the
price of gas delivered to Mississippi of $2.30/MMBtu in 1998 dollars,
escalated at 0.5 percent above general inflation.
B-46
<PAGE>
Footnotes to Exhibit B-1
(Continued)
18. Transmission revenues are based on the Partnership receiving a credit
against transmission service charges in an amount equal to system upgrades
made by Partnership pursuant to the Interconnection and Operating
Agreements between the Partnership and Entergy and TVA, respectively.
These agreements state that Entergy and TVA shall credit against the
Partnership's use an amount equal to the equivalent point-to-point
transmission service rate for such services until such time as the cost of
the system upgrades has been fully offset. The Power Purchase Agreements
state that to the extent the purchaser's receive such credit under
transmission service agreements with Entergy and TVA, the purchaser will
pay the Partnership an amount equal to such credit. Based on C. C. Pace,
the total amount of the credit is assumed to be approximately $3,400,000
per year. The total amount will not exceed the reimbursable cost of
transmission system upgrades which have been estimated by the Partnership
to be $20,000,000.
19. Based on a reinvestment rate on the Debt Service Reserve Account of 5.5
percent, as estimated by the Initial Purchasers. The Debt Service Reserve
Account requirements are equal to the next semiannual debt service
payment.
20. Non-fuel operating expenses estimated by the Partnership and escalated at
the change in inflation, with the exception of property taxes, the Panola
Partnership/Inducement fee, and the Corps of Engineer's fee. Also as
estimated by the Partnership, Panola Partnership inducement fee was
assumed to increase at 2.0 percent per year, and the Corps of Engineers'
fee for the use of Lake Enid was assumed to remain flat.
21. Payments into Major Maintenance Reserve Account are based on a projected
schedule of deposits provided by the Partnership.
22. The Partnership's local counsel has determined that the first property tax
payment will be due in 2002.
23. Pursuant to the Indenture, Cash Available for Debt Service includes the
deposits into the Major Maintenance Reserve Account, although these
deposits will be made after the payment of Debt Service.
24. Based on a principal amount of the Series A Bonds of $150,000,000 at an
interest rate, as reported by the Initial Purchasers, of 7.164 percent and
a principal amount of the Series B Bonds of $176,000,000 at an interest
rate, as reported by the Initial Purchasers, of 8.16 percent. Monthly
deposits to the Trustee are assumed to be made on the first of each month
prior to the due dates. Interest is to be funded from the proceeds of the
Bonds through the June 1, 2000 deposit. Pursuant to the Indenture,
letter-of-credit fees are included in the definition of Debt Service.
25. Represents any required transfers from the Debt Service Reserve Account to
meet debt service requirements. Amounts in excess of the Debt Service
Reserve Account requirement are to be transferred to the Revenue Account.
26. As defined in the Indenture.
27. Weighted average debt service coverage calculated as total net revenues
over the term of the Bonds divided by total Debt Service over the same
period.
28. Based on an initial Debt Service Reserve Account deposit of $12,551,000,
which is to be funded from the proceeds of the Bonds. The Debt Service
Reserve Account requirement is equal to the next semi-annual debt service
payment.
29. Major turbine overhaul expenses as estimated by the Partnership, adjusted
to reflect a general inflation rate of 2.6 percent per year.
30. Balance includes interest income based on a reinvestment rate of 5.5
percent per year, as estimated by the Initial Purchasers.
B-47
<PAGE>
Exhibit B-2
Batesville Project
Projected Operating Results
Sensitivity A - Reduced Availability
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ ------- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 87.00% 87.00% 87.00% 87.00% 87.00% 87.00%
Capacity Factor (4) 63.61% 60.84% 60.84% 60.04% 59.24% 58.89%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 92.20% 92.20% 92.20% 92.20% 92.20% 92.20%
Energy Sales (MWh) 1,746,700 2,864,000 2,864,000 2,826,300 2,788,700 2,772,300
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 92.20% 92.20% 92.20% 92.20% 92.20% 92.20%
Energy Sales (MWh) 873,300 1,432,000 1,432,000 1,413,200 1,394,300 1,386,200
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 18,476 30,295 30,295 29,897 29,499 29,326
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $55.15 54.69 54.35 54.35 54.35 60.35
Energy Rate ($/MWh)(13) $1.18 1.20 1.24 1.27 1.31 1.36
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $55.45 55.45 55.45 55.45 55.45 56.57
Energy Rate ($/MWh)(15) $1.09 1.12 1.15 1.18 1.21 1.24
Market Electricity Rates (16) $34.91 35.77 36.65 38.17 39.75 40.89
Natural Gas Price ($/MMBtu)(17) $2.445 2.521 2.599 2.679 2.762 2.848
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $17,463 29,684 29,502 29,502 29,502 32,759
Energy $1,747 2,921 3,007 3,052 3,095 3,188
Tracking Account Payment $307 520 536 545 555 568
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267
Aquila/UtiliCorp
Capacity $8,778 15,049 15,049 15,049 15,049 15,353
Energy $934 1,572 1,613 1,633 1,653 1,686
Tracking Account Payment $19 32 33 34 35 36
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133
Market $0 0 0 0 0 0
Interest Income (19) $403 917 864 863 861 944
--------- --------- --------- --------- --------- ---------
Total Operating Revenues $31,635 54,095 54,005 54,079 54,150 57,934
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $963 1,693 1,737 1,782 1,829 1,876
Deposits to Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Corps of Engineers $64 111 111 111 111 111
Subcontractor $115 203 208 214 219 225
Lateral Pipeline O&M $10 18 19 19 20 20
Back Up Power $158 279 286 294 302 309
Balance of Plant Parts $220 369 378 386 389 399
Equipment and Materials $165 279 288 288 293 299
Water Treatment Chemicals $93 157 161 163 165 168
SCR Chemicals $73 120 125 127 130 129
Supply/Waste Water Pumping Costs $97 163 168 170 172 175
Electrical Transmission O&M $6 10 10 11 11 11
Insurance $346 609 625 641 658 675
Administrative & General $462 812 833 855 877 900
Property Taxes (22) $0 0 1,900 1,900 1,900 1,900
Panola Partnership / Inducement A Payments $175 306 312 318 325 331
Trustee & Rating Agency Fees $54 93 93 93 93 93
--------- --------- --------- --------- --------- ---------
Total Operating Expenses $11,501 9,747 11,779 11,897 12,019 12,146
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $20,134 44,348 42,226 42,182 42,131 45,788
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700
Principal $0 8,250 6,900 7,350 7,800 11,400
Interest $6,269 10,598 10,031 9,529 8,994 8,371
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75
--------- --------- --------- --------- --------- ---------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.37 1.36 1.35 1.35 1.35 1.34
AVERAGE DEBT COVERAGE (27) 1.52
MINIMUM SENIOR DEBT COVERAGE 1.33
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Major Overhaul Expenses (29) $0 5,850 0 2,821 11,768 0
Major Maintenance Reserve Balance (30) $8,500 7,643 12,588 14,984 8,565 13,561
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ---- ---- ----
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 87.00% 87.00% 87.00%
Capacity Factor (4) 58.54% 57.89% 57.24%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 92.20% 92.20% 92.20%
Energy Sales (MWh) 2,756,000 2,725,300 2,694,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 92.20% 92.20% 92.20%
Energy Sales (MWh) 1,378,000 1,362,700 1,347,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 29,153 28,829 28,504
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 64.64 64.64 64.64
Energy Rate ($/MWh)(13) 1.39 1.43 1.47
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 56.57 56.57 56.57
Energy Rate ($/MWh)(15) 1.27 1.31 1.34
Market Electricity Rates (16) 42.06 42.89 43.73
Natural Gas Price ($/MMBtu)(17) 2.936 3.027 3.121
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 35,085 35,085 35,085
Energy 3,252 3,298 3,368
Tracking Account Payment 583 594 606
Transmission (18) 678 0 0
Aquila/UtiliCorp
Capacity 15,353 15,353 15,353
Energy 1,720 1,745 1,770
Tracking Account Payment 36 37 38
Transmission (18) 339 0 0
Market 0 0 0
Interest Income (19) 951 930 918
--------- --------- ---------
Total Operating Revenues 57,997 57,042 57,138
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 1,925 1,975 2,026
Deposits to Major Maintenance Reserve (21) 4,525 4,525 4,975
Corps of Engineers 111 111 111
Subcontractor 231 237 243
Lateral Pipeline O&M 21 21 22
Back Up Power 317 325 333
Balance of Plant Parts 405 413 416
Equipment and Materials 306 311 315
Water Treatment Chemicals 171 174 176
SCR Chemicals 132 135 137
Supply/Waste Water Pumping Costs 178 180 182
Electrical Transmission O&M 12 12 12
Insurance 692 710 729
Administrative & General 923 947 972
Property Taxes (22) 1,900 1,900 1,900
Panola Partnership / Inducement A Payments 338 345 351
Trustee & Rating Agency Fees 93 93 93
--------- --------- ---------
Total Operating Expenses 12,280 12,414 12,993
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 45,717 44,628 44,145
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 108,300 95,850 83,250
Principal 12,450 12,600 13,050
Interest 7,536 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000 176,000
Principal 0 0 0
Interest 14,362 14,362 14,362
Letter-of-Credit Fees 64 64 64
--------- --------- ---------
Total Debt Service 34,411 33,667 33,206
TRANSFERS FROM DSRA (25) 371 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.34 1.33 1.34
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (371) (226) (242)
Debt Service Reserve Account Balance (28) 16,914 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 4,525 4,525 4,975
Major Overhaul Expenses (29) 3,047 0 3,207
Major Maintenance Reserve Balance (30) 15,785 21,178 24,111
</TABLE>
B-48 & B-49
<PAGE>
Exhibit B-2
Batesville Project
Projected Operating Results
Sensitivity A - Reduced Availability
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 87.00% 87.00% 87.00% 87.00% 87.00% 87.00%
Capacity Factor (4) 57.16% 57.07% 56.31% 55.56% 55.03% 54.51%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 92.20% 92.20% 92.20% 92.20% 92.20% 92.20%
Energy Sales (MWh) 2,690,700 2,686,700 2,651,000 2,615,300 2,590,700 2,566,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 92.20% 92.20% 92.20% 92.20% 92.20% 92.20%
Energy Sales (MWh) 1,345,300 1,343,300 1,325,500 1,307,700 1,295,300 1,283,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 28,462 28,420 28,042 27,665 27,404 27,143
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $64.64 64.64 64.64 64.64 55.53 49.03
Energy Rate ($/MWh)(13) $1.52 1.57 1.62 1.66 1.71 1.76
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $56.57 56.57 56.57 56.57 56.57 56.57
Energy Rate ($/MWh)(15) $1.38 1.41 1.45 1.49 1.53 1.57
Market Electricity Rates (16) $45.28 46.89 48.85 50.88 52.38 53.92
Natural Gas Price ($/MMBtu)(17) $3.218 3.318 3.421 3.527 3.636 3.749
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $35,085 35,085 35,085 35,085 30,142 26,612
Energy $3,471 3,573 3,632 3,688 3,757 3,823
Tracking Account Payment $623 642 653 664 678 693
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $15,353 15,353 15,353 15,353 15,353 15,353
Energy $1,814 1,858 1,881 1,904 1,935 1,966
Tracking Account Payment $39 40 41 42 42 43
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 0 0 0
Interest Income (19) $904 894 900 869 749 651
--------- --------- --------- --------- --------- ---------
Total Operating Revenues $57,290 57,445 57,545 57,604 52,657 49,141
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $2,079 2,133 2,189 2,246 2,304 2,364
Deposits to Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Corps of Engineers $111 111 111 111 111 111
Subcontractor $249 256 262 269 276 283
Lateral Pipeline O&M $22 23 24 24 25 26
Back Up Power $343 351 361 370 379 389
Balance of Plant Parts $428 439 441 447 455 462
Equipment and Materials $323 330 334 337 342 350
Water Treatment Chemicals $181 185 187 190 193 196
SCR Chemicals $141 145 147 149 152 154
Supply/Waste Water Pumping Costs $186 193 195 196 198 204
Electrical Transmission O&M $12 13 13 13 14 14
Insurance $748 767 787 808 829 850
Administrative & General $997 1,023 1,050 1,077 1,105 1,134
Property Taxes (22) $1,900 1,900 1,900 4,438 4,386 4,489
Panola Partnership / Inducement A Payments $359 366 373 380 388 396
Trustee & Rating Agency Fees $93 93 93 93 93 93
--------- --------- --------- --------- --------- ---------
Total Operating Expenses $13,520 14,077 14,647 17,792 18,392 16,515
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $43,770 43,368 42,898 39,812 34,265 32,626
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0
Principal $13,500 14,100 15,300 15,300 12,000 0
Interest $4,787 3,809 2,778 1,682 645 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 9,328
Interest $14,362 14,362 14,362 14,362 14,362 14,171
Letter-of-Credit Fees $64 64 64 64 64 64
--------- --------- --------- --------- --------- ---------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29
ANNUAL DEBT SERVICE COVERAGE (26) 1.34 1.34 1.34 1.34 1.33 1.39
AVERAGE DEBT COVERAGE (27) 1.52
MINIMUM SENIOR DEBT COVERAGE 1.33
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Major Overhaul Expenses (29) $19,843 0 10,536 6,447 0 21,802
Major Maintenance Reserve Balance (30) $10,942 17,293 13,888 14,849 22,808 7,260
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ---- ---- ----
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 87.00% 87.00% 87.00%
Capacity Factor (4) 53.29% 52.07% 51.41%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 92.20% 92.20% 92.20%
Energy Sales (MWh) 2,508,700 2,451,300 2,420,300
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 92.20% 92.20% 92.20%
Energy Sales (MWh) 1,254,300 1,225,700 1,210,200
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 26,537 25,930 25,602
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 49.03 49.03 49.03
Energy Rate ($/MWh)(13) 1.82 1.88 1.93
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 56.57 56.57 56.57
Energy Rate ($/MWh)(15) 1.61 1.65 1.69
Market Electricity Rates (16) 56.72 59.63 61.47
Natural Gas Price ($/MMBtu)(17) 3.865 3.985 4.108
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 26,612 26,612 26,612
Energy 3,863 3,898 3,945
Tracking Account Payment 698 703 716
Transmission (18) 0 0 0
Aquila/UtiliCorp
Capacity 15,353 15,353 15,353
Energy 1,973 1,978 2,003
Tracking Account Payment 44 44 45
Transmission (18) 0 0 0
Market 0 0 0
Interest Income (19) 650 627 619
--------- --------- ---------
Total Operating Revenues 49,193 49,215 49,293
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 2,425 2,488 2,553
Deposits to Major Maintenance Reserve (21) 5,375 5,778 6,211
Corps of Engineers 111 111 111
Subcontractor 291 298 306
Lateral Pipeline O&M 26 27 28
Back Up Power 399 409 421
Balance of Plant Parts 463 467 472
Equipment and Materials 350 349 356
Water Treatment Chemicals 196 197 200
SCR Chemicals 154 154 156
Supply/Waste Water Pumping Costs 203 206 207
Electrical Transmission O&M 15 15 15
Insurance 872 895 918
Administrative & General 1,163 1,193 1,224
Property Taxes (22) 4,358 4,239 4,180
Panola Partnership / Inducement A Payments 404 412 420
Trustee & Rating Agency Fees 93 93 93
--------- --------- ---------
Total Operating Expenses 16,898 17,331 17,871
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 32,295 31,884 31,422
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0 0
Principal 0 0 0
Interest 0 0 0
Series B Bonds
Balance Outstanding 166,672 156,640 146,608
Principal 10,032 10,032 10,560
Interest 13,396 12,577 11,748
Letter-of-Credit Fees 64 64 64
--------- --------- ---------
Total Debt Service 23,492 22,673 22,372
TRANSFERS FROM DSRA (25) 409 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 1.39 1.41 1.43
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (409) (145) (607)
Debt Service Reserve Account Balance (28) 11,407 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 5,375 5,778 6,211
Major Overhaul Expenses (29) 0 5,224 0
Major Maintenance Reserve Balance (30) 13,034 14,305 21,303
</TABLE>
B-50 & B-51
<PAGE>
Exhibit B-2
Batesville Project
Projected Operating Results
Sensitivity A - Reduced Availability
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 87.00% 87.00% 87.00% 87.00% 87.00% 87.00%
Capacity Factor (4) 50.75% 50.85% 50.95% 48.40% 47.41% 46.39%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 92.20% 92.20% 92.20% 92.20% 92.20% 92.20%
Energy Sales (MWh) 2,389,300 2,394,000 2,398,700 2,278,700 2,232,000 2,184,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 92.20% 92.20% 92.20% 92.20% 92.20% 92.20%
Energy Sales (MWh) 1,194,700 1,197,000 1,199,300 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 1,139,300 1,116,000 1,092,000
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 25,274 25,324 25,373 24,104 23,610 23,102
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $49.03 49.03 49.03 49.03 49.03 49.03
Energy Rate ($/MWh)(13) $1.98 2.04 2.10 2.17 2.23 2.31
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $56.57 56.57 56.57 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $1.74 1.78 1.83 0.00 0.00 0.00
Market Electricity Rates (16) $63.36 65.23 67.15 70.20 71.23 73.71
Natural Gas Price ($/MMBtu)(17) $4.236 4.367 4.502 4.642 4.786 4.934
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $26,612 26,612 26,612 26,612 26,612 26,612
Energy $4,014 4,142 4,270 4,193 4,218 4,259
Tracking Account Payment $729 753 778 762 769 776
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $15,353 15,353 15,353 0 0 0
Energy $2,029 2,086 2,144 0 0 0
Tracking Account Payment $46 47 49 0 0 0
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 79,979 79,493 80,491
Interest Income (19) $586 616 463 746 715 677
--------- --------- --------- --------- --------- ---------
Total Operating Revenues $49,368 49,608 49,668 112,291 111,807 112,814
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 37,293 37,663 37,995
Labor $2,619 2,688 2,757 2,829 2,903 2,978
Deposits to Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Corps of Engineers $111 111 111 111 111 111
Subcontractor $314 322 331 339 348 357
Lateral Pipeline O&M $28 29 30 31 31 32
Back Up Power $432 442 454 465 478 490
Balance of Plant Parts $477 492 504 492 496 498
Equipment and Materials $358 370 381 369 372 373
Water Treatment Chemicals $202 208 214 208 209 210
SCR Chemicals $158 162 166 161 164 164
Supply/Waste Water Pumping Costs $211 215 223 215 218 219
Electrical Transmission O&M $16 16 17 17 17 18
Insurance $942 967 992 1,018 1,044 1,071
Administrative & General $1,256 1,289 1,322 1,357 1,392 1,428
Property Taxes (22) $4,065 3,965 4,124 4,244 4,331 4,161
Panola Partnership / Inducement A Payments $428 437 446 455 464 473
Trustee & Rating Agency Fees $93 93 93 93 93 93
--------- --------- --------- --------- --------- ---------
Total Operating Expenses $18,387 18,984 19,882 57,992 59,251 60,257
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $30,981 30,624 29,786 54,299 52,556 52,557
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0
Principal $0 0 0 0 0 0
Interest $0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816
Principal $10,208 12,144 7,568 18,480 18,832 19,008
Interest $10,893 10,021 9,123 8,283 6,768 5,228
Letter-of-Credit Fees $64 64 64 64 64 64
--------- --------- --------- --------- --------- ---------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.46 1.50 1.78 2.05 2.07 2.16
AVERAGE DEBT COVERAGE (27) 1.52
MINIMUM SENIOR DEBT COVERAGE 1.33
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Major Overhaul Expenses (29) $4,145 22,045 0 10,323 0 15,281
Major Maintenance Reserve Balance (30) $25,007 11,515 19,865 18,930 28,888 24,782
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ---- -------
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 87.00% 87.00%
Capacity Factor (4) 46.17% 44.92%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 92.20% 92.20%
Energy Sales (MWh) 2,173,300 881,100
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 92.20% 92.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 1,086,700 704,900
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 22,990 11,184
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 49.03 40.85
Energy Rate ($/MWh)(13) 2.38 2.45
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00 0.00
Energy Rate ($/MWh)(15) 0.00 0.00
Market Electricity Rates (16) 76.79 78.79
Natural Gas Price ($/MMBtu)(17) 5.087 5.245
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 26,612 11,087
Energy 4,368 1,824
Tracking Account Payment 796 333
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Market 83,448 55,539
Interest Income (19) 780 730
--------- -------
Total Operating Revenues 116,004 69,512
OPERATING EXPENSES ($000)(20)
Fuel Expense 38,983 26,071
Labor 3,056 1,567
Deposits to Major Maintenance Reserve (21) 525 282
Corps of Engineers 111 55
Subcontractor 366 188
Lateral Pipeline O&M 33 17
Back Up Power 503 359
Balance of Plant Parts 509 254
Equipment and Materials 381 190
Water Treatment Chemicals 214 107
SCR Chemicals 166 84
Supply/Waste Water Pumping Costs 222 111
Electrical Transmission O&M 18 9
Insurance 1,099 564
Administrative & General 1,465 752
Property Taxes (22) 3,921 1,795
Panola Partnership / Inducement A Payments 483 246
Trustee & Rating Agency Fees 93 46
--------- -------
Total Operating Expenses 52,148 32,697
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 63,856 36,815
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 49,808 25,520
Principal 24,288 25,520
Interest 3,569 1,041
Letter-of-Credit Fees 64 32
--------- -------
Total Debt Service 27,921 26,593
TRANSFERS FROM DSRA (25) 0 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 2.29 2.38
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account 12,385 (26,561)
Debt Service Reserve Account Balance (28) 26,561 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 525 282
Major Overhaul Expenses (29) 0 0
Major Maintenance Reserve Balance (30) 26,670 27,685
</TABLE>
B-52 & B-53
<PAGE>
Footnotes to Exhibit B-2
The footnotes to Exhibit B-2 are the same as the footnotes for Exhibit B-1,
except:
3. Assumed to be 5 percentage points less than that assumed in the Base Case
and no liquidated damage payments are due from the Contractor.
6. Assumed to be 5 percentage points less than that assumed in the Base Case
and no liquidated damage payments are due from the Contractor.
21. Assumes no reduction in major maintenance requirements due to decreased
availability.
B-54
<PAGE>
Exhibit B-3
Batesville Project
Projected Operating Results
Sensitivity B - Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 66.71% 63.73% 63.73% 63.29% 62.85% 62.04%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,832,000 3,000,000 3,000,000 2,979,300 2,958,700 2,920,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 916,000 1,500,000 1,500,000 1,489,700 1,479,300 1,460,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,405 7,405 7,405 7,405 7,405 7,405
Fuel Consumption (BBtu) 20,348 33,321 33,321 33,091 32,862 32,440
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $57.30 57.30 57.30 57.30 57.30 63.62
Energy Rate ($/MWh)(13) $0.31 0.31 0.32 0.33 0.33 0.35
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $58.33 58.33 58.33 58.33 58.33 59.51
Energy Rate ($/MWh)(15) $0.23 0.23 0.23 0.24 0.24 0.24
Market Electricity Rates (16) $34.55 35.56 36.59 37.95 39.36 40.54
Natural Gas Price ($/MMBtu)(17) $2.445 2.521 2.599 2.679 2.762 2.848
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $18,143 31,102 31,102 31,102 31,102 34,535
Energy $1,832 3,060 3,150 3,218 3,284 3,359
Tracking Account Payment ($1,257) (2,122) (2,188) (2,240) (2,293) (2,334)
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267
Aquila/UtiliCorp
Capacity $9,235 15,832 15,832 15,832 15,832 16,152
Energy $980 1,647 1,690 1,722 1,754 1,777
Tracking Account Payment ($769) (1,299) (1,339) (1,371) (1,404) (1,429)
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133
Market $0 0 0 0 0 0
Interest Income (19) $403 917 864 863 861 944
------ ------ ------ ------ ------ ------
Total Operating Revenues $30,550 52,537 52,511 52,525 52,535 56,404
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $963 1,693 1,737 1,782 1,829 1,876
Deposits to Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Corps of Engineers $64 111 111 111 111 111
Subcontractor $115 203 208 214 219 225
Lateral Pipeline O&M $10 18 19 19 20 20
Back Up Power $158 279 286 294 302 309
Balance of Plant Parts $231 387 396 407 413 421
Equipment and Materials $173 293 302 304 311 315
Water Treatment Chemicals $98 164 168 171 175 177
SCR Chemicals $77 126 131 134 138 136
Supply/Waste Water Pumping Costs $102 171 176 179 182 184
Electrical Transmission O&M $6 10 10 11 11 11
Insurance $346 609 625 641 658 675
Administrative & General $462 812 833 855 877 900
Property Taxes (22) $0 0 1,900 1,900 1,900 1,900
Panola Partnership / Inducement A Payments $175 306 312 318 325 331
Trustee & Rating Agency Fees $54 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $11,534 9,800 11,832 11,958 12,089 12,209
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $19,016 42,737 40,679 40,567 40,446 44,195
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 61.23% 60.91% 60.58%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,882,700 2,867,300 2,852,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,441,300 1,433,700 1,426,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,405 7,405 7,405
Fuel Consumption (BBtu) 32,017 31,847 31,677
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 68.14 68.14 68.14
Energy Rate ($/MWh)(13) 0.36 0.36 0.37
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 0.24 0.24 0.24
Market Electricity Rates (16) 41.75 42.82 43.92
Natural Gas Price ($/MMBtu)(17) 2.936 3.027 3.121
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 36,988 36,988 36,988
Energy 3,402 3,469 3,565
Tracking Account Payment (2,375) (2,436) (2,498)
Transmission (18) 678 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 1,799 1,836 1,874
Tracking Account Payment (1,454) (1,491) (1,529)
Transmission (18) 339 0 0
Market 0 0 0
Interest Income (19) 951 930 918
------ ------ ------
Total Operating Revenues 56,479 55,448 55,470
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 1,925 1,975 2,026
Deposits to Major Maintenance Reserve (21) 4,525 4,525 4,975
Corps of Engineers 111 111 111
Subcontractor 231 237 243
Lateral Pipeline O&M 21 21 22
Back Up Power 317 325 333
Balance of Plant Parts 424 434 441
Equipment and Materials 320 327 334
Water Treatment Chemicals 179 183 187
SCR Chemicals 138 142 145
Supply/Waste Water Pumping Costs 186 189 193
Electrical Transmission O&M 12 12 12
Insurance 692 710 729
Administrative & General 923 947 972
Property Taxes (22) 1,900 1,900 1,900
Panola Partnership / Inducement A Payments 338 345 351
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 12,335 12,476 13,067
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 44,144 42,972 42,403
</TABLE>
B-55
<PAGE>
Exhibit B-3
Batesville Project
Projected Operating Results
Sensitivity B - Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700
Principal $0 8,250 6,900 7,350 7,800 11,400
Interest $6,269 10,598 10,031 9,529 8,994 8,371
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75
------ ------ ------ ------ ------ ------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.29 1.31 1.30 1.30 1.29 1.29
AVERAGE DEBT COVERAGE (27) 1.45
MINIMUM SENIOR DEBT COVERAGE 1.24
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Major Overhaul Expenses (29) $0 5,850 0 2,821 11,768 0
Major Maintenance Reserve Balance (30) $8,500 7,643 12,588 14,984 8,565 13,561
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 108,300 95,850 83,250
Principal 12,450 12,600 13,050
Interest 7,536 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000 176,000
Principal 0 0 0
Interest 14,362 14,362 14,362
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 34,411 33,667 33,206
TRANSFERS FROM DSRA (25) 371 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.29 1.28 1.28
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (371) (226) (242)
Debt Service Reserve Account Balance (28) 16,914 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 4,525 4,525 4,975
Major Overhaul Expenses (29) 3,047 3,126 0
Major Maintenance Reserve Balance (30) 15,785 18,052 24,020
</TABLE>
B-56
<PAGE>
Exhibit B-3
Batesville Project
Projected Operating Results
Sensitivity B - Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 60.08% 59.58% 59.05% 58.53% 57.81% 57.10%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,828,300 2,804,700 2,780,000 2,755,300 2,721,700 2,688,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,414,200 1,402,300 1,390,000 1,377,700 1,360,800 1,344,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,405 7,405 7,405 7,405 7,405 7,405
Fuel Consumption (BBtu) 31,414 31,151 30,877 30,603 30,229 29,855
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $68.14 68.14 68.14 68.14 58.54 51.69
Energy Rate ($/MWh)(13) $0.39 0.40 0.41 0.42 0.43 0.44
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 59.51 59.51 59.51
Energy Rate ($/MWh)(15) $0.24 0.24 0.24 0.24 0.24 0.24
Market Electricity Rates (16) $45.31 46.74 48.69 50.71 52.36 54.07
Natural Gas Price ($/MMBtu)(17) $3.218 3.318 3.421 3.527 3.636 3.749
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $36,988 36,988 36,988 36,988 31,777 28,055
Energy $3,649 3,730 3,809 3,885 3,946 4,005
Tracking Account Payment ($2,554) (2,611) (2,668) (2,726) (2,777) (2,827)
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 16,152 16,152 16,152
Energy $1,906 1,940 1,973 2,006 2,033 2,060
Tracking Account Payment ($1,564) (1,599) (1,634) (1,669) (1,700) (1,731)
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 0 0 0
Interest Income (19) $904 894 900 869 749 651
------ ------ ------ ------ ------ ------
Total Operating Revenues $55,481 55,494 55,519 55,504 50,180 46,364
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $2,079 2,133 2,189 2,246 2,304 2,364
Deposits to Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Corps of Engineers $111 111 111 111 111 111
Subcontractor $249 256 262 269 276 283
Lateral Pipeline O&M $22 23 24 24 25 26
Back Up Power $343 351 361 370 379 389
Balance of Plant Parts $450 459 463 471 478 484
Equipment and Materials $339 345 350 355 359 367
Water Treatment Chemicals $190 193 196 200 202 205
SCR Chemicals $148 151 154 157 159 161
Supply/Waste Water Pumping Costs $195 202 204 207 208 214
Electrical Transmission O&M $12 13 13 13 14 14
Insurance $748 767 787 808 829 850
Administrative & General $997 1,023 1,050 1,077 1,105 1,134
Property Taxes (22) $1,900 1,900 1,900 4,438 4,386 4,489
Panola Partnership / Inducement A Payments $359 366 373 380 388 396
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $13,583 14,135 14,710 17,863 18,458 16,580
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $41,898 41,359 40,809 37,641 31,722 29,784
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 56.02% 54.95% 54.17%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,637,300 2,586,700 2,550,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,318,700 1,293,300 1,275,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,405 7,405 7,405
Fuel Consumption (BBtu) 29,293 28,730 28,323
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 51.69 51.69
Energy Rate ($/MWh)(13) 0.46 0.47 0.48
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 0.24 0.24 0.24
Market Electricity Rates (16) 56.68 59.38 61.45
Natural Gas Price ($/MMBtu)(17) 3.865 3.985 4.108
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 28,055 28,055
Energy 4,061 4,113 4,157
Tracking Account Payment (2,860) (2,892) (2,939)
Transmission (18) 0 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 2,074 2,087 2,111
Tracking Account Payment (1,751) (1,771) (1,800)
Transmission (18) 0 0 0
Market 0 0 0
Interest Income (19) 650 627 619
------ ------ ------
Total Operating Revenues 46,381 46,371 46,354
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 2,425 2,488 2,553
Deposits to Major Maintenance Reserve (21) 5,375 5,778 6,211
Corps of Engineers 111 111 111
Subcontractor 291 298 306
Lateral Pipeline O&M 26 27 28
Back Up Power 399 409 421
Balance of Plant Parts 487 493 497
Equipment and Materials 368 369 375
Water Treatment Chemicals 207 208 210
SCR Chemicals 162 163 164
Supply/Waste Water Pumping Costs 214 217 218
Electrical Transmission O&M 15 15 15
Insurance 872 895 918
Administrative & General 1,163 1,193 1,224
Property Taxes (22) 4,358 4,239 4,180
Panola Partnership / Inducement A Payments 404 412 420
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 16,970 17,408 17,944
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 29,411 28,963 28,410
</TABLE>
B-57
<PAGE>
Exhibit B-3
Batesville Project
Projected Operating Results
Sensitivity B - Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0
Principal $13,500 14,100 15,300 15,300 12,000 0
Interest $4,787 3,809 2,778 1,682 645 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 9,328
Interest $14,362 14,362 14,362 14,362 14,362 14,171
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29
ANNUAL DEBT SERVICE COVERAGE (26) 1.29 1.28 1.27 1.27 1.24 1.27
AVERAGE DEBT COVERAGE (27) 1.45
MINIMUM SENIOR DEBT COVERAGE 1.24
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Major Overhaul Expenses (29) $19,843 10,269 0 6,447 21,249 0
Major Maintenance Reserve Balance (30) $10,846 6,923 13,484 14,423 1,109 6,170
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0 0
Principal 0 0 0
Interest 0 0 0
Series B Bonds
Balance Outstanding 166,672 156,640 146,608
Principal 10,032 10,032 10,560
Interest 13,396 12,577 11,748
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 23,492 22,673 22,372
TRANSFERS FROM DSRA (25) 409 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 1.27 1.28 1.30
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (409) (145) (607)
Debt Service Reserve Account Balance (28) 11,407 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 5,375 5,778 6,211
Major Overhaul Expenses (29) 5,091 0 4,040
Major Maintenance Reserve Balance (30) 6,793 12,945 15,828
</TABLE>
B-58
<PAGE>
Exhibit B-3
Batesville Project
Projected Operating Results
Sensitivity B - Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 53.39% 53.11% 52.82% 51.39% 49.45% 48.80%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,513,300 2,500,000 2,486,700 2,419,300 2,328,000 2,297,300
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,256,700 1,250,000 1,243,300 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 1,209,700 1,164,000 1,148,700
Heat Rate (Btu/kWh)(10) 7,405 7,405 7,405 7,405 7,405 7,405
Fuel Consumption (BBtu) 27,915 27,767 27,619 26,871 25,857 25,516
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $51.69 51.69 51.69 51.69 51.69 51.69
Energy Rate ($/MWh)(13) $0.49 0.50 0.52 0.54 0.55 0.57
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $0.24 0.24 0.24 0.00 0.00 0.00
Market Electricity Rates (16) $63.59 65.17 66.79 70.58 72.58 73.97
Natural Gas Price ($/MMBtu)(17) $4.236 4.367 4.502 4.642 4.786 4.934
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $28,055 28,055 28,055 28,055 28,055 28,055
Energy $4,222 4,325 4,426 4,452 4,400 4,480
Tracking Account Payment ($2,987) (3,063) (3,141) (3,151) (3,126) (3,181)
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 0 0 0
Energy $2,134 2,178 2,223 0 0 0
Tracking Account Payment ($1,829) (1,876) (1,923) 0 0 0
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 85,381 84,483 84,969
Interest Income (19) $586 616 463 746 715 677
------ ------ ------ ------ ------ ------
Total Operating Revenues $46,333 46,387 46,254 115,482 114,527 115,000
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 41,577 41,247 41,966
Labor $2,619 2,688 2,757 2,829 2,903 2,978
Deposits to Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Corps of Engineers $111 111 111 111 111 111
Subcontractor $314 322 331 339 348 357
Lateral Pipeline O&M $28 29 30 31 31 32
Back Up Power $432 442 454 465 478 490
Balance of Plant Parts $501 514 522 523 517 524
Equipment and Materials $377 386 395 392 388 393
Water Treatment Chemicals $213 217 221 221 218 221
SCR Chemicals $166 169 172 171 171 172
Supply/Waste Water Pumping Costs $222 225 231 229 227 231
Electrical Transmission O&M $16 16 17 17 17 18
Insurance $942 967 992 1,018 1,044 1,071
Administrative & General $1,256 1,289 1,322 1,357 1,392 1,428
Property Taxes (22) $4,065 3,965 4,124 4,244 4,331 4,161
Panola Partnership / Inducement A Payments $428 437 446 455 464 473
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $18,460 19,048 19,935 62,367 62,897 64,305
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $27,873 27,339 26,319 53,115 51,630 50,695
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 47.68% 46.46%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 2,244,700 911,400
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 1,122,300 729,100
Heat Rate (Btu/kWh)(10) 7,405 7,405
Fuel Consumption (BBtu) 24,931 12,147
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 43.07
Energy Rate ($/MWh)(13) 0.58 0.60
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00 0.00
Energy Rate ($/MWh)(15) 0.00 0.00
Market Electricity Rates (16) 76.89 79.33
Natural Gas Price ($/MMBtu)(17) 5.087 5.245
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 11,688
Energy 4,512 1,887
Tracking Account Payment (3,204) (1,341)
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Market 86,294 57,840
Interest Income (19) 780 730
------ ------
Total Operating Revenues 116,437 70,803
OPERATING EXPENSES ($000)(20)
Fuel Expense 42,273 28,314
Labor 3,056 1,567
Deposits to Major Maintenance Reserve (21) 525 282
Corps of Engineers 111 55
Subcontractor 366 188
Lateral Pipeline O&M 33 17
Back Up Power 503 359
Balance of Plant Parts 525 262
Equipment and Materials 394 197
Water Treatment Chemicals 221 111
SCR Chemicals 172 87
Supply/Waste Water Pumping Costs 229 115
Electrical Transmission O&M 18 9
Insurance 1,099 564
Administrative & General 1,465 752
Property Taxes (22) 3,921 1,795
Panola Partnership / Inducement A Payments 483 246
Trustee & Rating Agency Fees 93 46
------ ------
Total Operating Expenses 55,487 34,966
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 60,950 35,837
</TABLE>
B-59
<PAGE>
Exhibit B-3
Batesville Project
Projected Operating Results
Sensitivity B - Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0
Principal $0 0 0 0 0 0
Interest $0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816
Principal $10,208 12,144 7,568 18,480 18,832 19,008
Interest $10,893 10,021 9,123 8,283 6,768 5,228
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.32 1.36 1.57 2.00 2.04 2.09
AVERAGE DEBT COVERAGE (27) 1.45
MINIMUM SENIOR DEBT COVERAGE 1.24
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Major Overhaul Expenses (29) $21,486 0 10,061 0 14,894 0
Major Maintenance Reserve Balance (30) $1,890 9,172 7,332 16,030 10,935 21,122
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 49,808 25,520
Principal 24,288 25,520
Interest 3,569 1,041
Letter-of-Credit Fees 64 32
------ ------
Total Debt Service 27,921 26,593
TRANSFERS FROM DSRA (25) 0 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 2.18 2.35
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account 12,385 (26,561)
Debt Service Reserve Account Balance (28) 26,561 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 525 282
Major Overhaul Expenses (29) 17,861 0
Major Maintenance Reserve Balance (30) 4,948 5,366
</TABLE>
B-60
<PAGE>
Footnotes to Exhibit B-3
The footnotes to Exhibit B-3 are the same as the footnotes for Exhibit B-1,
except:
10. Assumes Facility heat rate is 5 percent higher than that assumed in the
Base Case and no liquidated damage payments are due from the Contractor.
B-61
<PAGE>
Exhibit B-4
Batesville Project
Projected Operating Results
Sensitivity C - Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 66.71% 63.73% 63.73% 63.29% 62.85% 62.04%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,832,000 3,000,000 3,000,000 2,979,300 2,958,700 2,920,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 916,000 1,500,000 1,500,000 1,489,700 1,479,300 1,460,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 19,379 31,734 31,734 31,515 31,297 30,895
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $57.30 57.30 57.30 57.30 57.30 63.62
Energy Rate ($/MWh)(13) $1.18 1.20 1.24 1.27 1.31 1.36
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $58.33 58.33 58.33 58.33 58.33 59.51
Energy Rate ($/MWh)(15) $1.09 1.12 1.15 1.18 1.21 1.24
Market Electricity Rates (16) $34.55 35.56 36.59 37.95 39.36 40.54
Natural Gas Price ($/MMBtu)(17) $2.445 2.521 2.599 2.679 2.762 2.848
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $18,143 31,102 31,102 31,102 31,102 34,535
Energy $1,832 3,060 3,150 3,218 3,284 3,359
Tracking Account Payment $322 544 561 575 588 599
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267
Aquila/UtiliCorp
Capacity $9,235 15,832 15,832 15,832 15,832 16,152
Energy $980 1,647 1,690 1,722 1,754 1,777
Tracking Account Payment $20 34 35 36 37 37
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133
Market $0 0 0 0 0 0
Interest Income (19) $403 917 864 863 861 944
------ ------ ------ ------ ------ ------
Total Operating Revenues $32,919 56,536 56,634 56,747 56,858 60,803
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $1,059 1,862 1,911 1,961 2,012 2,064
Deposits to Major Maintenance Reserve (21) $9,350 4,978 4,978 4,978 4,978 4,978
Corps of Engineers $71 122 122 122 122 122
Subcontractor $127 223 229 235 241 247
Lateral Pipeline O&M $11 20 21 21 22 22
Back Up Power $175 307 315 323 331 340
Balance of Plant Parts $253 428 437 447 453 460
Equipment and Materials $192 320 329 335 342 346
Water Treatment Chemicals $107 180 185 189 192 195
SCR Chemicals $82 140 144 147 151 153
Supply/Waste Water Pumping Costs $113 189 194 197 200 202
Electrical Transmission O&M $6 11 11 12 12 12
Insurance $381 670 687 705 724 742
Administrative & General $508 893 917 940 965 990
Property Taxes (22) $0 0 2,090 2,090 2,090 2,090
Panola Partnership / Inducement A Payments $193 337 343 350 357 364
Trustee & Rating Agency Fees $59 102 102 102 102 102
------ ------ ------ ------ ------ ------
Total Operating Expenses $12,687 10,782 13,015 13,154 13,294 13,429
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $20,232 45,754 43,619 43,593 43,564 47,374
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 61.23% 60.91% 60.58%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,882,700 2,867,300 2,852,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,441,300 1,433,700 1,426,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 30,493 30,331 30,168
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 68.14 68.14 68.14
Energy Rate ($/MWh)(13) 1.39 1.43 1.47
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.27 1.31 1.34
Market Electricity Rates (16) 41.75 42.82 43.92
Natural Gas Price ($/MMBtu)(17) 2.936 3.027 3.121
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 36,988 36,988 36,988
Energy 3,402 3,469 3,565
Tracking Account Payment 609 625 641
Transmission (18) 678 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 1,799 1,836 1,874
Tracking Account Payment 38 39 40
Transmission (18) 339 0 0
Market 0 0 0
Interest Income (19) 951 930 918
------ ------ ------
Total Operating Revenues 60,956 60,039 60,178
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 2,118 2,173 2,229
Deposits to Major Maintenance Reserve (21) 4,978 4,978 5,473
Corps of Engineers 122 122 122
Subcontractor 254 261 267
Lateral Pipeline O&M 23 23 24
Back Up Power 348 358 368
Balance of Plant Parts 467 477 483
Equipment and Materials 350 357 364
Water Treatment Chemicals 197 201 205
SCR Chemicals 156 155 158
Supply/Waste Water Pumping Costs 203 211 214
Electrical Transmission O&M 13 13 13
Insurance 762 782 802
Administrative & General 1,016 1,042 1,069
Property Taxes (22) 2,090 2,090 2,090
Panola Partnership / Inducement A Payments 372 379 387
Trustee & Rating Agency Fees 102 102 102
------ ------ ------
Total Operating Expenses 13,571 13,724 14,370
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 47,385 46,315 45,808
</TABLE>
B-62
<PAGE>
Exhibit B-4
Batesville Project
Projected Operating Results
Sensitivity C - Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700
Principal $0 8,250 6,900 7,350 7,800 11,400
Interest $6,269 10,598 10,031 9,529 8,994 8,371
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75
------ ------ ------ ------ ------ ------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.38 1.40 1.39 1.39 1.39 1.38
AVERAGE DEBT COVERAGE (27) 1.57
MINIMUM SENIOR DEBT COVERAGE 1.36
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $9,350 4,978 4,978 4,978 4,978 4,978
Major Overhaul Expenses (29) $0 5,850 0 2,821 11,768 0
Major Maintenance Reserve Balance (30) $9,350 8,992 14,465 17,418 11,586 17,201
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 108,300 95,850 83,250
Principal 12,450 12,600 13,050
Interest 7,536 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000 176,000
Principal 0 0 0
Interest 14,362 14,362 14,362
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 34,411 33,667 33,206
TRANSFERS FROM DSRA (25) 371 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.39 1.38 1.39
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (371) (226) (242)
Debt Service Reserve Account Balance (28) 16,914 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 4,978 4,978 5,473
Major Overhaul Expenses (29) 3,047 3,126 0
Major Maintenance Reserve Balance (30) 20,078 23,034 29,774
</TABLE>
B-63
<PAGE>
Exhibit B-4
Batesville Project
Projected Operating Results
Sensitivity C - Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 60.08% 59.58% 59.05% 58.53% 57.81% 57.10%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,828,300 2,804,700 2,780,000 2,755,300 2,721,700 2,688,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,414,200 1,402,300 1,390,000 1,377,700 1,360,800 1,344,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 29,918 29,668 29,407 29,146 28,790 28,434
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $68.14 68.14 68.14 68.14 58.54 51.69
Energy Rate ($/MWh)(13) $1.52 1.57 1.62 1.66 1.71 1.76
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 59.51 59.51 59.51
Energy Rate ($/MWh)(15) $1.38 1.41 1.45 1.49 1.53 1.57
Market Electricity Rates (16) $45.31 46.74 48.69 50.71 52.36 54.07
Natural Gas Price ($/MMBtu)(17) $3.218 3.318 3.421 3.527 3.636 3.749
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $36,988 36,988 36,988 36,988 31,777 28,055
Energy $3,649 3,730 3,809 3,885 3,946 4,005
Tracking Account Payment $655 670 685 700 712 725
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 16,152 16,152 16,152
Energy $1,906 1,940 1,973 2,006 2,033 2,060
Tracking Account Payment $41 42 43 44 45 45
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 0 0 0
Interest Income (19) $904 894 900 869 749 651
------ ------ ------ ------ ------ ------
Total Operating Revenues $60,294 60,416 60,549 60,643 55,414 51,694
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $2,287 2,346 2,407 2,470 2,534 2,600
Deposits to Major Maintenance Reserve (21) $5,883 6,324 6,798 7,308 7,856 5,500
Corps of Engineers $122 122 122 122 122 122
Subcontractor $274 281 289 296 304 312
Lateral Pipeline O&M $25 25 26 27 27 28
Back Up Power $376 386 396 407 417 429
Balance of Plant Parts $492 501 513 521 527 532
Equipment and Materials $373 379 384 393 396 403
Water Treatment Chemicals $209 213 216 220 223 226
SCR Chemicals $161 164 167 169 176 177
Supply/Waste Water Pumping Costs $216 219 225 227 233 234
Electrical Transmission O&M $14 14 14 15 15 16
Insurance $823 844 866 889 912 935
Administrative & General $1,097 1,125 1,155 1,185 1,215 1,247
Property Taxes (22) $2,090 2,090 2,090 4,882 4,825 4,938
Panola Partnership / Inducement A Payments $394 402 410 419 427 435
Trustee & Rating Agency Fees $102 102 102 102 102 102
------ ------ ------ ------ ------ ------
Total Operating Expenses $14,938 15,537 16,180 19,652 20,311 18,236
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $45,356 44,879 44,369 40,991 35,103 33,458
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 56.02% 54.95% 54.17%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,637,300 2,586,700 2,550,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,318,700 1,293,300 1,275,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 27,898 27,362 26,974
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 51.69 51.69
Energy Rate ($/MWh)(13) 1.82 1.88 1.93
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.61 1.65 1.69
Market Electricity Rates (16) 56.68 59.38 61.45
Natural Gas Price ($/MMBtu)(17) 3.865 3.985 4.108
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 28,055 28,055
Energy 4,061 4,113 4,157
Tracking Account Payment 734 742 754
Transmission (18) 0 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 2,074 2,087 2,111
Tracking Account Payment 46 46 47
Transmission (18) 0 0 0
Market 0 0 0
Interest Income (19) 650 627 619
------ ------ ------
Total Operating Revenues 51,772 51,822 51,895
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 2,668 2,737 2,808
Deposits to Major Maintenance Reserve (21) 5,913 6,356 6,833
Corps of Engineers 122 122 122
Subcontractor 320 328 337
Lateral Pipeline O&M 29 30 30
Back Up Power 439 450 462
Balance of Plant Parts 538 539 547
Equipment and Materials 404 407 413
Water Treatment Chemicals 227 229 231
SCR Chemicals 178 178 180
Supply/Waste Water Pumping Costs 237 237 241
Electrical Transmission O&M 16 16 17
Insurance 960 985 1,010
Administrative & General 1,280 1,313 1,347
Property Taxes (22) 4,794 4,663 4,598
Panola Partnership / Inducement A Payments 444 453 462
Trustee & Rating Agency Fees 102 102 102
------ ------ ------
Total Operating Expenses 18,671 19,145 19,740
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 33,101 32,677 32,155
</TABLE>
B-64
<PAGE>
Exhibit B-4
Batesville Project
Projected Operating Results
Sensitivity C - Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0
Principal $13,500 14,100 15,300 15,300 12,000 0
Interest $4,787 3,809 2,778 1,682 645 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 9,328
Interest $14,362 14,362 14,362 14,362 14,362 14,171
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29
ANNUAL DEBT SERVICE COVERAGE (26) 1.39 1.39 1.38 1.38 1.36 1.42
AVERAGE DEBT COVERAGE (27) 1.57
MINIMUM SENIOR DEBT COVERAGE 1.36
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $5,883 6,324 6,798 7,308 7,856 5,500
Major Overhaul Expenses (29) $19,843 10,269 0 6,447 21,249 0
Major Maintenance Reserve Balance (30) $17,452 14,467 22,061 24,135 12,069 18,233
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0 0
Principal 0 0 0
Interest 0 0 0
Series B Bonds
Balance Outstanding 166,672 156,640 146,608
Principal 10,032 10,032 10,560
Interest 13,396 12,577 11,748
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 23,492 22,673 22,372
TRANSFERS FROM DSRA (25) 409 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 1.43 1.45 1.46
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (409) (145) (607)
Debt Service Reserve Account Balance (28) 11,407 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 5,913 6,356 6,833
Major Overhaul Expenses (29) 5,091 0 4,040
Major Maintenance Reserve Balance (30) 20,058 27,517 31,823
</TABLE>
B-65
<PAGE>
Exhibit B-4
Batesville Project
Projected Operating Results
Sensitivity C - Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 53.39% 53.11% 52.82% 52.04% 50.26% 49.41%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,513,300 2,500,000 2,486,700 2,450,000 2,366,000 2,326,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,256,700 1,250,000 1,243,300 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 1,225,000 1,183,000 1,163,000
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 26,586 26,445 26,304 25,916 25,028 24,604
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $51.69 51.69 51.69 51.69 51.69 51.69
Energy Rate ($/MWh)(13) $1.98 2.04 2.10 2.17 2.23 2.31
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $1.74 1.78 1.83 0.00 0.00 0.00
Market Electricity Rates (16) $63.59 65.17 66.79 70.04 71.91 73.50
Natural Gas Price ($/MMBtu)(17) $4.236 4.367 4.502 4.642 4.786 4.934
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $28,055 28,055 28,055 28,055 28,055 28,055
Energy $4,222 4,325 4,426 4,508 4,472 4,536
Tracking Account Payment $766 786 806 819 815 826
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 0 0 0
Energy $2,134 2,178 2,223 0 0 0
Tracking Account Payment $48 49 50 0 0 0
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 85,799 85,070 85,481
Interest Income (19) $586 616 463 746 715 677
------ ------ ------ ------ ------ ------
Total Operating Revenues $51,963 52,161 52,176 119,927 119,127 119,575
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 40,098 39,924 40,465
Labor $2,881 2,956 3,033 3,112 3,193 3,276
Deposits to Major Maintenance Reserve (21) $7,345 7,896 8,488 9,125 9,809 10,545
Corps of Engineers $122 122 122 122 122 122
Subcontractor $345 354 364 373 383 393
Lateral Pipeline O&M $31 32 33 34 34 35
Back Up Power $475 487 500 513 526 539
Balance of Plant Parts $554 563 574 581 578 583
Equipment and Materials $415 424 433 437 433 440
Water Treatment Chemicals $234 239 244 246 244 246
SCR Chemicals $181 188 190 191 192 192
Supply/Waste Water Pumping Costs $241 248 254 257 252 255
Electrical Transmission O&M $17 18 18 19 19 20
Insurance $1,036 1,063 1,091 1,119 1,149 1,178
Administrative & General $1,382 1,418 1,455 1,493 1,531 1,571
Property Taxes (22) $4,472 4,362 4,536 4,668 4,764 4,577
Panola Partnership / Inducement A Payments $471 481 490 500 510 520
Trustee & Rating Agency Fees $102 102 102 102 102 102
------ ------ ------ ------ ------ ------
Total Operating Expenses $20,304 20,953 21,927 62,990 63,765 65,059
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $31,659 31,208 30,249 56,937 55,362 54,516
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 48.50% 47.19%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 2,283,300 925,600
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 1,141,700 740,400
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 24,153 11,749
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 43.07
Energy Rate ($/MWh)(13) 2.38 2.45
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00 0.00
Energy Rate ($/MWh)(15) 0.00 0.00
Market Electricity Rates (16) 76.13 78.65
Natural Gas Price ($/MMBtu)(17) 5.087 5.245
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 11,688
Energy 4,589 1,916
Tracking Account Payment 836 350
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Market 86,918 58,232
Interest Income (19) 780 730
------ ------
Total Operating Revenues 121,179 72,916
OPERATING EXPENSES ($000)(20)
Fuel Expense 40,956 27,384
Labor 3,361 1,724
Deposits to Major Maintenance Reserve (21) 578 310
Corps of Engineers 122 61
Subcontractor 403 207
Lateral Pipeline O&M 36 19
Back Up Power 554 396
Balance of Plant Parts 586 293
Equipment and Materials 442 220
Water Treatment Chemicals 248 124
SCR Chemicals 192 97
Supply/Waste Water Pumping Costs 257 128
Electrical Transmission O&M 20 10
Insurance 1,209 620
Administrative & General 1,612 827
Property Taxes (22) 4,313 1,975
Panola Partnership / Inducement A Payments 531 271
Trustee & Rating Agency Fees 102 51
------ ------
Total Operating Expenses 55,522 34,717
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 65,657 38,199
</TABLE>
B-66
<PAGE>
Exhibit B-4
Batesville Project
Projected Operating Results
Sensitivity C - Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0
Principal $0 0 0 0 0 0
Interest $0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816
Principal $10,208 12,144 7,568 18,480 18,832 19,008
Interest $10,893 10,021 9,123 8,283 6,768 5,228
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.50 1.53 1.81 2.14 2.18 2.24
AVERAGE DEBT COVERAGE (27) 1.57
MINIMUM SENIOR DEBT COVERAGE 1.36
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $7,345 7,896 8,488 9,125 9,809 10,545
Major Overhaul Expenses (29) $21,486 0 10,061 0 14,894 0
Major Maintenance Reserve Balance (30) $19,432 28,397 28,386 39,072 36,136 48,668
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 49,808 25,520
Principal 24,288 25,520
Interest 3,569 1,041
Letter-of-Credit Fees 64 32
------ ------
Total Debt Service 27,921 26,593
TRANSFERS FROM DSRA (25) 0 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 2.35 2.44
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account 12,385 (26,561)
Debt Service Reserve Account Balance (28) 26,561 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 578 310
Major Overhaul Expenses (29) 17,861 0
Major Maintenance Reserve Balance (30) 34,062 35,309
</TABLE>
B-67
<PAGE>
Footnotes to Exhibit B-4
The footnotes to Exhibit B-4 are the same as the footnotes for Exhibit B-1,
except:
20. Non-fuel related operating and maintenance costs assumed to be 10 percent
higher than that assumed in the Base Case.
21. Assumed to be 10 percent higher than that assumed in the Base Case.
B-68
<PAGE>
Exhibit B-5
Batesville Project
Projected Operating Results
Sensitivity D - Increased Inflation (4%)
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 66.71% 63.73% 63.73% 63.29% 62.85% 62.04%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,832,000 3,000,000 3,000,000 2,979,300 2,958,700 2,920,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 916,000 1,500,000 1,500,000 1,489,700 1,479,300 1,460,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 19,379 31,734 31,734 31,515 31,297 30,895
COMMODITY PRICES
General Inflation (%)(11) 4.00 4.00 4.00 4.00 4.00 4.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $57.30 57.30 57.30 57.30 57.30 63.62
Energy Rate ($/MWh)(13) $1.18 1.21 1.25 1.29 1.33 1.38
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $58.33 58.33 58.33 58.33 58.33 59.51
Energy Rate ($/MWh)(15) $1.12 1.17 1.21 1.26 1.31 1.37
Market Electricity Rates (16) $35.50 37.03 38.63 40.61 42.69 44.57
Natural Gas Price ($/MMBtu)(17) $2.512 2.625 2.743 2.866 2.995 3.130
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $18,143 31,102 31,102 31,102 31,102 34,535
Energy $1,832 3,060 3,150 3,218 3,284 3,359
Tracking Account Payment $331 567 592 615 638 658
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267
Aquila/UtiliCorp
Capacity $9,235 15,832 15,832 15,832 15,832 16,152
Energy $1,007 1,715 1,784 1,842 1,903 1,953
Tracking Account Payment $21 35 37 38 40 41
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133
Market $0 0 0 0 0 0
Interest Income (19) $476 1,084 1,021 1,020 1,017 1,116
------ ------ ------ ------ ------ ------
Total Operating Revenues $33,028 56,795 56,918 57,067 57,216 61,215
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $976 1,740 1,809 1,882 1,957 2,035
Deposits to Major Maintenance Reserve (21) $4,100 5,475 5,475 5,475 5,475 5,475
Corps of Engineers $64 111 111 111 111 111
Subcontractor $117 209 217 226 235 244
Lateral Pipeline O&M $11 19 20 20 21 22
Back Up Power $163 291 303 315 328 341
Balance of Plant Parts $234 401 414 429 444 456
Equipment and Materials $176 302 311 322 333 342
Water Treatment Chemicals $99 169 175 181 187 192
SCR Chemicals $77 131 135 143 146 149
Supply/Waste Water Pumping Costs $102 176 180 188 195 197
Electrical Transmission O&M $6 10 11 11 12 12
Insurance $351 626 651 677 704 732
Administrative & General $468 834 868 902 939 976
Property Taxes (22) $0 0 1,900 1,900 1,900 1,900
Panola Partnership / Inducement A Payments $175 306 312 318 325 331
Trustee & Rating Agency Fees $54 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $7,173 10,893 12,985 13,193 13,405 13,608
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $25,855 45,902 43,933 43,874 43,811 47,607
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 61.23% 60.91% 60.58%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,882,700 2,867,300 2,852,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,441,300 1,433,700 1,426,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 30,493 30,331 30,168
COMMODITY PRICES
General Inflation (%)(11) 4.00 4.00 4.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 68.14 68.14 68.14
Energy Rate ($/MWh)(13) 1.42 1.46 1.51
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.42 1.48 1.54
Market Electricity Rates (16) 46.53 48.38 50.30
Natural Gas Price ($/MMBtu)(17) 3.271 3.418 3.572
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 36,988 36,988 36,988
Energy 3,402 3,469 3,565
Tracking Account Payment 679 706 733
Transmission (18) 678 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 2,005 2,074 2,146
Tracking Account Payment 42 44 46
Transmission (18) 339 0 0
Market 0 0 0
Interest Income (19) 1,124 1,099 1,085
------ ------ ------
Total Operating Revenues 61,408 60,532 60,715
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 2,117 2,201 2,289
Deposits to Major Maintenance Reserve (21) 5,475 5,475 5,738
Corps of Engineers 111 111 111
Subcontractor 254 264 274
Lateral Pipeline O&M 23 24 25
Back Up Power 354 369 382
Balance of Plant Parts 467 482 501
Equipment and Materials 350 361 376
Water Treatment Chemicals 197 204 211
SCR Chemicals 156 159 163
Supply/Waste Water Pumping Costs 203 211 218
Electrical Transmission O&M 13 13 14
Insurance 761 792 823
Administrative & General 1,015 1,056 1,098
Property Taxes (22) 1,900 1,900 1,900
Panola Partnership / Inducement A Payments 338 345 351
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 13,827 14,060 14,567
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 47,581 46,472 46,148
</TABLE>
B-69
<PAGE>
Exhibit B-5
Batesville Project
Projected Operating Results
Sensitivity D - Increased Inflation (4%)
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700
Principal $0 8,250 6,900 7,350 7,800 11,400
Interest $6,269 10,598 10,031 9,529 8,994 8,371
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75
------ ------ ------ ------ ------ ------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.76 1.41 1.40 1.40 1.40 1.39
AVERAGE DEBT COVERAGE (27) 1.67
MINIMUM SENIOR DEBT COVERAGE 1.35
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $4,100 5,475 5,475 5,475 5,475 5,475
Major Overhaul Expenses (29) $0 6,092 0 3,019 12,765 0
Major Maintenance Reserve Balance (30) $4,100 3,750 9,469 12,540 6,065 11,934
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 108,300 95,850 83,250
Principal 12,450 12,600 13,050
Interest 7,536 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000 176,000
Principal 0 0 0
Interest 14,362 14,362 14,362
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 34,411 33,667 33,206
TRANSFERS FROM DSRA (25) 371 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.39 1.39 1.40
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (371) (226) (242)
Debt Service Reserve Account Balance (28) 16,914 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 5,475 5,475 5,738
Major Overhaul Expenses (29) 3,395 3,531 0
Major Maintenance Reserve Balance (30) 14,790 17,695 24,583
</TABLE>
B-70
<PAGE>
Exhibit B-5
Batesville Project
Projected Operating Results
Sensitivity D - Increased Inflation (4%)
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 60.08% 59.58% 59.05% 58.53% 57.81% 57.10%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,828,300 2,804,700 2,780,000 2,755,300 2,721,700 2,688,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,414,200 1,402,300 1,390,000 1,377,700 1,360,800 1,344,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 29,918 29,668 29,407 29,146 28,790 28,434
COMMODITY PRICES
General Inflation (%)(11) 4.00 4.00 4.00 4.00 4.00 4.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $68.14 68.14 68.14 68.14 58.54 51.69
Energy Rate ($/MWh)(13) $1.56 1.61 1.66 1.72 1.77 1.82
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 59.51 59.51 59.51
Energy Rate ($/MWh)(15) $1.60 1.66 1.73 1.80 1.87 1.95
Market Electricity Rates (16) $52.60 55.00 58.07 61.30 64.17 67.17
Natural Gas Price ($/MMBtu)(17) $3.733 3.901 4.076 4.260 4.451 4.652
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $36,988 36,988 36,988 36,988 31,777 28,055
Energy $3,649 3,730 3,809 3,885 3,946 4,005
Tracking Account Payment $760 788 816 845 872 900
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 16,152 16,152 16,152
Energy $2,213 2,282 2,353 2,425 2,491 2,559
Tracking Account Payment $48 49 51 53 55 56
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 0 0 0
Interest Income (19) $1,069 1,057 1,063 1,028 885 770
------ ------ ------ ------ ------ ------
Total Operating Revenues $60,878 61,046 61,231 61,375 56,178 52,497
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $2,381 2,476 2,575 2,678 2,785 2,897
Deposits to Major Maintenance Reserve (21) $7,500 7,900 8,250 8,500 8,750 6,159
Corps of Engineers $111 111 111 111 111 111
Subcontractor $285 297 309 321 334 347
Lateral Pipeline O&M $26 27 28 29 30 31
Back Up Power $398 414 430 448 466 484
Balance of Plant Parts $513 530 546 562 580 593
Equipment and Materials $386 400 413 426 437 448
Water Treatment Chemicals $217 224 231 238 245 251
SCR Chemicals $170 177 179 186 192 198
Supply/Waste Water Pumping Costs $225 231 242 248 253 262
Electrical Transmission O&M $14 15 15 16 17 17
Insurance $856 891 926 963 1,002 1,042
Administrative & General $1,142 1,188 1,235 1,284 1,336 1,389
Property Taxes (22) $1,900 1,900 1,900 4,438 4,386 4,489
Panola Partnership / Inducement A Payments $359 366 373 380 388 396
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $16,576 17,240 17,856 20,921 21,405 19,207
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $44,302 43,806 43,375 40,454 34,773 33,290
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 56.02% 54.95% 54.17%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,637,300 2,586,700 2,550,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,318,700 1,293,300 1,275,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 27,898 27,362 26,974
COMMODITY PRICES
General Inflation (%)(11) 4.00 4.00 4.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 51.69 51.69
Energy Rate ($/MWh)(13) 1.89 1.96 2.01
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 2.02 2.10 2.19
Market Electricity Rates (16) 71.36 75.79 79.50
Natural Gas Price ($/MMBtu)(17) 4.861 5.080 5.308
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 28,055 28,055
Energy 4,061 4,113 4,157
Tracking Account Payment 923 946 975
Transmission (18) 0 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 2,611 2,663 2,731
Tracking Account Payment 58 59 61
Transmission (18) 0 0 0
Market 0 0 0
Interest Income (19) 768 741 732
------ ------ ------
Total Operating Revenues 52,628 52,729 52,862
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 3,013 3,133 3,258
Deposits to Major Maintenance Reserve (21) 6,714 7,319 7,978
Corps of Engineers 111 111 111
Subcontractor 361 376 391
Lateral Pipeline O&M 33 34 35
Back Up Power 504 524 545
Balance of Plant Parts 605 617 635
Equipment and Materials 455 466 478
Water Treatment Chemicals 257 262 268
SCR Chemicals 202 206 210
Supply/Waste Water Pumping Costs 265 272 279
Electrical Transmission O&M 18 19 20
Insurance 1,084 1,127 1,172
Administrative & General 1,445 1,503 1,563
Property Taxes (22) 4,358 4,239 4,180
Panola Partnership / Inducement A Payments 404 412 420
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 19,922 20,713 21,636
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 32,706 32,016 31,226
</TABLE>
B-71
<PAGE>
Exhibit B-5
Batesville Project
Projected Operating Results
Sensitivity D - Increased Inflation (4%)
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0
Principal $13,500 14,100 15,300 15,300 12,000 0
Interest $4,787 3,809 2,778 1,682 645 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 9,328
Interest $14,362 14,362 14,362 14,362 14,362 14,171
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29
ANNUAL DEBT SERVICE COVERAGE (26) 1.36 1.35 1.35 1.36 1.35 1.41
AVERAGE DEBT COVERAGE (27) 1.67
MINIMUM SENIOR DEBT COVERAGE 1.35
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $7,500 7,900 8,250 8,500 8,750 6,159
Major Overhaul Expenses (29) $23,033 12,083 0 7,794 26,040 0
Major Maintenance Reserve Balance (30) $10,648 7,157 15,872 17,610 1,465 7,719
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0 0
Principal 0 0 0
Interest 0 0 0
Series B Bonds
Balance Outstanding 166,672 156,640 146,608
Principal 10,032 10,032 10,560
Interest 13,396 12,577 11,748
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 23,492 22,673 22,372
TRANSFERS FROM DSRA (25) 409 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 1.41 1.42 1.42
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (409) (145) (607)
Debt Service Reserve Account Balance (28) 11,407 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 6,714 7,319 7,978
Major Overhaul Expenses (29) 6,411 0 5,227
Major Maintenance Reserve Balance (30) 8,524 16,397 20,214
</TABLE>
B-72
<PAGE>
Exhibit B-5
Batesville Project
Projected Operating Results
Sensitivity D - Increased Inflation (4%)
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 53.39% 53.11% 52.82% 52.04% 50.26% 49.41%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,513,300 2,500,000 2,486,700 2,450,000 2,366,000 2,326,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,256,700 1,250,000 1,243,300 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 1,225,000 1,183,000 1,163,000
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 26,586 26,445 26,304 25,916 25,028 24,604
COMMODITY PRICES
General Inflation (%)(11) 4.00 4.00 4.00 4.00 4.00 4.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $51.69 51.69 51.69 51.69 51.69 51.69
Energy Rate ($/MWh)(13) $2.08 2.15 2.22 2.30 2.37 2.45
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $2.28 2.37 2.46 0.00 0.00 0.00
Market Electricity Rates (16) $83.39 86.63 89.99 95.66 99.56 103.14
Natural Gas Price ($/MMBtu)(17) $5.547 5.797 6.057 6.330 6.615 6.913
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $28,055 28,055 28,055 28,055 28,055 28,055
Energy $4,222 4,325 4,426 4,508 4,472 4,536
Tracking Account Payment $1,004 1,043 1,085 1,117 1,127 1,158
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 0 0 0
Energy $2,799 2,896 2,995 0 0 0
Tracking Account Payment $63 65 68 0 0 0
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 117,184 117,779 119,952
Interest Income (19) $693 728 547 882 844 800
------ ------ ------ ------ ------ ------
Total Operating Revenues $52,988 53,264 53,327 151,745 152,276 154,500
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 54,683 55,184 56,693
Labor $3,389 3,524 3,665 3,812 3,964 4,123
Deposits to Major Maintenance Reserve (21) $8,696 9,479 10,333 11,263 12,278 13,383
Corps of Engineers $111 111 111 111 111 111
Subcontractor $406 423 439 457 475 494
Lateral Pipeline O&M $37 38 40 41 43 44
Back Up Power $567 590 613 638 664 690
Balance of Plant Parts $652 671 698 713 717 733
Equipment and Materials $490 506 522 537 539 551
Water Treatment Chemicals $275 285 294 302 303 310
SCR Chemicals $215 221 231 235 238 241
Supply/Waste Water Pumping Costs $287 296 306 312 316 321
Electrical Transmission O&M $20 21 22 23 24 25
Insurance $1,219 1,268 1,318 1,371 1,426 1,483
Administrative & General $1,625 1,690 1,758 1,828 1,901 1,977
Property Taxes (22) $4,065 3,965 4,124 4,244 4,331 4,161
Panola Partnership / Inducement A Payments $428 437 446 455 464 473
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $22,575 23,618 25,013 81,118 83,071 85,906
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $30,413 29,646 28,314 70,627 69,205 68,594
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 48.50% 47.19%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 2,283,300 925,600
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 1,141,700 740,400
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 24,153 11,749
COMMODITY PRICES
General Inflation (%)(11) 4.00 4.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 43.07
Energy Rate ($/MWh)(13) 2.53 2.61
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00 0.00
Energy Rate ($/MWh)(15) 0.00 0.00
Market Electricity Rates (16) 108.29 113.40
Natural Gas Price ($/MMBtu)(17) 7.224 7.549
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 11,688
Energy 4,589 1,916
Tracking Account Payment 1,188 503
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Market 123,635 83,961
Interest Income (19) 921 863
------ ------
Total Operating Revenues 158,388 98,931
OPERATING EXPENSES ($000)(20)
Fuel Expense 58,159 39,414
Labor 4,288 2,230
Deposits to Major Maintenance Reserve (21) 1,800 405
Corps of Engineers 111 55
Subcontractor 514 267
Lateral Pipeline O&M 46 24
Back Up Power 717 519
Balance of Plant Parts 747 378
Equipment and Materials 562 285
Water Treatment Chemicals 316 160
SCR Chemicals 247 125
Supply/Waste Water Pumping Costs 329 167
Electrical Transmission O&M 26 13
Insurance 1,542 802
Administrative & General 2,057 1,069
Property Taxes (22) 3,921 1,795
Panola Partnership / Inducement A Payments 483 246
Trustee & Rating Agency Fees 93 46
------ ------
Total Operating Expenses 75,958 48,000
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 82,430 50,931
</TABLE>
B-73
<PAGE>
Exhibit B-5
Batesville Project
Projected Operating Results
Sensitivity D - Increased Inflation (4%)
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0
Principal $0 0 0 0 0 0
Interest $0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816
Principal $10,208 12,144 7,568 18,480 18,832 19,008
Interest $10,893 10,021 9,123 8,283 6,768 5,228
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.44 1.46 1.69 2.65 2.72 2.82
AVERAGE DEBT COVERAGE (27) 1.67
MINIMUM SENIOR DEBT COVERAGE 1.35
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $8,696 9,479 10,333 11,263 12,278 13,383
Major Overhaul Expenses (29) $28,176 0 13,556 0 20,619 0
Major Maintenance Reserve Balance (30) $2,048 11,660 9,195 21,056 14,084 28,382
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 49,808 25,520
Principal 24,288 25,520
Interest 3,569 1,041
Letter-of-Credit Fees 64 32
------ ------
Total Debt Service 27,921 26,593
TRANSFERS FROM DSRA (25) 0 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 2.95 2.91
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account 12,385 (26,561)
Debt Service Reserve Account Balance (28) 26,561 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 1,800 405
Major Overhaul Expenses (29) 25,407 0
Major Maintenance Reserve Balance (30) 6,620 7,240
</TABLE>
B-74
<PAGE>
Footnotes to Exhibit B-5
The footnotes to Exhibit B-5 are the same as the footnotes for Exhibit B-1,
except:
11. General inflation and the GDP-IPD are assumed to escalate at a rate of 4.0
percent per year, rather than 2.6 percent per year, as assumed in the Base
Case.
17. The price of natural gas is assumed to escalate a 0.5 percent above
inflation, or 4.5 percent per year in this case.
19. Based on a reinvestment rate of 6.0 percent per year, as estimated by the
Initial Purchasers based on a general inflation rate of 4.0 percent per
year.
21. Deposits as estimated by the Partnership based on a general inflation rate
of 4.0 percent per year.
29. Major turbine overhaul expenses as estimated by the Partnership, adjusted
to reflect a general inflation rate of 4.0 percent per year.
30. Balance includes interest income based on a reinvestment rate of 6.0
percent per year, as estimated by the Initial Purchasers.
B-75
<PAGE>
Exhibit B-6
Batesville Project
Projected Operating Results
Sensitivity E - Increased Inflation (6%)
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 66.71% 63.73% 63.73% 63.29% 62.85% 62.04%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,832,000 3,000,000 3,000,000 2,979,300 2,958,700 2,920,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 916,000 1,500,000 1,500,000 1,489,700 1,479,300 1,460,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 19,379 31,734 31,734 31,515 31,297 30,895
COMMODITY PRICES
General Inflation (%)(11) 6.00 6.00 6.00 6.00 6.00 6.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $57.30 57.30 57.30 57.30 57.30 63.62
Energy Rate ($/MWh)(13) $1.19 1.22 1.26 1.31 1.35 1.41
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $58.33 58.33 58.33 58.33 58.33 59.51
Energy Rate ($/MWh)(15) $1.17 1.24 1.31 1.39 1.47 1.56
Market Electricity Rates (16) $36.88 39.21 41.69 44.67 47.86 50.93
Natural Gas Price ($/MMBtu)(17) $2.609 2.778 2.959 3.151 3.356 3.574
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $18,143 31,102 31,102 31,102 31,102 34,535
Energy $1,832 3,060 3,150 3,218 3,284 3,359
Tracking Account Payment $344 600 639 676 715 752
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267
Aquila/UtiliCorp
Capacity $9,235 15,832 15,832 15,832 15,832 16,152
Energy $1,046 1,816 1,925 2,026 2,133 2,232
Tracking Account Payment $22 38 40 42 45 47
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133
Market $0 0 0 0 0 0
Interest Income (19) $622 1,418 1,335 1,333 1,330 1,459
------ ------ ------ ------ ------ ------
Total Operating Revenues $33,227 57,265 57,423 57,629 57,841 61,936
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $995 1,807 1,916 2,031 2,152 2,282
Deposits to Major Maintenance Reserve (21) $4,500 6,650 6,650 6,650 6,650 6,650
Corps of Engineers $64 111 111 111 111 111
Subcontractor $119 217 230 243 258 274
Lateral Pipeline O&M $11 20 21 22 23 25
Back Up Power $170 309 327 347 368 390
Balance of Plant Parts $239 414 441 460 488 508
Equipment and Materials $179 311 329 349 364 381
Water Treatment Chemicals $101 175 186 195 206 215
SCR Chemicals $80 135 144 152 160 166
Supply/Waste Water Pumping Costs $104 180 194 201 213 223
Electrical Transmission O&M $6 11 11 12 13 14
Insurance $358 650 689 730 774 821
Administrative & General $477 867 919 974 1,032 1,094
Property Taxes (22) $0 0 1,900 1,900 1,900 1,900
Panola Partnership / Inducement A Payments $175 306 312 318 325 331
Trustee & Rating Agency Fees $54 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $7,632 12,256 14,473 14,788 15,130 15,478
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $25,595 45,009 42,950 42,841 42,711 46,458
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 61.23% 60.91% 60.58%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,882,700 2,867,300 2,852,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,441,300 1,433,700 1,426,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 30,493 30,331 30,168
COMMODITY PRICES
General Inflation (%)(11) 6.00 6.00 6.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 68.14 68.14 68.14
Energy Rate ($/MWh)(13) 1.45 1.50 1.56
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.65 1.75 1.86
Market Electricity Rates (16) 54.19 57.43 60.85
Natural Gas Price ($/MMBtu)(17) 3.807 4.054 4.317
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 36,988 36,988 36,988
Energy 3,402 3,469 3,565
Tracking Account Payment 790 837 887
Transmission (18) 678 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 2,335 2,462 2,596
Tracking Account Payment 49 52 55
Transmission (18) 339 0 0
Market 0 0 0
Interest Income (19) 1,469 1,438 1,418
------ ------ ------
Total Operating Revenues 62,202 61,398 61,661
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 2,418 2,564 2,717
Deposits to Major Maintenance Reserve (21) 6,650 6,650 6,972
Corps of Engineers 111 111 111
Subcontractor 290 307 326
Lateral Pipeline O&M 26 28 29
Back Up Power 414 439 465
Balance of Plant Parts 532 563 590
Equipment and Materials 402 421 445
Water Treatment Chemicals 225 237 250
SCR Chemicals 177 185 197
Supply/Waste Water Pumping Costs 233 245 261
Electrical Transmission O&M 14 15 16
Insurance 870 922 977
Administrative & General 1,160 1,230 1,303
Property Taxes (22) 1,900 1,900 1,900
Panola Partnership / Inducement A Payments 338 345 351
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 15,853 16,255 17,003
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 46,349 45,143 44,658
</TABLE>
B-76
<PAGE>
Exhibit B-6
Batesville Project
Projected Operating Results
Sensitivity E - Increased Inflation (6%)
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700
Principal $0 8,250 6,900 7,350 7,800 11,400
Interest $6,269 10,598 10,031 9,529 8,994 8,371
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75
------ ------ ------ ------ ------ ------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.74 1.38 1.37 1.37 1.37 1.36
AVERAGE DEBT COVERAGE (27) 1.78
MINIMUM SENIOR DEBT COVERAGE 1.24
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $4,500 6,650 6,650 6,650 6,650 6,650
Major Overhaul Expenses (29) $0 6,451 0 3,320 14,310 0
Major Maintenance Reserve Balance (30) $4,500 5,082 12,164 16,528 10,273 17,796
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 108,300 95,850 83,250
Principal 12,450 12,600 13,050
Interest 7,536 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000 176,000
Principal 0 0 0
Interest 14,362 14,362 14,362
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 34,411 33,667 33,206
TRANSFERS FROM DSRA (25) 371 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.36 1.35 1.35
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (371) (226) (242)
Debt Service Reserve Account Balance (28) 16,914 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 6,650 6,650 6,972
Major Overhaul Expenses (29) 3,954 4,192 0
Major Maintenance Reserve Balance (30) 22,005 26,333 35,543
</TABLE>
B-77
<PAGE>
Exhibit B-6
Batesville Project
Projected Operating Results
Sensitivity E - Increased Inflation (6%)
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 60.08% 59.58% 59.05% 58.53% 57.81% 57.10%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,828,300 2,804,700 2,780,000 2,755,300 2,721,700 2,688,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,414,200 1,402,300 1,390,000 1,377,700 1,360,800 1,344,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 29,918 29,668 29,407 29,146 28,790 28,434
COMMODITY PRICES
General Inflation (%)(11) 6.00 6.00 6.00 6.00 6.00 6.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $68.14 68.14 68.14 68.14 58.54 51.69
Energy Rate ($/MWh)(13) $1.62 1.68 1.75 1.81 1.88 1.94
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 59.51 59.51 59.51
Energy Rate ($/MWh)(15) $1.97 2.09 2.22 2.35 2.49 2.64
Market Electricity Rates (16) $64.86 69.12 74.39 80.04 85.39 91.10
Natural Gas Price ($/MMBtu)(17) $4.598 4.897 5.215 5.554 5.915 6.300
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $36,988 36,988 36,988 36,988 31,777 28,055
Energy $3,649 3,730 3,809 3,885 3,946 4,005
Tracking Account Payment $936 989 1,044 1,102 1,159 1,219
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 16,152 16,152 16,152
Energy $2,729 2,868 3,014 3,166 3,315 3,471
Tracking Account Payment $59 62 65 69 72 76
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 0 0 0
Interest Income (19) $1,398 1,382 1,390 1,344 1,157 1,007
------ ------ ------ ------ ------ ------
Total Operating Revenues $61,910 62,171 62,461 62,705 57,579 53,985
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $2,880 3,053 3,236 3,431 3,637 3,855
Deposits to Major Maintenance Reserve (21) $7,721 10,250 10,250 10,750 10,750 8,506
Corps of Engineers $111 111 111 111 111 111
Subcontractor $345 366 388 411 436 462
Lateral Pipeline O&M $31 33 35 37 39 42
Back Up Power $493 523 554 587 622 659
Balance of Plant Parts $624 652 688 723 755 790
Equipment and Materials $467 492 517 541 567 597
Water Treatment Chemicals $263 277 291 305 320 335
SCR Chemicals $204 215 225 240 249 262
Supply/Waste Water Pumping Costs $272 286 300 318 331 347
Electrical Transmission O&M $17 18 19 21 22 23
Insurance $1,036 1,098 1,164 1,234 1,308 1,387
Administrative & General $1,382 1,464 1,552 1,645 1,744 1,849
Property Taxes (22) $1,900 1,900 1,900 4,438 4,386 4,489
Panola Partnership / Inducement A Payments $359 366 373 380 388 396
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $18,198 21,197 21,696 25,265 25,758 24,203
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $43,712 40,974 40,765 37,440 31,821 29,782
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 56.02% 54.95% 54.17%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,637,300 2,586,700 2,550,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,318,700 1,293,300 1,275,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 27,898 27,362 26,974
COMMODITY PRICES
General Inflation (%)(11) 6.00 6.00 6.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 51.69 51.69
Energy Rate ($/MWh)(13) 2.02 2.10 2.18
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 2.80 2.97 3.14
Market Electricity Rates (16) 98.65 106.78 114.17
Natural Gas Price ($/MMBtu)(17) 6.709 7.145 7.610
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 28,055 28,055
Energy 4,061 4,113 4,157
Tracking Account Payment 1,274 1,331 1,397
Transmission (18) 0 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 3,610 3,752 3,921
Tracking Account Payment 80 83 87
Transmission (18) 0 0 0
Market 0 0 0
Interest Income (19) 1,004 970 957
------ ------ ------
Total Operating Revenues 54,236 54,456 54,726
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 4,086 4,331 4,591
Deposits to Major Maintenance Reserve (21) 9,427 9,750 10,250
Corps of Engineers 111 111 111
Subcontractor 490 519 550
Lateral Pipeline O&M 44 47 50
Back Up Power 699 740 785
Balance of Plant Parts 823 854 895
Equipment and Materials 621 644 673
Water Treatment Chemicals 348 362 378
SCR Chemicals 273 283 295
Supply/Waste Water Pumping Costs 360 376 394
Electrical Transmission O&M 24 26 28
Insurance 1,470 1,558 1,651
Administrative & General 1,960 2,077 2,202
Property Taxes (22) 4,358 4,239 4,180
Panola Partnership / Inducement A Payments 404 412 420
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 25,591 26,422 27,546
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 28,645 28,034 27,180
</TABLE>
B-78
<PAGE>
Exhibit B-6
Batesville Project
Projected Operating Results
Sensitivity E - Increased Inflation (6%)
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0
Principal $13,500 14,100 15,300 15,300 12,000 0
Interest $4,787 3,809 2,778 1,682 645 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 9,328
Interest $14,362 14,362 14,362 14,362 14,362 14,171
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29
ANNUAL DEBT SERVICE COVERAGE (26) 1.34 1.27 1.27 1.26 1.24 1.27
AVERAGE DEBT COVERAGE (27) 1.78
MINIMUM SENIOR DEBT COVERAGE 1.24
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $7,721 10,250 10,250 10,750 10,750 8,506
Major Overhaul Expenses (29) $28,402 15,186 0 10,176 34,652 0
Major Maintenance Reserve Balance (30) $17,883 14,467 25,947 28,726 7,266 16,390
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0 0
Principal 0 0 0
Interest 0 0 0
Series B Bonds
Balance Outstanding 166,672 156,640 146,608
Principal 10,032 10,032 10,560
Interest 13,396 12,577 11,748
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 23,492 22,673 22,372
TRANSFERS FROM DSRA (25) 409 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 1.24 1.24 1.24
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (409) (145) (607)
Debt Service Reserve Account Balance (28) 11,407 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 9,427 9,750 10,250
Major Overhaul Expenses (29) 8,862 0 7,507
Major Maintenance Reserve Balance (30) 18,348 29,658 34,922
</TABLE>
B-79
<PAGE>
Exhibit B-6
Batesville Project
Projected Operating Results
Sensitivity E - Increased Inflation (6%)
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 53.39% 53.11% 52.82% 52.04% 50.26% 49.41%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,513,300 2,500,000 2,486,700 2,450,000 2,366,000 2,326,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,256,700 1,250,000 1,243,300 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 1,225,000 1,183,000 1,163,000
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 26,586 26,445 26,304 25,916 25,028 24,604
COMMODITY PRICES
General Inflation (%)(11) 6.00 6.00 6.00 6.00 6.00 6.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $51.69 51.69 51.69 51.69 51.69 51.69
Energy Rate ($/MWh)(13) $2.26 2.35 2.44 2.54 2.64 2.75
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $3.33 3.53 3.75 0.00 0.00 0.00
Market Electricity Rates (16) $122.06 129.23 136.83 148.24 157.26 166.05
Natural Gas Price ($/MMBtu)(17) $8.104 8.631 9.192 9.790 10.426 11.104
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $28,055 28,055 28,055 28,055 28,055 28,055
Energy $4,222 4,325 4,426 4,508 4,472 4,536
Tracking Account Payment $1,467 1,554 1,646 1,727 1,776 1,860
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 0 0 0
Energy $4,097 4,320 4,554 0 0 0
Tracking Account Payment $92 97 103 0 0 0
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 181,594 186,039 193,116
Interest Income (19) $906 953 716 1,153 1,104 1,046
------ ------ ------ ------ ------ ------
Total Operating Revenues $54,990 55,456 55,652 217,037 221,446 228,612
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 84,570 86,979 91,067
Labor $4,866 5,158 5,468 5,796 6,144 6,512
Deposits to Major Maintenance Reserve (21) $10,250 10,500 14,000 17,309 19,240 21,386
Corps of Engineers $111 111 111 111 111 111
Subcontractor $584 619 656 695 737 781
Lateral Pipeline O&M $53 56 59 63 66 70
Back Up Power $832 882 935 991 1,051 1,113
Balance of Plant Parts $935 986 1,037 1,084 1,111 1,158
Equipment and Materials $701 743 783 816 834 872
Water Treatment Chemicals $395 416 439 459 469 489
SCR Chemicals $309 326 343 356 366 380
Supply/Waste Water Pumping Costs $411 431 455 474 486 506
Electrical Transmission O&M $29 31 33 35 37 39
Insurance $1,751 1,856 1,967 2,085 2,210 2,343
Administrative & General $2,334 2,474 2,623 2,780 2,947 3,123
Property Taxes (22) $4,065 3,965 4,124 4,244 4,331 4,161
Panola Partnership / Inducement A Payments $428 437 446 455 464 473
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $28,147 29,084 33,572 122,416 127,676 134,677
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $26,843 26,372 22,080 94,621 93,770 93,935
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 48.50% 47.19%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 2,283,300 925,600
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 1,141,700 740,400
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 24,153 11,749
COMMODITY PRICES
General Inflation (%)(11) 6.00 6.00
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 43.07
Energy Rate ($/MWh)(13) 2.86 2.98
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00 0.00
Energy Rate ($/MWh)(15) 0.00 0.00
Market Electricity Rates (16) 177.70 189.66
Natural Gas Price ($/MMBtu)(17) 11.825 12.594
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 11,688
Energy 4,589 1,916
Tracking Account Payment 1,944 839
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Market 202,880 140,424
Interest Income (19) 1,205 1,129
------ ------
Total Operating Revenues 238,673 155,996
OPERATING EXPENSES ($000)(20)
Fuel Expense 95,209 65,758
Labor 6,903 3,659
Deposits to Major Maintenance Reserve (21) 6,750 3,375
Corps of Engineers 111 55
Subcontractor 828 439
Lateral Pipeline O&M 74 39
Back Up Power 1,180 870
Balance of Plant Parts 1,202 621
Equipment and Materials 908 466
Water Treatment Chemicals 509 262
SCR Chemicals 397 205
Supply/Waste Water Pumping Costs 527 272
Electrical Transmission O&M 41 22
Insurance 2,483 1,316
Administrative & General 3,311 1,755
Property Taxes (22) 3,921 1,795
Panola Partnership / Inducement A Payments 483 246
Trustee & Rating Agency Fees 93 46
------ ------
Total Operating Expenses 124,930 81,201
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 113,743 74,795
</TABLE>
B-80
<PAGE>
Exhibit B-6
Batesville Project
Projected Operating Results
Sensitivity E - Increased Inflation (6%)
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0
Principal $0 0 0 0 0 0
Interest $0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816
Principal $10,208 12,144 7,568 18,480 18,832 19,008
Interest $10,893 10,021 9,123 8,283 6,768 5,228
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.27 1.31 1.32 3.55 3.68 3.87
AVERAGE DEBT COVERAGE (27) 1.78
MINIMUM SENIOR DEBT COVERAGE 1.24
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $10,250 10,500 14,000 17,309 19,240 21,386
Major Overhaul Expenses (29) $41,241 0 20,612 0 32,570 0
Major Maintenance Reserve Balance (30) $6,899 17,985 12,902 31,308 20,639 43,779
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 49,808 25,520
Principal 24,288 25,520
Interest 3,569 1,041
Letter-of-Credit Fees 64 32
------ ------
Total Debt Service 27,921 26,593
TRANSFERS FROM DSRA (25) 0 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 4.07 3.81
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account 12,385 (26,561)
Debt Service Reserve Account Balance (28) 26,561 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 6,750 3,375
Major Overhaul Expenses (29) 41,691 0
Major Maintenance Reserve Balance (30) 12,559 16,468
</TABLE>
B-81
<PAGE>
Footnotes to Exhibit B-6
The footnotes to Exhibit B-6 are the same as the footnotes for Exhibit B-1,
except:
11. General inflation and the GDP-IPD are assumed to escalate at a rate of 6.0
percent per year, rather than 2.6 percent per year, as assumed in the Base
Case.
17. The price of natural gas is assumed to escalate a 0.5 percent above
inflation, or 6.5 percent per year in this case.
19. Based on a reinvestment rate of 8.0 percent per year, as estimated by the
Initial Purchasers based on a general inflation rate of 6.0 percent per
year.
21. Deposits as estimated by the Partnership based on a general inflation rate
of 6.0 percent per year.
29. Major turbine overhaul expenses as estimated by the Partnership, adjusted
to reflect a general inflation rate of 6.0 percent per year.
30. Balance includes interest income based on a reinvestment rate of 8.0
percent per year, as estimated by the Initial Purchasers.
B-82
<PAGE>
Exhibit B-7
Batesville Project
Projected Operating Results
Sensitivity F - Increased Gas Escalation
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 66.71% 63.73% 63.73% 63.29% 62.85% 62.04%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,832,000 3,000,000 3,000,000 2,979,300 2,958,700 2,920,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 916,000 1,500,000 1,500,000 1,489,700 1,479,300 1,460,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 19,379 31,734 31,734 31,515 31,297 30,895
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $57.30 57.30 57.30 57.30 57.30 63.62
Energy Rate ($/MWh)(13) $1.18 1.20 1.24 1.28 1.31 1.36
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $58.33 58.33 58.33 58.33 58.33 59.51
Energy Rate ($/MWh)(15) $1.09 1.12 1.15 1.18 1.21 1.24
Market Electricity Rates (16) $34.55 35.56 36.59 37.95 39.36 40.54
Natural Gas Price ($/MMBtu)(17) $2.469 2.557 2.650 2.745 2.844 2.946
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $18,143 31,102 31,102 31,102 31,102 34,535
Energy $1,832 3,060 3,150 3,218 3,284 3,359
Tracking Account Payment $326 552 572 589 606 620
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267
Aquila/UtiliCorp
Capacity $9,235 15,832 15,832 15,832 15,832 16,152
Energy $980 1,647 1,690 1,722 1,754 1,777
Tracking Account Payment $20 35 36 37 38 39
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133
Market $0 0 0 0 0 0
Interest Income (19) $403 917 864 863 861 944
------ ------ ------ ------ ------ ------
Total Operating Revenues $32,922 56,545 56,646 56,762 56,877 60,825
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $963 1,693 1,737 1,782 1,829 1,876
Deposits to Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Corps of Engineers $64 111 111 111 111 111
Subcontractor $115 203 208 214 219 225
Lateral Pipeline O&M $10 18 19 19 20 20
Back Up Power $158 279 286 294 302 309
Balance of Plant Parts $231 387 396 407 413 421
Equipment and Materials $173 293 302 304 311 315
Water Treatment Chemicals $98 164 168 171 175 177
SCR Chemicals $77 126 131 134 138 136
Supply/Waste Water Pumping Costs $102 171 176 179 182 184
Electrical Transmission O&M $6 10 10 11 11 11
Insurance $346 609 625 641 658 675
Administrative & General $462 812 833 855 877 900
Property Taxes (22) $0 0 1,900 1,900 1,900 1,900
Panola Partnership / Inducement A Payments $175 306 312 318 325 331
Trustee & Rating Agency Fees $54 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $11,534 9,800 11,832 11,958 12,089 12,209
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $21,388 46,745 44,814 44,804 44,788 48,616
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 61.23% 60.91% 60.58%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,882,700 2,867,300 2,852,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,441,300 1,433,700 1,426,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 30,493 30,331 30,168
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 68.14 68.14 68.14
Energy Rate ($/MWh)(13) 1.40 1.44 1.49
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.28 1.31 1.34
Market Electricity Rates (16) 41.75 42.82 43.92
Natural Gas Price ($/MMBtu)(17) 3.052 3.162 3.276
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 36,988 36,988 36,988
Energy 3,402 3,469 3,565
Tracking Account Payment 633 653 673
Transmission (18) 678 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 1,799 1,836 1,874
Tracking Account Payment 40 41 42
Transmission (18) 339 0 0
Market 0 0 0
Interest Income (19) 951 930 918
------ ------ ------
Total Operating Revenues 60,981 60,069 60,211
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 1,925 1,975 2,026
Deposits to Major Maintenance Reserve (21) 4,525 4,525 4,975
Corps of Engineers 111 111 111
Subcontractor 231 237 243
Lateral Pipeline O&M 21 21 22
Back Up Power 317 325 333
Balance of Plant Parts 424 434 441
Equipment and Materials 320 327 334
Water Treatment Chemicals 179 183 187
SCR Chemicals 138 142 145
Supply/Waste Water Pumping Costs 186 189 193
Electrical Transmission O&M 12 12 12
Insurance 692 710 729
Administrative & General 923 947 972
Property Taxes (22) 1,900 1,900 1,900
Panola Partnership / Inducement A Payments 338 345 351
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 12,335 12,476 13,067
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 48,646 47,593 47,144
</TABLE>
B-83
<PAGE>
Exhibit B-7
Batesville Project
Projected Operating Results
Sensitivity F - Increased Gas Escalation
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700
Principal $0 8,250 6,900 7,350 7,800 11,400
Interest $6,269 10,598 10,031 9,529 8,994 8,371
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75
------ ------ ------ ------ ------ ------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.45 1.43 1.43 1.43 1.43 1.42
AVERAGE DEBT COVERAGE (27) 1.60
MINIMUM SENIOR DEBT COVERAGE 1.42
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Major Overhaul Expenses (29) $0 5,850 0 2,821 11,768 0
Major Maintenance Reserve Balance (30) $8,500 7,643 12,588 14,984 8,565 13,561
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 108,300 95,850 83,250
Principal 12,450 12,600 13,050
Interest 7,536 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000 176,000
Principal 0 0 0
Interest 14,362 14,362 14,362
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 34,411 33,667 33,206
TRANSFERS FROM DSRA (25) 371 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.42 1.42 1.43
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (371) (226) (242)
Debt Service Reserve Account Balance (28) 16,914 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 4,525 4,525 4,975
Major Overhaul Expenses (29) 3,047 3,126 0
Major Maintenance Reserve Balance (30) 15,785 18,052 24,020
</TABLE>
B-84
<PAGE>
Exhibit B-7
Batesville Project
Projected Operating Results
Sensitivity F - Increased Gas Escalation
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 60.08% 59.58% 59.05% 58.53% 57.81% 57.10%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,828,300 2,804,700 2,780,000 2,755,300 2,721,700 2,688,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,414,200 1,402,300 1,390,000 1,377,700 1,360,800 1,344,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 29,918 29,668 29,407 29,146 28,790 28,434
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $68.14 68.14 68.14 68.14 58.54 51.69
Energy Rate ($/MWh)(13) $1.53 1.58 1.63 1.68 1.73 1.78
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 59.51 59.51 59.51
Energy Rate ($/MWh)(15) $1.38 1.42 1.45 1.49 1.53 1.57
Market Electricity Rates (16) $45.31 46.74 48.69 50.71 52.36 54.07
Natural Gas Price ($/MMBtu)(17) $3.394 3.516 3.643 3.774 3.910 4.050
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $36,988 36,988 36,988 36,988 31,777 28,055
Energy $3,649 3,730 3,809 3,885 3,946 4,005
Tracking Account Payment $691 710 729 749 766 784
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 16,152 16,152 16,152
Energy $1,906 1,940 1,973 2,006 2,033 2,060
Tracking Account Payment $43 44 46 47 48 49
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 0 0 0
Interest Income (19) $904 894 900 869 749 651
------ ------ ------ ------ ------ ------
Total Operating Revenues $60,332 60,458 60,596 60,695 55,471 51,756
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $2,079 2,133 2,189 2,246 2,304 2,364
Deposits to Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Corps of Engineers $111 111 111 111 111 111
Subcontractor $249 256 262 269 276 283
Lateral Pipeline O&M $22 23 24 24 25 26
Back Up Power $343 351 361 370 379 389
Balance of Plant Parts $450 459 463 471 478 484
Equipment and Materials $339 345 350 355 359 367
Water Treatment Chemicals $190 193 196 200 202 205
SCR Chemicals $148 151 154 157 159 161
Supply/Waste Water Pumping Costs $195 202 204 207 208 214
Electrical Transmission O&M $12 13 13 13 14 14
Insurance $748 767 787 808 829 850
Administrative & General $997 1,023 1,050 1,077 1,105 1,134
Property Taxes (22) $1,900 1,900 1,900 4,438 4,386 4,489
Panola Partnership / Inducement A Payments $359 366 373 380 388 396
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $13,583 14,135 14,710 17,863 18,458 16,580
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $46,749 46,323 45,886 42,832 37,013 35,176
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 56.02% 54.95% 54.17%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,637,300 2,586,700 2,550,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,318,700 1,293,300 1,275,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 27,898 27,362 26,974
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 51.69 51.69
Energy Rate ($/MWh)(13) 1.84 1.90 1.95
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.61 1.65 1.70
Market Electricity Rates (16) 56.68 59.38 61.45
Natural Gas Price ($/MMBtu)(17) 4.196 4.347 4.504
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 28,055 28,055
Energy 4,061 4,113 4,157
Tracking Account Payment 797 810 827
Transmission (18) 0 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 2,074 2,087 2,111
Tracking Account Payment 50 51 52
Transmission (18) 0 0 0
Market 0 0 0
Interest Income (19) 650 627 619
------ ------ ------
Total Operating Revenues 51,839 51,894 51,972
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 2,425 2,488 2,553
Deposits to Major Maintenance Reserve (21) 5,375 5,778 6,211
Corps of Engineers 111 111 111
Subcontractor 291 298 306
Lateral Pipeline O&M 26 27 28
Back Up Power 399 409 421
Balance of Plant Parts 487 493 497
Equipment and Materials 368 369 375
Water Treatment Chemicals 207 208 210
SCR Chemicals 162 163 164
Supply/Waste Water Pumping Costs 214 217 218
Electrical Transmission O&M 15 15 15
Insurance 872 895 918
Administrative & General 1,163 1,193 1,224
Property Taxes (22) 4,358 4,239 4,180
Panola Partnership / Inducement A Payments 404 412 420
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 16,970 17,408 17,944
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 34,869 34,486 34,028
</TABLE>
B-85
<PAGE>
Exhibit B-7
Batesville Project
Projected Operating Results
Sensitivity F - Increased Gas Escalation
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0
Principal $13,500 14,100 15,300 15,300 12,000 0
Interest $4,787 3,809 2,778 1,682 645 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 9,328
Interest $14,362 14,362 14,362 14,362 14,362 14,171
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29
ANNUAL DEBT SERVICE COVERAGE (26) 1.43 1.43 1.43 1.43 1.43 1.49
AVERAGE DEBT COVERAGE (27) 1.60
MINIMUM SENIOR DEBT COVERAGE 1.42
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Major Overhaul Expenses (29) $19,843 10,269 0 6,447 21,249 0
Major Maintenance Reserve Balance (30) $10,846 6,923 13,484 14,423 1,109 6,170
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0 0
Principal 0 0 0
Interest 0 0 0
Series B Bonds
Balance Outstanding 166,672 156,640 146,608
Principal 10,032 10,032 10,560
Interest 13,396 12,577 11,748
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 23,492 22,673 22,372
TRANSFERS FROM DSRA (25) 409 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 1.50 1.53 1.55
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (409) (145) (607)
Debt Service Reserve Account Balance (28) 11,407 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 5,375 5,778 6,211
Major Overhaul Expenses (29) 5,091 0 4,040
Major Maintenance Reserve Balance (30) 6,793 12,945 15,828
</TABLE>
B-86
<PAGE>
Exhibit B-7
Batesville Project
Projected Operating Results
Sensitivity F - Increased Gas Escalation
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 53.39% 53.11% 52.82% 52.04% 50.26% 49.41%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,513,300 2,500,000 2,486,700 2,450,000 2,366,000 2,326,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,256,700 1,250,000 1,243,300 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 1,225,000 1,183,000 1,163,000
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 26,586 26,445 26,304 25,916 25,028 24,604
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $51.69 51.69 51.69 51.69 51.69 51.69
Energy Rate ($/MWh)(13) $2.02 2.08 2.14 2.21 2.28 2.35
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $1.74 1.79 1.83 0.00 0.00 0.00
Market Electricity Rates (16) $63.59 65.17 66.79 70.04 71.91 73.50
Natural Gas Price ($/MMBtu)(17) $4.666 4.834 5.008 5.188 5.375 5.568
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $28,055 28,055 28,055 28,055 28,055 28,055
Energy $4,222 4,325 4,426 4,508 4,472 4,536
Tracking Account Payment $844 870 897 915 916 933
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 0 0 0
Energy $2,134 2,178 2,223 0 0 0
Tracking Account Payment $53 54 56 0 0 0
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 85,799 85,070 85,481
Interest Income (19) $586 616 463 746 715 677
------ ------ ------ ------ ------ ------
Total Operating Revenues $52,046 52,250 52,272 120,023 119,227 119,681
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 44,818 44,839 45,668
Labor $2,619 2,688 2,757 2,829 2,903 2,978
Deposits to Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Corps of Engineers $111 111 111 111 111 111
Subcontractor $314 322 331 339 348 357
Lateral Pipeline O&M $28 29 30 31 31 32
Back Up Power $432 442 454 465 478 490
Balance of Plant Parts $501 514 522 529 525 530
Equipment and Materials $377 386 395 397 394 398
Water Treatment Chemicals $213 217 221 224 222 224
SCR Chemicals $166 169 172 173 174 174
Supply/Waste Water Pumping Costs $222 225 231 232 231 234
Electrical Transmission O&M $16 16 17 17 17 18
Insurance $942 967 992 1,018 1,044 1,071
Administrative & General $1,256 1,289 1,322 1,357 1,392 1,428
Property Taxes (22) $4,065 3,965 4,124 4,244 4,331 4,161
Panola Partnership / Inducement A Payments $428 437 446 455 464 473
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $18,460 19,048 19,935 65,627 66,514 68,026
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $33,586 33,202 32,337 54,396 52,713 51,655
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 48.50% 47.19%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 2,283,300 925,600
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 1,141,700 740,400
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 24,153 11,749
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 43.07
Energy Rate ($/MWh)(13) 2.43 2.50
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00 0.00
Energy Rate ($/MWh)(15) 0.00 0.00
Market Electricity Rates (16) 76.13 78.65
Natural Gas Price ($/MMBtu)(17) 5.769 5.976
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 11,688
Energy 4,589 1,916
Tracking Account Payment 948 398
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Market 86,918 58,232
Interest Income (19) 780 730
------ ------
Total Operating Revenues 121,291 72,964
OPERATING EXPENSES ($000)(20)
Fuel Expense 46,445 31,205
Labor 3,056 1,567
Deposits to Major Maintenance Reserve (21) 525 282
Corps of Engineers 111 55
Subcontractor 366 188
Lateral Pipeline O&M 33 17
Back Up Power 503 359
Balance of Plant Parts 534 267
Equipment and Materials 401 200
Water Treatment Chemicals 225 112
SCR Chemicals 175 88
Supply/Waste Water Pumping Costs 233 117
Electrical Transmission O&M 18 9
Insurance 1,099 564
Administrative & General 1,465 752
Property Taxes (22) 3,921 1,795
Panola Partnership / Inducement A Payments 483 246
Trustee & Rating Agency Fees 93 46
------ ------
Total Operating Expenses 59,686 37,869
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 61,605 35,095
</TABLE>
B-87
<PAGE>
Exhibit B-7
Batesville Project
Projected Operating Results
Sensitivity F - Increased Gas Escalation
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0
Principal $0 0 0 0 0 0
Interest $0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816
Principal $10,208 12,144 7,568 18,480 18,832 19,008
Interest $10,893 10,021 9,123 8,283 6,768 5,228
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.59 1.62 1.93 2.05 2.08 2.13
AVERAGE DEBT COVERAGE (27) 1.60
MINIMUM SENIOR DEBT COVERAGE 1.42
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Major Overhaul Expenses (29) $21,486 0 10,061 0 14,894 0
Major Maintenance Reserve Balance (30) $1,890 9,172 7,332 16,030 10,935 21,122
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 49,808 25,520
Principal 24,288 25,520
Interest 3,569 1,041
Letter-of-Credit Fees 64 32
------ ------
Total Debt Service 27,921 26,593
TRANSFERS FROM DSRA (25) 0 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 2.21 2.32
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account 12,385 (26,561)
Debt Service Reserve Account Balance (28) 26,561 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 525 282
Major Overhaul Expenses (29) 17,861 0
Major Maintenance Reserve Balance (30) 4,948 5,366
</TABLE>
B-88
<PAGE>
Footnotes to Exhibit B-7
The footnotes to Exhibit B-7 are the same as the footnotes for Exhibit B-1,
except:
17. Assumed to be escalated annually at a rate which is 1.0 percent above
inflation, increased from C.C. Pace's Base Case assumption of 0.5 percent
above inflation.
B-89
<PAGE>
Exhibit B-8
Batesville Project
Projected Operating Results
Sensitivity G - Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 61.15% 57.98% 57.98% 57.36% 56.74% 55.72%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,679,300 2,729,300 2,729,300 2,700,300 2,671,300 2,623,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 839,700 1,364,700 1,364,700 1,350,200 1,335,700 1,311,500
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 17,764 28,871 28,871 28,564 28,257 27,746
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $57.30 57.30 57.30 57.30 57.30 63.62
Energy Rate ($/MWh)(13) $1.18 1.20 1.24 1.27 1.31 1.36
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $58.33 58.33 58.33 58.33 58.33 59.51
Energy Rate ($/MWh)(15) $1.09 1.12 1.15 1.18 1.21 1.24
Market Electricity Rates (16) $32.82 34.11 35.44 36.82 38.25 39.51
Natural Gas Price ($/MMBtu)(17) $2.445 2.521 2.599 2.679 2.762 2.848
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $18,143 31,102 31,102 31,102 31,102 34,535
Energy $1,679 2,784 2,866 2,916 2,965 3,016
Tracking Account Payment $296 495 511 521 531 538
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267
Aquila/UtiliCorp
Capacity $9,235 15,832 15,832 15,832 15,832 16,152
Energy $898 1,498 1,537 1,560 1,584 1,596
Tracking Account Payment $18 31 32 33 33 34
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133
Market $0 0 0 0 0 0
Interest Income (19) $403 917 864 863 861 944
------ ------ ------ ------ ------ ------
Total Operating Revenues $32,655 56,059 56,143 56,227 56,308 60,215
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $963 1,693 1,737 1,782 1,829 1,876
Deposits to Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Corps of Engineers $64 111 111 111 111 111
Subcontractor $115 203 208 214 219 225
Lateral Pipeline O&M $10 18 19 19 20 20
Back Up Power $158 279 286 294 302 309
Balance of Plant Parts $212 352 360 369 373 378
Equipment and Materials $159 266 274 275 280 283
Water Treatment Chemicals $89 149 153 155 158 159
SCR Chemicals $71 115 119 122 124 122
Supply/Waste Water Pumping Costs $93 156 160 162 164 165
Electrical Transmission O&M $6 10 10 11 11 11
Insurance $346 609 625 641 658 675
Administrative & General $462 812 833 855 877 900
Property Taxes (22) $0 0 1,900 1,900 1,900 1,900
Panola Partnership / Inducement A Payments $175 306 312 318 325 331
Trustee & Rating Agency Fees $54 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $11,477 9,697 11,725 11,846 11,969 12,083
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $21,178 46,362 44,418 44,381 44,339 48,132
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 54.69% 54.68% 54.68%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,574,700 2,574,300 2,574,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,287,300 1,287,200 1,287,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 27,235 27,231 27,228
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 68.14 68.14 68.14
Energy Rate ($/MWh)(13) 1.39 1.43 1.47
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.27 1.31 1.34
Market Electricity Rates (16) 40.80 41.90 43.02
Natural Gas Price ($/MMBtu)(17) 2.936 3.027 3.121
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 36,988 36,988 36,988
Energy 3,038 3,115 3,218
Tracking Account Payment 544 561 578
Transmission (18) 678 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 1,607 1,649 1,691
Tracking Account Payment 34 35 36
Transmission (18) 339 0 0
Market 0 0 0
Interest Income (19) 951 930 918
------ ------ ------
Total Operating Revenues 60,331 59,430 59,581
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 1,925 1,975 2,026
Deposits to Major Maintenance Reserve (21) 4,525 4,525 4,975
Corps of Engineers 111 111 111
Subcontractor 231 237 243
Lateral Pipeline O&M 21 21 22
Back Up Power 317 325 333
Balance of Plant Parts 378 390 398
Equipment and Materials 286 293 301
Water Treatment Chemicals 160 164 168
SCR Chemicals 124 127 131
Supply/Waste Water Pumping Costs 166 170 174
Electrical Transmission O&M 12 12 12
Insurance 692 710 729
Administrative & General 923 947 972
Property Taxes (22) 1,900 1,900 1,900
Panola Partnership / Inducement A Payments 338 345 351
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 12,202 12,345 12,939
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 48,129 47,085 46,642
</TABLE>
B-90
<PAGE>
Exhibit B-8
Batesville Project
Projected Operating Results
Sensitivity G - Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700
Principal $0 8,250 6,900 7,350 7,800 11,400
Interest $6,269 10,598 10,031 9,529 8,994 8,371
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75
------ ------ ------ ------ ------ ------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.44 1.42 1.42 1.42 1.42 1.41
AVERAGE DEBT COVERAGE (27) 1.57
MINIMUM SENIOR DEBT COVERAGE 1.41
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Major Overhaul Expenses (29) $0 5,850 0 2,821 0 12,074
Major Maintenance Reserve Balance (30) $8,500 7,643 12,588 14,984 20,333 13,902
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 108,300 95,850 83,250
Principal 12,450 12,600 13,050
Interest 7,536 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000 176,000
Principal 0 0 0
Interest 14,362 14,362 14,362
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 34,411 33,667 33,206
TRANSFERS FROM DSRA (25) 371 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.41 1.41 1.41
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (371) (226) (242)
Debt Service Reserve Account Balance (28) 16,914 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 4,525 4,525 4,975
Major Overhaul Expenses (29) 3,047 0 3,207
Major Maintenance Reserve Balance (30) 16,145 21,558 24,512
</TABLE>
B-91
<PAGE>
Exhibit B-8
Batesville Project
Projected Operating Results
Sensitivity G - Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 53.76% 52.84% 52.85% 52.86% 51.72% 50.57%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,530,700 2,487,300 2,488,000 2,488,700 2,434,700 2,380,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,265,300 1,243,700 1,244,000 1,244,300 1,217,300 1,190,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 26,769 26,311 26,318 26,325 25,754 25,183
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $68.14 68.14 68.14 68.14 58.54 51.69
Energy Rate ($/MWh)(13) $1.52 1.57 1.62 1.66 1.71 1.76
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 59.51 59.51 59.51
Energy Rate ($/MWh)(15) $1.38 1.41 1.45 1.49 1.53 1.57
Market Electricity Rates (16) $44.50 46.02 47.99 50.03 51.72 53.47
Natural Gas Price ($/MMBtu)(17) $3.218 3.318 3.421 3.527 3.636 3.749
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $36,988 36,988 36,988 36,988 31,777 28,055
Energy $3,265 3,308 3,409 3,509 3,530 3,547
Tracking Account Payment $586 594 613 632 637 643
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 16,152 16,152 16,152
Energy $1,706 1,720 1,765 1,812 1,819 1,824
Tracking Account Payment $37 37 38 39 40 40
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 0 0 0
Interest Income (19) $904 894 900 869 749 651
------ ------ ------ ------ ------ ------
Total Operating Revenues $59,637 59,693 59,864 60,001 54,704 50,912
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $2,079 2,133 2,189 2,246 2,304 2,364
Deposits to Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Corps of Engineers $111 111 111 111 111 111
Subcontractor $249 256 262 269 276 283
Lateral Pipeline O&M $22 23 24 24 25 26
Back Up Power $343 351 361 370 379 389
Balance of Plant Parts $402 407 414 426 427 429
Equipment and Materials $304 306 313 321 321 325
Water Treatment Chemicals $170 171 176 180 181 182
SCR Chemicals $133 134 138 142 142 143
Supply/Waste Water Pumping Costs $175 179 183 187 186 189
Electrical Transmission O&M $12 13 13 13 14 14
Insurance $748 767 787 808 829 850
Administrative & General $997 1,023 1,050 1,077 1,105 1,134
Property Taxes (22) $1,900 1,900 1,900 4,438 4,386 4,489
Panola Partnership / Inducement A Payments $359 366 373 380 388 396
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $13,445 13,982 14,567 17,729 18,309 16,417
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $46,192 45,711 45,297 42,272 36,395 34,495
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 49.83% 49.08% 48.66%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,345,700 2,310,700 2,290,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,172,800 1,155,300 1,145,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 24,812 24,442 24,231
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 51.69 51.69
Energy Rate ($/MWh)(13) 1.82 1.88 1.93
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.61 1.65 1.69
Market Electricity Rates (16) 55.93 58.48 60.22
Natural Gas Price ($/MMBtu)(17) 3.865 3.985 4.108
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 28,055 28,055
Energy 3,612 3,674 3,734
Tracking Account Payment 653 663 678
Transmission (18) 0 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 1,844 1,864 1,896
Tracking Account Payment 41 41 42
Transmission (18) 0 0 0
Market 0 0 0
Interest Income (19) 650 627 619
------ ------ ------
Total Operating Revenues 51,007 51,076 51,176
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 2,425 2,488 2,553
Deposits to Major Maintenance Reserve (21) 5,375 5,778 6,211
Corps of Engineers 111 111 111
Subcontractor 291 298 306
Lateral Pipeline O&M 26 27 28
Back Up Power 399 409 421
Balance of Plant Parts 433 440 447
Equipment and Materials 327 329 337
Water Treatment Chemicals 184 186 189
SCR Chemicals 144 146 148
Supply/Waste Water Pumping Costs 190 194 196
Electrical Transmission O&M 15 15 15
Insurance 872 895 918
Administrative & General 1,163 1,193 1,224
Property Taxes (22) 4,358 4,239 4,180
Panola Partnership / Inducement A Payments 404 412 420
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 16,810 17,253 17,797
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 34,197 33,823 33,379
</TABLE>
B-92
<PAGE>
Exhibit B-8
Batesville Project
Projected Operating Results
Sensitivity G - Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0
Principal $13,500 14,100 15,300 15,300 12,000 0
Interest $4,787 3,809 2,778 1,682 645 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 9,328
Interest $14,362 14,362 14,362 14,362 14,362 14,171
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29
ANNUAL DEBT SERVICE COVERAGE (26) 1.42 1.41 1.41 1.42 1.41 1.47
AVERAGE DEBT COVERAGE (27) 1.57
MINIMUM SENIOR DEBT COVERAGE 1.41
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Major Overhaul Expenses (29) $0 20,359 10,536 0 6,615 0
Major Maintenance Reserve Balance (30) $31,208 18,314 14,965 22,432 24,193 30,524
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0 0
Principal 0 0 0
Interest 0 0 0
Series B Bonds
Balance Outstanding 166,672 156,640 146,608
Principal 10,032 10,032 10,560
Interest 13,396 12,577 11,748
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 23,492 22,673 22,372
TRANSFERS FROM DSRA (25) 409 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 1.47 1.50 1.52
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (409) (145) (607)
Debt Service Reserve Account Balance (28) 11,407 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 5,375 5,778 6,211
Major Overhaul Expenses (29) 22,369 0 5,360
Major Maintenance Reserve Balance (30) 15,209 21,823 23,874
</TABLE>
B-93
<PAGE>
Exhibit B-8
Batesville Project
Projected Operating Results
Sensitivity G - Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 48.23% 48.36% 48.49% 46.41% 44.95% 44.47%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,270,700 2,276,700 2,282,700 2,184,700 2,116,000 2,093,300
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,135,300 1,138,300 1,141,300 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 1,092,300 1,058,000 1,046,700
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 24,019 24,083 24,146 23,109 22,383 22,143
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $51.69 51.69 51.69 51.69 51.69 51.69
Energy Rate ($/MWh)(13) $1.98 2.04 2.10 2.17 2.23 2.31
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $1.74 1.78 1.83 0.00 0.00 0.00
Market Electricity Rates (16) $62.02 63.60 65.22 68.79 71.23 72.97
Natural Gas Price ($/MMBtu)(17) $4.236 4.367 4.502 4.642 4.786 4.934
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $28,055 28,055 28,055 28,055 28,055 28,055
Energy $3,815 3,939 4,063 4,020 3,999 4,082
Tracking Account Payment $692 716 740 730 729 744
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 0 0 0
Energy $1,928 1,984 2,041 0 0 0
Tracking Account Payment $43 45 46 0 0 0
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 75,139 75,361 76,378
Interest Income (19) $586 616 463 746 715 677
------ ------ ------ ------ ------ ------
Total Operating Revenues $51,271 51,506 51,560 108,690 108,859 109,935
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 35,755 35,705 36,419
Labor $2,619 2,688 2,757 2,829 2,903 2,978
Deposits to Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Corps of Engineers $111 111 111 111 111 111
Subcontractor $314 322 331 339 348 357
Lateral Pipeline O&M $28 29 30 31 31 32
Back Up Power $432 442 454 465 478 490
Balance of Plant Parts $453 468 479 472 470 477
Equipment and Materials $341 352 363 354 352 358
Water Treatment Chemicals $192 198 203 200 198 201
SCR Chemicals $150 154 158 154 156 157
Supply/Waste Water Pumping Costs $201 205 212 206 206 210
Electrical Transmission O&M $16 16 17 17 17 18
Insurance $942 967 992 1,018 1,044 1,071
Administrative & General $1,256 1,289 1,322 1,357 1,392 1,428
Property Taxes (22) $4,065 3,965 4,124 4,244 4,331 4,161
Panola Partnership / Inducement A Payments $428 437 446 455 464 473
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $18,318 18,914 19,809 56,395 57,216 58,620
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $32,953 32,592 31,751 52,295 51,643 51,315
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 43.56% 43.02%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 2,050,700 843,900
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 1,025,300 675,100
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 21,692 10,712
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 51.69 43.07
Energy Rate ($/MWh)(13) 2.38 2.45
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00 0.00
Energy Rate ($/MWh)(15) 0.00 0.00
Market Electricity Rates (16) 74.96 77.03
Natural Gas Price ($/MMBtu)(17) 5.087 5.245
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 28,055 11,688
Energy 4,122 1,747
Tracking Account Payment 751 319
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Market 76,856 52,003
Interest Income (19) 780 730
------ ------
Total Operating Revenues 110,564 66,487
OPERATING EXPENSES ($000)(20)
Fuel Expense 36,780 24,969
Labor 3,056 1,567
Deposits to Major Maintenance Reserve (21) 525 282
Corps of Engineers 111 55
Subcontractor 366 188
Lateral Pipeline O&M 33 17
Back Up Power 503 359
Balance of Plant Parts 480 243
Equipment and Materials 360 182
Water Treatment Chemicals 202 103
SCR Chemicals 157 81
Supply/Waste Water Pumping Costs 209 106
Electrical Transmission O&M 18 9
Insurance 1,099 564
Administrative & General 1,465 752
Property Taxes (22) 3,921 1,795
Panola Partnership / Inducement A Payments 483 246
Trustee & Rating Agency Fees 93 46
------ ------
Total Operating Expenses 49,861 31,564
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 60,703 34,923
</TABLE>
B-94
<PAGE>
Exhibit B-8
Batesville Project
Projected Operating Results
Sensitivity G - Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0
Principal $0 0 0 0 0 0
Interest $0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816
Principal $10,208 12,144 7,568 18,480 18,832 19,008
Interest $10,893 10,021 9,123 8,283 6,768 5,228
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.56 1.59 1.90 1.97 2.04 2.11
AVERAGE DEBT COVERAGE (27) 1.57
MINIMUM SENIOR DEBT COVERAGE 1.41
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Major Overhaul Expenses (29) $0 4,253 0 23,206 0 10,866
Major Maintenance Reserve Balance (30) $31,864 36,542 46,269 33,903 44,685 45,863
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 49,808 25,520
Principal 24,288 25,520
Interest 3,569 1,041
Letter-of-Credit Fees 64 32
------ ------
Total Debt Service 27,921 26,593
TRANSFERS FROM DSRA (25) 0 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 2.17 2.31
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account 12,385 (26,561)
Debt Service Reserve Account Balance (28) 26,561 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 525 282
Major Overhaul Expenses (29) 0 16,086
Major Maintenance Reserve Balance (30) 48,910 34,451
</TABLE>
B-95
<PAGE>
Footnotes to Exhibit B-8
The footnotes to Exhibit B-8 are the same as the footnotes for Exhibit B-1,
except:
4. Based on market prices equal to C.C. Pace's Downside Case.
16. Assumed to be equal to C.C. Pace's Downside Case.
B-96
<PAGE>
Exhibit B-9
Batesville Project
Projected Operating Results
Sensitivity H - No PPA Renewal & Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 61.15% 57.98% 57.98% 57.36% 56.74% 55.72%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,679,300 2,729,300 2,729,300 2,700,300 2,671,300 2,623,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 839,700 1,364,700 1,364,700 1,350,200 1,335,700 1,311,500
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 17,764 28,871 28,871 28,564 28,257 27,746
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $57.30 57.30 57.30 57.30 57.30 63.62
Energy Rate ($/MWh)(13) $1.18 1.20 1.24 1.27 1.31 1.36
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $58.33 58.33 58.33 58.33 58.33 59.51
Energy Rate ($/MWh)(15) $1.09 1.12 1.15 1.18 1.21 1.24
Market Electricity Rates (16) $32.82 34.11 35.44 36.82 38.25 39.51
Natural Gas Price ($/MMBtu)(17) $2.445 2.521 2.599 2.679 2.762 2.848
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $18,143 31,102 31,102 31,102 31,102 34,535
Energy $1,679 2,784 2,866 2,916 2,965 3,016
Tracking Account Payment $296 495 511 521 531 538
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267
Aquila/UtiliCorp
Capacity $9,235 15,832 15,832 15,832 15,832 16,152
Energy $898 1,498 1,537 1,560 1,584 1,596
Tracking Account Payment $18 31 32 33 33 34
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133
Market $0 0 0 0 0 0
Interest Income (19) $403 917 864 863 861 944
------ ------ ------ ------ ------ ------
Total Operating Revenues $32,655 56,059 56,143 56,227 56,308 60,215
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $963 1,693 1,737 1,782 1,829 1,876
Deposits to Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Corps of Engineers $64 111 111 111 111 111
Subcontractor $115 203 208 214 219 225
Lateral Pipeline O&M $10 18 19 19 20 20
Back Up Power $158 279 286 294 302 309
Balance of Plant Parts $212 352 360 369 373 378
Equipment and Materials $159 266 274 275 280 283
Water Treatment Chemicals $89 149 153 155 158 159
SCR Chemicals $71 115 119 122 124 122
Supply/Waste Water Pumping Costs $93 156 160 162 164 165
Electrical Transmission O&M $6 10 10 11 11 11
Insurance $346 609 625 641 658 675
Administrative & General $462 812 833 855 877 900
Property Taxes (22) $0 0 1,900 1,900 1,900 1,900
Panola Partnership / Inducement A Payments $175 306 312 318 325 331
Trustee & Rating Agency Fees $54 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $11,477 9,697 11,725 11,846 11,969 12,083
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $21,178 46,362 44,418 44,381 44,339 48,132
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 54.69% 54.68% 54.68%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,574,700 2,574,300 2,574,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,287,300 1,287,200 1,287,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 27,235 27,231 27,228
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 68.14 68.14 68.14
Energy Rate ($/MWh)(13) 1.39 1.43 1.47
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.27 1.31 1.34
Market Electricity Rates (16) 40.80 41.90 43.02
Natural Gas Price ($/MMBtu)(17) 2.936 3.027 3.121
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 36,988 36,988 36,988
Energy 3,038 3,115 3,218
Tracking Account Payment 544 561 578
Transmission (18) 678 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 1,607 1,649 1,691
Tracking Account Payment 34 35 36
Transmission (18) 339 0 0
Market 0 0 0
Interest Income (19) 951 930 918
------ ------ ------
Total Operating Revenues 60,331 59,430 59,581
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 1,925 1,975 2,026
Deposits to Major Maintenance Reserve (21) 4,525 4,525 4,975
Corps of Engineers 111 111 111
Subcontractor 231 237 243
Lateral Pipeline O&M 21 21 22
Back Up Power 317 325 333
Balance of Plant Parts 378 390 398
Equipment and Materials 286 293 301
Water Treatment Chemicals 160 164 168
SCR Chemicals 124 127 131
Supply/Waste Water Pumping Costs 166 170 174
Electrical Transmission O&M 12 12 12
Insurance 692 710 729
Administrative & General 923 947 972
Property Taxes (22) 1,900 1,900 1,900
Panola Partnership / Inducement A Payments 338 345 351
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 12,202 12,345 12,939
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 48,129 47,085 46,642
</TABLE>
B-97
<PAGE>
Exhibit B-9
Batesville Project
Projected Operating Results
Sensitivity H - No PPA Renewal & Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700
Principal $0 8,250 6,900 7,350 7,800 11,400
Interest $6,269 10,598 10,031 9,529 8,994 8,371
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75
------ ------ ------ ------ ------ ------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.44 1.42 1.42 1.42 1.42 1.41
AVERAGE DEBT COVERAGE (27) 2.39
MINIMUM SENIOR DEBT COVERAGE 1.41
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Major Overhaul Expenses (29) $0 5,850 0 2,821 0 12,074
Major Maintenance Reserve Balance (30) $8,500 7,643 12,588 14,984 20,333 13,902
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 108,300 95,850 83,250
Principal 12,450 12,600 13,050
Interest 7,536 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000 176,000
Principal 0 0 0
Interest 14,362 14,362 14,362
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 34,411 33,667 33,206
TRANSFERS FROM DSRA (25) 371 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.41 1.41 1.41
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (371) (226) (242)
Debt Service Reserve Account Balance (28) 16,914 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 4,525 4,525 4,975
Major Overhaul Expenses (29) 3,047 0 3,207
Major Maintenance Reserve Balance (30) 16,145 21,558 24,512
</TABLE>
B-98
<PAGE>
Exhibit B-9
Batesville Project
Projected Operating Results
Sensitivity H - No PPA Renewal & Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 53.76% 52.84% 52.85% 52.86% 52.01% 51.17%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,530,700 2,487,300 2,488,000 2,488,700 1,020,300 0
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,265,300 1,243,700 1,244,000 1,244,300 1,224,300 1,204,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 1,428,400 2,408,700
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 26,769 26,311 26,318 26,325 25,902 25,479
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $68.14 68.14 68.14 68.14 24.39 0.00
Energy Rate ($/MWh)(13) $1.52 1.57 1.62 1.66 1.71 0.00
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 59.51 59.51 59.51
Energy Rate ($/MWh)(15) $1.38 1.41 1.45 1.49 1.53 1.57
Market Electricity Rates (16) $42.51 41.94 45.90 50.03 51.65 53.32
Natural Gas Price ($/MMBtu)(17) $3.218 3.318 3.421 3.527 3.636 3.749
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $36,988 36,988 36,988 36,988 13,240 0
Energy $3,265 3,308 3,409 3,509 1,479 0
Tracking Account Payment $586 594 613 632 267 0
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 16,152 16,152 16,152
Energy $1,706 1,720 1,765 1,812 1,829 1,846
Tracking Account Payment $37 37 38 39 40 41
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 0 73,777 128,432
Interest Income (19) $904 894 900 869 749 651
------ ------ ------ ------ ------ ------
Total Operating Revenues $59,637 59,693 59,864 60,001 107,534 147,122
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 36,625 63,674
Labor $2,079 2,133 2,189 2,246 2,304 2,364
Deposits to Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Corps of Engineers $111 111 111 111 111 111
Subcontractor $249 256 262 269 276 283
Lateral Pipeline O&M $22 23 24 24 25 26
Back Up Power $343 351 361 370 379 389
Balance of Plant Parts $402 407 414 426 430 434
Equipment and Materials $304 306 313 321 323 329
Water Treatment Chemicals $170 171 176 180 182 184
SCR Chemicals $133 134 138 142 143 145
Supply/Waste Water Pumping Costs $175 179 183 187 187 191
Electrical Transmission O&M $12 13 13 13 14 14
Insurance $748 767 787 808 829 850
Administrative & General $997 1,023 1,050 1,077 1,105 1,134
Property Taxes (22) $1,900 1,900 1,900 4,438 4,386 4,489
Panola Partnership / Inducement A Payments $359 366 373 380 388 396
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $13,445 13,982 14,567 17,729 54,942 80,106
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $46,192 45,711 45,297 42,272 52,592 67,016
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 50.68% 50.20% 49.64%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 0 0 0
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,193,000 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 2,386,000 3,545,000 3,505,500
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 25,239 24,999 24,721
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 0.00 0.00 0.00
Energy Rate ($/MWh)(13) 0.00 0.00 0.00
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 0.00 0.00
Energy Rate ($/MWh)(15) 1.61 0.00 0.00
Market Electricity Rates (16) 55.58 57.92 59.68
Natural Gas Price ($/MMBtu)(17) 3.865 3.985 4.108
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 0 0 0
Energy 0 0 0
Tracking Account Payment 0 0 0
Transmission (18) 0 0 0
Aquila/UtiliCorp
Capacity 16,152 0 0
Energy 1,876 0 0
Tracking Account Payment 41 0 0
Transmission (18) 0 0 0
Market 132,614 205,326 209,208
Interest Income (19) 650 627 619
------ ------ ------
Total Operating Revenues 151,333 205,953 209,827
OPERATING EXPENSES ($000)(20)
Fuel Expense 65,029 99,612 101,555
Labor 2,425 2,488 2,553
Deposits to Major Maintenance Reserve (21) 5,375 5,778 6,211
Corps of Engineers 111 111 111
Subcontractor 291 298 306
Lateral Pipeline O&M 26 27 28
Back Up Power 399 409 421
Balance of Plant Parts 440 450 456
Equipment and Materials 333 337 344
Water Treatment Chemicals 187 190 193
SCR Chemicals 147 149 151
Supply/Waste Water Pumping Costs 193 199 200
Electrical Transmission O&M 15 15 15
Insurance 872 895 918
Administrative & General 1,163 1,193 1,224
Property Taxes (22) 4,358 4,239 4,180
Panola Partnership / Inducement A Payments 404 412 420
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 81,861 116,895 119,379
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 69,472 89,058 90,448
</TABLE>
B-99
<PAGE>
Exhibit B-9
Batesville Project
Projected Operating Results
Sensitivity H - No PPA Renewal & Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0
Principal $13,500 14,100 15,300 15,300 12,000 0
Interest $4,787 3,809 2,778 1,682 645 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 9,328
Interest $14,362 14,362 14,362 14,362 14,362 14,171
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29
ANNUAL DEBT SERVICE COVERAGE (26) 1.42 1.41 1.41 1.42 2.01 2.85
AVERAGE DEBT COVERAGE (27) 2.39
MINIMUM SENIOR DEBT COVERAGE 1.41
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Major Overhaul Expenses (29) $0 20,359 10,536 0 6,615 0
Major Maintenance Reserve Balance (30) $31,208 18,314 14,965 22,432 24,193 30,524
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0 0
Principal 0 0 0
Interest 0 0 0
Series B Bonds
Balance Outstanding 166,672 156,640 146,608
Principal 10,032 10,032 10,560
Interest 13,396 12,577 11,748
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 23,492 22,673 22,372
TRANSFERS FROM DSRA (25) 409 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 2.97 3.93 4.07
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (409) (145) (607)
Debt Service Reserve Account Balance (28) 11,407 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 5,375 5,778 6,211
Major Overhaul Expenses (29) 22,369 0 5,360
Major Maintenance Reserve Balance (30) 15,209 21,823 23,874
</TABLE>
B-100
<PAGE>
Exhibit B-9
Batesville Project
Projected Operating Results
Sensitivity H - No PPA Renewal & Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 49.08% 49.18% 49.27% 47.70% 46.42% 45.67%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 0 0 0 0 0 0
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 0 0 0 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 3,466,000 3,472,500 3,479,000 3,368,000 3,278,000 3,225,000
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 24,442 24,488 24,534 23,751 23,116 22,743
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $0.00 0.00 0.00 0.00 0.00 0.00
Energy Rate ($/MWh)(13) $0.00 0.00 0.00 0.00 0.00 0.00
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $0.00 0.00 0.00 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $0.00 0.00 0.00 0.00 0.00 0.00
Market Electricity Rates (16) $61.49 63.10 64.76 67.87 70.06 72.09
Natural Gas Price ($/MMBtu)(17) $4.236 4.367 4.502 4.642 4.786 4.934
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $0 0 0 0 0 0
Energy $0 0 0 0 0 0
Tracking Account Payment $0 0 0 0 0 0
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $0 0 0 0 0 0
Energy $0 0 0 0 0 0
Tracking Account Payment $0 0 0 0 0 0
Transmission (18) $0 0 0 0 0 0
Market $213,124 219,115 225,300 228,586 229,657 232,490
Interest Income (19) $586 616 463 746 715 677
------ ------ ------ ------ ------ ------
Total Operating Revenues $213,710 219,731 225,763 229,332 230,372 233,167
OPERATING EXPENSES ($000)(20)
Fuel Expense $103,525 106,935 110,454 110,246 110,626 112,210
Labor $2,619 2,688 2,757 2,829 2,903 2,978
Deposits to Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Corps of Engineers $111 111 111 111 111 111
Subcontractor $314 322 331 339 348 357
Lateral Pipeline O&M $28 29 30 31 31 32
Back Up Power $432 442 454 465 478 490
Balance of Plant Parts $461 476 487 485 485 490
Equipment and Materials $347 358 369 364 364 368
Water Treatment Chemicals $195 201 207 205 205 207
SCR Chemicals $153 156 160 158 161 161
Supply/Waste Water Pumping Costs $204 208 216 212 213 216
Electrical Transmission O&M $16 16 17 17 17 18
Insurance $942 967 992 1,018 1,044 1,071
Administrative & General $1,256 1,289 1,322 1,357 1,392 1,428
Property Taxes (22) $4,065 3,965 4,124 4,244 4,331 4,161
Panola Partnership / Inducement A Payments $428 437 446 455 464 473
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $121,866 125,871 130,287 130,924 132,183 134,450
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $91,844 93,860 95,476 98,408 98,189 98,717
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 44.76% 44.16%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 3,161,000 1,559,000
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 22,291 10,994
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 0.00 0.00
Energy Rate ($/MWh)(13) 0.00 0.00
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00 0.00
Energy Rate ($/MWh)(15) 0.00 0.00
Market Electricity Rates (16) 74.03 75.89
Natural Gas Price ($/MMBtu)(17) 5.087 5.245
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Market 234,009 118,313
Interest Income (19) 780 730
------ ------
Total Operating Revenues 234,789 119,043
OPERATING EXPENSES ($000)(20)
Fuel Expense 113,394 57,659
Labor 3,056 1,567
Deposits to Major Maintenance Reserve (21) 525 282
Corps of Engineers 111 55
Subcontractor 366 188
Lateral Pipeline O&M 33 17
Back Up Power 503 359
Balance of Plant Parts 493 249
Equipment and Materials 370 187
Water Treatment Chemicals 208 105
SCR Chemicals 161 83
Supply/Waste Water Pumping Costs 215 109
Electrical Transmission O&M 18 9
Insurance 1,099 564
Administrative & General 1,465 752
Property Taxes (22) 3,921 1,795
Panola Partnership / Inducement A Payments 483 246
Trustee & Rating Agency Fees 93 46
------ ------
Total Operating Expenses 126,514 64,272
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 108,275 54,771
</TABLE>
B-101
<PAGE>
Exhibit B-9
Batesville Project
Projected Operating Results
Sensitivity H - No PPA Renewal & Reduced Market Prices
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0
Principal $0 0 0 0 0 0
Interest $0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816
Principal $10,208 12,144 7,568 18,480 18,832 19,008
Interest $10,893 10,021 9,123 8,283 6,768 5,228
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0
ANNUAL DEBT SERVICE COVERAGE (26) 4.34 4.35 5.70 3.69 3.85 4.06
AVERAGE DEBT COVERAGE (27) 2.39
MINIMUM SENIOR DEBT COVERAGE 1.41
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Major Overhaul Expenses (29) $0 4,253 22,618 0 10,591 0
Major Maintenance Reserve Balance (30) $31,864 36,542 23,651 33,247 33,402 44,825
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 49,808 25,520
Principal 24,288 25,520
Interest 3,569 1,041
Letter-of-Credit Fees 64 32
------ ------
Total Debt Service 27,921 26,593
TRANSFERS FROM DSRA (25) 0 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 3.88 3.06
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account 12,385 (26,561)
Debt Service Reserve Account Balance (28) 26,561 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 525 282
Major Overhaul Expenses (29) 15,678 0
Major Maintenance Reserve Balance (30) 32,137 33,303
</TABLE>
B-102
<PAGE>
Footnotes to Exhibit B-9
The footnotes to Exhibit B-9 are the same as the footnotes for Exhibit B-1,
except:
12. Virginia Power assumed to renew the Virginia Power Purchase Agreement
through May 31, 2013.
13. Virginia Power assumed to renew the Virginia Power Purchase Agreement
through May 31, 2013.
14. Aquila/UtiliCorp assumed to renew the Aquila/UtiliCorp Power Purchase
Agreement through December 31, 2015.
15. Aquila/UtiliCorp assumed to renew the Aquila/UtiliCorp Power Purchase
Agreement through December 31, 2015.
16. Assumed to be equal to C.C. Pace's Downside Case.
B-103
<PAGE>
Exhibit B-10
Batesville Project
Projected Operating Results
Sensitivity I - No PPA Renewal
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 66.71% 63.73% 63.73% 63.29% 62.85% 62.04%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,832,000 3,000,000 3,000,000 2,979,300 2,958,700 2,920,700
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 916,000 1,500,000 1,500,000 1,489,700 1,479,300 1,460,300
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 19,379 31,734 31,734 31,515 31,297 30,895
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $57.30 57.30 57.30 57.30 57.30 63.62
Energy Rate ($/MWh)(13) $1.18 1.20 1.24 1.27 1.31 1.36
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $58.33 58.33 58.33 58.33 58.33 59.51
Energy Rate ($/MWh)(15) $1.09 1.12 1.15 1.18 1.21 1.24
Market Electricity Rates (16) $34.55 35.56 36.59 37.95 39.36 40.54
Natural Gas Price ($/MMBtu)(17) $2.445 2.521 2.599 2.679 2.762 2.848
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $18,143 31,102 31,102 31,102 31,102 34,535
Energy $1,832 3,060 3,150 3,218 3,284 3,359
Tracking Account Payment $322 544 561 575 588 599
Transmission (18) $1,322 2,267 2,267 2,267 2,267 2,267
Aquila/UtiliCorp
Capacity $9,235 15,832 15,832 15,832 15,832 16,152
Energy $980 1,647 1,690 1,722 1,754 1,777
Tracking Account Payment $20 34 35 36 37 37
Transmission (18) $661 1,133 1,133 1,133 1,133 1,133
Market $0 0 0 0 0 0
Interest Income (19) $403 917 864 863 861 944
------ ------ ------ ------ ------ ------
Total Operating Revenues $32,919 56,536 56,634 56,747 56,858 60,803
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 0 0
Labor $963 1,693 1,737 1,782 1,829 1,876
Deposits to Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Corps of Engineers $64 111 111 111 111 111
Subcontractor $115 203 208 214 219 225
Lateral Pipeline O&M $10 18 19 19 20 20
Back Up Power $158 279 286 294 302 309
Balance of Plant Parts $231 387 396 407 413 421
Equipment and Materials $173 293 302 304 311 315
Water Treatment Chemicals $98 164 168 171 175 177
SCR Chemicals $77 126 131 134 138 136
Supply/Waste Water Pumping Costs $102 171 176 179 182 184
Electrical Transmission O&M $6 10 10 11 11 11
Insurance $346 609 625 641 658 675
Administrative & General $462 812 833 855 877 900
Property Taxes (22) $0 0 1,900 1,900 1,900 1,900
Panola Partnership / Inducement A Payments $175 306 312 318 325 331
Trustee & Rating Agency Fees $54 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $11,534 9,800 11,832 11,958 12,089 12,209
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $21,385 46,736 44,802 44,789 44,769 48,594
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 61.23% 60.91% 60.58%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,882,700 2,867,300 2,852,000
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,441,300 1,433,700 1,426,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 0 0 0
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 30,493 30,331 30,168
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 68.14 68.14 68.14
Energy Rate ($/MWh)(13) 1.39 1.43 1.47
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 59.51 59.51
Energy Rate ($/MWh)(15) 1.27 1.31 1.34
Market Electricity Rates (16) 41.75 42.82 43.92
Natural Gas Price ($/MMBtu)(17) 2.936 3.027 3.121
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 36,988 36,988 36,988
Energy 3,402 3,469 3,565
Tracking Account Payment 609 625 641
Transmission (18) 678 0 0
Aquila/UtiliCorp
Capacity 16,152 16,152 16,152
Energy 1,799 1,836 1,874
Tracking Account Payment 38 39 40
Transmission (18) 339 0 0
Market 0 0 0
Interest Income (19) 951 930 918
------ ------ ------
Total Operating Revenues 60,956 60,039 60,178
OPERATING EXPENSES ($000)(20)
Fuel Expense 0 0 0
Labor 1,925 1,975 2,026
Deposits to Major Maintenance Reserve (21) 4,525 4,525 4,975
Corps of Engineers 111 111 111
Subcontractor 231 237 243
Lateral Pipeline O&M 21 21 22
Back Up Power 317 325 333
Balance of Plant Parts 424 434 441
Equipment and Materials 320 327 334
Water Treatment Chemicals 179 183 187
SCR Chemicals 138 142 145
Supply/Waste Water Pumping Costs 186 189 193
Electrical Transmission O&M 12 12 12
Insurance 692 710 729
Administrative & General 923 947 972
Property Taxes (22) 1,900 1,900 1,900
Panola Partnership / Inducement A Payments 338 345 351
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 12,335 12,476 13,067
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 48,621 47,563 47,111
</TABLE>
B-104
<PAGE>
Exhibit B-10
Batesville Project
Projected Operating Results
Sensitivity I - No PPA Renewal
<TABLE>
<CAPTION>
Year Ending December 31, 2000(1) 2001 2002 2003 2004 2005
- ------------------------ -------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $150,000 150,000 141,750 134,850 127,500 119,700
Principal $0 8,250 6,900 7,350 7,800 11,400
Interest $6,269 10,598 10,031 9,529 8,994 8,371
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 0
Interest $8,378 14,362 14,362 14,362 14,362 14,362
Letter-of-Credit Fees $54 92 92 92 92 75
------ ------ ------ ------ ------ ------
Total Debt Service $14,700 33,302 31,385 31,333 31,248 34,208
TRANSFERS FROM DSRA (25) $0 971 22 38 0 0
ANNUAL DEBT SERVICE COVERAGE (26) 1.45 1.43 1.43 1.43 1.43 1.42
AVERAGE DEBT COVERAGE (27) 2.66
MINIMUM SENIOR DEBT COVERAGE 1.42
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $4,128 (971) (22) (38) 1,521 117
Debt Service Reserve Account Balance (28) $16,679 15,708 15,686 15,648 17,168 17,285
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $8,500 4,525 4,525 4,525 4,525 4,525
Major Overhaul Expenses (29) $0 5,850 0 2,821 11,768 0
Major Maintenance Reserve Balance (30) $8,500 7,643 12,588 14,984 8,565 13,561
<CAPTION>
Year Ending December 31, 2006 2007 2008
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 108,300 95,850 83,250
Principal 12,450 12,600 13,050
Interest 7,536 6,641 5,730
Series B Bonds
Balance Outstanding 176,000 176,000 176,000
Principal 0 0 0
Interest 14,362 14,362 14,362
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 34,411 33,667 33,206
TRANSFERS FROM DSRA (25) 371 226 242
ANNUAL DEBT SERVICE COVERAGE (26) 1.42 1.42 1.43
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (371) (226) (242)
Debt Service Reserve Account Balance (28) 16,914 16,688 16,445
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 4,525 4,525 4,975
Major Overhaul Expenses (29) 3,047 3,126 0
Major Maintenance Reserve Balance (30) 15,785 18,052 24,020
</TABLE>
B-105
<PAGE>
Exhibit B-10
Batesville Project
Projected Operating Results
Sensitivity I - No PPA Renewal
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 60.08% 59.58% 59.05% 58.53% 57.88% 57.23%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 2,828,300 2,804,700 2,780,000 2,755,300 1,135,300 0
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,414,200 1,402,300 1,390,000 1,377,700 1,362,300 1,347,000
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 0 0 0 0 1,589,400 2,694,000
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 29,918 29,668 29,407 29,146 28,822 28,497
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $68.14 68.14 68.14 68.14 24.39 0.00
Energy Rate ($/MWh)(13) $1.52 1.57 1.62 1.66 1.71 0.00
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $59.51 59.51 59.51 59.51 59.51 59.51
Energy Rate ($/MWh)(15) $1.38 1.41 1.45 1.49 1.53 1.57
Market Electricity Rates (16) $45.31 46.74 48.69 50.71 52.35 54.04
Natural Gas Price ($/MMBtu)(17) $3.218 3.318 3.421 3.527 3.636 3.749
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $36,988 36,988 36,988 36,988 13,240 0
Energy $3,649 3,730 3,809 3,885 1,646 0
Tracking Account Payment $655 670 685 700 297 0
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $16,152 16,152 16,152 16,152 16,152 16,152
Energy $1,906 1,940 1,973 2,006 2,035 2,065
Tracking Account Payment $41 42 43 44 45 45
Transmission (18) $0 0 0 0 0 0
Market $0 0 0 0 83,205 145,584
Interest Income (19) $904 894 900 869 749 651
------ ------ ------ ------ ------ ------
Total Operating Revenues $60,294 60,416 60,549 60,643 117,369 164,497
OPERATING EXPENSES ($000)(20)
Fuel Expense $0 0 0 0 40,753 71,216
Labor $2,079 2,133 2,189 2,246 2,304 2,364
Deposits to Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Corps of Engineers $111 111 111 111 111 111
Subcontractor $249 256 262 269 276 283
Lateral Pipeline O&M $22 23 24 24 25 26
Back Up Power $343 351 361 370 379 389
Balance of Plant Parts $450 459 463 471 478 485
Equipment and Materials $339 345 350 355 360 368
Water Treatment Chemicals $190 193 196 200 203 206
SCR Chemicals $148 151 154 157 159 162
Supply/Waste Water Pumping Costs $195 202 204 207 208 214
Electrical Transmission O&M $12 13 13 13 14 14
Insurance $748 767 787 808 829 850
Administrative & General $997 1,023 1,050 1,077 1,105 1,134
Property Taxes (22) $1,900 1,900 1,900 4,438 4,386 4,489
Panola Partnership / Inducement A Payments $359 366 373 380 388 396
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $13,583 14,135 14,710 17,863 59,213 87,800
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $46,711 46,281 45,839 42,780 58,156 76,697
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00%
Capacity Factor (4) 56.36% 55.48% 54.88%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 0 0 0
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20%
Energy Sales (MWh) 1,326,500 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061
Market Energy Sales 2,653,000 3,918,000 3,875,000
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052
Fuel Consumption (BBtu) 28,063 27,630 27,327
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 0.00 0.00 0.00
Energy Rate ($/MWh)(13) 0.00 0.00 0.00
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 59.51 0.00 0.00
Energy Rate ($/MWh)(15) 1.61 0.00 0.00
Market Electricity Rates (16) 56.48 59.01 61.00
Natural Gas Price ($/MMBtu)(17) 3.865 3.985 4.108
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 0 0 0
Energy 0 0 0
Tracking Account Payment 0 0 0
Transmission (18) 0 0 0
Aquila/UtiliCorp
Capacity 16,152 0 0
Energy 2,086 0 0
Tracking Account Payment 46 0 0
Transmission (18) 0 0 0
Market 149,841 231,201 236,375
Interest Income (19) 650 627 619
------ ------ ------
Total Operating Revenues 168,775 231,828 236,994
OPERATING EXPENSES ($000)(20)
Fuel Expense 72,306 110,093 112,260
Labor 2,425 2,488 2,553
Deposits to Major Maintenance Reserve (21) 5,375 5,778 6,211
Corps of Engineers 111 111 111
Subcontractor 291 298 306
Lateral Pipeline O&M 26 27 28
Back Up Power 399 409 421
Balance of Plant Parts 489 498 504
Equipment and Materials 370 372 380
Water Treatment Chemicals 208 210 213
SCR Chemicals 163 165 167
Supply/Waste Water Pumping Costs 215 219 221
Electrical Transmission O&M 15 15 15
Insurance 872 895 918
Administrative & General 1,163 1,193 1,224
Property Taxes (22) 4,358 4,239 4,180
Panola Partnership / Inducement A Payments 404 412 420
Trustee & Rating Agency Fees 93 93 93
------ ------ ------
Total Operating Expenses 89,283 127,515 130,225
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 79,492 104,313 106,769
</TABLE>
B-106
<PAGE>
Exhibit B-10
Batesville Project
Projected Operating Results
Sensitivity I - No PPA Renewal
<TABLE>
<CAPTION>
Year Ending December 31, 2009 2010 2011 2012 2013 2014
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $70,200 56,700 42,600 27,300 12,000 0
Principal $13,500 14,100 15,300 15,300 12,000 0
Interest $4,787 3,809 2,778 1,682 645 0
Series B Bonds
Balance Outstanding $176,000 176,000 176,000 176,000 176,000 176,000
Principal $0 0 0 0 0 9,328
Interest $14,362 14,362 14,362 14,362 14,362 14,171
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $32,713 32,335 32,503 31,407 27,070 23,563
TRANSFERS FROM DSRA (25) $184 0 548 2,198 1,766 29
ANNUAL DEBT SERVICE COVERAGE (26) 1.43 1.43 1.43 1.43 2.21 3.26
AVERAGE DEBT COVERAGE (27) 2.66
MINIMUM SENIOR DEBT COVERAGE 1.42
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account ($184) 95 (548) (2,198) (1,766) (29)
Debt Service Reserve Account Balance (28) $16,262 16,357 15,809 13,611 11,845 11,816
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $5,348 5,749 6,180 6,644 7,142 5,000
Major Overhaul Expenses (29) $19,843 10,269 0 6,447 21,249 0
Major Maintenance Reserve Balance (30) $10,846 6,923 13,484 14,423 1,109 6,170
<CAPTION>
Year Ending December 31, 2015 2016 2017
- ------------------------ ------ ------ ------
<S> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0 0
Principal 0 0 0
Interest 0 0 0
Series B Bonds
Balance Outstanding 166,672 156,640 146,608
Principal 10,032 10,032 10,560
Interest 13,396 12,577 11,748
Letter-of-Credit Fees 64 64 64
------ ------ ------
Total Debt Service 23,492 22,673 22,372
TRANSFERS FROM DSRA (25) 409 145 607
ANNUAL DEBT SERVICE COVERAGE (26) 3.40 4.61 4.80
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account (409) (145) (607)
Debt Service Reserve Account Balance (28) 11,407 11,262 10,655
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 5,375 5,778 6,211
Major Overhaul Expenses (29) 5,091 0 4,040
Major Maintenance Reserve Balance (30) 6,793 12,945 15,828
</TABLE>
B-107
<PAGE>
Exhibit B-10
Batesville Project
Projected Operating Results
Sensitivity I - No PPA Renewal
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100 806,100 806,100 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00% 92.00% 92.00% 92.00% 92.00%
Capacity Factor (4) 54.27% 54.13% 54.00% 53.01% 51.51% 50.73%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400 537,400 537,400 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000 473,000 473,000 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800 69,800 69,800 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 0 0 0 0 0 0
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124 7,124 7,124 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700 268,700 268,700 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500 236,500 236,500 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500 30,500 30,500 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400 4,400 4,400 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20% 97.20% 97.20% 97.20% 97.20%
Energy Sales (MWh) 0 0 0 0 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061 7,061 7,061 7,061 7,061
Market Energy Sales 3,832,000 3,822,500 3,813,000 3,743,000 3,637,000 3,582,000
Heat Rate (Btu/kWh)(10) 7,052 7,052 7,052 7,052 7,052 7,052
Fuel Consumption (BBtu) 27,023 26,956 26,889 26,396 25,648 25,260
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60 2.60 2.60 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) $0.00 0.00 0.00 0.00 0.00 0.00
Energy Rate ($/MWh)(13) $0.00 0.00 0.00 0.00 0.00 0.00
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) $0.00 0.00 0.00 0.00 0.00 0.00
Energy Rate ($/MWh)(15) $0.00 0.00 0.00 0.00 0.00 0.00
Market Electricity Rates (16) $63.04 64.57 66.13 69.39 70.99 72.53
Natural Gas Price ($/MMBtu)(17) $4.236 4.367 4.502 4.642 4.786 4.934
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity $0 0 0 0 0 0
Energy $0 0 0 0 0 0
Tracking Account Payment $0 0 0 0 0 0
Transmission (18) $0 0 0 0 0 0
Aquila/UtiliCorp
Capacity $0 0 0 0 0 0
Energy $0 0 0 0 0 0
Tracking Account Payment $0 0 0 0 0 0
Transmission (18) $0 0 0 0 0 0
Market $241,569 246,819 252,154 259,727 258,191 259,802
Interest Income (19) $586 616 463 746 715 677
------ ------ ------ ------ ------ ------
Total Operating Revenues $242,155 247,435 252,617 260,473 258,906 260,479
OPERATING EXPENSES ($000)(20)
Fuel Expense $114,457 117,713 121,058 122,521 122,742 124,632
Labor $2,619 2,688 2,757 2,829 2,903 2,978
Deposits to Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Corps of Engineers $111 111 111 111 111 111
Subcontractor $314 322 331 339 348 357
Lateral Pipeline O&M $28 29 30 31 31 32
Back Up Power $432 442 454 465 478 490
Balance of Plant Parts $510 524 534 539 538 544
Equipment and Materials $383 394 404 404 404 408
Water Treatment Chemicals $216 221 226 228 227 230
SCR Chemicals $169 172 175 176 178 179
Supply/Waste Water Pumping Costs $226 229 236 236 236 240
Electrical Transmission O&M $16 16 17 17 17 18
Insurance $942 967 992 1,018 1,044 1,071
Administrative & General $1,256 1,289 1,322 1,357 1,392 1,428
Property Taxes (22) $4,065 3,965 4,124 4,244 4,331 4,161
Panola Partnership / Inducement A Payments $428 437 446 455 464 473
Trustee & Rating Agency Fees $93 93 93 93 93 93
------ ------ ------ ------ ------ ------
Total Operating Expenses $132,942 136,790 141,027 143,358 144,454 147,031
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) $109,213 110,645 111,590 117,115 114,452 113,448
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
PERFORMANCE
Plant Output (kW)(2) 806,100 806,100
Availability Factor (%)(3) 92.00% 92.00%
Capacity Factor (4) 49.64% 48.06%
Sales to Virginia Power
Annual Average Capacity (kW) 537,400 537,400
Summer Cond. Standard Capacity (kW)(5) 473,000 473,000
Summer Cond. Supplemental Capacity (kW)(5) 69,800 69,800
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(7) 7,124 7,124
Sales to Aquila/UtiliCorp
Annual Average Capacity (kW) 268,700 268,700
Standard Capacity (kW)(5) 236,500 236,500
Supplemental Capacity (kW)(5) 30,500 30,500
Surplus Supplemental Capacity (kW)(8) 4,400 4,400
Contract Availability (%)(6) 97.20% 97.20%
Energy Sales (MWh) 0 0
Contract Heat Rate (Btu/kWh)(9) 7,061 7,061
Market Energy Sales 3,505,000 1,697,000
Heat Rate (Btu/kWh)(10) 7,052 7,052
Fuel Consumption (BBtu) 24,717 11,967
COMMODITY PRICES
General Inflation (%)(11) 2.60 2.60
Virginia Power Electricity Rates
Average Capacity Rate ($/kW-yr)(12) 0.00 0.00
Energy Rate ($/MWh)(13) 0.00 0.00
Aquila/UtiliCorp Electricity Rates
Average Capacity Rate ($/kW-yr)(14) 0.00 0.00
Energy Rate ($/MWh)(15) 0.00 0.00
Market Electricity Rates (16) 75.27 77.89
Natural Gas Price ($/MMBtu)(17) 5.087 5.245
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Virginia Power
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Aquila/UtiliCorp
Capacity 0 0
Energy 0 0
Tracking Account Payment 0 0
Transmission (18) 0 0
Market 263,821 132,179
Interest Income (19) 780 730
------ ------
Total Operating Revenues 264,601 132,909
OPERATING EXPENSES ($000)(20)
Fuel Expense 125,734 62,763
Labor 3,056 1,567
Deposits to Major Maintenance Reserve (21) 525 282
Corps of Engineers 111 55
Subcontractor 366 188
Lateral Pipeline O&M 33 17
Back Up Power 503 359
Balance of Plant Parts 547 272
Equipment and Materials 410 204
Water Treatment Chemicals 231 115
SCR Chemicals 179 90
Supply/Waste Water Pumping Costs 238 119
Electrical Transmission O&M 18 9
Insurance 1,099 564
Administrative & General 1,465 752
Property Taxes (22) 3,921 1,795
Panola Partnership / Inducement A Payments 483 246
Trustee & Rating Agency Fees 93 46
------ ------
Total Operating Expenses 139,012 69,443
CASH AVAILABLE
FOR DEBT SERVICE ($000)(23) 125,589 63,466
</TABLE>
B-108
<PAGE>
Exhibit B-10
Batesville Project
Projected Operating Results
Sensitivity I - No PPA Renewal
<TABLE>
<CAPTION>
Year Ending December 31, 2018 2019 2020 2021 2022 2023
- ------------------------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding $0 0 0 0 0 0
Principal $0 0 0 0 0 0
Interest $0 0 0 0 0 0
Series B Bonds
Balance Outstanding $136,048 125,840 113,696 106,128 87,648 68,816
Principal $10,208 12,144 7,568 18,480 18,832 19,008
Interest $10,893 10,021 9,123 8,283 6,768 5,228
Letter-of-Credit Fees $64 64 64 64 64 64
------ ------ ------ ------ ------ ------
Total Debt Service $21,165 22,229 16,755 26,827 25,664 24,300
TRANSFERS FROM DSRA (25) $0 2,783 0 578 680 0
ANNUAL DEBT SERVICE COVERAGE (26) 5.16 5.10 6.66 4.39 4.49 4.67
AVERAGE DEBT COVERAGE (27) 2.66
MINIMUM SENIOR DEBT COVERAGE 1.42
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account $552 (2,783) 5,147 (578) (680) 1,864
Debt Service Reserve Account Balance (28) $11,206 8,423 13,570 12,992 12,312 14,176
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) $6,677 7,178 7,717 8,295 8,917 9,586
Major Overhaul Expenses (29) $21,486 0 10,061 0 14,894 17,409
Major Maintenance Reserve Balance (30) $1,890 9,172 7,332 16,030 10,935 3,713
<CAPTION>
Year Ending December 31, 2024 2025(1)
- ------------------------ ------ --------
<S> <C> <C>
ANNUAL DEBT SERVICE (24)
Series A Bonds
Balance Outstanding 0 0
Principal 0 0
Interest 0 0
Series B Bonds
Balance Outstanding 49,808 25,520
Principal 24,288 25,520
Interest 3,569 1,041
Letter-of-Credit Fees 64 32
------ ------
Total Debt Service 27,921 26,593
TRANSFERS FROM DSRA (25) 0 26,561
ANNUAL DEBT SERVICE COVERAGE (26) 4.50 3.39
AVERAGE DEBT COVERAGE (27)
MINIMUM SENIOR DEBT COVERAGE
DEBT SERVICE RESERVE ACCOUNT
Payments into Debt Service Reserve Account 12,385 (26,561)
Debt Service Reserve Account Balance (28) 26,561 0
MAJOR MAINTENANCE RESERVE
Payments into Major Maintenance Reserve (21) 525 282
Major Overhaul Expenses (29) 0 0
Major Maintenance Reserve Balance (30) 4,442 4,846
</TABLE>
B-109
<PAGE>
Footnotes to Exhibit B-10
The footnotes to Exhibit B-8 are the same as the footnotes for Exhibit B-1,
except:
12. Virginia Power assumed to renew the Virginia Power Purchase Agreement
through May 31, 2013.
13. Virginia Power assumed to renew the Virginia Power Purchase Agreement
through May 31, 2013.
14. Aquila/UtiliCorp assumed to renew the Aquila/UtiliCorp Power Purchase
Agreement through December 31, 2015.
15. Aquila/UtiliCorp assumed to renew the Aquila/UtiliCorp Power Purchase
Agreement through December 31, 2015.
B-110
<PAGE>
ANNEX C
INDEPENDENT ELECTRICITY MARKET AND FUEL CONSULTANT'S REPORT
After the expiration of the term of the power purchase agreements, we will
have to sell the power produced by our power facility in the competitive
southeastern power market. Further, without the power purchase agreements, we
will have to procure the natural gas required to operate our power facility. We
included this independent electricity market and fuel consultant's report
prepared by C.C. Pace Consulting, L.L.C. in order to, among other things:
- assess the ability of our power facility to compete in the southeastern
power market;
- predict the price for power in the southeastern power market during the
time in which we will be selling our power facility's power in this
market; and
- assess our ability to obtain natural gas after the expiration of the power
purchase agreements and predict the price which we will pay for natural
gas.
We retained C.C. Pace Consulting, L.L.C. as an independent consultant in
connection with the offering of the private bonds. C.C. Pace Consulting, L.L.C.
is not an employee, affiliate or agent of us, and does not have any relationship
to us other than as an independent consultant. We paid C.C. Pace Consulting,
L.L.C. a fee for the consulting services provided to us in connection with the
issuance of the private bonds.
C-1
<PAGE>
ANNEX C
================================================================================
CC Pace
CONSULTING, LLC
SOUTHEAST POWER MARKET ASSESSMENT AND
MARKET CLEARING PRICE FORECAST
FINAL REPORT
FOR
LS POWER, L.L.C.
May 13, 1999
PREPARED BY:
C.C. PACE CONSULTING, L.L.C.
Corporate Offices
4401 Fair Lakes Court
Suite 400
Fairfax, VA 22033
Phone (703) 818-9100
Fax (703) 818-9108
================================================================================
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
TABLE OF CONTENTS
- --------------------------------------------------------------------------------
I. EXECUTIVE SUMMARY......................................................C-1
RESULTS AND CONCLUSIONS................................................C-1
Project Results..................................................C-4
Base Case........................................................C-4
Downside Case....................................................C-5
APPROACH...............................................................C-6
CEMAS............................................................C-7
ASSUMPTIONS............................................................C-7
DOWNSIDE CASE..........................................................C-9
II. MARKET CLEARING PRICE APPROACH........................................C-10
APPROACH..............................................................C-10
REVENUE REQUIREMENT MODULE............................................C-12
UNIT FUEL PRICING MODULE..............................................C-13
HOURLY LOAD MODULE....................................................C-13
BIDDING ANALYSIS MODULE...............................................C-13
Equilibrium Pricing of Expansion Capacity.......................C-14
MARKET CLEARING PRICE MODULE..........................................C-16
DETERMINATION OF COMPETITIVE MARKET EXPANSION PLAN....................C-16
OUTLINE OF REPORT.....................................................C-17
III. SOUTHEAST MARKET PRICING RESULTS......................................C-18
CEMAS SIMULATED MARKET PRICING RATES..................................C-18
SYSTEM MARKET PRICING AND REVENUES - BASE CASE........................C-18
LS POWER UNIT RESULTS - BASE CASE.....................................C-20
SYSTEM RESULTS DOWNSIDE CASE..........................................C-21
LS POWER UNIT RESULTS - DOWNSIDE CASE.................................C-22
IV. MARKET AREA DEFINITION AND TRANSMISSION...............................C-24
TRANSMISSION..........................................................C-26
V. ELECTRICITY DEMAND IN THE SOUTHEAST MARKET............................C-28
EXISTING DEMAND PROFILE...............................................C-28
C.C. PACE'S LOAD FORECASTING METHODOLOGY..............................C-30
FORECAST RESULTS......................................................C-32
HOURLY LOAD FORECASTS.................................................C-34
- --------------------------------------------------------------------------------
i
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
VI. SOUTHEAST POWER GENERATION RESOURCES..................................C-36
GENERATION PROFILE....................................................C-36
GENERATING UNIT COST PROFILE..........................................C-37
C.C. PACE MARKET STUDY RESOURCE ADDITION ASSUMPTIONS..................C-40
DETERMINATION OF COMPETITIVE MARKET EXPANSION PLANT...................C-42
VII. FUEL PRICING..........................................................C-45
HISTORICAL FUEL PRICING...............................................C-45
COAL..................................................................C-50
C.C. Pace Coal Price Forecast.........................................C-52
FUEL OIL..............................................................C-55
C.C. Pace Fuel Oil Price Forecast.....................................C-56
Distillate Oil........................................................C-56
Residual Oil..........................................................C-58
URANIUM...............................................................C-58
NATURAL GAS...........................................................C-58
C.C. Pace Natural Gas Price Forecast..................................C-59
FUEL PRICE FORECASTING METHODOLOGY....................................C-62
ATTACHMENT I: REGIONAL MARKET DEFINITION AND TRANSMISSION CAPABILITY
ASSUMPTIONS & SUPPORTING ANALYSIS
ATTACHMENT II: DEMAND ASSUMPTIONS & SUPPORTING ANALYSIS
ATTACHMENT III: EXISTING AND PLANNED UNIT COST ASSUMPTIONS & SUPPORTING ANALYSIS
ATTACHMENT IV: FUEL PRICING ASSUMPTIONS & SUPPORTING ANALYSIS
- --------------------------------------------------------------------------------
ii
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
================================================================================
This Report was produced by C.C. Pace Consulting L.L.C. This Report is meant to
be read as a whole and in conjunction with this disclaimer. Any use of this
Report other than as a whole and in conjunction with this disclaimer is
forbidden. Any use of this Report outside of its stated purpose without the
written consent of C.C. Pace Consulting L.L.C. is forbidden. Except for its
stated purpose, this Report may not be copied or distributed in whole or in part
without C.C. Pace Consulting L.L.C.'s prior express written permission.
This Report, information, and statements herein are based in whole or in part on
information obtained from various sources. While C.C. Pace Consulting L.L.C.'s
believes such information to be accurate, it makes no assurances as to the
accuracy of any such information or any conclusions based thereon. C.C. Pace
Consulting L.L.C. assumes no responsibility for the results of any actions taken
on the basis of this Report.
================================================================================
- --------------------------------------------------------------------------------
iii
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
I. EXECUTIVE SUMMARY
- ------------------------------------------------------------------------------
C.C. Pace Consulting, L.L.C. (C.C. Pace) has prepared this independent
assessment of the Southeast United States electricity market (covering the
states of Arkansas, Northern Florida, East Texas, Louisiana, Mississippi,
Tennessee, Alabama, and Georgia) and the economic competitiveness of the
Batesville, Mississippi power project (Project or Batesville) under construction
by LSP Energy Partnership (The Partnership). 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
to 2025.
This report includes a prediction of market clearing prices and dispatch
profiles for the Project for the "Base" and "Downside" cases, and a description
of the key assumptions and the methodology used in developing this assessment.
To perform the analysis, C.C. Pace utilized its Capacity & Energy Market
Analysis System (CEMAS). CEMAS is an integrated resource planning tool designed
to simulate the deregulated power generation market and to project market
clearing prices for both capacity and energy under different market structures
and scenarios.
RESULTS AND CONCLUSIONS
The following represents conclusions and key findings of C.C. Pace's southeast
market assessment and market clearing price forecast. They are:
i. Compared to other power market regions, the southeastern power market is
highly competitive. The market's competitiveness is evidenced by the
region's large volume of power transactions. The market region represents
such a large amount of transactions that the region has become a market
standard for power deliveries referenced by the New York Mercantile
Exchange and Chicago Board of Trade futures contracts.
ii. C.C. Pace anticipates that given the rapid pace of this wholesale energy
market's development, a competitive and deregulated environment for retail
customers' energy requirements will be implemented on a near- to mid-term
basis (i.e., before the expiration of the power sales agreements that the
Partnership has entered into with Virginia Power and Aquila/UtiliCorp).
The development of this kind of capacity and energy market will enhance
the Partnership's ability to make power sales and should provide
additional marketing flexibility to the Partnership if the Virginia Power
and Aquila/UtiliCorp power purchase agreements expire.
iii. The technical capability of the Project to start up and shut down quickly
should allow the Partnership's power purchasers, at times when the
Partnership's power purchasers control
- --------------------------------------------------------------------------------
C-1
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
the dispatch of the Project, and the Partnership's, at times when the
Partnership controls the operation of the Project, to select operating
hours in which revenues and profitability can be maximized.
iv. The market for power in the southeast is characterized by:
a) Sustained energy demand growth expected to continue at a
steady annual average pace of 1.51% to 2.24% over the next 20
years. This sustained growth rate is higher than virtually any
region in the United States and makes the southeastern market
both the largest and the fastest growing demand center;
b) Ready access to competitively priced gas supply from a
diversified range of sources through an extensive interstate
gas pipeline transmission system;
c) Natural gas-based generation currently determining market
prices for electricity 30% of the time, rising to 70% over the
next 20 years;
d) A well-developed electrical transmission system capable of
transferring high volumes of electricity throughout the
southeast and covering over ten states and approximately 20%
of the electricity demand in the United States.
v. The most significant factors affecting the pricing of electricity in the
southeastern power market are:
a) Fuel costs;
b) The efficiency and replacement rate of existing generating
assets and capital costs of replacing existing generating
assets;
c) The cost and efficiency of incremental capacity additions
which are undertaken to meet future energy requirements and
maintain system reliability; and,
d) Increases in annual peak demand and energy requirements.
vi. C.C. Pace's Base Case market price forecasts are between $29.95 per
megawatt hour (MWh) and $33.75/MWh (measured in 1998 real dollars) for the
period from 2000 to 2025. C.C. Pace expects that due to incremental demand
and the large amount of capacity additions necessary to meet market
demand, the southeastern power market will realize an approximate 0.5%
real price increase in electricity prices over the period from 2000 to
2025 which is almost directly reflective of the real price escalation of
natural gas. Exhibit I - 1 to the C.C. Pace report summarizes the
southeastern system's market price results between 2000 and 2025 for the
Base Case.
vii. C.C. Pace's Downside Case market price forecast (i.e., a conservative case
in which there is a 95% probability that market prices will be equal to or
greater than the Downside Case result obtained) is between $27.25/MWh and
$32.20/MWh (measured in 1998 real dollars) for the period from 2000 to
2025.
- --------------------------------------------------------------------------------
C-2
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
viii. The Project represents a low cost, highly competitive, and much needed
resource for the growing southeastern market equaling only a small
fraction of the capacity required in the southeastern power market (only
1.85% of the total required expansion capacity) by the year 2020.
ix. The Project has many strong competitive advantages such as:
a) location which provides low cost access to gas and water;
b) direct access to multiple power markets via bi-directional
transmission links into both the TVA and Entergy power
systems;
c) state of the art generation technology which is the most
efficient in the market; and
d) close proximity to fuel production regions lowering fuel
supply and transportation costs.
These competitive advantages create an operational profile which suggest
that the Project will be a low cost and profitable resource in the
southeastern power market.
x. Virginia Power and Aquila/UtiliCorp, the two initial long-term power
purchasers, have entered into mutually acceptably priced power purchase
agreements with the Project. Both power purchasers are active in the
wholesale power market and are regionally well-positioned to operate in
the southeastern power market.
xi. The power purchase agreements are of high strategic value to both Virginia
Power and Aquila/Utilicorp, complementing their current utility and
non-utility operations and market positions. Specifically, neither entity
owns or operates any significant amount of generating capacity in the
southeastern power market and, with the Project's capacity, they are able
to trade firm capacity and energy in the southeastern market, doubling
each company's marketing area and allowing them to serve virtually any
customer across ten to twelve states.
xii. The extension options under the Power Purchase Agreements are
approximately 40% lower than the Projected Market Price and current
utility total cost of generation indicating a high likelihood of
extension.
xiii. Based on the timely construction of pipeline laterals and interconnection
facilities and the Project's maximum hourly fuel demand from the Tennessee
Gas and ANR gas pipelines, market priced natural gas supplies and
interstate transportation will be available in sufficient quantities and
on acceptable terms and conditions to support merchant plant generation
requirements from years 13 to 25 of the Project's operation.
xiv. Southeastern market utilities expect consistent and relatively high
(compared to the national average) summer peak demand and energy
requirements to increase at an average annual rate of 2.16% and 1.57% over
the next 10 years, respectively.
xv. To provide full access to both TVA and Entergy power markets, the
Partnership has arranged for the upgrade of certain transmission
facilities. Under the agreements with TVA
- --------------------------------------------------------------------------------
C-3
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
and Entergy, the Partnership will be granted transmission upgrade credits
up to the value of the transmission upgrade costs for the transmission of
energy across the TVA and Entergy systems. C.C. Pace estimates that
beginning in the first year of the Project's operation and continuing
until the total transmission upgrade cost is repaid to the Partnership,
the Partnership will accumulate additional revenues equal to a minimum of
approximately $3.4 million per year related to these transmission upgrades
credits.
Exhibit I - 1: Annual System Market Clearing Price - Base and Downside Case
(1998 Real Dollars)
- --------------------------------------------------------------------------------
====================================================================
Downside
Case
Base Case Market
Market Clearing
Clearing Price Price Price Price
Year $/MWh Escalation $/MWh Escalation
--------------------------------------------------------------------
2000 29.95 27.25
--------------------------------------------------------------------
2002 31.20 4.19% 28.99 6.40%
--------------------------------------------------------------------
2004 31.79 1.88% 29.48 1.68%
--------------------------------------------------------------------
2006 31.66 -0.42% 29.55 0.22%
--------------------------------------------------------------------
2008 31.41 -0.79% 29.38 -0.57%
--------------------------------------------------------------------
2010 31.75 1.10% 29.84 1.57%
--------------------------------------------------------------------
2012 32.49 2.33% 30.60 2.55%
--------------------------------------------------------------------
2014 32.78 0.89% 30.89 0.94%
--------------------------------------------------------------------
2016 33.39 1.87% 31.52 2.06%
--------------------------------------------------------------------
2018 33.76 1.10% 31.71 0.59%
--------------------------------------------------------------------
2020 33.94 0.52% 32.22 1.63%
--------------------------------------------------------------------
2021 34.06 0.37% 32.12 -0.32%
--------------------------------------------------------------------
2022 33.57 -1.45% 32.01 -0.34%
--------------------------------------------------------------------
2023 33.59 0.08% 32.12 0.35%
--------------------------------------------------------------------
2024 33.63 0.12% 32.00 -0.40%
--------------------------------------------------------------------
2025 33.78 0.43% 32.20 0.64%
====================================================================
- --------------------------------------------------------------------------------
Project Results
Base Case
To provide projections of Project dispatch, operating profile, and market
revenues, C.C. Pace explicitly modeled the Project as a resource in the
Southeast market. Specifically, the Project's heat rate efficiency, delivered
fuel costs, and variable operating costs were input in the model to allow the
simulation and unit dispatch when system marginal costs were equal to or higher
than Project variable costs. Based on this modeling approach, Exhibit I - 2
provides a summary of key Batesville unit operational results for the Base Case.
As shown in Exhibit I - 2, the Batesville unit is projected to be economically
dispatched at an annual capacity factor of approximately 51%-69%. Average
market-based revenues for the Batesville unit are projected to be between
$32.82/MWh in year 2000 and rise in real dollars to $39.33 by the year 2025.
Thus, the Batesville unit will achieve revenues above variable operational costs
(fuel and variable O&M) of between $15.36/MWh in the year 2001 and $19.66/MWh by
the year 2025. Lastly, due to the Project's transmission advantage,
- --------------------------------------------------------------------------------
C-4
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
it is able to exceed average market prices slightly by selling in the highest
priced market to optimize revenues.
Exhibit I - 2: Batesville Unit Annual Operational Summary (1998 Real Dollars)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
==================================================================================================================
Average
Market
Fuel Price
Generation Capacity Cost Variable Fixed Revenue Coverage Cover Received Price
Year GWh Factor $1000 O&M $1000 Cost $1000 $1000 $1000 $/MWh $/MWh Escalation
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
*2000 2,748 41.83% 45,173 2,748 -- 90,187 42,266 15.38 32.82
2002 4,500 68.50% 74,969 4,500 -- 148,591 69,122 15.36 33.02 0.61%
2004 4,438 67.55% 74,666 4,438 -- 149,730 70,627 15.92 33.74 2.18%
2006 4,324 65.81% 73,465 4,324 -- 147,003 69,214 16.01 34.00 0.77%
2008 4,278 65.11% 73,414 4,278 -- 145,377 67,684 15.82 33.98 -0.05%
2010 4,207 64.04% 72,934 4,207 -- 144,532 67,391 16.02 34.35 1.09%
2012 4,133 62.90% 72,350 4,133 -- 146,296 69,813 16.89 35.40 3.05%
2014 4,032 61.37% 71,294 4,032 -- 144,588 69,262 17.18 35.86 1.31%
2016 3,880 59.05% 69,290 3,880 -- 145,125 71,955 18.55 37.41 4.31%
2018 3,770 57.38% 67,994 3,770 -- 143,467 71,703 19.02 38.06 1.74%
2020 3,730 56.77% 67,960 3,730 -- 141,610 69,920 18.75 37.97 -0.24%
2021 3,675 55.94% 67,277 3,675 -- 142,654 71,702 19.51 38.81 2.24%
2022 3,549 54.01% 65,271 3,549 -- 137,826 69,006 19.45 38.84 0.06%
2023 3,489 53.10% 64,484 3,489 -- 134,984 67,012 19.21 38.69 -0.38%
2024 3,425 52.14% 63,635 3,425 -- 133,788 66,727 19.48 39.06 0.94%
2025 3,332 50.72% 62,216 3,332 -- 131,048 65,500 19.66 39.33 0.69%
==================================================================================================================
</TABLE>
* 2000 represents only a partial operational year with an on-line date of June
2000.
- --------------------------------------------------------------------------------
Downside Case
Exhibit I - 3 outlines the operational results of the Batesville unit associated
with C.C. Pace's Downside Case and the difference relative to the Base Case. The
Downside Case represents an unlikely scenario of the impact on the Project's
revenues and dispatch based on the compound effects of (i) a significant
improvement of expansion capacity capital costs (i.e., $50/kW cost reduction for
combustion turbines and $64/kW cost reduction for combined cycle installed
costs), and (ii) system capacity exceeds requirements by 2,400 MW or
approximately three times the size of the Project's installed capacity. As shown
in Exhibit I - 3, given system overcapacity, the Project is forecast to be
dispatched at an annual capacity factor between 46% and 62%, a decrease of
between 4% and 7% as compared to the Base Case. Average revenues for the
Batesville unit are projected to be between $31.18/MWh in the year 2000
increasing in real dollars to $38.52/MWh in 2025. Overall, during the forecast
period, average annual revenues earned by the Project were slightly less than in
the Base Case, the reduction ranging from $14.0 million to $18.6 million.
- --------------------------------------------------------------------------------
C-5
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit I - 3: C.C. Pace Downside Case Results and Base Case Differential
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------
Avg.
Fuel Variable Fixed Market
Generation Capacity Cost O&M Cost Revenue Coverage Cover Clearing Price
Year GWh Factor $1000 $1000 $1000 $1000 $1000 $/MWh Price $/MWh Escalation
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000 2,519 38.34% 41,415 2,519 -- 78,546 34,612 13.74 31.18
2002 4,094 62.31% 68,200 4,094 -- 130,935 58,641 14.32 31.98 2.58%
2004 4,007 60.99% 67,397 4,007 -- 131,373 59,969 14.97 32.79 2.51%
2006 3,862 58.79% 65,612 3,862 -- 128,358 58,883 15.24 33.23 1.36%
2008 3,861 58.77% 66,255 3,861 -- 128,500 58,384 15.12 33.28 0.15%
2010 3,731 56.79% 64,673 3,731 -- 126,177 57,772 15.48 33.82 1.61%
2012 3,733 56.82% 65,348 3,733 -- 130,396 61,315 16.42 34.93 3.29%
2014 3,571 54.36% 63,153 3,571 -- 126,655 59,931 16.78 35.46 1.53%
2016 3,466 52.76% 61,896 3,466 -- 127,691 62,328 17.98 36.84 3.87%
2018 3,406 51.84% 61,433 3,406 -- 126,422 61,583 18.08 37.12 0.77%
2020 3,424 52.12% 62,379 3,424 -- 126,956 61,152 17.86 37.08 -0.11%
2021 3,277 49.87% 59,968 3,277 -- 124,894 61,649 18.81 38.12 2.80%
2022 3,174 48.32% 58,379 3,174 -- 122,122 60,568 19.08 38.47 0.94%
2023 3,140 47.79% 58,025 3,140 -- 120,593 59,429 18.93 38.41 -0.16%
2024 3,076 46.82% 57,143 3,076 -- 118,317 58,098 18.89 38.46 0.13%
2025 3,038 46.24% 56,705 3,038 -- 117,021 57,279 18.86 38.52 0.16%
- --------------------------------------------------------------------------------------------------------------
</TABLE>
Difference from Base Case
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------
Avg.
Fuel Variable Fixed Market
Generation Capacity Cost O&M Cost Revenue Coverage Cover Clearing Price
Year GWh Factor $1000 $1000 $1000 $1000 $1000 $/MWh Price $/MWh Escalation
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000 -229 -3.48% -3,758 -229 -- -11,640 -7,654 -1.64 -1.64
2002 -406 -6.18% -6,769 -406 -- -17,657 -10,481 -1.04 -1.04 1.97%
2004 -431 -6.56% -7,269 -431 -- -18,357 -10,657 -0.95 -0.95 0.33%
2006 -461 -7.02% -7,853 -461 -- -18,645 -10,331 -0.76 -0.77 0.59%
2008 -417 -6.34% -7,159 -417 -- -16,876 -9,300 -0.70 -0.70 0.20%
2010 -476 -7.25% -8,261 -476 -- -18,355 -9,618 -0.53 -0.54 0.52%
2012 -399 -6.08% -7,002 -399 -- -15,900 -8,498 -0.47 -0.47 0.24%
2014 -460 -7.01% -8,141 -460 -- -17,933 -9,332 -0.40 -0.40 0.23%
2016 -413 -6.29% -7,394 -413 -- -17,434 -9,627 -0.57 -0.57 -0.44%
2018 -364 -5.54% -6,561 -364 -- -17,045 -10,120 -0.94 -0.94 -0.97%
2020 -306 -4.66% -5,581 -306 -- -14,655 -8,768 -0.89 -0.89 0.14%
2021 -399 -6.07% -7,309 -399 -- -17,761 -10,053 -0.70 -0.70 0.56%
2022 -374 -5.70% -6,892 -374 -- -15,704 -8,437 -0.36 -0.37 0.88%
2023 -349 -5.31% -6,459 -349 -- -14,391 -7,583 -0.28 -0.28 0.22%
2024 -349 -5.32% -6,492 -349 -- -15,470 -8,629 -0.59 -0.59 -0.81%
2025 -295 -4.48% -5,511 -295 -- -14,027 -8,221 -0.80 -0.80 -0.53%
- --------------------------------------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
APPROACH
C.C. Pace conducted a detailed analysis of the Southeast market clearing prices.
This analysis provides in-depth insight into the Southeast power market
fundamentals and the emerging competitive market. The analysis was built around
C.C. Pace's competitive market vision of an "one-price" market for both capacity
and energy. C.C. Pace used CEMAS to provide a dynamic analysis of future trends
in market clearing prices, capital recovery, and seasonal and hourly market
pricing.
The fundamentals and functional background of the CEMAS model and methodology
are described below.
- --------------------------------------------------------------------------------
C-6
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
CEMAS
C.C. Pace has developed and tested an analytical approach to forecasting
electricity prices in a deregulated electric power market. The approach centers
on the concept of replacement power equilibrium pricing.
C.C. Pace's modeling approach determines the market pricing necessary to provide
incremental expansion unit revenues to meet their all-in generation costs. When
this pricing level is attained, the system is considered to be in equilibrium,
since incremental generators will cover all of their generation costs while
receiving a fair rate of return on equity. Achieving this cost recovery target
establishes a condition in which demand can be met while providing the economic
incentives necessary for generators to invest capital to serve current and
future load.
C.C. Pace's approach incorporates five market analysis tools with the capability
to simulate hourly operations of an electric system, forecast unit dispatch, and
project market clearing prices for both capacity and energy. CEMAS consists of
five interrelated modules which are described in greater detail in Section II:
1. Revenue Requirement Module
2. Unit Fuel Pricing Module
3. Bidding Analysis Module
4. Hourly Load Module
5. Market Clearing Price Module
CEMAS was designed based on C.C. Pace's experience in deregulated or competitive
markets in which the clearing prices of generation are a function of the
underlying generation cost structure, fuel pricing, transmission capacity,
supply availability, demand fluctuations, and the bidding strategies of
participants.
The CEMAS model was calibrated against historical data for 1994-1996. In
addition, C.C. Pace derived the current all-in price of generation (i.e., prices
that include variable and fixed capital-related costs) through analysis of the
current electricity rates of the region's utilities. The model's projected
market prices in the year 2000 were consistent with the derived current market
prices.
ASSUMPTIONS
The key Base Case assumptions underlying the Southeastern Market Study are
detailed in Sections IV, V, VI, and VII. These assumptions span the areas of
load growth, fuel pricing, expansion unit cost and performance, transmission
transfer capability and pricing, market area definition and the financing
structure of existing and expansion units. These base case assumptions were
developed by C.C. Pace in order to bracket the most probable need for new
capacity and market pricing available to
- --------------------------------------------------------------------------------
C-7
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
the Project. Exhibit I - 4 summarizes the major assumption variables of C.C.
Pace's Base Case forecast.
Exhibit I - 4: Key Assumptions - Base Case
- --------------------------------------------------------------------------------
================================================================================
Base Case
- --------------------------------------------------------------------------------
Load Growth
- --------------------------------------------------------------------------------
Energy Demand 1.51% to 2.24% per year
- --------------------------------------------------------------------------------
Peak Demand 1.51% to 2.24% per year
- --------------------------------------------------------------------------------
Expansion Unit Costs
- --------------------------------------------------------------------------------
CT - Installed Costs $300/kW
- --------------------------------------------------------------------------------
CC - Installed Costs $500/kW
- --------------------------------------------------------------------------------
CT - Efficiency (linear improvement) 10,100 Btu/kWh (2000)
9,350 Btu/kWh (2020)
- --------------------------------------------------------------------------------
CC - Efficiency (linear improvement) 6,860 Btu/kWh (2000)
6,360 Btu/kWh (2020)
- --------------------------------------------------------------------------------
Natural Gas Henry Hub Price - 1998 $2.20/MMBtu
- --------------------------------------------------------------------------------
Existing Unit Costs
- --------------------------------------------------------------------------------
Fixed Capital Costs Current Book Value
- --------------------------------------------------------------------------------
Fixed & Variable O&M Current Derived Cost / 0% real escalation
- --------------------------------------------------------------------------------
Fuel Cost Escalation Rates
- --------------------------------------------------------------------------------
Natural Gas 0.5% per year real
- --------------------------------------------------------------------------------
Fuel Oil (No.6 and No. 2) 0.0% per year real
- --------------------------------------------------------------------------------
Coal -1.0% per year real
- --------------------------------------------------------------------------------
Uranium 0.0% per year real
- --------------------------------------------------------------------------------
Transfer Capacity and Pricing
- --------------------------------------------------------------------------------
SPP-SE to/from TVA 4,800 MW / $1.75/MWh
- --------------------------------------------------------------------------------
SPP-SE to/from Southern 2,000MW / $1.82/MWh
- --------------------------------------------------------------------------------
TVA to/from Southern 3,000 MW / $2.15/MWh
- --------------------------------------------------------------------------------
Nuclear and Coal Plant Performance 85% Capacity Factor
- --------------------------------------------------------------------------------
Demand Side Management
- --------------------------------------------------------------------------------
Annual Interruptible Demand 5,697 - 6,293 MW
- --------------------------------------------------------------------------------
Macroeconomic
- --------------------------------------------------------------------------------
Interest Rate 8.5%
- --------------------------------------------------------------------------------
Return on Equity 14%
- --------------------------------------------------------------------------------
Percent Equity 30%
================================================================================
- --------------------------------------------------------------------------------
C.C. Pace believes that the assumptions presented above are conservative
estimates of the future range of variables which yield a highly probable Base
Case market price estimate. The following summarizes major assumptions:
Load Growth
o Assumed no export of energy to the capacity short Midwest or
Mid-Atlantic regions.
o Included the full impact of demand-side management on peak demand.
Expansion Units
- --------------------------------------------------------------------------------
C-8
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
o Expansion unit capital costs are consistent with current market
prices and assumed no real price increases.
o Assumed heat rates are approximately 5 to 7% better than any
combustion turbines or combined cycle technology currently
commercially available.
o Expansion plan did not incorporate the probable requirement for
retirement and replacement of 17,000 MW of nuclear capacity in the
latter study period.
Existing Utility Capacity
o Initial cost recovery is based on current book value which is
significantly below current auction value of the units.
o Operating capacity factor is assumed to be approximately 5-10%
higher than current average achievable unit capacity factors.
Downside Case
The key assumptions for the Downside Case are the same as those for the Base
Case with the exception of (i) $50/kW cost reduction for combustion turbines and
$64/kW cost reduction for combined cycle installed costs, (ii) system generation
capacity exceeds generation requirements by 2,400 MW, and (iii) + 5% heat rate
efficiency improvement. This case was developed by C.C. Pace to represent a
scenario which would have a 95% probability of occurrence.
- --------------------------------------------------------------------------------
C-9
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
II. MARKET CLEARING PRICE APPROACH
- --------------------------------------------------------------------------------
C.C. Pace's market clearing price forecast of the Southeast United States
electricity market consists of multiple, interrelated analytical processes. C.C.
Pace employed utility grade computer simulation models to evaluate the existing
supply and demand relationships in the region, match future utility operations
to forecasts of demand, and predict the electricity prices resulting from
industry deregulation.
This section provides necessary background material including the fundamentals
of C.C. Pace's Capacity and Energy Market Analysis System (CEMAS).
APPROACH
C.C. Pace conducted a detailed analysis of Southeast market clearing prices.
This analysis provides in-depth insight into the fundamentals of Southeast
market and the emerging competitive market. The analysis was based on C.C.
Pace's competitive market vision of an "one-price" market for both capacity and
energy. A description of C.C. Pace's approach to this analysis is described
below.
C.C. Pace's approach incorporates five market analysis tools that provide the
capability to project market clearing prices for both capacity and energy. As we
illustrate in Exhibit II - 1, C.C. Pace's Capacity & Energy Market Analysis
System (CEMAS) consists of five modules. These modules are:
1. Revenue Requirement Module: This module compares fixed and variable
costs for all generating units with all-in revenues generated from a
given bidding strategy. It then reports information regarding over
or under-recovery (stranded costs) to the Bid Analysis Module.
2. Unit Fuel Pricing Module: This module calculates fuel prices for
each unit and transfers the data to the Revenue Requirement Module.
These fuel pricing calculations take into account escalation
schedules, transportation costs, fuel quality, and fuel procurement
and contractual constraints.
3. Bidding Analysis Module: Based on the fixed and variable costs of
generating units and over and under-recovery data generated by the
Revenue Requirement Module, this module generates bids for each unit
on the system and transfers those bids to the Market Clearing Price
Module for production simulation.
- --------------------------------------------------------------------------------
C-10
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
4. Hourly Load Module: The Hourly Load Module aggregates actual utility
hourly loads as reported to the FERC to create an integrated system
hourly load profile. This module uses forecasts of peak and energy
demand to develop the base system load profile over the study
period. The results of the Hourly Load Module are drawn upon by the
Market Clearing Price Module to simulate daily system demand.
5. Market Clearing Price Module: This module performs a detailed
operations and dispatch simulation based on bid prices generated by
the Bidding Analysis Module and the hourly load data generated by
the Hourly Load Module. For each hour in the study period, the
module dispatches generating units according to their bid prices and
availabilities. The Market Clearing Price Module uses a utility
grade dispatch model (PROSYM) to model the hourly system constraints
of a regional power pool, optimizing least cost generation choices
to match demand fluctuations. The module then produces hourly market
clearing prices, which are passed to the Revenue Requirement Module
to evaluate system operations and market price stability. Based on
this analysis, CEMAS will either produce a new iteration of
optimized bids or, if the market is deemed stable, summarize market
clearing prices for each study period.
Exhibit II - 1: C.C. Pace CEMAS Methodology
- --------------------------------------------------------------------------------
[FLOW CHART OMITTED]
- --------------------------------------------------------------------------------
CEMAS was designed based on C.C. Pace's market experience, which shows that
clearing prices of competitive generation markets are a function of the
underlying generation cost structure, supply availability and demand
fluctuations, the bidding strategies that participants adopt and the incremental
cost of expansion units. C.C. Pace has sought with CEMAS to integrate these
components into a system capable of accurately projecting market clearing prices
in a competitive market.
- --------------------------------------------------------------------------------
C-11
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
The following sections review in greater detail the individual modules of the
CEMAS analytical system--their purposes, inputs, and relationship to the whole
modeling system.
REVENUE REQUIREMENT MODULE
The Revenue Requirement Module is the foundation input and calculation module of
CEMAS. It maintains data characterizing each generating unit in the market area
(both existing and planned) and is used to:
o Organize and store historical unit information regarding capacity,
generation, O&M, and capital costs.
o Provide an interface mechanism with the Bidding Analysis Module to
provide data for bid construction.
o Create an analysis mechanism for run results from the Market Pricing
Module by matching unit revenues derived from bidding strategies to
actual fixed cost recovery requirements. This evaluation is
essential in benchmarking bidding strategies and capacity and energy
market pricing, as well as determining potential stranded costs on
either a unit or system basis.
o Provide a cost competitiveness evaluation tool for comparison of the
relative cost and capacity mix for various utilities in the
interconnected region.
C.C. Pace also uses the Revenue Requirement Module as a tool to perform
sensitivity analyses of unit fixed cost structures. Specifically, the Revenue
Requirement Module permits the adjustment of return on equity for each unit,
interest rates, fixed O&M, debt term, unit book value (lowering or
"writing-off"), and consolidation or disaggregation of units to simulate various
market conditions and deregulation scenarios. All these capabilities permit the
flexibility to model virtually any utility system or project the impact of
multiple restructuring scenarios on market prices.
The detailed unit characterization data maintained by the Revenue Requirement
Module includes information on utility system, in-service date, nameplate
capacity, fuel type, fuel pricing, fixed O&M cost, variable O&M cost, heat rate,
historical generation, current book value, annual depreciation expense, annual
interest expense, and annual return-on-equity requirement. C.C. Pace gathered
such information from Forms EIA-411, EIA-412, FERC Form 1, and Rural Utilities
Service Form 12a.
- --------------------------------------------------------------------------------
C-12
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
UNIT FUEL PRICING MODULE
The purpose of the Unit Fuel Pricing Module is to provide the Revenue
Requirement Module with detail on each unit's fuel price and account for
plant-specific fuel procurement and contracting practices, pricing differences,
transportation costs, and fuel quality variances. The Unit Fuel Pricing Module:
o Organizes and stores historical unit fuel prices;
o Analyzes seasonal and annual fuel pricing trends for individual
units and entire systems; and
o Provides input to the Revenue Requirement Module and Market Clearing
Price Module.
The Fuel Pricing Module calculates the average fuel costs for each fuel type
(i.e., coal, uranium, natural gas, No. 6 and No. 2 fuel oil), and develops fuel
disaggregation factors for each unit. The Unit Fuel Pricing Module adopts this
process to project annual fuel costs given a market area price for a type of
fuel. This market area fuel price is then adjusted each year by the study's
assumed long-range fuel pricing forecast escalators as detailed in Section VII.
At this stage, unit-specific fuel prices are then entered into the Revenue
Requirement Module to calculate variable operating costs and other variables
necessary for bidding analysis.
HOURLY LOAD MODULE
Load characterization defines how many supply resources are needed, as well as
how these resources will be used on a daily, weekly, and seasonal basis.
Consequently, hourly demand is an important determinant of the escalation of
system costs. CEMAS characterizes this important variable by modeling all market
pricing scenarios with an hourly load module that replicates the actual 8,760
hours of demand occurring in a utility system each year. In this way, modeling
results reflect not only the cost to serve a certain level of demand, but also
show how hourly changes impact the use of different types of generation units.
As we further detail in Section V, the Hourly Load Module aggregates actual
utility hourly loads as reported to the FERC to create an integrated system
hourly load profile. It then uses utility adjusted forecasts of peak and energy
demand to escalate the base system load profile over the study period. The
results are drawn upon by the Market Clearing Price Module to simulate daily
system demand.
BIDDING ANALYSIS MODULE
Given the fundamental change in the electricity market from a regulated cost of
service to a more market driven mechanism, it is expected (and it has been
demonstrated in other competitive
- --------------------------------------------------------------------------------
C-13
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
markets such as Chile, Norway, the United Kingdom, New Zealand, and Australia)
that a bidding process will be developed as the basis of determining which
generators will be used in a given hour. To account for the change from
cost-driven dispatch to market-driven dispatch, C.C. Pace has developed a
Bidding Analysis Module to assist in formulating generators' bids. The Bidding
Analysis Module assesses generators' variable and fixed costs requirements,
system demand, relative competitiveness, and experience from the results of the
previous day's bidding to:
o Generate bids based on each generator's place in the dispatch queue;
o Maximize revenues where total fixed and variable cost recovery can
not be achieved due to market forces;
o Maximize upside revenue potential during periods of peak demand or
unit outages;
o Replicate the activities and consequent pricing of existing
competitive markets; and
o Provide analysis tools for bidding strategies of generators in
competitive markets.
Equilibrium Pricing of Expansion Capacity
While at anytime, given the actual supply/demand balance in the market,
generators can adopt various bidding strategies to increase their market
revenues, Exhibit II - 2 presents the basis of market price equilibrium in a
competitive market. Specifically, the cost of new capacity will ultimately set a
market price cap under pricing equilibrium. For example, if market prices are
above the cost of new capacity additions, market entrants will build new units
until they drive the market price down to minimum return levels. Conversely, if
market prices are below the cost of expansion units, no units will be built
unless prices rise to support their construction.
Given the foregoing, Exhibit II - 2 provides a theoretical market pricing
formula consisting of new CC and CT units. Exhibit II - 2 details the all-in
cost (i.e. fixed and variable) of expansion units operating at various capacity
factors. For example, at 35% capacity factor the all-in cost of a CC and CT unit
would be $41.53/MWh and $39.67/MWh, respectively. Assuming all generators
receive the incremental market price when dispatched and a market price cap of
the on-line peak capacity at approximately $126/MWh, Exhibit 1 shows the minimum
bidding level of units to reach their fixed cost recovery.
With these assumptions, Exhibit II - 2 shows that except at dispatch of 10% or
lower, all generators can bid to their variable cost and still achieve their
minimum revenue requirement. Further, Exhibit II - 2 also shows that between
40%-45% capacity a break-even point exists where CC capacity becomes the most
economic capacity.
Lastly, in the column labeled "Average Market Price $/MWh" is the theoretical
pricing curve cap or equilibrium point. Specifically, when pricing levels rise
above those levels, new capacity installations are signaled until the market
price comes to rest back at the equilibrium point. For example, if the market
price is $35.00/MWh for an average of 70% of the year, a new CC can be
- --------------------------------------------------------------------------------
C-14
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
built and dispatched at that level for only $28.66/MWh. Therefore, a developer
would see a profit opportunity there and would seek to build capacity to reduce
this market pricing.
Exhibit II - 2: Equilibrium Market Prices Based on Expansion Unit Costs
- --------------------------------------------------------------------------------
Dispatch CC CT Incremental Average Percent Return
Factor/System All-In All-In Market Price Market Price Over Revenue
Load Factor $/MWh $/MWh $/MWh $/MWh Requirement
- --------------------------------------------------------------------------------
5 195.98 126.35 126.35 126.35 -1%
10 105.88 75.79 25.23 76.53 1%
15 75.85 58.94 25.23 59.43 1%
20 60.83 50.51 25.23 50.88 1%
25 51.82 45.45 25.23 45.75 1%
30 45.82 42.08 25.23 42.33 1%
35 41.53 39.67 25.23 39.88 1%
40 38.31 37.87 25.23 38.05 0%
45 35.81 36.46 15.78 35.79 0%
50 33.80 35.34 15.78 33.79 0%
55 32.17 34.42 15.78 32.15 0%
60 30.80 33.65 15.78 30.79 0%
65 29.65 33.01 15.78 29.63 0%
70 28.66 32.45 15.78 28.64 0%
75 27.80 31.97 15.78 27.79 0%
80 27.05 31.55 15.78 27.04 0%
85 26.38 31.18 15.78 26.37 0%
90 25.79 30.85 15.78 25.79 0%
95 25.27 30.55 15.78 25.26 0%
100 24.79 30.28 15.78 24.79 0%
- --------------------------------------------------------------------------------
---------------------------------------------------------------------------
Assumptions:
---------------------------------------------------------------------------
Unit Type CC CT
Heat Rate Btu/kWh 6,600 9,700
Variable O&M $/MWh 1.00 3.50
Fuel Cost for Year $/MMBtu 2.24 2.24
Fixed Cost $ 28,817,000 10,247,000
Capacity MW 360 230
Variable Cost $/MWh 15.78 25.23
Fixed Cost @100% Load Factor $/MWh 9.01 5.06
---------------------------------------------------------------------------
Based on the results of this analysis, prices defined by the costs of building
and operating new CT and CC generators place a theoretical cap on power prices.
Consequently, C.C. Pace's analysis model is driven to alter bidding strategies
and capacity additions to achieve a market pricing level approximately +/- 5%
from this equilibrium. Specifically, C.C. Pace assumed that peaking capacity
(units operating for 5% or less capacity factor) would bid their all-in costs.
All other generating units would bid their variable costs.
The Market Clearing Price Module, given these input bid prices for each unit,
matches supply resources to demand to derive revenue results through dispatch
optimization of these bid prices. These revenue results are fed back into the
Revenue Requirement Module. Fixed cost recovery analysis is performed at this
stage with the results being transferred back into the Bidding Analysis
Module for further iterations if the market price does not come with 5% of
expansion capacity recovery targets.
- --------------------------------------------------------------------------------
C-15
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
MARKET CLEARING PRICE MODULE
The Market Clearing Price Module uses a utility grade dispatch model (PROSYM) to
model hourly system constraints of a regional power pool, optimizing least cost
generation choices to match demand fluctuations. The Market Clearing Price
Module matches the outputs of the Bidding Analysis Module, Revenue Requirement
Module, and the Hourly Load Module to determine market prices for each forecast
period.
PROSYM is a chronological hybrid electric utility production simulation modeling
system developed by The Simulation Group and used extensively by utilities and
public utility commissions. It is designed to perform planning studies, and as
result of its chronological structure, PROSYM accomplishes detailed hour-by-hour
investigation of electric utility operations. It utilizes the Monte Carlo method
(i.e., a random number generator is used to determine unit availability during
the simulation period) of outage distribution along with chronological
constraints to simulate the system's operation. Given a sufficient number of
iterations, the Monte Carlo method is typically more accurate than probabilistic
dispatch.
Because PROSYM is a chronological model, it permits highly detailed description
of the modeling environment. This capability adds increased modeling control
over variable inputs and results in more accurate simulation of utility
operation in a given market area, such as the Southeastern region under
consideration in this study. Additionally, PROSYM has the capability to simulate
a market structure where units compete on an optimized total cost basis (one bid
price to recover both capital and energy costs) rather than traditional marginal
cost optimization. This capability allows C.C. Pace to simulate alternative
market structures, such as the competitive generation market resulting from
electricity industry restructuring.
Once information on bids is entered into PROSYM, the model optimizes resource
utilization. Market clearing prices are tracked hourly providing each operating
generator with the same market clearing price for the given hour of operation.
Hourly revenues are tracked to provide annual revenues per unit based on market
clearing prices.
DETERMINATION OF COMPETITIVE MARKET EXPANSION PLAN
The C.C. Pace market study does not add expansion units to meet a fixed target
reserve margin as is the current planning method for regulated utilities. A
competitive market structure dictates, by definition, that participants will
build expansion units only if they expect to receive a sufficient return on
their investment. Therefore, in the analysis expansion units are added only when
the market price can support them.
To determine the competitive market expansion plan, C.C. Pace followed three
rules or steps to arrive at the optimal expansion plan. These rules or steps are
as follows:
- --------------------------------------------------------------------------------
C-16
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
1. Use of the existing units and planned utility unit additions as the
minimum expansion plan as a starting point.
2. The addition of expansion units in each year up to such point that
the whole class of units (i.e., combined cycle or combustion
turbines) receive full recovery. This was done to the point that the
next unit added to the system would not be able to recover its
costs.
3. Unit additions were optimized for each sub-system (i.e., SPP-SE,
TVA, and Southern) and each year of the study period to yield the
largest number of combined cycle units and combustion turbine units
possible while still maintaining full recovery of these units.
OUTLINE OF REPORT
The remainder of this report is organized into five additional sections:
o Section III, Southeast Market Pricing Results, provides detailed
market clearing price results.
o Section IV, Market Area Definition and Transmission, provides
support for the selection of the market area and the transmission
transfer capability and pricing assumptions.
o Section V, Electricity Demand in the Southeast Market, provides
demand growth expectations for the market area.
o Section VI, Southeast Power Generation Resources, reviews existing
generation resources and details expansion unit assumptions.
o Section VII, Fuel Pricing, provides fuel pricing and escalation
expectations.
- --------------------------------------------------------------------------------
C-17
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
III. SOUTHEAST MARKET PRICING RESULTS
- --------------------------------------------------------------------------------
C.C. Pace conducted an assessment and forecast of market clearing prices in the
Southeast power market for the period 2000 through 2025. New market pricing
tools are required for the emerging competitive marketplace where generators
have no guaranteed customers through regulated franchise areas. Accordingly,
C.C. Pace's analysis utilized our proprietary Capacity & Energy Market Analysis
System (CEMAS) forecasting system. As detailed in the previous sections, CEMAS
was developed to provide the capability to project market clearing prices for
both capacity and energy in a competitive market.
C.C. Pace's market price forecast results for the proposed Project for the Base
and Downside cases are presented below.
CEMAS SIMULATED MARKET PRICING RATES
C.C. Pace's Base Case market price forecast was founded on our expected
assumptions for a competitive market. These assumptions are detailed in
subsequent sections regarding fuel pricing, demand, expansion capacity and
existing unit fixed costs. The Base Case represents a system optimization of
these factors given a competitive market structure. Specifically, given the cost
structure of generating units, demand, fuel pricing, and other key factors, the
CEMAS model simulated the Southeast system and optimized unit dispatch and
bidding to identify the market pricing and price distribution to allow the
system to recover variable costs of generation units (except those fixed costs
that are determined above market or "stranded").
SYSTEM MARKET PRICING AND REVENUES - BASE CASE
Exhibit III - 1 below summarizes the Southeastern system's (TVA, Southern, and
SPP-SE) operational results between 2000-2025. As shown in Exhibit III - 1,
market clearing prices are projected to increase in real dollars over the study
period by approximately 0.5%, annually, or almost directly correlated to the
anticipated increase in natural gas prices. Total system stranded costs
(represented by negative coverage) range from approximately $1.28 billion in
2000 to full recovery by the year 2002. These stranded costs represent an
average of 4.3% of total system costs in the initial study years.
- --------------------------------------------------------------------------------
C-18
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
Exhibit III - 1: Annual System Summary - Base Case (1998 Real Dollars)
<TABLE>
<CAPTION>
====================================================================================================================================
Avg.
Market
Clearing
Capacity Generation Capacity Fuel Cost Variable O&M Fixed Cost Revenue Coverage Cover Price Price
Year MW GWh Factor $1000 $1000 $1000 $1000 $1000 $/MWh $/MWh Escalation
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000 100,297 518,343 59.00% 6,463,498 568,451 9,157,427 15,523,496 -665,879 -1.28 29.95
2002 102,427 538,655 60.38% 6,672,923 589,483 9,305,890 16,808,358 240,062 0.45 31.20 4.19%
2004 105,607 558,590 60.03% 6,956,957 613,786 9,514,373 17,758,292 673,176 1.21 31.79 1.88%
2006 111,147 579,927 59.56% 7,085,728 637,187 9,881,445 18,358,555 754,195 1.30 31.66 -0.42%
2008 115,997 600,519 59.10% 7,330,797 658,640 10,217,950 18,860,175 652,788 1.09 31.41 -0.79%
2010 120,027 621,359 59.10% 7,647,450 681,101 10,504,616 19,729,198 896,030 1.44 31.75 1.10%
2012 123,727 641,693 59.21% 7,940,551 698,971 10,790,175 20,850,537 1,420,840 2.21 32.49 2.33%
2014 127,527 662,527 59.31% 8,225,445 718,235 11,066,650 21,718,146 1,707,816 2.58 32.78 0.89%
2016 131,227 683,001 59.41% 8,584,518 738,210 11,352,209 22,807,030 2,132,094 3.12 33.39 1.87%
2018 135,487 704,505 59.36% 8,925,967 761,729 11,649,059 23,784,767 2,448,011 3.47 33.76 1.10%
2020 139,517 725,730 59.38% 9,275,428 780,967 11,935,722 24,628,449 2,636,333 3.63 33.94 0.52%
2021 141,677 736,290 59.33% 9,451,574 787,627 12,112,504 25,080,431 2,728,726 3.71 34.06 0.37%
2022 144,197 747,754 59.20% 9,622,510 792,862 12,318,748 25,101,179 2,367,059 3.17 33.57 -1.45%
2023 145,997 758,500 59.31% 9,813,549 801,077 12,466,069 25,481,685 2,400,990 3.17 33.59 0.08%
2024 148,157 770,106 59.34% 10,029,254 809,617 12,642,853 25,901,491 2,419,767 3.14 33.63 0.12%
2025 149,957 781,121 59.46% 10,241,047 817,908 12,790,175 26,383,905 2,534,775 3.25 33.78 0.43%
====================================================================================================================================
</TABLE>
- --------------------------------------------------------------------------------
Specifically, Exhibit III - 2 summarizes annual capacity additions by region and
technology. As shown by Exhibit III - 2, the Southeast region will require over
40,000 MW of capacity additions by the year 2020 and over 51,000 MW by the year
2025, under Base Case demand assumptions. Additionally, Exhibit III - 2
indicates that gas-fired combined cycle capacity is a preferred generation
technology by a margin of nearly 4:1. Importantly, these capacity addition
requirements do not assume any existing capacity retirement. Section VI
describes in detail the underlying methodology used to develop C.C. Pace's
competitive capacity expansion plan used in the market price forecast.
Exhibit III - 2: Expansion Capacity Additions by Year - Base Case
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
===========================================================================================================
Year 2000 2004 2008 2012 2016 2020 2021 2022 2023 2024 2025
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
SE CC 750 1,110 5,070 6,870 7,950 8,310 10,470 12,270 12,990 14,430 15,150
SE CT -- 460 2,530 3,680 3,680 3,910 3,910 3,910 3,910 3,910 3,910
- -----------------------------------------------------------------------------------------------------------
SOCO CC 300 660 2,820 5,700 7,860 9,660 9,660 9,660 10,020 10,380 10,740
SOCO CT 215 1,825 3,665 4,125 5,275 7,115 7,115 7,115 7,115 7,115 7,115
- -----------------------------------------------------------------------------------------------------------
TVA CC 360 2,880 3,240 4,680 7,560 11,160 11,160 11,880 12,600 12,960 13,680
TVA CT -- -- -- -- 230 690 690 690 690 690 690
- -----------------------------------------------------------------------------------------------------------
Total CC 1,410 4,650 11,130 17,250 23,370 29,130 31,290 33,810 35,610 37,770 39,570
Total CT 215 2,285 6,195 7,805 9,185 11,715 11,715 11,715 11,715 11,715 11,715
Total 1,625 6,935 17,325 25,055 32,555 40,845 43,005 45,525 47,325 49,485 51,285
===========================================================================================================
</TABLE>
- --------------------------------------------------------------------------------
A key factor behind system market prices is the amount of time each fuel (i.e.,
natural gas, coal and oil) comprises the marginally dispatched unit.
Accordingly, C.C. Pace calculated the "time on the margin" of specific fuels to
measure a fundamental driver to future market pricing.
- --------------------------------------------------------------------------------
C-19
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Specifically, this analysis measures the fuel-based technology which is the last
dispatched in each hour. Knowledge of the "fuel on the margin" indicates the
general level of fuel price linkage or risk of the market. Exhibit III - 3 shows
the percentage of "fuel on the margin" over the course of the study.
Exhibit III - 3: Percent Hours on the Margin by Fuel Type
- --------------------------------------------------------------------------------
================================================================================
2000 2010 2014 2016 2018 2020 2025
- --------------------------------------------------------------------------------
Nuclear -- -- -- -- -- -- --
Hydro -- -- -- -- -- -- --
Coal 42.6 11.8 6.3 4.1 2.8 2.1 0.7
Gas Steam 25.1 14.2 11.5 10.7 12.9 12.5 11.8
Existing CT 22.9 14.1 13.1 13.6 13.0 12.0 11.9
Exp CC 3.8 40.7 49.3 52 51.0 53.0 52.0
LSP Unit 0.9 2.7 2.8 2.5 2.4 2.4 6.4
Exp CT 0.6 14.8 15.5 15.7 16.4 17.2 16.4
Other Purchases 4.1 1.7 1.5 1.4 1.5 0.8 0.8
- --------------------------------------------------------------------------------
Total 100% 100% 100% 100% 100% 100% 100%
================================================================================
- --------------------------------------------------------------------------------
As shown in Exhibit III - 4, coal is initially the marginal fuel for the highest
percentage of time, roughly 42%. This time on the margin generally occurs during
the off-peak periods of the year. However, as system demand increases and more
gas-fired capacity is added to the system, natural gas becomes the dominant fuel
on the margin. Based on this analysis, C.C. Pace concludes that as demand grows,
the market risk to the Project will decrease substantially. Further, by the time
of expiration of the initial power sales contracts, gas-fired capacity will
comprise 2/3 of the margin. Therefore, the risk that market prices will be lower
than Project costs is remote. Further, since market prices in the future will be
based on natural gas, increases in gas prices should generally translate into
higher electricity prices.
LS POWER UNIT RESULTS - BASE CASE
Exhibit III - 4 provides a summary of key Project operational results for the
Base Case. As shown in Exhibit III - 4, the Project is projected to be
economically dispatched at an annual capacity factor of approximately 51%-69%.
Average market-based revenues are projected to be between $32.82/MWh in the year
2000 and rise in real dollars to $39.33 in the year 2025. As a result of this
real price increase, the Project will achieve revenues above variable
operational costs (fuel and variable O&M) of between $15.36/MWh in the year 2001
and $19.66/MWh by the year 2025. Total revenue ranges from $131 million to $150
million over the study period.
- --------------------------------------------------------------------------------
C-20
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit III - 4: LS Power Unit Annual Operational Summary -(1998 Real Dollars)^
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
=================================================================================================================================
Average
Market
Price
Generation Capacity Fuel Cost Variable O&M Fixed Cost Revenue Coverage Cover Received Price
Year GWh Factor $1000 $1000 $1000 $1000 $1000 $/MWh $/MWh Escalation
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
*2000 2,748 41.83% 45,173 2,748 -- 90,187 42,266 15.38 32.82
2002 4,500 68.50% 74,969 4,500 -- 148,591 69,122 15.36 33.02 0.61%
2004 4,438 67.55% 74,666 4,438 -- 149,730 70,627 15.92 33.74 2.18%
2006 4,324 65.81% 73,465 4,324 -- 147,003 69,214 16.01 34.00 0.77%
2008 4,278 65.11% 73,414 4,278 -- 145,377 67,684 15.82 33.98 -0.05%
2010 4,207 64.04% 72,934 4,207 -- 144,532 67,391 16.02 34.35 1.09%
2012 4,133 62.90% 72,350 4,133 -- 146,296 69,813 16.89 35.40 3.05%
2014 4,032 61.37% 71,294 4,032 -- 144,588 69,262 17.18 35.86 1.31%
2016 3,880 59.05% 69,290 3,880 -- 145,125 71,955 18.55 37.41 4.31%
2018 3,770 57.38% 67,994 3,770 -- 143,467 71,703 19.02 38.06 1.74%
2020 3,730 56.77% 67,960 3,730 -- 141,610 69,920 18.75 37.97 -0.24%
2021 3,675 55.94% 67,277 3,675 -- 142,654 71,702 19.51 38.81 2.24%
2022 3,549 54.01% 65,271 3,549 -- 137,826 69,006 19.45 38.84 0.06%
2023 3,489 53.10% 64,484 3,489 -- 134,984 67,012 19.21 38.69 -0.38%
2024 3,425 52.14% 63,635 3,425 -- 133,788 66,727 19.48 39.06 0.94%
2025 3,332 50.72% 62,216 3,332 -- 131,048 65,500 19.66 39.33 0.69%
=================================================================================================================================
</TABLE>
^ No fixed costs for the Batesville unit were assumed by C.C. Pace.
* 2000 represents only a partial operational year with an on-line date of
June 2000.
- --------------------------------------------------------------------------------
To provide these forecasts of Project dispatch, operating profile, and market
revenues, C.C. Pace explicitly modeled the Project as a resource in the
Southeast market. Specifically, the Project's heat rate efficiency, delivered
fuel costs, and variable operating costs were input in the model to allow the
simulation to dispatch the unit when system marginal costs were equal to or
higher than Project variable costs. The LS Power unit specifications modeled are
provided in Section VI.
SYSTEM RESULTS DOWNSIDE CASE
C.C. Pace's Downside Case market price forecast (i.e., a conservative case in
which C.C. Pace believes there is a 95% probability that market prices will be
equal to or greater than these results) is between $27.25/MWh and $32.20/MWh
(1998 real dollars) for the period 2000 to 2025. The Downside Case price
forecasts are only 5-10% lower than the Base Case results, thereby highlighting
the overall conservatism of the Base Case.
Exhibit III - 5 summarizes the Southeastern system's market clearing price
results between 2000-2025 for the Base and Downside Cases.
- --------------------------------------------------------------------------------
C-21
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit III - 5: Annual System Market Clearing Price - Base and Downside Case
(1998 Real Dollars)
- --------------------------------------------------------------------------------
================================================================================
Downside Case
Base Case Market Market
Clearing Price Clearing Price
Year $/MWh Price Escalation $/MWh Price Escalation
- --------------------------------------------------------------------------------
2000 29.95 27.25
- --------------------------------------------------------------------------------
2002 31.20 4.19% 28.99 6.40%
- --------------------------------------------------------------------------------
2004 31.79 1.88% 29.48 1.68%
- --------------------------------------------------------------------------------
2006 31.66 -0.42% 29.55 0.22%
- --------------------------------------------------------------------------------
2008 31.41 -0.79% 29.38 -0.57%
- --------------------------------------------------------------------------------
2010 31.75 1.10% 29.84 1.57%
- --------------------------------------------------------------------------------
2012 32.49 2.33% 30.60 2.55%
- --------------------------------------------------------------------------------
2014 32.78 0.89% 30.89 0.94%
- --------------------------------------------------------------------------------
2016 33.39 1.87% 31.52 2.06%
- --------------------------------------------------------------------------------
2018 33.76 1.10% 31.71 0.59%
- --------------------------------------------------------------------------------
2020 33.94 0.52% 32.22 1.63%
- --------------------------------------------------------------------------------
2021 34.06 0.37% 32.12 -0.32%
- --------------------------------------------------------------------------------
2022 33.57 -1.45% 32.01 -0.34%
- --------------------------------------------------------------------------------
2023 33.59 0.08% 32.12 0.35%
- --------------------------------------------------------------------------------
2024 33.63 0.12% 32.00 -0.40%
- --------------------------------------------------------------------------------
2025 33.78 0.43% 32.20 0.64%
================================================================================
- --------------------------------------------------------------------------------
BATESVILLE UNIT RESULTS - DOWNSIDE CASE
Exhibit III 6 outlines the operational results of the LS Power unit associated
with C.C. Pace's Downside Case and the difference relative to the Base Case. The
Downside Case represents an unlikely scenario of the impact on the Project's
revenues and dispatch given that there is a significant improvement of expansion
capacity capital costs (i.e., $50/kW cost reduction for combustion turbines and
$64/kW cost reduction for combined cycle installed costs) and system capacity
exceeds requirements by 2,400 MW or approximately three times the size of the
Project's installed capacity. As shown in Exhibit III 6, given this overcapacity
the Project is projected to be dispatched at an annual capacity factor between
46% and 62%, a decrease of between 4-7% as compared to the Base Case. Average
revenues for the unit are projected to be between $31.18/MWh in the year 2000
increasing in real dollars to $38.52/MWh in 2025. Overall, during the forecast
period, average annual revenues earned by the Project were slightly less than in
the Base Case, the reduction ranging from $14.0 million to $18.6 million, or
approximately 13% less, as compared to the base case.
- --------------------------------------------------------------------------------
C-22
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit III - 6: Batesville Downside Case Results and Base Case Differential
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Variable Avg. Market
Generation Capacity Fuel Cost O&M Fixed Cost Revenue Coverage Cover Clearing Price Price
Year GWh Factor $1000 $1000 $1000 $1000 $1000 $/MWh $/MWh Escalation
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000 2,519 38.34% 41,415 2,519 -- 78,546 34,612 13.74 31.18
2002 4,094 62.31% 68,200 4,094 -- 130,935 58,641 14.32 31.98 2.58%
2004 4,007 60.99% 67,397 4,007 -- 131,373 59,969 14.97 32.79 2.51%
2006 3,862 58.79% 65,612 3,862 -- 128,358 58,883 15.24 33.23 1.36%
2008 3,861 58.77% 66,255 3,861 -- 128,500 58,384 15.12 33.28 0.15%
2010 3,731 56.79% 64,673 3,731 -- 126,177 57,772 15.48 33.82 1.61%
2012 3,733 56.82% 65,348 3,733 -- 130,396 61,315 16.42 34.93 3.29%
2014 3,571 54.36% 63,153 3,571 -- 126,655 59,931 16.78 35.46 1.53%
2016 3,466 52.76% 61,896 3,466 -- 127,691 62,328 17.98 36.84 3.87%
2018 3,406 51.84% 61,433 3,406 -- 126,422 61,583 18.08 37.12 0.77%
2020 3,424 52.12% 62,379 3,424 -- 126,956 61,152 17.86 37.08 -0.11%
2021 3,277 49.87% 59,968 3,277 -- 124,894 61,649 18.81 38.12 2.80%
2022 3,174 48.32% 58,379 3,174 -- 122,122 60,568 19.08 38.47 0.94%
2023 3,140 47.79% 58,025 3,140 -- 120,593 59,429 18.93 38.41 -0.16%
2024 3,076 46.82% 57,143 3,076 -- 118,317 58,098 18.89 38.46 0.13%
2025 3,038 46.24% 56,705 3,038 -- 117,021 57,279 18.86 38.52 0.16%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Difference from Base Case
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Variable Avg. Market
Generation Capacity Fuel Cost O&M Fixed Cost Revenue Coverage Cover Clearing Price Price
Year GWh Factor $1000 $1000 $1000 $1000 $1000 $/MWh $/MWh Escalation
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000 -229 -3.48% -3,758 -229 -- -11,640 -7,654 -1.64 -1.64
2002 -406 -6.18% -6,769 -406 -- -17,657 -10,481 -1.04 -1.04 1.97%
2004 -431 -6.56% -7,269 -431 -- -18,357 -10,657 -0.95 -0.95 0.33%
2006 -461 -7.02% -7,853 -461 -- -18,645 -10,331 -0.76 -0.77 0.59%
2008 -417 -6.34% -7,159 -417 -- -16,876 -9,300 -0.70 -0.70 0.20%
2010 -476 -7.25% -8,261 -476 -- -18,355 -9,618 -0.53 -0.54 0.52%
2012 -399 -6.08% -7,002 -399 -- -15,900 -8,498 -0.47 -0.47 0.24%
2014 -460 -7.01% -8,141 -460 -- -17,933 -9,332 -0.40 -0.40 0.23%
2016 -413 -6.29% -7,394 -413 -- -17,434 -9,627 -0.57 -0.57 -0.44%
2018 -364 -5.54% -6,561 -364 -- -17,045 -10,120 -0.94 -0.94 -0.97%
2020 -306 -4.66% -5,581 -306 -- -14,655 -8,768 -0.89 -0.89 0.14%
2021 -399 -6.07% -7,309 -399 -- -17,761 -10,053 -0.70 -0.70 0.56%
2022 -374 -5.70% -6,892 -374 -- -15,704 -8,437 -0.36 -0.37 0.88%
2023 -349 -5.31% -6,459 -349 -- -14,391 -7,583 -0.28 -0.28 0.22%
2024 -349 -5.32% -6,492 -349 -- -15,470 -8,629 -0.59 -0.59 -0.81%
2025 -295 -4.48% -5,511 -295 -- -14,027 -8,221 -0.80 -0.80 -0.53%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
C-23
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
IV. MARKET AREA DEFINITION AND TRANSMISSION
- --------------------------------------------------------------------------------
C.C. Pace defined the relevant market area for the Southeast market by
assessing: a) the location of the Project, b) the transmission interconnections
and capabilities which the Project would have access over the course of the
study period, and c) areas where market prices and demand growth have indicated
a need for additional resources. As a result of this analysis, C.C. Pace has
defined the market area for the Southeast Market Study to consist of the
following utility systems:
o The major utilities in the NERC Southwest Power Pool Southeast
sub-region (SPP-SE)(1) - Entergy-Arkansas, Entergy-Louisiana,
Entergy-Mississippi, Entergy-New Orleans, Entergy-Gulf States,
Central Louisiana Electric Company, Southwestern Electric Power, and
Cajun Electric;
o The utilities in the NERC Southern sub-region - Alabama Power,
Mississippi Power, Georgia Power, Gulf Power, Savannah Electric,
Municipal Electric Authority of Georgia, and Oglethorpe Power;
o The Tennessee Valley Authority;
o The South Mississippi Electric Power Association, and
o Alabama Electric Cooperative.
These utility systems were chosen as the first tier (i.e., directly
interconnected or within one wheel) utility systems to the Project. Second tier
utility systems (indirectly connected utilities such as Duke Power and utilities
to the North and Northwest) were not modeled due to the increased cost of
transmission access limiting the net price of electricity (i.e., minus
transmission costs) available to the Project.
Exhibit IV - 1 displays a map of the major first tier utility systems' service
areas to provide an understanding of the size and breadth of this market area.
Exhibit IV - 2 provides a written description of the service areas of these
utilities. Overall, this market area assessment shows that the proposed Project
is ideally located to serve one of the largest interconnected regions in the
U.S. The Project would have direct access, through the use of integrated
transmission systems operated by TVA and Entergy, to over 87,000 MW of peak
demand if the Project existed today. By the year 2000, the peak demand level for
this region is expected to be over 94,000 MW.
- --------
(1) In late 1998, the Entergy Operating Companies switched membership to the
SERC region of NERC from SPP. This change does not affect the assumptions nor
the results of C.C. Pace's market clearing price forecast.
- --------------------------------------------------------------------------------
C-24
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit IV - 1: Map of Major First Tier Utility Companies
- --------------------------------------------------------------------------------
[GRAPHIC OMITTED]
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
C-25
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit IV - 2: Description of First Tier Utilities
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
=========================================================================================================================
Utility Estimated Areas Served
1997 Peak Demand
=========================================================================================================================
<S> <C> <C>
Georgia Power 13,153 Shares the majority of the State of Georgia with
Oglethorpe Power Cooperative members, and the Municipal
Electric Authority of Georgia members
- -------------------------------------------------------------------------------------------------------------------------
Alabama Power 9,778 Shares the southern 2/3 of the State of Alabama with
Alabama Electric Cooperative members and municipals
- -------------------------------------------------------------------------------------------------------------------------
Mississippi Power 2,209 Southeastern Mississippi
- -------------------------------------------------------------------------------------------------------------------------
Savannah Electric & Power Company 802 Savannah, Georgia area
- -------------------------------------------------------------------------------------------------------------------------
Gulf Power 2,040 Western half of the Florida Panhandle
- -------------------------------------------------------------------------------------------------------------------------
Alabama Electric Cooperative 1,395 Wholesale Generating Cooperative selling power to member
cooperatives throughout the Southern 2/3 of Alabama
- -------------------------------------------------------------------------------------------------------------------------
South Mississippi Electric Power Association 979 Wholesale Generating Cooperative selling power to member
cooperatives in Southeastern Mississippi
- -------------------------------------------------------------------------------------------------------------------------
Tennessee Valley Authority 26,661 Nearly all of Tennessee, Northern Alabama, Northeastern
Mississippi and some of Southern Kentucky are served by
cooperatives buying power from TVA
- -------------------------------------------------------------------------------------------------------------------------
Cajun Electric Power Cooperative, Inc. 1,491 Wholesale Generating Cooperative selling power to member
cooperatives in Louisiana
- -------------------------------------------------------------------------------------------------------------------------
Central Louisiana Elec. Power Co., Inc. 1,560 Central Louisiana
- -------------------------------------------------------------------------------------------------------------------------
Southwestern Electric Power Co. 4,157 Far Northeast Texas and Western Arkansas
- -------------------------------------------------------------------------------------------------------------------------
Entergy - Arkansas, Inc. 6,131 Southeastern 2/3 of Arkansas
- -------------------------------------------------------------------------------------------------------------------------
Entergy - Gulf States, Inc. 6,517 Southern Louisiana, small portion of East Texas
- -------------------------------------------------------------------------------------------------------------------------
Entergy - Louisiana, Inc. 5,261 Northern Louisiana
- -------------------------------------------------------------------------------------------------------------------------
Entergy - Mississippi, Inc. 2,658 The Western half of Mississippi
- -------------------------------------------------------------------------------------------------------------------------
Entergy - New Orleans, Inc. 1,192 The city of New Orleans
=========================================================================================================================
</TABLE>
- --------------------------------------------------------------------------------
TRANSMISSION
The Southeast electric market modeled by C.C. Pace is an actively traded and
dynamic market for wholesale power transactions. Significant long-term capacity
transfers take place between and within the North American Electric Reliability
Council's sub-regions of Tennessee Valley Authority (TVA), Southern, and
Southwest Power Pool-Southeast (SPP-SE). On a daily non-firm basis, economy
energy markets are highly active, with lower cost utilities selling excess power
supplies at or near their marginal cost of production to utilities with higher
incremental costs. Exhibits I-1 through I-3 in Attachment I provide historical
net sales/purchases among and between sub-regions in the Southeast power market
for both capacity and energy.
Southeast market area power tends to flow South and East, starting with TVA's
low-cost generation resources in the northern market area, flowing into the
Southern sub-region. The Southern Company (which dominates the Southern
sub-region) actively trades with TVA to its North and with their utility
neighbors to the Northeast (i.e., SCE&G, SCPS, Duke, etc.). The Southern Company
also trades heavily with Florida utilities, selling not only their
"coal-by-wire" contract capacity its FPC and FP&L, but also unit shares and
economy energy sales with Florida utilities. The SPP-SE sub-region both
purchases and sells electricity with TVA and the Southern sub-regions. These
sales depend on demand conditions and the relationship of gas prices to coal
- --------------------------------------------------------------------------------
C-26
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
(i.e., when gas prices are high/low SPP-SE utilities buy/sell economy power
from/to TVA and Southern).
C.C. Pace modeled this situation with three distinct, yet interconnected utility
regions as shown in Exhibit IV - 3. Transfer capability between regions was
generally based on utility reports of interconnection ratings. However, the
transfer capacity was adjusted from these reports in order to maintain the
calibration of C.C. Pace's dispatch model to historical inter-utility transfers
(various operational and power quality constraints may prevent the utilities
from using certain connections simultaneously).
Exhibit IV - 3: Regional Modeling Definition and Transmission Assumptions
- --------------------------------------------------------------------------------
[GRAPHIC OMITTED]
- --------------------------------------------------------------------------------
Transmission pricing was based on current pricing, adjusted for the expected
changes in rates over time. C.C. Pace assumed that transmission rates would
range from $1.75/MWh - $2.15/MWh for utilities interconnected with TVA and
Entergy (see Exhibit IV - 3).
- --------------------------------------------------------------------------------
C-27
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
V. ELECTRICITY DEMAND IN THE SOUTHEAST MARKET
- --------------------------------------------------------------------------------
The electricity market prices in a given market are highly dependent on
electricity demand. To ensure this variable was accurately modeled, C.C. Pace
developed an independent demand forecast for the three major utility regions in
the Southeast (i.e., SPP-SE, Southern and TVA sub-region). This forecast was
prepared based on the current and projected economic conditions for each of
these sub-regions.
This section presents the following: 1) the published forecasts of utilities in
the Southeast market; 2) the region's existing demand profile; 3) C.C. Pace's
approach and methodology to load forecasting, and 4) key input assumptions used
in the market study.
EXISTING DEMAND PROFILE
For each utility's respective demand forecast, C.C. Pace reviewed published data
from the Regional Electricity Supply & Demand Projections (EIA-411) report
submitted by the NERC sub-regions to the U.S. Energy Information Administration
(EIA). The EIA-411 report provides historical and projected peak and energy
demands shown in Exhibit IV-1 for the combined sub-regions of SPP-SE,
SERC-Southern, and SERC-TVA.
Exhibit V - 1 indicates that Southeast market utilities expect summer peak
demand and energy to increase at an average rate of 2.16% and 1.57% per year
over the next 10 years, respectively. Specifically, peak demand is projected to
grow from 87,387 MW to 96,763 MW between 1996 and 2000. Thereafter, peak demand
is expected to rise to approximately 108,200 MW by the year 2006. Net energy is
expected to escalate from a base of approximately 477,045 GWh in 1997 to nearly
553,028 GWh by the year 2006.
Importantly, given this level of load growth (approximately 11,000 MW of peak
demand growth), the proposed Project would represent less than one-tenth of the
total increase in the Southeast's market peak demand requirements. Therefore,
there is little doubt that the Project's capacity and energy will be necessary
to meet future system energy and reliability requirements.
- --------------------------------------------------------------------------------
C-28
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit V - 1: Southeast Demand and Energy Requirements Forecast^
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
====================================================================================================================================
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Peak Demand Summer (MW) 87,387 90,686 92,867 94,709 96,763 98,683 100,466 102,307 104,148 106,250 108,200
Peak Demand Winter (MW) 80,995 78,194 80,374 81,926 83,421 85,137 86,848 88,509 90,268 92,095 92,663
Net Energy for Load (MWh) 473,337 477,045 486,016 491,744 501,873 510,658 517,713 525,811 533,107 544,615 553,028
- ------------------------------------------------------------------------------------------------------------------------------------
System Load Factor 61.83% 60.05% 59.74% 59.27% 59.21% 59.07% 58.83% 58.67% 58.43% 58.51% 58.35%
- ------------------------------------------------------------------------------------------------------------------------------------
Summer Change (MW) 3,299 2,181 1,842 2,054 1,920 1,783 1,841 1,841 2,102 1,950
Winter Change (MW) (2,801) 2,180 1,552 1,495 1,716 1,711 1,661 1,759 1,827 568
Energy Change (MWh) 3,708 8,971 5,728 10,129 8,785 7,055 8,098 7,296 11,508 8,413
- ------------------------------------------------------------------------------------------------------------------------------------
Summer Change (%) 3.78% 2.41% 1.98% 2.17% 1.98% 1.81% 1.83% 1.80% 2.02% 1.84%
Winter Change (%) -3.46% 2.79% 1.93% 1.82% 2.06% 2.01% 1.91% 1.99% 2.02% 0.62%
Energy Change (%) 0.78% 1.88% 1.18% 2.06% 1.75% 1.38% 1.56% 1.39% 2.16% 1.54%
- ------------------------------------------------------------------------------------------------------------------------------------
Summer Peak Growth 2.16%
Winter Peak Growth 1.35%
Energy Growth 1.57%
====================================================================================================================================
</TABLE>
^ Source: EIA-411
- --------------------------------------------------------------------------------
Also shown in Exhibit V - 1, the Southeast market has a relatively high current
load factor of over 61%. However, in the future, utilities are expecting this
load factor to decrease by over 3% to approximately 58%(1). This decreasing load
factor will have the impact of increasing the amount of capacity needed to meet
reserve and reliability requirements. However, to be conservative, C.C. Pace's
market study assumes that the customer mix, load shape, and consequently this
high load factor will be maintained throughout the study period, thereby
slightly decreasing the need for incremental expansion capacity.
As is shown in Exhibit V - 2 and Exhibit V - 3, direct load management and
interruptible demand account for 5,400 MW to 6,400 MW of the Southeast utilities
"resources" to meet or reduce peak demand requirements. Despite the inclusion of
direct load management and interruptible demand, Exhibit V - 2 and Exhibit V - 3
indicate the following:
o Regional expansion requirements are approximately 7,000 MW over the
next 10 years.
o Even with a net increase of 14,000 MW of capacity and the inclusion
of 5,200 MW of interruptible demand to reduce peak demand, system
reserve margin is expected to drop below 10%, far below the NERC
standard of 15% reserve margin.
o Consequently, utility forecasts heavily underscore the need for the
proposed Project.
- --------
(1) Utility forecasts do not contain any description or explanation of the
forecast results. However, C.C. Pace believes that one reason for the decrease
in load factor could be a relative increase in the residential or commercial
demand relative to higher load factor industrial customers.
- --------------------------------------------------------------------------------
C-29
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit V - 2: Market Demand and Reserve Margin - Summer
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
===================================================================================================================================
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Internal Demand 90,480 92,549 94,339 96,371 98,262 99,992 101,779 103,587 105,649 107,577
Standby Demand 206 318 370 392 421 474 528 561 601 623
Total Internal Demand 90,686 92,867 94,709 96,763 98,683 100,466 102,307 104,148 106,250 108,200
Direct Ctrl Load Mgt 210 194 188 182 182 182 182 182 182 182
Interruptible Demand 5,697 5,874 6,058 6,292 6,293 6,181 6,188 6,052 5,929 5,255
Net Internal Demand 84,779 86,799 88,463 90,289 92,208 94,103 95,937 97,914 100,139 102,763
Total Owned Capacity 98,675 98,886 100,605 101,133 101,372 102,746 102,572 103,498 104,246 105,221
Inoperable Capacity 1,343 1,289 1,289 1,289 1,289 1,289 1,289 1,289 1,289 1,289
Net Operable Capacity 97,332 97,597 99,316 99,844 100,083 101,457 101,283 102,209 102,957 103,932
IPPs 1,019 1,615 2,318 3,146 4,567 5,259 6,001 6,752 7,561 8,462
Capacity Purchases 3,277 3,741 3,152 3,145 2,797 2,944 2,916 3,166 3,419 3,450
Full Respons Purchases 1,061 921 929 786 486 493 500 508 515 515
Capacity Sales 4,329 4,352 3,672 3,508 3,113 3,193 3,109 3,138 3,160 3,160
Full Respons Sales 1,782 1,782 1,782 1,705 1,705 1,705 1,705 1,705 1,705 1,705
Adjustments -- -- -- -- -- -- -- -- -- --
Planned Capacity Res 97,299 98,601 101,114 102,627 104,334 106,467 107,091 108,989 110,777 112,684
- -----------------------------------------------------------------------------------------------------------------------------------
Reserve Margin (MW) 12,520 11,802 12,651 12,338 12,126 12,364 11,154 11,075 10,638 9,921
Reserve Margin (%) 12.87% 11.97% 12.51% 12.02% 11.62% 11.61% 10.42% 10.16% 9.60% 8.80%
===================================================================================================================================
</TABLE>
- --------------------------------------------------------------------------------
Exhibit V - 3: Market Demand and Reserve Margin - Winter
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
===================================================================================================================================
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Internal Demand 78,013 80,117 81,584 83,029 84,717 86,397 88,011 89,723 91,523 92,062
Standby Demand 181 257 342 392 420 451 498 545 572 601
Total Internal Demand 78,194 80,374 81,926 83,421 85,137 86,848 88,509 90,268 92,095 92,663
Direct Ctrl Load Mgt 117 101 94 89 89 88 89 89 88 89
Interruptible Demand 5,477 5,807 5,764 5,708 5,716 5,613 5,645 5,523 5,430 5,221
Net Internal Demand 72,600 74,466 76,068 77,624 79,332 81,147 82,775 84,656 86,577 87,353
Total Owned Capacity 99,486 101,053 100,778 101,531 102,067 103,140 104,175 104,848 105,849 106,389
Inoperable Capacity 1,386 1,325 1,329 1,289 1,289 1,289 1,289 1,289 1,289 1,289
Net Operable Capacity 98,100 99,728 99,449 100,242 100,778 101,851 102,886 103,559 104,560 105,100
IPPs 519 519 519 1,459 1,959 2,709 3,459 4,209 4,959 4,959
Capacity Purchases 2,441 2,418 2,514 2,491 2,467 2,399 2,564 2,760 2,824 2,905
Full Respons Purchases 903 911 920 928 898 906 913 921 929 929
Capacity Sales 3,998 3,964 3,992 3,235 3,090 3,113 3,093 3,109 3,138 3,138
Full Respons Sales 1,782 1,782 1,782 1,705 1,705 1,705 1,705 1,705 1,705 1,705
Adjustments -- -- -- -- -- -- -- -- -- --
Planned Capacity Res 97,062 98,701 98,490 100,957 102,114 103,846 105,816 107,419 109,205 109,826
- -----------------------------------------------------------------------------------------------------------------------------------
Reserve Margin (MW) 24,462 24,235 22,422 23,333 22,782 22,699 23,041 22,763 22,628 22,473
Reserve Margin (%) 25.20% 24.55% 22.77% 23.11% 22.31% 21.86% 21.77% 21.19% 20.72% 20.46%
===================================================================================================================================
</TABLE>
- --------------------------------------------------------------------------------
C.C. PACE'S LOAD FORECASTING METHODOLOGY
C.C. Pace performed an independent forecast of demand growth in the Southeast
market. To benchmark utility forecasts, C.C. Pace's independent forecast was
conducted according to the methodology illustrated in Exhibit V - 4. This
methodology has two primary components. The first is the use of econometric
models to forecast annual peak demand and energy levels based on changes in
population, employment, income, and other factors. The second component of the
- --------------------------------------------------------------------------------
C-30
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
methodology is the translation of historical hourly demand levels and forecasted
peak demands to create predicted hourly load profiles.
Typically, the most accurate means of projecting future demand is not done
solely by analyzing past trends in peak and energy demand, but by analyzing the
underlying factors which drive the consumption of electricity. This approach is
often referred to as a "bottom-up" analytical approach. As shown in Exhibit V -
4, the foundation of C.C. Pace's load forecasting methodology is a bottom-up
analytical approach.
Exhibit V - 4: C.C. Pace Load Forecasting Methodology
- --------------------------------------------------------------------------------
[FLOW CHART OMITTED]
- --------------------------------------------------------------------------------
C.C. Pace generated its demand forecast based on the historical relationships
between regional demand and multiple historic economic indicators (i.e.,
population, employment and income) between 1989-1995. To generate this demand
forecast, C.C. Pace:
o Forecasted demand based on the historical trend of the logarithms of
population, employment and income.
o Forecasted demand based on a forecast of these same indicators
generated by the Bureau of Economic Affairs (BEA). The BEA generally
projected a slow economic growth that would lower demand growth in
half from historic trends.
- --------------------------------------------------------------------------------
C-31
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
o Averaged these two forecasts to generate a conservative base case of
electricity demand growth.
Other issues considered with respect to C.C. Pace's independent forecast
include:
o Normal weather conditions are assumed. No factors were included to
simulate extreme weather conditions.
o The forecast incorporated all demand and energy reductions from
utility dispatchable and non-dispatchable DSM programs as published
in Utility Demand forecasts. C.C. Pace believes that this is a
conservative assumption in that many DSM programs are extremely
aggressive in future years and will most likely fall short of goals.
o The economic outlook for this twenty-year forecast attempts to
describe the short-term outlook for the current business cycle, as
well as the long-term trend behavior for the economy. It is
important to note that identification of the long-term trend in
economic/demographic conditions represents the primary focus of this
forecast.
FORECAST RESULTS
C.C. Pace developed an independent demand forecast for the three major utility
regions in the Southeast (i.e., SPP-SE, Southern, and TVA sub-regions). C.C.
Pace prepared a demand forecast based on current and projected economic
conditions for each of these sub-regions. Please refer to Attachment II,
Exhibits II-1 through II-6, which detail C.C. Pace's supporting data and demand
forecasts.
Based on the results of C.C. Pace's independent forecast, regional electricity
peak demand growth will slow from its historical growth rate of approximately
3.25% per year to between 1.51% to 2.24% annually over the next 20 years. C.C.
Pace forecasts a slightly lower annual escalation rate than currently filed
utility forecasts. Specifically, regional utility forecasts project 2.16% annual
demand growth from 1996-2006, while C.C. Pace projects a 2.01% demand growth
over the same time period. While C.C. Pace growth rate projections are slightly
lower than utility forecasts, the starting point of peak and energy demand are
slightly higher. Therefore, the overall level of C.C. Pace's forecast is
slightly higher than current utility forecasts. However, as shown in Exhibit V -
5 and Exhibit V - 6, C.C. Pace's forecasts are well below historical demand
growth trends. Consequently, utility forecasts were determined to be highly
unrealistic.
- --------------------------------------------------------------------------------
C-32
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit V - 5: C.C. Pace vs. Utility Energy Demand Forecast
- --------------------------------------------------------------------------------
[GRAPH OMITTED]
- --------------------------------------------------------------------------------
Exhibit V - 6: C.C. Pace vs. Utility Peak Demand Forecast
- --------------------------------------------------------------------------------
[GRAPH OMITTED]
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
C-33
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
C.C. Pace's regression analysis indicated an extremely strong correlation
between electricity demand and the economic indicators. Specifically, Exhibit
II-2 in Attachment II summarizes C.C. Pace's regression analyses which produced
R(2) factors of 0.975, 0.987, and 0.964 for SPP-SE, Southern, and TVA,
respectively. Therefore, regression results show that over 98% of all changes in
economic indicators correlate to changes in electricity demand. C.C. Pace's
regression formulas yield only a total of 579 MW/year or 5,075 GWh average error
for the entire Southeast market's historic electricity demand.
Unless significant changes occur in the historic correlation of economic drivers
and electricity demand or the projected growth rates of these economic drivers
fall short, it is highly probable that utility forecasts are conservative and
underestimated. These conservative forecasts may be explained by two factors:
o The utilities' optimistic estimates of the effects of current and
future demand side management and conservation programs on total
system demand.
o The utilities' propensity to down play the generation opportunities
for independent power producers.
HOURLY LOAD FORECASTS
The forecast of overall demand growth is not the only element needed to
accurately characterize future demand. The characterization and replication of
daily, weekly, and seasonal load variations significantly impact the usage,
type, and cost of resources required by a utility system. The last step in C.C.
Pace's load forecasting methodology is the projection of hourly demand values.
C.C. Pace's methodology calls for the application of annual growth factors
derived from our peak demand and energy forecasts to the actual 8,760 hours of
demand occurring in a utility system. In this way, our market modeling system
will have the highest level of detail to reflect not only the cost to serve a
certain megawatt of demand, but also how hourly changes impact the use of
different types of generation units. Specifically, hourly system needs and
constraints are particularly critical when analyzing hourly distributions of
market clearing prices.
C.C. Pace uses an Hourly Load Module tool to translate annual peak and energy
demand growth factors into future hourly demand for a given study period. The
translation process is a two step process:
1) The first step involves aggregating actual utility hourly loads as
reported to Federal Energy Regulatory Commission (for each utility
under consideration in this study). This aggregation creates an
integrated hourly system load profile for the Southeastern market
area (this will be referred to as base system hourly load file).
- --------------------------------------------------------------------------------
C-34
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
2) The second step involves applying annual growth factors to the base system
hourly load file (created in step 1), to create an hourly demand file for
each year in the study.
C.C. Pace assumed that the system load shape that exists currently would be
maintained throughout the study. However, system load factor does change
slightly as the result of applying annual peak and energy growth factors. As the
relationship of peak demand and energy change, so will the system load factor
and shape change.
- --------------------------------------------------------------------------------
C-35
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
VI. SOUTHEAST POWER GENERATION RESOURCES
- --------------------------------------------------------------------------------
Section VI focuses on the following:
o Providing a profile of the existing generation resources of this
market;
o Identifying the fixed capital and operational costs of these
resources; and,
o C.C. Pace's assumptions associated with the type and cost of new
resource additions.
GENERATION PROFILE
The Southeast market area is comprised of a diverse group of resources utilizing
various fuels. However, as shown in Exhibit VI - 1, coal-fired and nuclear
capacity dominate the region's capacity mix comprising over 66% of the installed
capacity. In particular, coal fired capacity is the dominant generation type
totaling over 48% of the installed capacity of the region, or over 46,000 MW.
Exhibit VI - 1: Southeast Market Generation Capacity
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
============================================================================================================================
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
IPPs 519 1,019 1,615 2,318 3,146 4,567 5,259 6,001 6,752 7,561 8,462
Nuclear 16,718 16,747 16,760 16,872 16,886 16,886 16,886 16,886 16,886 16,886 16,886
Coal 46,868 46,932 46,840 46,933 46,919 46,919 46,919 46,919 46,919 46,919 46,893
ST - Dual Fuel 15,049 15,049 15,049 14,884 14,884 14,825 14,825 14,825 14,825 14,825 14,825
ST - Gas 2,874 2,873 2,873 2,873 2,873 2,873 2,829 2,829 2,829 2,829 2,829
ST - Oil 122 122 122 122 122 122 122 122 122 122 122
Hydro 8,157 8,157 8,192 8,192 8,192 8,192 8,192 8,192 8,192 8,192 8,192
CT 5,548 5,689 5,915 5,915 5,915 6,224 6,365 6,615 6,765 6,765 6,765
CC 486 486 486 486 486 486 486 486 486 711 936
Other -- 52 81 1,760 2,288 2,277 3,554 3,130 3,906 4,429 5,205
- ----------------------------------------------------------------------------------------------------------------------------
Total Capacity 96,341 97,126 97,933 100,355 101,711 103,371 105,437 106,005 107,682 109,239 111,115
============================================================================================================================
</TABLE>
Further, the region has significant hydro resources comprising approximately 8%
of the installed capacity mix, or approximately 8,000 MW of capacity. This
compares to other regions which typically have hydro resources of 5% of total
installed capacity.
Southeast (specifically SPP-SE) steam turbine gas and oil fired capacity
comprise a substantial share of system resources at 16,750 MW or 17% of
installed capacity. The TVA and Southern sub-regions have few of these oil or
gas-fired steam units. The reason for this capacity composition is the SPP-SE's
location near to the gulf coast oil and gas producing regions. This location
provides a significant cost advantage in the transportation and availability of
these fuels.
- --------------------------------------------------------------------------------
C-36
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Finally, Exhibit VI - 2 depicts the Southeast market's projected generation
requirements by generation type. As is shown in Exhibit VI - 2, the Southeast
market is highly dependent on nuclear and coal resources for its generation
requirements. In 1996, over 83% of the region's requirements were generated by
coal or nuclear resources. Gas or oil-fired capacity provided about 10% of the
region's energy requirements.
Exhibit VI - 2: Southeast Generation Requirements by Capacity Type
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
============================================================================================================================
MWh 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Coal 270,032 287,008 289,164 291,284 299,172 294,675 298,484 305,138 305,253 305,406 303,345
Nuclear 117,168 118,383 117,708 120,616 119,633 120,731 120,774 120,190 118,648 120,334 120,797
Hydro 30,247 28,143 27,566 28,044 28,073 28,126 28,178 28,231 28,283 28,335 28,368
ST - Gas 40,023 36,207 36,939 35,712 37,086 40,515 39,873 39,621 42,668 41,430 41,425
ST - Oil 1,419 185 170 164 209 216 215 227 238 227 209
CT - Oil/Gas 1,978 2,944 4,939 5,504 6,318 5,636 6,190 7,003 8,428 7,520 6,970
CC - Oil/Gas 134 503 386 388 384 1,712 2,044 1,949 2,061 4,687 7,992
IPPs 1,814 501 877 1,133 1,418 8,699 9,985 10,510 11,769 16,396 21,348
Other 443 4,415 3,227 4,336 5,838 5,767 7,617 8,268 12,243 13,926 16,273
- ----------------------------------------------------------------------------------------------------------------------------
Total
Production 463,258 478,289 480,976 487,181 498,131 506,077 513,360 521,137 529,591 538,261 546,727
============================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
============================================================================================================================
Percent of Gen. 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Coal 58.29% 60.01% 60.12% 59.79% 60.06% 58.23% 58.14% 58.55% 57.64% 56.74% 55.48%
Nuclear 25.29% 24.75% 24.47% 24.76% 24.02% 23.86% 23.53% 23.06% 22.40% 22.36% 22.09%
Hydro 6.53% 5.88% 5.73% 5.76% 5.64% 5.56% 5.49% 5.42% 5.34% 5.26% 5.19%
ST - Gas 8.64% 7.57% 7.68% 7.33% 7.45% 8.01% 7.77% 7.60% 8.06% 7.70% 7.58%
ST - Oil 0.31% 0.04% 0.04% 0.03% 0.04% 0.04% 0.04% 0.04% 0.04% 0.04% 0.04%
CT - Oil/Gas 0.43% 0.62% 1.03% 1.13% 1.27% 1.11% 1.21% 1.34% 1.59% 1.40% 1.27%
CC - Oil/Gas 0.03% 0.11% 0.08% 0.08% 0.08% 0.34% 0.40% 0.37% 0.39% 0.87% 1.46%
IPPs 0.39% 0.10% 0.18% 0.23% 0.28% 1.72% 1.95% 2.02% 2.22% 3.05% 3.90%
Other 0.10% 0.92% 0.67% 0.89% 1.17% 1.14% 1.48% 1.59% 2.31% 2.59% 2.98%
- ----------------------------------------------------------------------------------------------------------------------------
Total
Production 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%
============================================================================================================================
</TABLE>
- --------------------------------------------------------------------------------
Gas-fired capacity is expected to play an increasing future role in satisfying
capacity and energy needs. With the relatively low price of natural gas
delivered to the region, the increased efficiency of gas turbine and gas
combined cycle technology, and reduced capital costs of gas turbine and gas
combined cycle technology, most utilities in these sub-regions are planning to
only install these technologies in the future. In fact, C.C. Pace's capacity
expansion plan predicts that gas fired generation will be the only generation
type added to meet demand over the study period.
GENERATING UNIT COST PROFILE
C.C. Pace reviewed the cost profile of the existing installed capacity base.
This analysis is particularly important for assessing the need and
competitiveness of resource additions in a given market area. Specifically,
knowledge of the cost magnitude and competitiveness of existing capacity is
essential for a planned project to assess who the competitors will be in the
market and what cost advantages a new unit must have over existing units.
Further, the full costs of generation are particularly important, given C.C.
Pace's CEMAS modeling system. The current wholesale market does not include the
recovery of fixed O&M or
- --------------------------------------------------------------------------------
C-37
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
capital investment when determining market prices. However, C.C. Pace's model of
the future market structure emphasizes these fixed costs as essential to
determining sustainable, all-in capacity and energy prices.
Exhibit VI - 3 provides a comparison of the capital costs for selected utilities
in the Southeast market area. Capital costs are organized by generation
technology (i.e., steam, nuclear, hydro, pumped storage, gas-fired steam
turbine, and gas turbine). Unit original book value data was obtained from FERC
Form 1 for investor owned utilities and EIA-412 for public utilities. The
following are summary observations of these costs:
o The average capital cost of nuclear capacity in the region is
approximately $1,762/kW. Nuclear capacity capital costs range from a
low of $1,659/kW for TVA to a high of $2,088/kW and $2,098/kW for
Entergy-Mississippi and Entergy-Louisiana, respectively. This high
cost of nuclear capacity indicates a potential area of weakness for
the region as a whole and Entergy in particular. These high capital
costs result in a high level of potential stranded costs for these
utilities in a deregulated electric marketplace.
o Overall, the average capital cost of steam turbine capacity in the
region is approximately $316/kW. This capacity has an average heat
rate of 10,248 Btu/kWh and O&M costs of $15.30/kW.
o There is little true peaking capacity among the major utilities
(i.e., only 6.9% of these utilities' capacity is combustion
turbine). This capacity has low capital costs (average $144/kW) but
high variable costs as indicated by an average heat rate of 14,448
Btu/kWh.
- --------------------------------------------------------------------------------
C-38
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VI - 3: Major Southeast Utility Unit Cost Summary
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
================================================================================================================================
Gas Turbine Hydroelectric Nuclear Pump Storage Steam Steam Gas Total
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Entergy Louisiana, Inc.
- --------------------------------------------------------------------------------------------------------------------------------
Capacity (MW) 21 -- 1,200 -- 4,171 481 5,873
Plant Cost ($) 2,119,268 -- 2,517,886,191 -- 490,286,777 69,695,996 3,079,988,232
Non-Fuel O&M ($) 65,771 -- 94,663,917 -- 25,759,926 4,556,400 125,046,014
MMBtu Consumed 92,391 -- 94,053,249 -- 122,664,170 4,592,599 221,402,409
Generation (MWh) 3,709 -- 8,926,846 -- 11,198,362 379,899 20,508,816
Plant Cost ($/kW) 102.38 -- 2,098.45 -- 117.54 144.96 524.47
Non-Fuel O&M ($/kW) 3.18 -- 78.89 -- 6.18 9.48 21.29
Heat Rate (btu/kWh) 24,910 -- 10,536 -- 10,954 12,089 10,795
- --------------------------------------------------------------------------------------------------------------------------------
Entergy Mississippi, Inc.
- --------------------------------------------------------------------------------------------------------------------------------
Capacity (MW) -- -- -- -- 3,148 -- 3,148
Plant Cost ($) -- -- -- -- 588,041,216 -- 588,041,216
Non-Fuel O&M ($) -- -- -- -- 21,008,302 -- 21,008,302
MMBtu Consumed -- -- -- -- 95,309,173 -- 95,309,173
Generation (MWh) -- -- -- -- 7,997,977 -- 7,997,977
Plant Cost ($/kW) -- -- -- -- 186.79 -- 186.79
Non-Fuel O&M ($/kW) -- -- -- -- 6.67 -- 6.67
Heat Rate (btu/kWh) -- -- -- -- 11,917 -- 11,917
- --------------------------------------------------------------------------------------------------------------------------------
Georgia Power Co.
- --------------------------------------------------------------------------------------------------------------------------------
Capacity (MW) 1,882 654 1,962 424 10,862 -- 15,783
Plant Cost ($) 308,409,336 261,877,850 4,097,191,570 382,672,136 2,831,060,288 -- 7,881,211,180
Non-Fuel O&M ($) 7,373,471 7,146,024 139,628,840 2,409,711 210,538,867 -- 367,096,913
MMBtu Consumed 4,268,732 0 150,972,733 0 492,672,103 -- 647,913,568
Generation (MWh) 320,944 1,916,193 14,238,184 644,528 47,436,174 -- 64,556,023
Plant Cost ($/kW) 163.91 400.62 2,088.05 902.29 260.65 -- 499.34
Non-Fuel O&M ($/kW) 3.92 10.93 71.16 5.68 19.38 -- 23.26
Heat Rate (btu/kWh) 13,301 -- 10,603 -- 10,386 -- 10,036
- --------------------------------------------------------------------------------------------------------------------------------
Mississippi Power Co.
- --------------------------------------------------------------------------------------------------------------------------------
Capacity (MW) 226 -- -- -- 1,887 -- 2,113
Plant Cost ($) 68,706,383 -- -- -- 653,936,538 -- 722,642,921
Non-Fuel O&M ($) 6,232,766 -- -- -- 42,153,343 -- 48,386,109
MMBtu Consumed -- -- -- -- 90,558,823 -- 90,558,823
Generation (MWh) 1,055,765 -- -- -- 9,109,565 -- 10,165,330
Plant Cost ($/kW) 303.94 -- -- -- 346.57 -- 342.01
Non-Fuel O&M ($/kW) 27.57 -- -- -- 22.34 -- 22.90
Heat Rate (btu/kWh) -- -- -- -- 9,941 -- 8,909
- --------------------------------------------------------------------------------------------------------------------------------
TVA
- --------------------------------------------------------------------------------------------------------------------------------
Capacity (MW) 3,957 4,016 10,075 1,739 40,445 481 60,713
Plant Cost ($) 498,027,430 1,049,474,040 16,713,024,660 332,111,635 14,576,980,209 68,236,582 33,237,854,556
Non-Fuel O&M ($) 13,791,637 32,633,695 601,556,274 5,628,315 626,213,116 4,624,698 1,284,447,735
MMBtu Consumed 7,962,055 -- 652,495,175 -- 1,970,051,869 6,312,727 2,636,821,825
Generation (MWh) 528,303 15,888,087 61,771,767 2,342,945 194,669,157 581,443 275,781,702
Plant Cost ($/kW) 125.86 261.32 1,658.86 190.98 360.41 141.86 547.46
Non-Fuel O&M ($/kW) 3.49 8.13 59.71 3.24 15.48 9.61 21.16
Heat Rate (btu/kWh) 15,071 -- 10,563 -- 10,120 10,857 9,561
- --------------------------------------------------------------------------------------------------------------------------------
Total
- --------------------------------------------------------------------------------------------------------------------------------
Capacity (MW) 6,085 4,670 13,237 2,163 60,513 962 87,630
Plant Cost ($) 877,262,417 1,311,351,890 23,328,102,421 714,783,771 19,140,305,028 137,932,578 45,509,738,105
Non-Fuel O&M ($) 27,463,645 39,779,719 835,849,031 8,038,026 925,673,554 9,181,098 1,845,985,073
MMBtu Consumed 12,323,177 -- 897,521,157 -- 2,771,256,138 10,905,326 3,692,005,798
Generation (MWh) 1,908,721 17,804,280 84,936,797 2,987,473 270,411,235 961,342 379,009,848
Plant Cost ($/kW) 144.16 280.82 1,762.33 330.44 316.30 143.41 519.34
Non-Fuel O&M ($/kW) 4.51 8.52 63.14 3.72 15.30 9.55 21.07
Heat Rate (btu/kWh) 14,448 -- 10,567 -- 10,248 11,344 9,741
================================================================================================================================
</TABLE>
In terms of generation costs, Exhibit VI - 4 summarizes regional fixed and
variable generation costs. As shown, TVA is the low cost region at approximately
$30.00/MWh followed by Southern at $34.25/MWh and SPP-SE at $43.89/MWh. For the
entire region, total system costs averaged $35.36/MWh in 1996. Of this
$35.36/MWh, roughly two-thirds was represented by fixed costs or $21.45/MWh.
Attachment III, Exhibits III-1 through III-5 provide a complete summary of
embedded generation costs by capacity type.
- --------------------------------------------------------------------------------
C-39
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VI - 4: Southeast Generation Embedded Cost Summary
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Sub- Data 1993 1994 1995 1996 1993 1994 1995 1996
Region $/MWh $/MWh $/MWh $/MWh
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
SE Sum of Fuel Total $ 1,867,532,387 1,868,059,363 1,862,044,354 2,092,774,453 16.74 16.05 15.18 17.60
Sum of Variable O&M Total $ 154,788,958 149,459,506 138,567,175 144,891,245 1.39 1.28 1.13 1.22
Sum of Fixed O&M Total $ 664,848,108 643,591,122 594,591,197 618,054,741 5.96 5.53 4.85 5.20
Sum of Fixed Total $ 2,628,021,478 2,630,874,090 2,177,515,045 2,362,347,881 23.55 22.60 17.75 19.87
Total Variable 2,022,321,345 2,017,518,869 2,000,611,529 2,237,665,698 18.12 17.33 16.31 18.82
Total Fixed 3,292,869,586 3,274,465,212 2,772,106,242 2,980,402,622 29.51 28.13 22.60 25.07
Total Costs 5,315,190,931 5,291,984,081 4,772,717,771 5,218,068,320 47.63 45.46 38.92 43.89
Sum of Total Gen 111,592,339 116,414,552 122,643,983 118,900,272
- ------------------------------------------------------------------------------------------------------------------------------------
STHRN Sum of Fuel Total $ 2,650,887,219 2,469,510,964 2,553,488,940 2,582,567,092 14.36 13.40 13.37 12.85
Sum of Variable O&M Total $ 215,836,060 205,488,878 213,915,846 221,354,195 1.17 1.11 1.12 1.10
Sum of Fixed O&M Total $ 878,920,888 837,986,761 858,858,704 1,153,310,764 4.76 4.55 4.50 5.74
Sum of Fixed Total $ 3,036,946,162 2,920,811,179 2,980,484,957 3,185,602,590 16.45 15.84 15.61 15.86
Total Variable 2,866,723,279 2,674,999,842 2,767,404,786 2,803,921,287 15.53 14.51 14.49 13.96
Total Fixed 3,915,867,050 3,758,797,940 3,839,343,661 4,078,213,354 21.21 20.39 20.11 20.30
Total Costs 6,782,590,329 6,433,797,782 6,606,748,447 6,882,134,641 36.74 34.90 34.60 34.25
Sum of Total Gen 184,594,371 184,357,607 190,946,391 200,916,764
- ------------------------------------------------------------------------------------------------------------------------------------
TVA Sum of Fuel Total $ 1,383,242,181 1,450,390,521 1,348,406,720 1,394,624,396 10.49 10.69 9.92 9.09
Sum of Variable O&M Total $ 118,526,097 133,461,829 122,458,535 148,074,903 0.90 0.98 0.90 0.96
Sum of Fixed O&M Total $ 474,104,388 533,847,315 489,834,138 592,299,609 3.59 3.94 3.60 3.86
Sum of Fixed Total $ 2,068,141,925 2,063,827,599 2,072,201,869 2,498,948,727 15.68 15.21 15.24 16.28
Total Variable 1,501,768,278 1,583,852,350 1,470,865,255 1,542,699,299 11.39 11.68 10.82 10.05
Total Fixed 2,542,246,313 2,597,674,914 2,562,036,007 3,091,248,336 19.27 19.15 18.84 20.14
Total Costs 4,044,014,591 4,181,527,264 4,032,901,262 4,633,947,635 30.66 30.83 29.66 30.19
Sum of Total Gen 131,904,978 135,648,800 135,963,145 153,474,504
- ------------------------------------------------------------------------------------------------------------------------------------
Total Sum of Fuel Total $ 5,901,661,787 5,787,960,848 5,763,940,014 6,069,965,941 13.79 13.26 12.82 12.83
Total Sum of Variable O&M Total $ 489,151,115 488,410,213 474,941,556 514,320,343 1.14 1.12 1.06 1.09
Total Sum of Fixed O&M Total $ 2,017,873,384 2,015,425,198 1,943,284,039 2,363,665,114 4.71 4.62 4.32 4.99
Total Sum of Fixed Total $ 7,733,109,565 7,615,512,868 7,230,201,871 8,046,899,198 18.06 17.45 16.08 17.00
Total Variable 6,390,812,902 6,276,371,061 6,238,881,570 6,584,286,284 14.93 14.38 13.88 13.91
Total Fixed 9,750,982,949 9,630,938,066 9,173,485,910 10,149,864,312 22.78 22.07 20.41 21.45
Total Costs 16,141,795,851 15,907,309,127 15,412,367,480 16,734,150,596 37.71 36.45 34.28 35.36
Total Sum of Total Gen 428,091,688 436,420,958 449,553,519 473,291,540
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
C.C. PACE MARKET STUDY RESOURCE ADDITION ASSUMPTIONS
In evaluating potential generation technologies for meeting future demand
requirements in the Southeast region, C.C. Pace assessed each technology's
maturity level, operating history, and duty cycle. The Southeast region's
existing power supply system is comprised of an abundance of base load power
plants (e.g., coal, nuclear and hydro) and limited intermediate and peaking
capabilities.
Based on C.C. Pace's review of available generation technologies and
consultation with equipment manufacturers, three generic types of technologies
were potential candidates for meeting future demand requirements for purposes of
this analysis:
o Pulverized-Coal Plant: designed to operate for meeting system base
load demand.
o Combined Cycle Plant: designed to operate at capacity factors from
55-90% and up to meet intermediate to base load requirements.
o Combustion Turbine Plant: designed to operate at a 3-15% capacity
factor for meeting peak load requirements.
- --------------------------------------------------------------------------------
C-40
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
C.C. Pace developed cost and performance characteristics for each sub-region
independently. Exhibit VI - 5 presents a summary of the cost and performance
characteristics of the three expansion options described above for the SPP-SE
sub-region. For the purposes of this study, information presented for each of
these options represents "typical" configurations, rather than a specific
vendor's cost and performance data. Further, C.C. Pace assumed an increasing
rate of efficiency of CT and CC technology each year. Specifically, CT's were
assumed to increase efficiency from 10,100 to 9,350 Btu/kWh from 2000 to 2020.
CC technology was assumed to improve from 6,860 to 6,360 Btu/kWh from 2000 to
2020.
Additionally, it should be noted that C.C. Pace developed these expansion unit
costs and operational characteristics as predictions of next generation
equipment. Specifically, C.C. Pace's improvements to current "state-of-the-art"
equipment in the Base Case Assumptions. These improvements are expected to be
commercially available from 2005 to 2020.
Exhibit VI - 5: SPP-SE Expansion Unit Characteristics
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Item Unit CT CC Coal
- --------------------------------------------------------------------------------
Assumptions
Capacity MW 230 360 500
Cost $/kW 300 500 1,100
Capacity Factor* % 15% 85% 85%
Annual Maintenance Weeks 2 3 4
Forced Outage % 2.5% 2.5% 5.0%
Fuel Cost $/MMBtu 2.24 2.24 1.37
Fixed O&M $/kW-yr 4.00 12.00 29.00
Variable O&M $/MWh 3.50 0.75 1.50
Heat Rate Btu/kWh 9,700 6,600 9,600
Percent Equity % 30% 30% 30%
Discount Rate % 8.5% 8.5% 8.5%
Return on Equity % 14% 14% 14%
Project Life Years 20 20 20
Installed Cost ($000) 69,000 180,000 550,000
Fixed O&M ($000) 920 4,320 14,500
Amount of Equity ($000) 20,700 54,000 165,000
Amount of Debt ($000) 48,300 126,000 385,000
- --------------------------------------------------------------------------------
Annual Fixed Costs
Total Debt ($000) 5,104 13,315 40,683
Interest ($000) 4,106 10,710 32,725
Principal ($000) 998 2,605 7,958
ROI ($000) 2,898 7,560 23,100
Fixed O&M ($000) 920 4,320 14,500
Taxes ($000) 1,265 3,218 12,375
Total Fixed ($000) 10,187 28,413 90,658
- --------------------------------------------------------------------------------
Cost Summary
Variable Costs $/MWh 25.23 15.53 14.65
Fixed Costs $/MWh 33.71 10.60 24.35
Total Costs $/MWh 58.93 26.13 39.00
- --------------------------------------------------------------------------------
* Capacity factor assumed for expansion planning purposes only
- --------------------------------------------------------------------------------
The only difference between the three sub-regions regarding plant performance
and cost estimates is the delivered price of fuel. To develop expansion unit
fuel price assumptions for
- --------------------------------------------------------------------------------
C-41
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
gas-fired expansion units, C.C. Pace used the fuel price assumptions defined in
Section VII for each state and applied an adjustment based on the weighted
average retail electricity sales for the states in the sub-region. Exhibit V-6
further presents C.C. Pace's calculations of fixed costs for each of the three
expansion options given our base case assumptions. The fixed cost data presented
in this table was used to evaluate market clearing prices in the Revenue
Requirement and Bid Analysis Module presented in Section II and to screen for
the appropriate additions mix to develop a least cost expansion plan. As shown
in the table, annual fixed costs for each of the expansion options include debt
payment (both interest and principal), return on equity, fixed O&M, and taxes.
In conducting our analysis, C.C. Pace assumed a financing structure of 30%
equity and 70% debt, and a 14% return on equity required by developers to
construct these power plants. Attachment III, Exhibits III-7 and III-8 provide
expansion unit characteristics for the Southern and TVA sub-regions.
Through the use of this screening analysis, C.C. Pace arrived at one major
conclusion:
o Because of the high capital costs of the pulverized coal option
(i.e., more than double the gas-fired combined cycle option) these
units were found to be uneconomic compared to the combined cycle
option. Specifically, expansion planning results found that
gas-fired combined cycle units would be the only base load
generation option considered in the CEMAS base case scenarios.
Operational assumptions for the LS Power unit are summarized in Exhibit VI - 6
below:
Exhibit VI - 6: Batesville Unit Specifications
- --------------------------------------------------------------------------------
================================================================================
Name LSP Unit
- --------------------------------------------------------------------------------
On-Line Date June 1, 2000
- --------------------------------------------------------------------------------
Equivalent Force Outage Rate % 2.80%
- --------------------------------------------------------------------------------
Annual Maintenance Requirements % 5.2% per year
- --------------------------------------------------------------------------------
Net Output MW 750
- --------------------------------------------------------------------------------
Variable O&M Expense $/MWh 1.00
- --------------------------------------------------------------------------------
1998 Deliverable Fuel Cost $/MMBtu 2.30 - Mississippi
- --------------------------------------------------------------------------------
Cost Per Start $ $2,500
- --------------------------------------------------------------------------------
Heat Rate Efficiency Btu/kWh 7,050
- --------------------------------------------------------------------------------
Minimum Operating Load MW 175
- --------------------------------------------------------------------------------
Service Area Location TVA
- --------------------------------------------------------------------------------
Interconnected Utilities TVA, SPP-SE
- --------------------------------------------------------------------------------
Transmission Pricing Arrangements TVA- SPP-SE @ $0.00/MWh and
Southern @ $1.82/MWh
================================================================================
DETERMINATION OF COMPETITIVE MARKET EXPANSION PLAN
The C.C. Pace market study does not add expansion units to meet a fixed target
reserve margin as is the current planning method for regulated utilities. A
competitive market structure dictates, by
- --------------------------------------------------------------------------------
C-42
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
definition, that participants will build expansion units only if they expect to
receive a sufficient return on their investment. Therefore, in the analysis
expansion units are added only when the market price can support them.
To determine the competitive market expansion plan, C.C. Pace followed three
rules or steps to arrive at the optimal expansion plan. These rules or steps are
as follows:
1. Use of the existing units and planned utility unit additions as the
minimum expansion plan as a starting point.
2. The addition of expansion units in each year up to such point that
the whole class of units (i.e., combined cycle or combustion
turbines) receive full recovery. This was done to the point that the
next unit added to the system would not be able to recover its
costs.
3. Unit additions were optimized for each sub-system (i.e., SPP-SE,
TVA, and Southern) and each year of the study period to yield the
largest number of combined cycle units and combustion turbine units
possible while still maintaining full recovery of these units.
4. Model determined the optimal cost solution and capacity mix of
combined cycle and combustion turbine technology in each year
modeled.
5. The model did not assume or allow for the retirement of existing
capacity.
- --------------------------------------------------------------------------------
C-43
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
TABLE OF CONTENTS
- --------------------------------------------------------------------------------
VII. FUEL PRICING..........................................................C-45
HISTORICAL FUEL PRICING...............................................C-45
COAL..................................................................C-50
C.C. Pace Coal Price Forecast...............................C-52
FUEL OIL..............................................................C-55
C.C. Pace Fuel Oil Price Forecast...........................C-56
Distillate Oil........................................................C-56
Residual Oil..........................................................C-58
URANIUM...............................................................C-58
NATURAL GAS...........................................................C-58
C.C. Pace Natural Gas Price Forecast........................C-59
FUEL PRICE FORECASTING METHODOLOGY....................................C-62
- --------------------------------------------------------------------------------
C-44
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
VII. FUEL PRICING
- --------------------------------------------------------------------------------
C.C. Pace's fuel pricing analysis focuses on the four fossil fuels most commonly
used to generate power in the Southeast region: natural gas, coal, No. 2 fuel
oil (distillate) and No. 6 fuel oil (residual), and uranium. This section
discusses historical fuel prices and trends and C.C. Pace's fuel price
forecasting methodology, underlying assumptions, and major conclusions.
HISTORICAL FUEL PRICING
C.C. Pace used FERC Form 423 data for plant specific fuel costs to build a
history of each of the utilities' delivered monthly average cost of natural gas,
oil, and coal between 1994 and 1997. This data determines the fuel procurement
variances of each facility throughout the Southeast market. Exhibit VII - 1 and
Exhibit VII - 2 illustrate the average prices regional utilities paid for coal,
No. 2 oil, and natural gas delivered to their power plants.(1)
As shown in Exhibit VII - 1, coal has the lowest and most stable pricing of the
three generation fuels, ranging between an average monthly cost of $1.20 -
$1.50/MMBtu. Natural gas, until the recent market volatility, was the second
lowest priced commodity with an historic average price of $1.75 - $2.10/MMBtu.
However, since 1996, natural gas pricing has been quite volatile, ranging from a
high of nearly $4.50/MMBtu to a low of $1.95/MMBtu. Lastly, delivered No. 2 fuel
oil pricing to the Southeast utilities has typically ranged between a low of
$3.50/MMBtu to a high of $4.25/MMBtu. On average, Southeast utilities pay
approximately $4.00/MMBtu for No. 2 fuel oil.
- --------
(1) No. 6 fuel oil prices are not included due to the low usage of this fuel
resulting in an incomplete price data series.
- --------------------------------------------------------------------------------
C-45
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VII - 1: Average Southeast Monthly Fuel Prices
- --------------------------------------------------------------------------------
[GRAPH OMITTED]
- --------------------------------------------------------------------------------
The Southeast market is dominated by coal-fired generation, which currently
comprise 57% of total generation requirements, followed by nuclear at 22% of
generation. Exhibit VII - 3 provides a comparison of generation by fuel type for
January 1994 and July 1997, as well as C.C. Pace's forecasted generation mix for
2006 and 2014 . As shown in Exhibit VII - 3, coal, uranium, fuel oil, and water
generation declined slightly from 1994 through 1997, while natural gas-fired
generation has increased by nearly 10%. Into the future, gas-fired capacity
continues to increase market share, with coal-fired and nuclear generation
decreasing as a result.
Gas-fired generation has increased historically, and will continue to increase,
its relative generation share for the following reasons:
o Utilities rely more on gas-fired steam turbines and combined cycle
facilities to meet incremental demand.
o No significant coal, uranium or hydro facilities have been built in
the system, therefore, increased generation from existing facilities
is very limited.
o Incremental capacity additions have been almost exclusively
gas-fired combustion turbines or combined cycle facilities.
- --------------------------------------------------------------------------------
C-46
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VII - 2: Historical Southeast Market Monthly Fuel Prices
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
===================================================================================================================================
COAL GAS OIL
- -----------------------------------------------------------------------------------------------------------------------------------
Total Total Total Cost - Cost -
Generation Cost Cost Generation Cost Cost Generation Cost No.6 No.2
MWh $1,000 c/MMBtu MWh $1,000 c/MMBtu MWh $1,000 c/MMBtu c/MMBtu
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Jan-94 22,124,104 351,086 158.62 2,208,060 61,564 254.18 626,739 15,163 166.91 356.32
- -----------------------------------------------------------------------------------------------------------------------------------
Feb-94 17,679,400 277,098 155.14 1,535,698 50,070 223.74 211,670 5,919 151.52 367.63
- -----------------------------------------------------------------------------------------------------------------------------------
Mar-94 19,774,758 306,040 155.02 2,293,154 67,886 224.16 52,104 1,927 90.25 375.15
- -----------------------------------------------------------------------------------------------------------------------------------
Apr-94 18,763,474 294,711 153.01 3,479,077 82,272 240.20 63,810 2,833 143.86 377.41
- -----------------------------------------------------------------------------------------------------------------------------------
May-94 20,119,280 314,498 125.23 3,421,252 91,514 211.69 283,779 5,724 185.48 376.99
- -----------------------------------------------------------------------------------------------------------------------------------
Jun-94 24,534,784 389,015 162.27 5,208,530 124,334 237.84 489,172 9,705 190.31 379.50
- -----------------------------------------------------------------------------------------------------------------------------------
Jul-94 24,458,550 381,195 125.45 5,701,358 138,933 228.45 90,810 2,953 220.44 375.88
- -----------------------------------------------------------------------------------------------------------------------------------
Aug-94 24,750,010 383,501 152.98 5,778,937 126,842 207.62 38,977 1,761 242.24 378.49
- -----------------------------------------------------------------------------------------------------------------------------------
Sep-94 21,370,005 329,294 119.76 5,092,173 96,367 171.73 48,138 1,773 216.63 387.36
- -----------------------------------------------------------------------------------------------------------------------------------
Oct-94 19,821,039 288,101 117.89 4,150,679 75,463 138.63 31,956 1,127 -- 236.57
- -----------------------------------------------------------------------------------------------------------------------------------
Nov-94 17,526,153 253,209 120.36 3,904,530 77,082 193.91 52,674 1,879 140.05 299.38
- -----------------------------------------------------------------------------------------------------------------------------------
Dec-94 18,426,724 280,924 158.15 3,514,057 73,808 164.24 49,914 2,047 117.19 374.92
===================================================================================================================================
Jan-95 20,689,382 309,762 125.75 3,616,625 75,763 197.58 47,459 1,876 93.95 413.20
- -----------------------------------------------------------------------------------------------------------------------------------
Feb-95 18,326,194 273,692 147.92 3,005,697 56,529 174.62 45,189 1,654 130.82 383.51
- -----------------------------------------------------------------------------------------------------------------------------------
Mar-95 18,783,970 284,939 120.94 3,804,675 68,254 165.38 46,589 2,013 130.82 388.51
- -----------------------------------------------------------------------------------------------------------------------------------
Apr-95 19,315,180 284,214 148.22 3,698,891 71,461 182.72 38,967 1,484 262.64 339.56
- -----------------------------------------------------------------------------------------------------------------------------------
May-95 22,146,968 336,546 148.54 5,142,433 105,219 197.06 48,451 1,882 260.44 327.67
- -----------------------------------------------------------------------------------------------------------------------------------
Jun-95 23,602,858 353,392 147.90 6,165,722 126,572 176.12 48,048 1,792 265.67 353.51
- -----------------------------------------------------------------------------------------------------------------------------------
Jul-95 26,424,921 403,866 147.76 7,165,224 136,030 182.01 81,345 3,032 215.29 344.26
- -----------------------------------------------------------------------------------------------------------------------------------
Aug-95 26,924,544 406,359 146.46 7,730,297 142,571 178.85 221,623 9,378 201.77 361.05
- -----------------------------------------------------------------------------------------------------------------------------------
Sep-95 22,537,466 339,826 146.19 5,352,536 104,026 162.53 36,641 1,512 -- 365.36
- -----------------------------------------------------------------------------------------------------------------------------------
Oct-95 21,112,932 302,669 140.33 4,356,305 91,452 199.44 34,810 1,254 96.05 291.74
- -----------------------------------------------------------------------------------------------------------------------------------
Nov-95 19,928,492 286,562 143.42 3,592,823 78,900 209.44 38,672 1,440 -- 363.59
- -----------------------------------------------------------------------------------------------------------------------------------
Dec-95 22,026,556 320,983 141.64 3,155,712 93,476 233.07 44,483 1,733 94.14 374.76
===================================================================================================================================
Jan-96 22,783,035 330,314 145.63 2,805,626 93,987 297.43 273,002 8,109 141.94 333.51
- -----------------------------------------------------------------------------------------------------------------------------------
Feb-96 19,879,913 286,524 147.73 2,290,225 105,226 426.64 650,978 19,339 213.63 425.86
- -----------------------------------------------------------------------------------------------------------------------------------
Mar-96 20,592,796 301,030 151.76 2,619,842 85,293 328.04 508,033 14,345 230.22 435.56
- -----------------------------------------------------------------------------------------------------------------------------------
Apr-96 19,547,461 278,185 148.50 2,837,316 84,003 335.38 55,344 2,128 252.78 322.13
- -----------------------------------------------------------------------------------------------------------------------------------
May-96 22,925,109 335,791 142.48 4,705,902 128,650 251.16 89,885 4,172 289.83 367.66
- -----------------------------------------------------------------------------------------------------------------------------------
Jun-96 23,890,570 359,235 144.72 5,690,429 156,021 260.72 75,131 2,952 266.39 354.78
- -----------------------------------------------------------------------------------------------------------------------------------
Jul-96 26,659,876 391,638 140.60 6,245,339 190,950 268.65 66,698 2,668 235.40 334.67
- -----------------------------------------------------------------------------------------------------------------------------------
Aug-96 26,284,323 382,918 144.71 5,700,327 158,183 256.15 41,790 1,803 108.68 385.15
- -----------------------------------------------------------------------------------------------------------------------------------
Sep-96 22,701,825 327,668 139.07 4,011,747 92,711 208.68 37,229 1,831 98.22 373.57
- -----------------------------------------------------------------------------------------------------------------------------------
Oct-96 21,155,627 307,670 146.15 3,054,152 69,600 196.16 29,190 1,326 99.66 404.23
- -----------------------------------------------------------------------------------------------------------------------------------
Nov-96 20,374,835 310,331 146.38 2,797,081 87,758 269.35 77,238 3,834 113.41 435.34
- -----------------------------------------------------------------------------------------------------------------------------------
Dec-96 21,353,143 316,790 146.68 2,138,188 96,483 399.46 351,802 11,487 157.69 397.63
===================================================================================================================================
Jan-97 22,733,641 337,064 147.95 2,267,971 94,044 373.13 717,217 22,565 211.38 450.69
- -----------------------------------------------------------------------------------------------------------------------------------
Feb-97 19,024,112 277,458 144.04 1,981,622 72,174 328.27 257,177 8,083 198.00 273.71
- -----------------------------------------------------------------------------------------------------------------------------------
Mar-97 19,982,215 292,249 118.31 2,417,119 55,941 247.38 127,783 4,312 283.00 331.10
- -----------------------------------------------------------------------------------------------------------------------------------
Apr-97 21,282,807 312,097 122.38 2,834,388 66,921 261.35 38,729 1,660 146.13 333.20
- -----------------------------------------------------------------------------------------------------------------------------------
May-97 22,250,297 327,167 148.85 3,815,593 97,014 249.83 75,318 2,797 284.17 340.55
- -----------------------------------------------------------------------------------------------------------------------------------
Jun-97 22,329,324 335,255 148.00 4,982,774 136,941 261.50 121,705 4,336 176.93 365.88
- -----------------------------------------------------------------------------------------------------------------------------------
Jul-97 27,403,597 408,382 142.45 7,354,311 209,383 231.42 233,934 9,875 268.71 401.82
- -----------------------------------------------------------------------------------------------------------------------------------
Aug-97 27,364,654 397,833 137.17 6,110,283 168,951 259.58 278,462 10,311 274.16 415.19
- -----------------------------------------------------------------------------------------------------------------------------------
Sep-97 26,051,087 376,162 144.08 4,977,085 159,161 335.67 421,260 12,083 278.15 408.17
- -----------------------------------------------------------------------------------------------------------------------------------
Oct-97 24,602,391 359,296 140.36 3,460,631 133,490 300.54 465,985 14,551 269.47 380.71
- -----------------------------------------------------------------------------------------------------------------------------------
Nov-97 23,279,358 324,345 145.98 2,214,124 93,089 314.23 645,396 19,370 272.12 318.12
- -----------------------------------------------------------------------------------------------------------------------------------
Dec-97 25,099,662 358,487 134.84 2,511,636 80,968 283.07 482,907 14,158 280.73 389.68
===================================================================================================================================
Jan-98 22,737,415 324,851 135.87 2,100,560 64,933 263.63 460,976 13,909 183.18 389.40
- -----------------------------------------------------------------------------------------------------------------------------------
Feb-98 19,041,341 276,007 136.27 1,642,384 46,403 261.05 413,535 10,839 181.64 377.52
- -----------------------------------------------------------------------------------------------------------------------------------
Mar-98 21,727,077 308,421 145.93 2,666,485 74,293 262.48 854,785 21,175 235.27 341.99
- -----------------------------------------------------------------------------------------------------------------------------------
Apr-98 19,827,438 285,295 139.92 3,158,128 87,361 231.22 488,352 11,809 231.80 327.19
- -----------------------------------------------------------------------------------------------------------------------------------
May-98 23,978,614 349,018 138.05 5,268,293 145,615 245.09 983,037 24,558 217.28 375.51
- -----------------------------------------------------------------------------------------------------------------------------------
Jun-98 26,922,286 394,444 137.91 6,479,957 183,134 242.72 837,948 25,429 210.74 365.09
- -----------------------------------------------------------------------------------------------------------------------------------
Jul-98 29,239,346 422,903 137.94 7,428,063 208,690 246.54 930,532 26,417 216.16 353.13
- -----------------------------------------------------------------------------------------------------------------------------------
Aug-98 27,926,127 405,134 138.83 7,354,783 193,863 243.06 782,895 20,279 199.51 326.53
- -----------------------------------------------------------------------------------------------------------------------------------
Sep-98 25,894,183 370,405 140.21 6,271,442 150,344 245.28 1,110,419 30,863 208.23 321.75
- -----------------------------------------------------------------------------------------------------------------------------------
Oct-98 22,631,872 339,654 132.46 3,829,610 91,513 243.03 87,788 2,772 203.79 298.70
- -----------------------------------------------------------------------------------------------------------------------------------
Nov-98 20,747,953 293,753 137.30 3,068,049 75,151 233.40 276,384 5,998 197.11 298.42
- -----------------------------------------------------------------------------------------------------------------------------------
Dec-98 22,965,644 320,071 133.96 3,164,258 81,914 248.69 626,932 13,363 197.11 307.26
===================================================================================================================================
</TABLE>
- --------------------------------------------------------------------------------
Overall, C.C. Pace expects the trend in gas-fired generation to maintain its
increasing significance in meeting generation requirements. Specifically, C.C.
Pace's capacity expansion plan shows that all incremental capacity additions in
the region are slated to be gas-fired
- --------------------------------------------------------------------------------
C-47
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
generation options. Therefore, almost all incremental demand will be served by
gas-fired generation.
- --------------------------------------------------------------------------------
C-48
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VII - 3: Comparison of Generation by Fuel Type
- --------------------------------------------------------------------------------
January 1994
[PIE CHART OMITTED]
July 1997
[PIE CHART OMITTED]
2006
[PIE CHART OMITTED]
- --------------------------------------------------------------------------------
C-49
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
----------------------------------------
2014
[PIE CHART OMITTED]
----------------------------------------
COAL
As stated previously, coal prices, as presented in Exhibit VII - 4 and Exhibit
VII - 5, have generally shown the least variability of the fossil fuels used in
the region, varying by only 40 cents per MMBtu during this time period. In terms
of overall pricing levels, the Tennessee Valley Authority's coal costs are
consistently lower than other major Southeast electric utility coal consumers.
TVA has historically purchased coal for approximately 44 cents per MMBtu below
the cost for other regional utilities. The majority of this cost advantage can
be explained by the quality of coal consumed by TVA and its proximity to coal
reserves. For example, TVA's coal averaged higher than 2.1% sulfur content over
this time period, while the other large coal consumers averaged around 1% sulfur
content.
- --------------------------------------------------------------------------------
C-50
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VII - 4: Historical Average Coal Prices (In Nominal Terms)
- --------------------------------------------------------------------------------
[GRAPH OMITTED]
- --------------------------------------------------------------------------------
Exhibit VII - 5 shows SERC versus U.S. historical average coal prices. The
average price differential between the SERC and U.S. average price of coal is
only 15 cents/MMBtu. The pricing differential typically caused by the higher
transportation costs of Southeastern utilities relative to other regions. At the
other end of the spectrum, Alabama Power was once a high cost purchaser of coal;
however, Alabama Power (along with the rest of the Southern Company utilities)
has undergone significant cost cutting efforts and lowered its coal costs over
time to reach parity with the other investor-owned utilities.
Overall, the average price for Southeastern coal follows the national coal
pricing trend, as shown in Exhibit VII - 5.
- --------------------------------------------------------------------------------
C-51
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VII - 5: SERC vs. U.S. Historical Average Coal Prices
- --------------------------------------------------------------------------------
[GRAPH OMITTED]
- --------------------------------------------------------------------------------
U.S. coal prices have generally been on a downward trend since the mid-1980s.
Despite this historical trend of declining coal prices, most forecasts have
typically anticipated real coal price increases (see Exhibit VII - 6). However,
in more recent years, forecasters have begun to revise their expectations based
on the continuing trend in national coal prices. As shown Exhibit VII - 6, AGA,
GRI, EIA, and DRI now anticipate real prices to decrease slightly in the future.
Exhibit VII - 6: Comparison of Projected Trends in Real Coal Prices: 1995-2010
- --------------------------------------------------------------------------------
=====================================================================
AGA GRI EIA DRI WEFA
=====================================================================
1994 1.50% -0.50% 1.20% 0.80% 2.30%
1995 0.30% -0.60% 0.80% 0.60% 2.50%
1996 N.A. -0.47% -0.50% -1.26% 0.38%
---------------------------------------------------------------------
Notes: AGA (American Gas Association), GRI (Gas Research Institute), EIA
(Energy Information Administration), DRI (DRI/McGraw Hill), WEFA (WEFA
Group)
- --------------------------------------------------------------------------------
C.C. Pace Coal Price Forecast
C.C. Pace's coal price forecast considered the following to be key elements to
assess the dynamics of the Southeast and the broader U.S. coal market:
- --------------------------------------------------------------------------------
C-52
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
o Procurement characteristics of utilities (i.e., cost and quality,
spot versus contract);
o Supply sources;
o Regional supply market;
o Commodity pricing trends, and
o Market factors affecting supply
C.C. Pace's assessment of the future price of coal has found that due to
increased productivity and lack of incremental coal demand outside of existing
coal-fired capacity, we expect national coal prices will continue a downward
trend and decline in real terms by 1.50% per year until the year 2015. C.C. Pace
expects a slightly different profile for coal supplies destined for the
Southeast. Specifically, the Southeast obtains a majority of its supply from
Appalachia. C.C. Pace's analysis shows that Appalachia will not experience the
same productivity gains as other supply regions (mainly the Powder River Basin).
Consequently, Southeast spot coal prices will experience only a 1.0% real price
decline.
However, C.C. Pace projects a significant price decline in the average
Southeastern utility cost of coal. This price decline is attributable to the
expected expiration of utility coal contracts which are at a significant premium
over spot coal prices. These expectations are based on the interplay of the
following market factors:
o Increased mining productivity,
o Industry deregulation and the expiration of premium priced coal
contracts,
o Competition from foreign coal imports and alternatives to
traditional domestic coal supplies.
Specifically, Exhibit VII - 7 below summarizes the plant specific coal costs of
"over-market" plants. Exhibit VII - 7 summarizes those facilities which C.C.
Pace has determined purchase coal under fixed contracts at well above
market-based coal prices. As shown, C.C. Pace estimates that approximately 35
million tons of coal is purchased at above market rates of $1.81/MMBtu. C.C.
Pace assumes that from 1998-2005 these over market contracts expire and these
facilities' coal costs will fall to an entirely market derived price. Attachment
IV contains Exhibits IV-1 through IV-5 which detail both "over-market" and
market-based coal price assumptions for each Southeastern coal-fired power
plant.
- --------------------------------------------------------------------------------
C-53
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VII - 7: Southeast Market vs. Over-Market Coal Price Summary
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
Total Over-Market Market Based
- -----------------------------------------------------------------------------------------------------------------
Prchsd Prchsd Percent of Prchsd Percent of
Tons Cost Tons Total Cost Tons Total Cost
Plant (000) c/MMBtu (000) Prchsd c/MMBtu (000) Prchsd c/MMBtu
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Southern
- -----------------------------------------------------------------------------------------------------------------
Barry 4,371 176 2,623 60.00% 204 1,749 40.00% 134
- -----------------------------------------------------------------------------------------------------------------
Crist 1,498 216 1,498 100.00% 216 -- 0.00% 141
- -----------------------------------------------------------------------------------------------------------------
Gadsden 253 182 215 85.00% 191 38 15.00% 130
- -----------------------------------------------------------------------------------------------------------------
Gaston 4,123 165 1,360 33.00% 212 2,762 67.00% 142
- -----------------------------------------------------------------------------------------------------------------
Gorgas 3,591 158 1,796 50.00% 180 1,796 50.00% 142
- -----------------------------------------------------------------------------------------------------------------
Greene County 1,470 131 441 30.00% 153 1,029 70.00% 122
- -----------------------------------------------------------------------------------------------------------------
Miller 8,800 166 5,104 58.00% 190 3,696 42.00% 134
- -----------------------------------------------------------------------------------------------------------------
White Bluff 6,010 182 5,108 85.00% 186 901 15.00% 158
- -----------------------------------------------------------------------------------------------------------------
Bowen 8,116 140 852 10.50% 171 7,264 89.50% 136
- -----------------------------------------------------------------------------------------------------------------
Harlee Branch 2,861 155 648 22.65% 175 2,213 77.35% 149
- -----------------------------------------------------------------------------------------------------------------
Scherer 10,349 174 2,160 20.87% 230 8,189 79.13% 159
- -----------------------------------------------------------------------------------------------------------------
Smith 1,104 172 575 52.10% 202 529 47.90% 141
- -----------------------------------------------------------------------------------------------------------------
Wansley 3,408 186 2,215 65.00% 208 1,193 35.00% 145
- -----------------------------------------------------------------------------------------------------------------
Southern Subtotal 55,952 167 24,595 43.96% 196 31,357 56.04% 144
- -----------------------------------------------------------------------------------------------------------------
SWEPCO
- -----------------------------------------------------------------------------------------------------------------
Flint Creek 2,015 143 1,310 65.00% 162 705 35.00% 108
- -----------------------------------------------------------------------------------------------------------------
Welsh 5,785 177 3,760 65.00% 200 2,025 35.00% 135
- -----------------------------------------------------------------------------------------------------------------
SWEPCO Subtotal 7,800 168 5,070 65.00% 190 2,730 35.00% 128
- -----------------------------------------------------------------------------------------------------------------
SOMI
- -----------------------------------------------------------------------------------------------------------------
Morrow 926 205 926 100.00% -- -- 0.00% 134
- -----------------------------------------------------------------------------------------------------------------
TVA
- -----------------------------------------------------------------------------------------------------------------
Allen (TN) 2,095 110 -- 0.00% 132 2,095 100.00% 110
- -----------------------------------------------------------------------------------------------------------------
Bull Run 1,782 109 346 19.39% 115 1,436 80.61% 107
- -----------------------------------------------------------------------------------------------------------------
Colbert 3,224 116 806 25.00% 126 2,418 75.00% 112
- -----------------------------------------------------------------------------------------------------------------
Gallatin 2,574 117 660 25.64% 130 1,914 74.36% 113
- -----------------------------------------------------------------------------------------------------------------
Johnsonville 3,688 116 864 23.43% 123 2,824 76.57% 114
- -----------------------------------------------------------------------------------------------------------------
Shawnee 3,573 125 1,440 40.31% 137 2,133 59.69% 117
- -----------------------------------------------------------------------------------------------------------------
Widows Creek 3,986 114 660 16.56% 134 3,326 83.44% 110
- -----------------------------------------------------------------------------------------------------------------
TVA Subtotal 20,922 116 4,776 22.83% 130 16,146 77.17% 112
- -----------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------
Total 85,600 155 35,366 41.32% 181 50,234 58.68% 133
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
Also of note, C.C. Pace projects an increase in TVA coal costs (relative to
other utilities) due to environmental constraints. Specifically, C.C. Pace
assumes there will be no price decline in TVA current spot coal purchases.
Further, C.C. Pace expects an overall price increase in coal supplied to the
Paradise power plant due to environmental constraints which will soon apply to
this facility. Specifically, C.C. Pace assumed that current coal procurement
costs will rise by approximately 10-15% in real terms.
- --------------------------------------------------------------------------------
C-54
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
FUEL OIL
To develop a detailed fuel oil price assessment for the Southeast, C.C. Pace
considered the three primary factors that impact the fuel oil commodity pricing.
They are:
o Crude oil markets
o Demand for fuel oil
o Residual oil and other refined oil products
C.C. Pace compared the historical pricing trends of crude oil, residual fuel
oil, and two other major refined products (i.e., gasoline, distillate fuel oil).
Exhibit VII - 8 shows the price histories of these petroleum products. As shown
in Exhibit VII - 8, the price paid for residual oil, as well as other refined
products moves in almost direct correlation with crude oil prices. As a
consequence of this relationship, Exhibit VII - 8 supports that the main driver
to residual or distillate fuel oil pricing is the supply/demand balance for
crude oil.
As shown in Exhibit VII - 8, in terms of general fuel oil market trends, the
price of both residual and distillate increased in 1989 and 1990. The price
increase in 1990 was primarily attributable to Iraq's invasion of Kuwait and the
subsequent U.N. embargo on oil exports from both Iraq and Kuwait. The price of
both products fell every year from 1991-1994, followed by a slight rise in 1995.
Even with the impact of the Gulf War, the average price increase over this
period was only 2.2% for No. 2 fuel oil and 2.9% for No. 6 fuel oil, slightly
below or equal to inflation.
- --------------------------------------------------------------------------------
C-55
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VII - 8: Price Comparison of Crude Oil and Major Refined Products
- --------------------------------------------------------------------------------
[GRAPH OMITTED]
- --------------------------------------------------------------------------------
Backcasting further into the mid- to late 1980s provides little additional
information due to the influence of OPEC. Oil prices fell dramatically in 1986
as Saudi Arabia ignored the rest of OPEC and expanded production. The price
increases in subsequent years were partially attributable to the artificially
low price level the market achieved in 1986 and the restoration of a long term
market balance.
Based on the analysis of long term oil price trends and the supply/demand
balance for crude oil, C.C. Pace anticipates that world oil prices (both crude
oil and refined products) will remain constant in real terms. Because long-term
crude oil prices are not projected to rise faster than the rate of inflation,
refined product prices (i.e., residual and distillate fuel oil) can also be
expected to remain stable over the long run. Nearly all forecasters share C.C.
Pace's view that real oil prices will remain flat over the long term.
C.C. Pace Fuel Oil Price Forecast
Distillate Oil
Because fuel oil is used in such small quantities in the Southeast, plant
specific data does not yield consistent and accurate delivered fuel costs. To
achieve more accurate data, C.C. Pace
- --------------------------------------------------------------------------------
C-56
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
aggregated fuel consumption and pricing data at the state level. Monthly data on
consumption and delivered fuel cost electric utilities from 1994 to the present
was analyzed to arrive at average state-wide delivered distillate prices.
Distillate prices were assumed to remain constant (in real terms) throughout the
forecasting period. Plant-level distillate prices are therefore:
Alabama - $3.98/MMBtu
Gaston
Portland
Arkansas - $4.21/MMBtu
o Blytheville
o Cecil Lynch
o Paragould Turbine
Georgia - $4.17/MMBtu
o Arkwright
o Atkinson
o Bowen
o McDonough
o McManus
o Mitchell (GA)
o Wansley
o Wilson
Louisiana - $3.85/MMBtu
o A.B. Paterson
o Buras
Mississippi - $3.93/MMBtu
o Paulding
o Rex Brown
Tennessee - $4.37/MMBtu
o Gallatin
o Johnsonville
- --------------------------------------------------------------------------------
C-57
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Residual Oil
Base year residual oil prices were estimated by calculating the average price
difference of residual and distillate oil sold in the U.S. and adjusting the
state level distillate prices by this amount (i.e., $1.69/MMBtu). The
plant-level residual oil price for the only plant unit in the region using
residual oil as its primary fuel is:
Georgia-$2.48/MMBtu
o McManus
URANIUM
C.C. Pace did not conduct a detailed uranium market pricing study. However, C.C.
Pace analyzed historic uranium costs of the major power plants in the Southeast.
As shown in Exhibit VII - 9, it is evident that the utility uranium costs have
been converging at between $5.00-7.00/MWh. Average fuel costs at TVA's newly
operational Watts Bar nuclear facility were below this range during 1996 at
$3.18/MWh. C.C. Pace does not expect any real price movement of uranium over the
next 20 years. Therefore, C.C. Pace assumed utility uranium prices would be
equal to their 1996 average value and escalated at 0.0% annually, in real terms.
Exhibit VII - 9: Southeast Nuclear Generation Historical Prices - $/MWh
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------
1988 1989 1990 1991 1992 1993 1994 1995 1996
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Farley 6.94 6.46 5.95 5.71 4.35 5.09 4.92 5.01 4.96
Arkansas 7.92 8.07 7.83 7.53 6.86 6.03 5.17 5.59 5.45
Waterford 8.59 7.99 7.70 6.52 5.81 5.19 5.24 5.51 5.56
Hatch 10.95 11.20 8.77 6.95 7.12 6.13 7.28 7.17 6.20
Vogtle 11.99 11.00 10.12 8.57 6.02 5.54 5.60 5.01 4.78
Grand Gulf 15.00 12.52 11.87 9.50 7.49 5.95 5.56 5.59 5.27
Browns Ferry N.A. N.A. N.A. 22.51 12.64 11.94 11.27 6.03 6.16
Sequoyah 8.86 9.56 8.99 9.11 9.99 10.17 10.70 6.17 5.40
Watts Bar N.A. N.A. N.A. N.A. N.A. N.A. N.A. N.A. 3.18
- ------------------------------------------------------------------------------------------------------
Weighted Avg 10.01 9.56 8.66 8.10 7.42 6.43 6.67 5.73 5.38
- ------------------------------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
NATURAL GAS
Most, if not all gas destined for the Southeast region originates either from
the Gulf Coast or Louisiana production areas.
As an indicator of future expectations of Gulf Coast gas pricing, Exhibit VI-10
provides a summary of Henry-Hub based NYMEX five-year strip gas prices.
Examining NYMEX price history, NYMEX prices have averaged between $1.63 and
$2.59/MMBtu. In the future, the NYMEX price strip anticipates further average
price erosion to the $2.20 - $2.30 level over 1998
- --------------------------------------------------------------------------------
C-58
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
through 2000. As shown in Exhibit VII - 10, the NYMEX forward curve has shifted
up dramatically since last summer. For example, the 1999 NYMEX strip has risen
approximately $0.25 over the past 8 months. Despite the upward shift, the price
expectations are still well below 1997 averages.
Exhibit VII - 10: Historical and Projected NYMEX Henry Hub Gas Prices
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Ann. Avg. of Nearby Ann. Avg. NYMEX Henry Hub Price "Strips"
- --------------------------------------------------------------------------------
Year NYMEX Henry Hub Price 7/1/97 1/30/98 3/3/98
- --------------------------------------------------------------------------------
1992 $1.81
- --------------------------------------------------------------------------------
1993 $2.11
- --------------------------------------------------------------------------------
1994 $1.98
- --------------------------------------------------------------------------------
1995 $1.63
- --------------------------------------------------------------------------------
1996 $2.40
- --------------------------------------------------------------------------------
1997 $2.49
- --------------------------------------------------------------------------------
1998 $2.15 $2.22 $2.35
- --------------------------------------------------------------------------------
1999 $2.11 $2.28 $2.37
- --------------------------------------------------------------------------------
2000 $2.17 $2.32 $2.36
- --------------------------------------------------------------------------------
Further, Exhibit VII - 11 provides comparisons of the forecasted real growth
rates of gas prices by several commonly referenced forecasters. These forecasts
show a consistent downward pattern from past forecast years. However, all
forecasters still predict a real price increase for gas over the long term.
Current rates range between 0.9% to a high of 3.1% real escalation.
Exhibit VII - 11: Ten Year Price Forecasts of Annual Average Rates of Change
(Real Terms)
- --------------------------------------------------------------------------------
----------------------------------------------------------------------
Percent
Reduction
1993 1994 1995 1996 '93 to latest
----------------------------------------------------------------------
AGA 4.20% 2.49% 1.38% n/a 66%
GRI 3.46% 2.40% 1.70% 0.90% 74%
DRI 4.98% 4.25% 4.15% 3.16% 37%
EIA 4.23% 3.48% 3.09% 2.40% 43%
----------------------------------------------------------------------
- --------------------------------------------------------------------------------
Overall, market forecasting mechanisms such as NYMEX Swaps indicate that gas
priced from the Henry Hub should be priced at $2.00/MMBtu or higher for the next
5 years. Independent forecasters concur with this expectation calling for real
price escalation of approximately 1-2% from current market pricing levels of
$2.00-$2.15/MMBtu.
C.C. Pace Natural Gas Price Forecast
C.C. Pace's gas market analysis strongly indicates a change in the Southeast gas
market's supply and demand balance, resulting in lower future market prices.
C.C. Pace's underlying analysis of the gas commodity supply/demand balance for
Gulf Coast gas indicates the following:
- --------------------------------------------------------------------------------
C-59
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
o Trends in consumption show the gas demand growing moderately.
o Demand for Gulf Coast gas supplies from its traditional Northeast
markets will decrease with the completion of additional pipeline
projects from Canadian supply basins.
o Gulf Coast production capacity is increasing. C.C. Pace's market
review shows that Gulf Coast production will likely increase by over
1 Bcf per day over the next 12-18 months, several projects for
increased Gulf Coast production to market (i.e., gathering system
interconnects with major east coast interstate pipelines) are under
development, and peaking supply storage capacity in the Gulf Coast
and in the Northeast market area is increasing -- augmenting Gulf
Coast gas production capability.
o 1997 storage injections coupled with a mild 1997-1998 winter in the
Northeast will allow production to catch up to historical storage
reserve levels.
C.C. Pace expects market pricing to fall from 1996 and 1997 Henry Hub cash price
high values of $2.76/MMBtu and $2.57/MMBtu, respectively. Specifically, C.C.
Pace expects that 1998 prices will achieve approximately $2.20/MMBtu with a 0.5%
annual real price escalation, thereafter.
In terms of plant specific gas prices, C.C. Pace derived gas prices on a state
level based on the historic basis differential between the Henry Hub cash price
and delivered utility gas prices. For each state, C.C. Pace calculated the
average difference between the Henry Hub price and the average electric utility
gas price for the period 1994-1997 (see Exhibit VII - 12). The state basis
differential was then applied to C.C. Pace's forecast of annual average gas
prices at the Henry Hub (see Exhibit VII - 13) through 2015.
Exhibit VII - 12: Average Electric Utility Delivered Gas Cost Basis Difference
from Henry Hub - (cents/MMBtu)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1994 1995 1996 *1997 Average
- --------------------------------------------------------------------------------
Alabama 58 23 11 57 37
Arkansas (14) (11) (4) (23) (13)
Louisiana 28 4 18 1 13
Mississippi 33 (6) 13 2 10
Georgia** N.A. N.A. N.A. N.A. 25
Tennessee** N.A. N.A. N.A. N.A. 25
Texas 24 2 (25) (11) (3)
- --------------------------------------------------------------------------------
* Average through August 1997.
** Gas use for utility did not provide useable numbers for basis calculation.
C.C. Pace's estimated transportation costs to these states to be 25
cents/MMBtu.
- --------------------------------------------------------------------------------
C-60
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Exhibit VII - 13: Southeast Gas Hub and Delivered to Utility Gas Forecast
($/MMBtu)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Year Henry Hub Alabama Arkansas Louisiana Mississippi Georgia Tennessee Texas
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1998 2.20 2.57 2.07 2.33 2.30 2.45 2.45 2.17
1999 2.21 2.58 2.08 2.34 2.32 2.46 2.46 2.19
2000 2.22 2.60 2.09 2.35 2.33 2.47 2.47 2.20
2001 2.23 2.61 2.10 2.36 2.34 2.49 2.49 2.21
2002 2.24 2.62 2.11 2.37 2.35 2.50 2.50 2.22
2003 2.26 2.64 2.12 2.39 2.36 2.51 2.51 2.23
2004 2.27 2.65 2.13 2.40 2.37 2.52 2.52 2.24
2005 2.28 2.66 2.14 2.41 2.39 2.54 2.54 2.25
2006 2.29 2.68 2.16 2.42 2.40 2.55 2.55 2.26
2007 2.30 2.69 2.17 2.43 2.41 2.56 2.56 2.27
2008 2.31 2.70 2.18 2.45 2.42 2.58 2.58 2.29
2009 2.32 2.72 2.19 2.46 2.43 2.59 2.59 2.30
2010 2.34 2.73 2.20 2.47 2.45 2.60 2.60 2.31
2011 2.35 2.74 2.21 2.48 2.46 2.61 2.61 2.32
2012 2.36 2.76 2.22 2.50 2.47 2.63 2.63 2.33
2013 2.37 2.77 2.23 2.51 2.48 2.64 2.64 2.34
2014 2.38 2.78 2.24 2.52 2.50 2.65 2.65 2.36
2015 2.39 2.80 2.25 2.53 2.51 2.67 2.67 2.37
2016 2.41 2.81 2.27 2.55 2.52 2.68 2.68 2.38
2017 2.42 2.83 2.28 2.56 2.53 2.69 2.69 2.39
2018 2.43 2.84 2.29 2.57 2.55 2.71 2.71 2.40
2019 2.44 2.86 2.30 2.58 2.56 2.72 2.72 2.41
2020 2.46 2.87 2.31 2.60 2.57 2.73 2.73 2.43
- -------------------------------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
These regional prices were then applied to each plant based on its location. The
following lists each plant's location and 1998 base year gas price.
- --------------------------------------------------------------------------------
C-61
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
Alabama-$2.57/MMBtu
o Chickasaw
o Greene County Combustion Turbine
o McWilliams
Arkansas-$2.07/MMBtu
o Carl Bailey
o Harvey Couch
o Lake Catherine
o Mabelvale
o McClellan
o Paragould Turbine
o Robert E. Ritchie
o Thomas Fitzhugh
Georgia-$2.45/MMBtu
o Atkinson
o Boulevard
o Crisp
o John Harmon
o McIntosh (GA)
o Plant Kraft (Port Wentworth)
o RVIerside
o Robins
Tennessee-$2.45/MMBtu
o Allen (TN)
o Colbert
Texas-$2.17/MMBtu
o Lewis Creek
o Nelson
o Sabine
o Willow Glen
Louisiana-$2.33/MMBtu
o Big Cajun 1
o Coughlin
o D.G. Hunter
o Doc Bonin
o Franklin
o Houma
o Little Gypsy
o Michoud
o Ninemile Point
o Plaquemine
o Ruston
o Sterlington
o Teche
o Waterford
Mississippi-$2.30/MMBtu
o Baxter Wilson
o Benndale
o Chevron Cogen (Standard Oil)
o Delta
o Eaton
o Gerald Andrus
o Henderson-Ms
o Jack Watson
o Moselle
o Rex Brown
o Sweatt
o Wilkins
o Wright
o Yazoo
FUEL PRICE FORECASTING METHODOLOGY
In developing long-term fuel price forecast inputs, C.C. Pace followed the
methodology outlined in Exhibit VII - 14. As shown, C.C. Pace collected
historical plant level fuel pricing for a three year period from FERC and EIA
sources. The average cost of fuel at each plant was then compared to the
weighted average cost of that fuel for all plants in the entire market area. A
"fuel factor" (i.e., the ratio of that unit's fuel cost to the weighted average)
was then derived for each unit and assigned to that unit within the CEMAS data
set. Due to the long term horizon of the Southeast Market study and the lack of
consistent seasonal patterns of natural gas, C.C. Pace did not assume any
seasonal price changes for natural gas or any other fuels.
- --------------------------------------------------------------------------------
C-62
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
To develop unit fuel price assumptions for gas-fired expansion units, C.C. Pace
used the fuel price assumptions defined for each state and applied an adjustment
based on the weighted average retail electricity sales for the states in the
sub-region.
Exhibit VII - 14: C.C. Pace Fuel Pricing Methodology
- --------------------------------------------------------------------------------
[FLOW CHART OMITTED]
- --------------------------------------------------------------------------------
Next, long-term fuel escalation factors were developed based on C.C. Pace's
market outlook summarized above for the study period and shown in Exhibit VII -
15. The forecasted growth rates were then applied to the weighted average fuel
prices previously derived. Lastly, these projected annual fuel prices for the
four fossil-fuel categories were fed into the Fuel Pricing section of the Market
Clearing Price Module and Revenue Requirements Module.
- --------------------------------------------------------------------------------
Exhibit VII - 15: Average Annual Fuel Price Escalation*
- --------------------------------------------------------------------------------
---------------------------------------------------
Escalation
Rate
---------------------------------------------------
Coal -1.0%
---------------------------------------------------
No. 6 0.0%
---------------------------------------------------
No. 2 0.0%
---------------------------------------------------
Natural Gas 0.5%
---------------------------------------------------
Nuclear (Uranium) 0.0%
---------------------------------------------------
* All escalation rates are expressed in real terms (i.e., exclusive
of the effects of inflation).
- --------------------------------------------------------------------------------
C-63
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
ATTACHMENT I
REGIONAL MARKET DEFINITION AND TRANSMISSION CAPABILITY
ASSUMPTIONS & SUPPORTING ANALYSIS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit I-1: Southeast Net Purchases/(Sales) - MWh
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Year
Sub-Region S/B Sub-Region 1990 1991 1992 1993 1994 1995 1996
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
SE AZNMA 38 -- -- -- -- 600 316,454
ECARSR 4,320 3,564 -- 231,848 303,155 430,021 (4,276)
EMO 122,717 (161,957) (367,750) 593,329 456,108 (1,957,507) 25,469
ERCOTS (306,240) (270,675) 82,822 (82,127) 286,872 446,673 (425,299)
FRCCSR (4,560) -- (210,132) (104,092) -- -- (124,497)
N 3,223,131 1,817,766 2,209,852 1,105,544 3,632,445 2,816,862 4,214,805
VACAR -- -- 1,350 14,025 -- -- --
WC 2,369,303 3,513,167 5,735,641 5,798,503 5,025,043 6,608,970 5,557,015
- ------------------------------------------------------------------------------------------------------------------------------------
SE Total 5,408,709 4,901,865 7,451,783 7,557,030 9,703,623 8,345,619 9,559,671
- ------------------------------------------------------------------------------------------------------------------------------------
STHRN AEP -- -- -- -- (14,152) (12,722) (15,097)
APS -- -- -- -- -- (1,359) (1,157)
ECARSR 1,765,541 1,588,190 2,157,204 2,479,853 1,068,659 1,575,219 1,445,379
EMO -- -- -- -- -- -- 12,003
ERCOTS -- -- -- -- -- -- 51,855
FRCCSR (24,146,324) (19,909,692) (17,200,925) (12,877,370) (10,819,517) (10,515,810) (10,212,770)
N -- -- -- -- -- 168,066 36,737
PJM -- -- 80,441 108,853 77,375 27,380 109,416
RMPA -- -- -- -- -- (2,561) --
SCI 129,744 -- -- -- (43,300) (41,675) (41,785)
VACAR 44,925 (21,406) 215,135 115,394 (1,323,818) (900,454) (651,729)
WC -- (21,492) -- -- -- -- --
MAPPSR -- -- -- -- -- -- --
- ------------------------------------------------------------------------------------------------------------------------------------
STHRN Total (22,206,114) (18,364,400) (14,748,145) (10,173,270) (11,054,753) (9,703,916) (9,267,148)
- ------------------------------------------------------------------------------------------------------------------------------------
TVA AEP 11,250 -- -- 831,175 76,222 323,256 (214,524)
ECARSR (2,628,403) (2,699,467) (2,566,447) (802,790) (1,390,212) (2,272,393) (5,729,577)
EMO -- -- -- -- 1,200,007 1,845,380 (575,987)
ERCOTS -- -- -- -- -- -- 1,236
FRCCSR -- -- -- -- -- 7,900 10,089
N -- -- -- 75,899 68,748 226,011 120,114
PJM -- -- -- -- -- -- 324,438
SCI -- -- -- (234,591) (1,152,441) 9,706 15,130
VACAR (1,259,925) (1,043,500) (995,687) (1,681,658) (965,150) (1,120,689) (1,375,509)
WC -- -- -- -- -- -- 100
NI -- -- -- -- -- -- 10
- ------------------------------------------------------------------------------------------------------------------------------------
TVA Total (3,877,078) (3,742,967) (3,562,134) (1,811,965) (2,162,826) (980,829) (7,424,480)
- ------------------------------------------------------------------------------------------------------------------------------------
Grand Total (20,674,483) (17,205,502) (10,858,496) (4,428,205) (3,513,956) (2,339,126) (7,131,957)
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Exhibit I-2: Southeast Net Purchases/(Sales) - MWh
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
1990 1991 1992 1993 1994 1995 1996
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
SE 5,408,709 4,901,865 7,451,783 7,557,030 9,703,623 8,345,619 9,559,671
STHRN (22,206,114) (18,364,400) (14,748,145) (10,173,270) (11,054,753) (9,703,916) (9,267,148)
TVA (3,877,078) (3,742,967) (3,562,134) (1,811,965) (2,162,826) (980,829) (7,424,480)
- -----------------------------------------------------------------------------------------------------------------------
Total (20,674,483) (17,205,502) (10,858,496) (4,428,205) (3,513,956) (2,339,126) (7,131,957)
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
Exhibit I-3: Southeast Net Purchases/(Sales) @100% LF - MW
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
1990 1991 1992 1993 1994 1995 1996
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
SE 617 560 851 863 1,108 953 1,091
STHRN (2,535) (2,096) (1,684) (1,161) (1,262) (1,108) (1,058)
TVA (443) (427) (407) (207) (247) (112) (848)
- -----------------------------------------------------------------------------------------------------------------------
Total (2,360) (1,964) (1,240) (506) (401) (267) (814)
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
ATTACHMENT II
DEMAND ASSUMPTIONS & SUPPORTING ANALYSIS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit II-1: Historical Levels of Key Economic Indicators - 1989-1996
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
1989 1990 1991 1992 1993 1994 1995 1996
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
SPP-SE
- ------------------------------------------------------------------------------------------------------------------------------------
Total Employment (000) 2,452 2,452 2,511 2,529 2,526 2,591 2,644 2,702
Total Disposable Personal Income (000) 116 117 120 124 127 131 134 136
Total Population (000) 7,298 7,287 7,342 7,412 7,475 7,542 7,613 7,669
Demand 110,638 113,274 115,165 116,963 123,299 125,552 132,509 136,682
- ------------------------------------------------------------------------------------------------------------------------------------
Southern
- ------------------------------------------------------------------------------------------------------------------------------------
Total Employment (000) 5,946 6,064 6,043 6,114 6,335 6,557 6,655 6,842
Total Disposable Personal Income (000) 224 228 231 241 247 256 267 273
Total Population (000) 13,126 13,266 13,451 13,665 75,948 14,114 14,324 14,522
Demand 149,114 154,870 157,874 159,847 170,949 172,980 181,320 188,615
- ------------------------------------------------------------------------------------------------------------------------------------
TVA
- ------------------------------------------------------------------------------------------------------------------------------------
Total Employment (000) 2,720 2,740 2,730 2,776 2,849 3,038 3,076 3,121
Total Disposable Personal Income (000) 102 103 104 110 114 117 122 123
Total Population (000) 5,946 5,986 6,048 6,125 6,207 6,291 6,377 6,455
Demand 118,595 118,983 128,717 122,661 129,884 133,854 142,031 148,040
- ------------------------------------------------------------------------------------------------------------------------------------
Total
- ------------------------------------------------------------------------------------------------------------------------------------
Total Employment (000) 11,119 11,256 11,284 11,420 11,711 12,186 12,375 12,665
Total Disposable Personal Income (000) 441 448 456 476 488 504 523 533
Total Population (000) 26,369 26,538 26,840 27,201 89,629 27,948 28,313 28,646
Demand 378,347 387,127 401,756 399,471 424,132 432,386 455,860 473,337
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit II-2: Statistical Relationship between Economic Indicators and Demand
- --------------------------------------------------------------------------------
Standard Standard
Deviation Deviation
Sub Region R(2) GWh MW - YR
- --------------------------------------------------------------------------------
SPP-SE 0.975 1,492 170
STHRN 0.987 1,574 180
TVA 0.964 2,010 229
- --------------------------------------------------------------------------------
Total N.A. 5,075 579
- --------------------------------------------------------------------------------
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit II-3: Growth Rates of Demand and Key Drivers
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------
1989- 1996- 2000- 2005- 2010- 2015-
1996 2000 2005 2010 2015 2020
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
SPP-SE
- --------------------------------------------------------------------------------------------------------
Total Employment (000) 1.40% 1.43% 1.22% 1.11% 1.00% 1.02%
Total Disposable Personal Income (000) 2.38% 2.25% 2.13% 2.09% 2.06% 2.09%
Total Population (000) 0.71% 0.68% 0.66% 0.67% 0.70% 0.70%
Demand 3.07% 2.39% 2.04% 1.85% 1.72% 1.59%
- --------------------------------------------------------------------------------------------------------
Southern
- --------------------------------------------------------------------------------------------------------
Total Employment (000) 2.02% 1.90% 1.69% 1.59% 1.49% 1.52%
Total Disposable Personal Income (000) 2.87% 2.73% 2.56% 2.50% 2.45% 2.48%
Total Population (000) 1.45% 1.22% 1.18% 1.19% 1.20% 1.21%
Demand 3.41% 2.56% 2.10% 1.82% 1.58% 1.47%
- --------------------------------------------------------------------------------------------------------
TVA
- --------------------------------------------------------------------------------------------------------
Total Employment (000) 1.98% 1.74% 1.49% 1.42% 1.34% 1.39%
Total Disposable Personal Income (000) 2.78% 2.49% 2.32% 2.31% 2.31% 2.35%
Total Population (000) 1.18% 0.92% 0.85% 0.89% 0.93% 0.94%
Demand 3.22% 1.72% 1.41% 1.52% 1.62% 1.50%
- --------------------------------------------------------------------------------------------------------
Total
- --------------------------------------------------------------------------------------------------------
Total Employment (000) 1.88% 1.76% 1.54% 1.45% 1.35% 1.39%
Total Disposable Personal Income (000) 2.72% 2.55% 2.40% 2.35% 2.32% 2.36%
Total Population (000) 1.19% 1.01% 0.97% 0.99% 1.01% 1.02%
Demand 3.25% 2.24% 1.87% 1.74% 1.63% 1.51%
- --------------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit II-4: Projected Growth of Subregional Demand Forecasts - 1998-2015
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
SPP-SE
- -------------------------------------------------------------------------------------------------------------------------------
Demand (GWH) 2.13% 2.40% 2.34% 2.13% 2.08% 2.04% 2.00% 1.96% 1.92% 1.88%
Summer Peak (MW) 3.87% 2.40% 2.34% 2.13% 2.08% 2.04% 2.00% 1.96% 1.92% 1.88%
Winter Peak (MW) -2.13% 2.40% 2.34% 2.13% 2.08% 2.04% 2.00% 1.96% 1.92% 1.88%
- -------------------------------------------------------------------------------------------------------------------------------
Southern
- -------------------------------------------------------------------------------------------------------------------------------
Demand (GWH) 2.20% 2.52% 2.47% 2.19% 2.14% 2.10% 2.06% 2.02% 1.88% 1.85%
Summer Peak (MW) 2.56% 2.52% 2.47% 2.19% 2.14% 2.10% 2.06% 2.02% 1.88% 1.85%
Winter Peak (MW) 0.79% 2.52% 2.47% 2.19% 2.14% 2.10% 2.06% 2.02% 1.88% 1.85%
- -------------------------------------------------------------------------------------------------------------------------------
TVA
- -------------------------------------------------------------------------------------------------------------------------------
Demand (GWH) 2.19% 1.49% 1.46% 1.46% 1.43% 1.41% 1.39% 1.37% 1.57% 1.54%
Summer Peak (MW) 4.31% 1.49% 1.46% 1.46% 1.43% 1.41% 1.39% 1.37% 1.57% 1.54%
Winter Peak (MW) 3.24% 1.49% 1.46% 1.46% 1.43% 1.41% 1.39% 1.37% 1.57% 1.54%
- -------------------------------------------------------------------------------------------------------------------------------
Total
- -------------------------------------------------------------------------------------------------------------------------------
Demand (GWH) 2.18% 2.16% 2.12% 1.94% 1.91% 1.87% 1.84% 1.81% 1.80% 1.77%
Summer Peak (MW) 3.45% 2.18% 2.14% 1.96% 1.92% 1.89% 1.85% 1.82% 1.80% 1.77%
Winter Peak (MW) 0.82% 2.13% 2.09% 1.92% 1.89% 1.85% 1.82% 1.79% 1.79% 1.75%
- -------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- -------------------------------------------------------------------------------------------------------
2008 2009 2010 2011 2012 2013 2014 2015
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
SPP-SE
- -------------------------------------------------------------------------------------------------------
Demand (GWH) 1.85% 1.82% 1.78% 1.78% 1.75% 1.72% 1.69% 1.66%
Summer Peak (MW) 1.85% 1.82% 1.78% 1.78% 1.75% 1.72% 1.69% 1.66%
Winter Peak (MW) 1.85% 1.82% 1.78% 1.78% 1.75% 1.72% 1.69% 1.66%
- -------------------------------------------------------------------------------------------------------
Southern
- -------------------------------------------------------------------------------------------------------
Demand (GWH) 1.82% 1.79% 1.76% 1.62% 1.60% 1.58% 1.55% 1.53%
Summer Peak (MW) 1.82% 1.79% 1.76% 1.62% 1.60% 1.58% 1.55% 1.53%
Winter Peak (MW) 1.82% 1.79% 1.76% 1.62% 1.60% 1.58% 1.55% 1.53%
- -------------------------------------------------------------------------------------------------------
TVA
- -------------------------------------------------------------------------------------------------------
Demand (GWH) 1.52% 1.49% 1.47% 1.68% 1.65% 1.62% 1.60% 1.57%
Summer Peak (MW) 1.52% 1.49% 1.47% 1.68% 1.65% 1.62% 1.60% 1.57%
Winter Peak (MW) 1.52% 1.49% 1.47% 1.68% 1.65% 1.62% 1.60% 1.57%
- -------------------------------------------------------------------------------------------------------
Total
- -------------------------------------------------------------------------------------------------------
Demand (GWH) 1.74% 1.71% 1.68% 1.68% 1.66% 1.63% 1.61% 1.58%
Summer Peak (MW) 1.74% 1.71% 1.69% 1.68% 1.66% 1.63% 1.61% 1.58%
Winter Peak (MW) 1.73% 1.70% 1.67% 1.68% 1.66% 1.63% 1.60% 1.58%
- -------------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit II-5: Subregional Demand Forecasts - 1998-2015
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
SPP-SE
- ----------------------------------------------------------------------------------------------------------------------
Demand (GWH) 142,577 145,998 149,420 152,600 155,780 158,962 162,146 165,331 168,502 171,675
Summer Peak (MW) 27,156 27,808 28,460 29,066 29,671 30,277 30,884 31,491 32,094 32,699
Winter Peak (MW) 21,303 21,814 22,325 22,800 23,275 23,751 24,226 24,702 25,176 25,650
- ----------------------------------------------------------------------------------------------------------------------
Southern
- ----------------------------------------------------------------------------------------------------------------------
Demand (GWH) 197,010 201,985 206,965 211,489 216,019 220,555 225,097 229,646 233,961 238,283
Summer Peak (MW) 38,752 39,730 40,710 41,600 42,491 43,383 44,276 45,171 46,020 46,870
Winter Peak (MW) 32,596 33,419 34,243 34,991 35,741 36,491 37,243 37,995 38,709 39,424
- ----------------------------------------------------------------------------------------------------------------------
TVA
- ----------------------------------------------------------------------------------------------------------------------
Demand (GWH) 154,596 156,892 159,188 161,504 163,820 166,135 168,449 170,762 173,437 176,112
Summer Peak (MW) 27,610 28,020 28,430 28,844 29,257 29,671 30,084 30,497 30,975 31,452
Winter Peak (MW) 28,425 28,847 29,269 29,695 30,121 30,547 30,972 31,398 31,889 32,381
- ----------------------------------------------------------------------------------------------------------------------
Total
- ----------------------------------------------------------------------------------------------------------------------
Demand (GWH) 494,183 504,875 515,573 525,593 535,619 545,652 555,692 565,739 575,901 586,069
Summer Peak (MW) 93,518 95,558 97,600 99,509 101,419 103,331 105,244 107,159 109,089 111,021
Winter Peak (MW) 82,323 84,080 85,837 87,487 89,137 90,789 92,441 94,095 95,775 97,456
- ----------------------------------------------------------------------------------------------------------------------
<CAPTION>
- ------------------------------------------------------------------------------------------------
2008 2009 2010 2011 2012 2013 2014 2015
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
SPP-SE
- ------------------------------------------------------------------------------------------------
Demand (GWH) 174,848 178,024 181,201 184,424 187,648 190,874 194,101 197,330
Summer Peak (MW) 33,303 33,908 34,513 35,127 35,741 36,356 36,970 37,585
Winter Peak (MW) 26,124 26,599 27,073 27,555 28,037 28,519 29,001 29,483
- ------------------------------------------------------------------------------------------------
Southern
- ------------------------------------------------------------------------------------------------
Demand (GWH) 242,611 246,945 251,285 255,360 259,441 263,528 267,622 271,722
Summer Peak (MW) 47,721 48,574 49,427 50,229 51,032 51,836 52,641 53,447
Winter Peak (MW) 40,140 40,857 41,576 42,250 42,925 43,601 44,279 44,957
- ------------------------------------------------------------------------------------------------
TVA
- ------------------------------------------------------------------------------------------------
Demand (GWH) 178,785 181,458 184,129 187,219 190,309 193,397 196,484 199,570
Summer Peak (MW) 31,930 32,407 32,884 33,436 33,988 34,539 35,091 35,642
Winter Peak (MW) 32,873 33,364 33,855 34,423 34,992 35,559 36,127 36,694
- ------------------------------------------------------------------------------------------------
Total
- ------------------------------------------------------------------------------------------------
Demand (GWH) 596,244 606,426 616,615 627,003 637,398 647,799 658,208 668,623
Summer Peak (MW) 112,954 114,889 116,825 118,792 120,761 122,731 124,702 126,675
Winter Peak (MW) 99,137 100,820 102,504 104,228 105,953 107,679 109,406 111,135
- ------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit II-6: Utility vs. C.C. Pace Demand Forecast Comparison
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
1998 1999 2000 2001 2002 2003 2004 2005 2006
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
C.C. Pace
- ----------------------------------------------------------------------------------------------------------
SPP-SE
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 142,577 145,998 149,420 152,600 155,780 158,962 162,146 165,331 168,502
Summer Peak (MW) 27,156 27,808 28,460 29,066 29,671 30,277 30,884 31,491 32,094
Winter Peak (MW) 21,303 21,814 22,325 22,800 23,275 23,751 24,226 24,702 25,176
- ----------------------------------------------------------------------------------------------------------
Southern
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 197,010 201,985 206,965 211,489 216,019 220,555 225,097 229,646 233,961
Summer Peak (MW) 38,752 39,730 40,710 41,600 42,491 43,383 44,276 45,171 46,020
Winter Peak (MW) 32,596 33,419 34,243 34,991 35,741 36,491 37,243 37,995 38,709
- ----------------------------------------------------------------------------------------------------------
TVA
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 154,596 156,892 159,188 161,504 163,820 166,135 168,449 170,762 173,437
Summer Peak (MW) 27,610 28,020 28,430 28,844 29,257 29,671 30,084 30,497 30,975
Winter Peak (MW) 28,425 28,847 29,269 29,695 30,121 30,547 30,972 31,398 31,889
- ----------------------------------------------------------------------------------------------------------
Total
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 494,183 504,875 515,573 525,593 535,619 545,652 555,692 565,739 575,901
Summer Peak (MW) 93,518 95,558 97,600 99,509 101,419 103,331 105,244 107,159 109,089
Winter Peak (MW) 82,323 84,080 85,837 87,487 89,137 90,789 92,441 94,095 95,775
- ----------------------------------------------------------------------------------------------------------
Utilties
- ----------------------------------------------------------------------------------------------------------
SPP-SE
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 134,134 133,288 136,539 138,883 140,089 141,288 141,123 145,140 146,027
Summer Peak (MW) 25,965 26,142 26,660 27,058 27,364 27,697 28,027 28,506 28,801
Winter Peak (MW) 18,926 18,993 19,059 19,397 19,688 19,937 20,163 20,528 20,760
- ----------------------------------------------------------------------------------------------------------
Southern
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 199,723 202,392 206,024 209,365 212,116 215,918 220,280 224,769 229,510
Summer Peak (MW) 39,423 40,460 41,447 42,455 43,413 44,405 45,399 46,500 47,644
Winter Peak (MW) 33,939 34,792 35,658 36,473 37,333 38,181 39,153 40,164 40,050
- ----------------------------------------------------------------------------------------------------------
TVA
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 152,159 156,064 159,310 162,410 165,508 168,605 171,704 174,706 177,491
Summer Peak (MW) 27,479 28,107 28,656 29,170 29,689 30,205 30,722 31,244 31,752
Winter Peak (MW) 27,509 28,141 28,704 29,267 29,827 30,391 30,952 31,403 31,853
- ----------------------------------------------------------------------------------------------------------
Total
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 486,016 491,744 501,873 510,658 517,713 525,811 533,107 544,615 553,028
Summer Peak (MW) 92,867 94,709 96,763 98,683 100,466 102,307 104,148 106,250 108,197
Winter Peak (MW) 80,374 81,926 83,421 85,137 86,848 88,509 90,268 92,095 92,663
- ----------------------------------------------------------------------------------------------------------
Difference
- ----------------------------------------------------------------------------------------------------------
SPP-SE
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 8,443 12,710 12,881 13,717 15,691 17,674 21,023 20,191 22,475
Summer Peak (MW) 1,191 1,666 1,800 2,008 2,307 2,580 2,857 2,985 3,293
Winter Peak (MW) 2,377 2,821 3,266 3,403 3,587 3,814 4,063 4,174 4,416
- ----------------------------------------------------------------------------------------------------------
Southern
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) -2,713 -407 941 2,124 3,903 4,637 4,817 4,877 4,451
Summer Peak (MW) -671 -730 -737 -855 -922 -1,022 -1,123 -1,329 -1,624
Winter Peak (MW) -1,343 -1,373 -1,415 -1,482 -1,592 -1,690 -1,910 -2,169 -1,341
- ----------------------------------------------------------------------------------------------------------
TVA
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 2,437 828 -122 -906 -1,688 -2,470 -3,255 -3,944 -4,054
Summer Peak (MW) 131 -87 -226 -326 -432 -534 -638 -747 -777
Winter Peak (MW) 916 706 565 428 294 156 20 -5 36
- ----------------------------------------------------------------------------------------------------------
Total
- ----------------------------------------------------------------------------------------------------------
Demand (GWH) 8,167 13,131 13,700 14,935 17,906 19,841 22,585 21,124 22,873
Summer Peak (MW) 651 849 837 826 953 1,024 1,096 909 892
Winter Peak (MW) 1,949 2,154 2,416 2,350 2,289 2,280 2,173 2,000 3,112
- ----------------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
ATTACHMENT III
EXISTING AND PLANNED UNIT COST ASSUMPTIONS
& SUPPORTING ANALYSIS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit III-1: Southeast Steam Generation Embedded Cost Summary
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
Sub-Region Data 1993 1994 1995 1996
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Steam $ 1,637,316,069 1,648,821,207 1,647,898,095 1,879,507,980
Sum of Variable O&M Steam $ 56,110,855 56,535,684 55,556,413 55,344,461
Sum of Fixed O&M Steam $ 254,190,431 256,722,818 254,462,338 251,533,731
Sum of Fixed Steam $ 667,860,725 682,577,036 559,173,509 549,830,230
Total Variable 1,693,426,924 1,705,356,891 1,703,454,508 1,934,852,441
Total Fixed 922,051,156 939,299,854 813,635,847 801,363,961
Total Costs 2,615,478,080 2,644,656,745 2,517,090,355 2,736,216,402
Sum of Steam Gen 74,854,356 79,566,581 86,767,931 80,075,877
- --------------------------------------------------------------------------------------------------------------------
STHRN Sum of Fuel Steam $ 2,416,294,601 2,212,630,755 2,288,807,399 2,310,629,821
Sum of Variable O&M Steam $ 111,985,984 110,515,156 114,186,219 117,662,009
Sum of Fixed O&M Steam $ 458,834,554 453,429,046 454,963,906 472,869,666
Sum of Fixed Steam $ 1,250,865,832 1,205,769,544 1,215,996,463 1,260,083,627
Total Variable 2,528,280,585 2,323,145,911 2,402,993,618 2,428,291,830
Total Fixed 1,709,700,386 1,659,198,590 1,670,960,369 1,732,953,293
Total Costs 4,237,980,971 3,982,344,501 4,073,953,987 4,161,245,123
Sum of Steam Gen 128,184,763 124,617,317 132,954,616 139,204,824
- --------------------------------------------------------------------------------------------------------------------
TVA Sum of Fuel Steam $ 1,232,508,847 1,236,668,549 1,191,126,696 1,189,490,468
Sum of Variable O&M Steam $ 54,621,571 65,001,999 64,414,856 70,123,167
Sum of Fixed O&M Steam $ 218,486,282 260,007,995 257,659,422 280,492,666
Sum of Fixed Steam $ 833,867,192 904,156,825 958,283,427 939,224,042
Total Variable 1,287,130,418 1,301,670,548 1,255,541,552 1,259,613,635
Total Fixed 1,052,353,474 1,164,164,820 1,215,942,849 1,219,716,708
Total Costs 2,339,483,892 2,465,835,368 2,471,484,401 2,479,330,343
Sum of Steam Gen 97,201,013 92,082,543 94,384,049 97,045,750
- --------------------------------------------------------------------------------------------------------------------
Total Sum of Fuel Steam $ 5,286,119,517 5,098,120,511 5,127,832,190 5,379,628,269
Total Sum of Variable O&M Steam $ 222,718,410 232,052,839 234,157,488 243,129,637
Total Sum of Fixed O&M Steam $ 931,511,267 970,159,859 967,085,666 1,004,896,063
Total Sum of Fixed Steam $ 2,752,593,749 2,792,503,405 2,733,453,399 2,749,137,899
Total Variable 5,508,837,927 5,330,173,350 5,361,989,678 5,622,757,906
Total Fixed 3,684,105,016 3,762,663,264 3,700,539,065 3,754,033,962
Total Costs 9,192,942,943 9,092,836,614 9,062,528,743 9,376,791,868
Total Sum of Steam Gen 300,240,133 296,266,441 314,106,596 316,326,451
- --------------------------------------------------------------------------------------------------------------------
<CAPTION>
- ---------------------------------------------------------------------------------------------
Sub-Region Data 1993 1994 1995 1996
$/MWh $/MWh $/MWh $/MWh
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Steam $ 21.87 20.72 18.99 23.47
Sum of Variable O&M Steam $ 0.75 0.71 0.64 0.69
Sum of Fixed O&M Steam $ 3.40 3.23 2.93 3.14
Sum of Fixed Steam $ 8.92 8.58 6.44 6.87
Total Variable 22.62 21.43 19.63 24.16
Total Fixed 12.32 11.81 9.38 10.01
Total Costs 34.94 33.24 29.01 34.17
Sum of Steam Gen
- ---------------------------------------------------------------------------------------------
STHRN Sum of Fuel Steam $ 18.85 17.76 17.21 16.60
Sum of Variable O&M Steam $ 0.87 0.89 0.86 0.85
Sum of Fixed O&M Steam $ 3.58 3.64 3.42 3.40
Sum of Fixed Steam $ 9.76 9.68 9.15 9.05
Total Variable 19.72 18.64 18.07 17.44
Total Fixed 13.34 13.31 12.57 12.45
Total Costs 33.06 31.96 30.64 29.89
Sum of Steam Gen
- ---------------------------------------------------------------------------------------------
TVA Sum of Fuel Steam $ 12.68 13.43 12.62 12.26
Sum of Variable O&M Steam $ 0.56 0.71 0.68 0.72
Sum of Fixed O&M Steam $ 2.25 2.82 2.73 2.89
Sum of Fixed Steam $ 8.58 9.82 10.15 9.68
Total Variable 13.24 14.14 13.30 12.98
Total Fixed 10.83 12.64 12.88 12.57
Total Costs 24.07 26.78 26.19 25.55
Sum of Steam Gen
- ---------------------------------------------------------------------------------------------
Total Sum of Fuel Steam $ 17.61 17.21 16.33 17.01
Total Sum of Variable O&M Steam $ 0.74 0.78 0.75 0.77
Total Sum of Fixed O&M Steam $ 3.10 3.27 3.08 3.18
Total Sum of Fixed Steam $ 9.17 9.43 8.70 8.69
Total Variable 18.35 17.99 17.07 17.78
Total Fixed 12.27 12.70 11.78 11.87
Total Costs 30.62 30.69 28.85 29.64
Total Sum of Steam Gen
- ---------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit III-2: Southeast Nuclear Generation Embedded Cost Summary
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
Sub-Region Data 1993 1994 1995 1996
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Nuclear $ 228,666,362 216,429,419 211,995,630 210,991,949
Sum of Variable O&M Nuclear $ 97,496,291 91,696,568 81,799,172 88,012,443
Sum of Fixed O&M Nuclear $ 401,313,363 377,517,913 330,812,881 355,737,211
Sum of Fixed Nuclear $ 1,849,400,190 1,815,948,122 1,483,182,385 1,674,455,197
Total Variable 326,162,653 308,125,987 293,794,802 299,004,392
Total Fixed 2,250,713,553 2,193,466,035 1,813,995,266 2,030,192,408
Total Costs 2,576,876,206 2,501,592,022 2,107,790,068 2,329,196,800
Sum of Nuke Gen 34,996,064 35,329,549 34,566,276 37,422,994
- --------------------------------------------------------------------------------------------------------------------
STHRN Sum of Fuel Nuclear $ 224,754,066 249,740,179 236,918,156 232,594,371
Sum of Variable O&M Nuclear $ 95,719,685 87,083,707 88,626,819 92,542,965
Sum of Fixed O&M Nuclear $ 386,402,568 351,676,391 357,691,491 372,844,034
Sum of Fixed Nuclear $ 1,600,549,536 1,511,299,495 1,470,513,874 1,550,345,078
Total Variable 320,473,751 336,823,886 325,544,975 325,137,336
Total Fixed 1,986,952,104 1,862,975,886 1,828,205,365 1,923,189,112
Total Costs 2,307,425,855 2,199,799,772 2,153,750,340 2,248,326,448
Sum of Nuke Gen 40,096,590 43,068,450 42,310,669 43,716,533
- --------------------------------------------------------------------------------------------------------------------
TVA Sum of Fuel Nuclear $ 134,620,098 201,473,184 142,998,266 194,190,337
Sum of Variable O&M Nuclear $ 51,235,067 54,464,251 47,948,142 68,080,077
Sum of Fixed O&M Nuclear $ 204,940,269 217,857,003 191,792,568 272,320,309
Sum of Fixed Nuclear $ 999,959,494 914,200,075 877,064,027 1,340,142,006
Total Variable 185,855,165 255,937,435 190,946,408 262,270,414
Total Fixed 1,204,899,763 1,132,057,078 1,068,856,595 1,612,462,315
Total Costs 1,390,754,928 1,387,994,513 1,259,803,003 1,874,732,729
Sum of Nuke Gen 12,327,848 18,365,833 23,365,730 35,426,263
- --------------------------------------------------------------------------------------------------------------------
Total Sum of Fuel Nuclear $ 588,040,526 667,642,782 591,912,052 637,776,657
Total Sum of Variable O&M Nuclear $ 244,451,043 233,244,526 218,374,133 248,635,485
Total Sum of Fixed O&M Nuclear $ 992,656,200 947,051,307 880,296,940 1,000,901,554
Total Sum of Fixed Nuclear $ 4,449,909,220 4,241,447,692 3,830,760,286 4,564,942,281
Total Variable 832,491,569 900,887,308 810,286,185 886,412,142
Total Fixed 5,442,565,420 5,188,498,999 4,711,057,226 5,565,843,835
Total Costs 6,275,056,989 6,089,386,307 5,521,343,411 6,452,255,977
Total Sum of Nuke Gen 87,420,502 96,763,833 100,242,675 116,565,790
- --------------------------------------------------------------------------------------------------------------------
<CAPTION>
- --------------------------------------------------------------------------------------------
Sub-Region Data 1993 1994 1995 1996
$/MWh $/MWh $/MWh $/MWh
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Nuclear $ 6.53 6.13 6.13 5.64
Sum of Variable O&M Nuclear $ 2.79 2.60 2.37 2.35
Sum of Fixed O&M Nuclear $ 11.47 10.69 9.57 9.51
Sum of Fixed Nuclear $ 52.85 51.40 42.91 44.74
Total Variable 9.32 8.72 8.50 7.99
Total Fixed 64.31 62.09 52.48 54.25
Total Costs 73.63 70.81 60.98 62.24
Sum of Nuke Gen
- --------------------------------------------------------------------------------------------
STHRN Sum of Fuel Nuclear $ 5.61 5.80 5.60 5.32
Sum of Variable O&M Nuclear $ 2.39 2.02 2.09 2.12
Sum of Fixed O&M Nuclear $ 9.64 8.17 8.45 8.53
Sum of Fixed Nuclear $ 39.92 35.09 34.76 35.46
Total Variable 7.99 7.82 7.69 7.44
Total Fixed 49.55 43.26 43.21 43.99
Total Costs 57.55 51.08 50.90 51.43
Sum of Nuke Gen
- --------------------------------------------------------------------------------------------
TVA Sum of Fuel Nuclear $ 10.92 10.97 6.12 5.48
Sum of Variable O&M Nuclear $ 4.16 2.97 2.05 1.92
Sum of Fixed O&M Nuclear $ 16.62 11.86 8.21 7.69
Sum of Fixed Nuclear $ 81.11 49.78 37.54 37.83
Total Variable 15.08 13.94 8.17 7.40
Total Fixed 97.74 61.64 45.74 45.52
Total Costs 112.81 75.57 53.92 52.92
Sum of Nuke Gen
- --------------------------------------------------------------------------------------------
Total Sum of Fuel Nuclear $ 6.73 6.90 5.90 5.47
Total Sum of Variable O&M Nuclear $ 2.80 2.41 2.18 2.13
Total Sum of Fixed O&M Nuclear $ 11.35 9.79 8.78 8.59
Total Sum of Fixed Nuclear $ 50.90 43.83 38.21 39.16
Total Variable 9.52 9.31 8.08 7.60
Total Fixed 62.26 53.62 47.00 47.75
Total Costs 71.78 62.93 55.08 55.35
Total Sum of Nuke Gen
- --------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit III-3: Southeast Hydro Generation Embedded Cost Summary
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
Subregion Data 1993 1994 1995 1996
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Hydro $ 843,183 1,030,216 955,941 952,033
Sum of Variable O&M Hydro $ 973,498 1,036,972 907,702 1,238,416
Sum of Fixed O&M Hydro $ 7,204,249 7,282,389 6,793,227 8,293,296
Sum of Fixed Hydro $ 105,891,391 127,984,741 131,648,919 134,631,576
Total Variable 1,816,681 2,067,188 1,863,643 2,190,449
Total Fixed 113,095,640 135,267,130 138,442,146 142,924,872
Total Costs 114,912,321 137,334,318 140,305,789 145,115,321
Sum of Hydro Gen 1,728,722 1,507,454 1,295,965 1,385,968
- -----------------------------------------------------------------------------------------------------------------
STHRN Sum of Fuel Hydro $ 719,237 936,811 1,494,060 2,221,409
Sum of Variable O&M Hydro $ 5,357,022 5,413,183 7,771,422 7,094,931
Sum of Fixed O&M Hydro $ 21,802,102 22,134,079 31,790,875 289,644,461
Sum of Fixed Hydro $ 171,458,668 169,872,115 226,730,715 279,543,857
Total Variable 6,076,259 6,349,994 9,265,482 9,316,340
Total Fixed 193,260,770 192,006,194 258,521,590 308,488,318
Total Costs 199,337,029 198,356,188 267,787,072 317,804,658
Sum of Hydro Gen 15,643,863 15,673,151 14,539,342 16,235,920
- -----------------------------------------------------------------------------------------------------------------
TVA Sum of Fuel Hydro $ 41,672 29,494 76,221 21,951
Sum of Variable O&M Hydro $ 12,012,020 13,206,991 9,172,183 8,948,955
Sum of Fixed O&M Hydro $ 48,048,080 52,827,963 36,688,732 35,795,819
Sum of Fixed Hydro $ 185,063,894 189,175,638 179,631,657 164,262,687
Total Variable 12,053,692 13,236,485 9,248,404 8,970,906
Total Fixed 233,111,974 242,003,601 216,320,389 200,058,506
Total Costs 245,165,666 255,240,086 225,568,793 209,029,412
Sum of Hydro Gen 22,059,186 24,961,393 17,819,970 20,785,284
- -----------------------------------------------------------------------------------------------------------------
Total Sum of Fuel Hydro $ 1,604,092 1,996,521 2,526,222 3,195,393
Total Sum of Variable O&M Hydro $ 18,342,540 19,657,146 17,851,307 17,282,302
Total Sum of Fixed O&M Hydro $ 77,054,431 82,244,431 75,272,834 333,733,576
Total Sum of Fixed Hydro $ 462,413,953 487,032,494 538,011,291 578,438,120
Total Variable 19,946,632 21,653,667 20,377,529 20,477,695
Total Fixed 539,468,384 569,276,925 613,284,125 651,471,696
Total Costs 559,415,016 590,930,592 633,661,654 671,949,391
Total Sum of Hydro Gen 39,431,771 42,141,998 33,655,277 38,407,172
- -----------------------------------------------------------------------------------------------------------------
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Subregion Data 1993 1994 1995 1996
$/MWh $/MWh $/MWh $/MWh
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Hydro $ 0.49 0.68 0.74 0.69
Sum of Variable O&M Hydro $ 0.56 0.69 0.70 0.89
Sum of Fixed O&M Hydro $ 4.17 4.83 5.24 5.98
Sum of Fixed Hydro $ 61.25 84.90 101.58 97.14
Total Variable 1.05 1.37 1.44 1.58
Total Fixed 65.42 89.73 106.83 103.12
Total Costs 66.47 91.10 108.26 104.70
Sum of Hydro Gen
- ----------------------------------------------------------------------------------------------------
STHRN Sum of Fuel Hydro $ 0.05 0.06 0.10 0.14
Sum of Variable O&M Hydro $ 0.34 0.35 0.53 0.44
Sum of Fixed O&M Hydro $ 1.39 1.41 2.19 17.84
Sum of Fixed Hydro $ 10.96 10.84 15.59 17.22
Total Variable 0.39 0.41 0.64 0.57
Total Fixed 12.35 12.25 17.78 19.00
Total Costs 12.74 12.66 18.42 19.57
Sum of Hydro Gen
- ----------------------------------------------------------------------------------------------------
TVA Sum of Fuel Hydro $ 0.00 0.00 0.00 0.00
Sum of Variable O&M Hydro $ 0.54 0.53 0.51 0.43
Sum of Fixed O&M Hydro $ 2.18 2.12 2.06 1.72
Sum of Fixed Hydro $ 8.39 7.58 10.08 7.90
Total Variable 0.55 0.53 0.52 0.43
Total Fixed 10.57 9.70 12.14 9.63
Total Costs 11.11 10.23 12.66 10.06
Sum of Hydro Gen
- ----------------------------------------------------------------------------------------------------
Total Sum of Fuel Hydro $ 0.04 0.05 0.08 0.08
Total Sum of Variable O&M Hydro $ 0.47 0.47 0.53 0.45
Total Sum of Fixed O&M Hydro $ 1.95 1.95 2.24 8.69
Total Sum of Fixed Hydro $ 11.73 11.56 15.99 15.06
Total Variable 0.51 0.51 0.61 0.53
Total Fixed 13.68 13.51 18.22 16.96
Total Costs 14.19 14.02 18.83 17.50
Total Sum of Hydro Gen
- ----------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit III-4: Southeast Other Generation Embedded Cost Summary
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Sub-Region Data 1993 1994 1995 1996
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Oth Prod $ 706,773 1,778,521 1,194,688 1,322,491
Sum of Variable O&M Oth Prod $ 208,314 190,282 303,888 295,925
Sum of Fixed O&M Oth Prod $ 2,140,065 2,068,002 2,522,751 2,490,503
Sum of Tot Fixed Oth Prod $ 4,869,173 4,364,191 3,510,232 3,430,878
Total Variable 915,087 1,968,803 1,498,576 1,618,416
Total Fixed 7,009,238 6,432,193 6,032,983 5,921,381
Total Costs 7,924,325 8,400,996 7,531,559 7,539,797
Sum of Other Gen 13,196 10,967 13,811 15,433
- -------------------------------------------------------------------------------------------------------------------
STHRN Sum of Fuel Oth Prod $ 9,119,315 6,203,219 26,269,325 37,121,491
Sum of Variable O&M Oth Prod $ 2,773,369 2,476,832 3,331,386 4,054,290
Sum of Fixed O&M Oth Prod $ 11,881,664 10,747,245 14,412,432 17,952,603
Sum of Tot Fixed Oth Prod $ 14,072,126 33,870,025 67,243,904 95,630,028
Total Variable 11,892,684 8,680,051 29,600,711 41,175,781
Total Fixed 25,953,790 44,617,270 81,656,336 113,582,631
Total Costs 37,846,474 53,297,321 111,257,047 154,758,412
Sum of Other Gen 669,155 998,688 1,141,764 1,759,487
- -------------------------------------------------------------------------------------------------------------------
TVA Sum of Fuel Oth Prod $ 16,071,564 12,219,294 14,205,537 10,921,640
Sum of Variable O&M Oth Prod $ 657,439 788,588 923,354 922,704
Sum of Fixed O&M Oth Prod $ 2,629,757 3,154,354 3,693,416 3,690,815
Sum of Tot Fixed Oth Prod $ 49,251,345 56,295,061 57,222,758 55,319,992
Total Variable 16,729,003 13,007,882 15,128,891 11,844,344
Total Fixed 51,881,102 59,449,415 60,916,174 59,010,807
Total Costs 68,610,105 72,457,297 76,045,065 70,855,151
Sum of Other Gen 316,931 239,032 393,396 217,207
- -------------------------------------------------------------------------------------------------------------------
Total Sum of Fuel Oth Prod $ 25,897,652 20,201,034 41,669,550 49,365,622
Total Sum of Variable O&M Oth Prod $ 3,639,122 3,455,702 4,558,628 5,272,919
Total Sum of Fixed O&M Oth Prod $ 16,651,486 15,969,601 20,628,599 24,133,921
Total Sum of Tot Fixed Oth Prod $ 68,192,643 94,529,278 127,976,894 154,380,898
Total Variable 29,536,774 23,656,736 46,228,178 54,638,541
Total Fixed 84,844,129 110,498,879 148,605,493 178,514,819
Total Costs 114,380,903 134,155,615 194,833,671 233,153,360
Total Sum of Other Gen 999,282 1,248,687 1,548,971 1,992,127
- -------------------------------------------------------------------------------------------------------------------
<CAPTION>
- -----------------------------------------------------------------------------------------------------
Sub-Region Data 1993 1994 1995 1996
$/MWh $/MWh $/MWh $/MWh
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Oth Prod $ 53.56 162.17 86.50 85.69
Sum of Variable O&M Oth Prod $ 15.79 17.35 22.00 19.17
Sum of Fixed O&M Oth Prod $ 162.17 188.57 182.67 161.38
Sum of Tot Fixed Oth Prod $ 368.98 397.94 254.17 222.31
Total Variable 69.34 179.52 108.51 104.87
Total Fixed 531.15 586.50 436.83 383.68
Total Costs 600.50 766.02 545.34 488.55
Sum of Other Gen
- -----------------------------------------------------------------------------------------------------
STHRN Sum of Fuel Oth Prod $ 13.63 6.21 23.01 21.10
Sum of Variable O&M Oth Prod $ 4.14 2.48 2.92 2.30
Sum of Fixed O&M Oth Prod $ 17.76 10.76 12.62 10.20
Sum of Tot Fixed Oth Prod $ 21.03 33.91 58.89 54.35
Total Variable 17.77 8.69 25.93 23.40
Total Fixed 38.79 44.68 71.52 64.55
Total Costs 56.56 53.37 97.44 87.96
Sum of Other Gen
- -----------------------------------------------------------------------------------------------------
TVA Sum of Fuel Oth Prod $ 50.71 51.12 36.11 50.28
Sum of Variable O&M Oth Prod $ 2.07 3.30 2.35 4.25
Sum of Fixed O&M Oth Prod $ 8.30 13.20 9.39 16.99
Sum of Tot Fixed Oth Prod $ 155.40 235.51 145.46 254.69
Total Variable 52.78 54.42 38.46 54.53
Total Fixed 163.70 248.71 154.85 271.68
Total Costs 216.48 303.13 193.30 326.21
Sum of Other Gen
- -----------------------------------------------------------------------------------------------------
Total Sum of Fuel Oth Prod $ 25.92 16.18 26.90 24.78
Total Sum of Variable O&M Oth Prod $ 3.64 2.77 2.94 2.65
Total Sum of Fixed O&M Oth Prod $ 16.66 12.79 13.32 12.11
Total Sum of Tot Fixed Oth Prod $ 68.24 75.70 82.62 77.50
Total Variable 29.56 18.95 29.84 27.43
Total Fixed 84.91 88.49 95.94 89.61
Total Costs 114.46 107.44 125.78 117.04
Total Sum of Other Gen
- -----------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit III-5: Southeast Total Generation Embedded Cost Summary
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Sub-Region Data 1993 1994 1995 1996
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Total $ 1,867,532,387 1,868,059,363 1,862,044,354 2,092,774,453
Sum of Variable O&M Total $ 154,788,958 149,459,506 138,567,175 144,891,245
Sum of Fixed O&M Total $ 664,848,108 643,591,122 594,591,197 618,054,741
Sum of Fixed Total $ 2,628,021,478 2,630,874,090 2,177,515,045 2,362,347,881
Total Variable 2,022,321,345 2,017,518,869 2,000,611,529 2,237,665,698
Total Fixed 3,292,869,586 3,274,465,212 2,772,106,242 2,980,402,622
Total Costs 5,315,190,931 5,291,984,081 4,772,717,771 5,218,068,320
Sum of Total Gen 111,592,339 116,414,552 122,643,983 118,900,272
- -------------------------------------------------------------------------------------------------------------------
STHRN Sum of Fuel Total $ 2,650,887,219 2,469,510,964 2,553,488,940 2,582,567,092
Sum of Variable O&M Total $ 215,836,060 205,488,878 213,915,846 221,354,195
Sum of Fixed O&M Total $ 878,920,888 837,986,761 858,858,704 1,153,310,764
Sum of Fixed Total $ 3,036,946,162 2,920,811,179 2,980,484,957 3,185,602,590
Total Variable 2,866,723,279 2,674,999,842 2,767,404,786 2,803,921,287
Total Fixed 3,915,867,050 3,758,797,940 3,839,343,661 4,078,213,354
Total Costs 6,782,590,329 6,433,797,782 6,606,748,447 6,882,134,641
Sum of Total Gen 184,594,371 184,357,607 190,946,391 200,916,764
- -------------------------------------------------------------------------------------------------------------------
TVA Sum of Fuel Total $ 1,383,242,181 1,450,390,521 1,348,406,720 1,394,624,396
Sum of Variable O&M Total $ 118,526,097 133,461,829 122,458,535 148,074,903
Sum of Fixed O&M Total $ 474,104,388 533,847,315 489,834,138 592,299,609
Sum of Fixed Total $ 2,068,141,925 2,063,827,599 2,072,201,869 2,498,948,727
Total Variable 1,501,768,278 1,583,852,350 1,470,865,255 1,542,699,299
Total Fixed 2,542,246,313 2,597,674,914 2,562,036,007 3,091,248,336
Total Costs 4,044,014,591 4,181,527,264 4,032,901,262 4,633,947,635
Sum of Total Gen 131,904,978 135,648,800 135,963,145 153,474,504
- -------------------------------------------------------------------------------------------------------------------
Total Sum of Fuel Total $ 5,901,661,787 5,787,960,848 5,763,940,014 6,069,965,941
Total Sum of Variable O&M Total $ 489,151,115 488,410,213 474,941,556 514,320,343
Total Sum of Fixed O&M Total $ 2,017,873,384 2,015,425,198 1,943,284,039 2,363,665,114
Total Sum of Fixed Total $ 7,733,109,565 7,615,512,868 7,230,201,871 8,046,899,198
Total Variable 6,390,812,902 6,276,371,061 6,238,881,570 6,584,286,284
Total Fixed 9,750,982,949 9,630,938,066 9,173,485,910 10,149,864,312
Total Costs 16,141,795,851 15,907,309,127 15,412,367,480 16,734,150,596
Total Sum of Total Gen 428,091,688 436,420,958 449,553,519 473,291,540
- -------------------------------------------------------------------------------------------------------------------
<CAPTION>
- ---------------------------------------------------------------------------------------
Sub-Region Data 1993 1994 1995 1996
$/MWh $/MWh $/MWh $/MWh
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SE Sum of Fuel Total $ 16.74 16.05 15.18 17.60
Sum of Variable O&M Total $ 1.39 1.28 1.13 1.22
Sum of Fixed O&M Total $ 5.96 5.53 4.85 5.20
Sum of Fixed Total $ 23.55 22.60 17.75 19.87
Total Variable 18.12 17.33 16.31 18.82
Total Fixed 29.51 28.13 22.60 25.07
Total Costs 47.63 45.46 38.92 43.89
Sum of Total Gen
- ---------------------------------------------------------------------------------------
STHRN Sum of Fuel Total $ 14.36 13.40 13.37 12.85
Sum of Variable O&M Total $ 1.17 1.11 1.12 1.10
Sum of Fixed O&M Total $ 4.76 4.55 4.50 5.74
Sum of Fixed Total $ 16.45 15.84 15.61 15.86
Total Variable 15.53 14.51 14.49 13.96
Total Fixed 21.21 20.39 20.11 20.30
Total Costs 36.74 34.90 34.60 34.25
Sum of Total Gen
- ---------------------------------------------------------------------------------------
TVA Sum of Fuel Total $ 10.49 10.69 9.92 9.09
Sum of Variable O&M Total $ 0.90 0.98 0.90 0.96
Sum of Fixed O&M Total $ 3.59 3.94 3.60 3.86
Sum of Fixed Total $ 15.68 15.21 15.24 16.28
Total Variable 11.39 11.68 10.82 10.05
Total Fixed 19.27 19.15 18.84 20.14
Total Costs 30.66 30.83 29.66 30.19
Sum of Total Gen
- ---------------------------------------------------------------------------------------
Total Sum of Fuel Total $ 13.79 13.26 12.82 12.83
Total Sum of Variable O&M Total $ 1.14 1.12 1.06 1.09
Total Sum of Fixed O&M Total $ 4.71 4.62 4.32 4.99
Total Sum of Fixed Total $ 18.06 17.45 16.08 17.00
Total Variable 14.93 14.38 13.88 13.91
Total Fixed 22.78 22.07 20.41 21.45
Total Costs 37.71 36.45 34.28 35.36
Total Sum of Total Gen
- ---------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit III-6: Expansion Unit Characteristics - SE
- ----------------------------------------------------------------------
Item Unit CT CC Coal
- ----------------------------------------------------------------------
Assumptions
Capacity MW 230 360 500
Cost $/kW 300 500 1,100
Capacity Factor* % 15% 85% 85%
Annual Maintenance Weeks 2 3 4
Forced Outage % 2.5% 2.5% 5.0%
Fuel Cost $/MMBtu 2.24 2.24 1.37
Fixed O&M $/kW-yr 4.00 12.00 29.00
Variable O&M $/MWh 3.50 0.75 1.50
Heat Rate Btu/kWh 9,700 6,600 9,600
Percent Equity % 30% 30% 30%
Discount Rate % 8.5% 8.5% 8.5%
Return on Equity % 14% 14% 14%
Project Life Years 20 20 20
Installed Cost ($000) 69,000 180,000 550,000
Fixed O&M ($000) 920 4,320 14,500
Amount of Equity ($000) 20,700 54,000 165,000
Amount of Debt ($000) 48,300 126,000 385,000
- ----------------------------------------------------------------------
Annual Fixed Costs
Total Debt ($000) 5,104 13,315 40,683
Interest ($000) 4,106 10,710 32,725
Principal ($000) 998 2,605 7,958
ROI ($000) 2,898 7,560 23,100
Fixed O&M ($000) 920 4,320 14,500
Taxes ($000) 1,265 3,218 12,375
Total Fixed ($000) 10,187 28,413 90,658
- ----------------------------------------------------------------------
Cost Summary
Variable Costs $/MWh 25.23 15.53 14.65
Fixed Costs $/MWh 33.71 10.60 24.35
Total Costs $/MWh 58.93 26.13 39.00
- ----------------------------------------------------------------------
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit III-7: Expansion Unit Characteristics - Southern
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
Item Unit CT CC Coal USGen CT Mid-GA CC
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Assumptions
Capacity MW 230 360 500 215 300
Cost $/kW 300 500 1,100 238 415
Capacity Factor* % 15.0% 85.0% 85.0% 15.0% 85.0%
Annual Maintenance Weeks 2 3 4 2 3
Forced Outage % 2.5% 2.5% 5.0% 2.5% 2.5%
Fuel Cost $/MMBtu 2.38 2.38 1.44 2.38 2.38
Fixed O&M $/kW-yr 4 12 29 8 12
Variable O&M $/MWh 3.50 0.75 2.50 3.50 3.50
Heat Rate Btu/kWh 9,700 6,600 9,600 9,700 7,500
Percent Equity % 30.0% 30.0% 30.0% 30.0% 30.0%
Discount Rate % 8.5% 8.5% 8.5% 8.5% 8.5%
Return on Equity % 14.0% 14.0% 14.0% 14.0% 15.0%
Project Life Years 20 20 20 20 20
Installed Cost ($000) 69,000 180,000 550,000 51,170 124,500
Fixed O&M ($000) 920 4,320 14,500 1,720 3,600
Amount of Equity ($000) 20,700 54,000 165,000 15,351 37,350
Amount of Debt ($000) 48,300 126,000 385,000 35,819 87,150
- -----------------------------------------------------------------------------------------------
Annual Fixed Costs
Total Debt ($000) 5,104 13,315 40,683 3,785 9,209
Interest ($000) 4,106 10,710 32,725 3,045 7,408
Principal ($000) 998 2,605 7,958 740 1,801
ROI ($000) 2,898 7,560 23,100 2,149 5,603
Fixed O&M ($000) 920 4,320 14,500 1,720 3,600
Taxes ($000) 1,265 3,218 12,375 1,184 2,681
Total Fixed ($000) 10,187 28,413 90,658 8,838 21,093
- -----------------------------------------------------------------------------------------------
Cost Summary
Variable Costs $/MWh 26.59 16.46 16.32 26.59 21.35
Fixed Costs $/MWh 33.71 10.60 24.35 31.28 9.44
Total Costs $/MWh 60.29 27.06 40.67 57.87 30.79
- -----------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit III-8: Expansion Unit Characteristics-TVA
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
Item Unit CT CC Coal Red Hills
- ----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Assumptions
Capacity MW 230 360 500 440
Cost $/kW 300 500 1,100 1,050
Capacity Factor* % 15.0% 85.0% 85.0% 85.0%
Annual Maintenance Weeks 2 3 4 4
Forced Outage % 2.5% 2.5% 5.0% 5.0%
Fuel Cost $/MMBtu 2.34 2.34 1.30 1.00
Fixed O&M $/kW-yr 4.00 12.00 29.00 29.00
Variable O&M $/MWh 3.50 0.75 1.50 1.50
Heat Rate Btu/kWh 9,700 6,600 9,600 9,600
Percent Equity % 30.0% 30.0% 30.0% 30.0%
Discount Rate % 8.5% 8.5% 8.5% 8.5%
Return on Equity % 14.0% 14.0% 14.0% 14.0%
Project Life Years 20 20 20 20
Installed Cost ($000) 69,000 180,000 550,000 462,000
Fixed O&M ($000) 920 4,320 14,500 12,760
Amount of Equity ($000) 20,700 54,000 165,000 138,600
Amount of Debt ($000) 48,300 126,000 385,000 323,400
- ----------------------------------------------------------------------------------
Annual Fixed Costs
Total Debt ($000) 5,104 13,315 40,683 34,174
Interest ($000) 4,106 10,710 32,725 27,489
Principal ($000) 998 2,605 7,958 6,685
ROI ($000) 2,898 7,560 23,100 19,404
Fixed O&M ($000) 920 4,320 14,500 12,760
Taxes ($000) 1,265 3,218 12,375 10,890
Total Fixed ($000) 10,187 28,413 90,658 77,228
- ----------------------------------------------------------------------------------
Cost Summary
Variable Costs $/MWh 26.20 16.19 13.98 11.10
Fixed Costs $/MWh 33.71 10.60 24.35 23.57
Total Costs $/MWh 59.90 26.79 38.33 34.67
- ----------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
CC Pace
- --------------------------------------------------------------------------------
ATTACHMENT IV
FULE PRICING ASSUMPTIONS & SUPPORTING ANALYSIS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit IV-1: Southeast Coal Percent of Volumes Purchased "Over-Market" Costs
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------
Barry Crist Gadsden Gaston Gorgas Greene County Miller White Bluff
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1996 60% 100% 85% 85% 50% 30% 58% 85%
1997 60% 100% 85% 85% 50% 30% 58% 85%
1998 60% 100% 85% 85% 50% 30% 58% 85%
1999 45% 100% 64% 64% 38% 23% 44% 64%
2000 45% 100% 64% 64% 38% 23% 44% 64%
2001 45% 100% 64% 64% 38% 23% 44% 64%
2002 23% 100% 32% 32% 19% 11% 22% 32%
2003 23% 100% 32% 32% 19% 11% 22% 32%
2004 23% 50% 32% 32% 19% 11% 22% 32%
2005 0% 50% 0% 0% 0% 0% 0% 0%
2006 0% 50% 0% 0% 0% 0% 0% 0%
2007 0% 0% 0% 0% 0% 0% 0% 0%
2008 0% 0% 0% 0% 0% 0% 0% 0%
2009 0% 0% 0% 0% 0% 0% 0% 0%
2010 0% 0% 0% 0% 0% 0% 0% 0%
2011 0% 0% 0% 0% 0% 0% 0% 0%
2012 0% 0% 0% 0% 0% 0% 0% 0%
2013 0% 0% 0% 0% 0% 0% 0% 0%
2014 0% 0% 0% 0% 0% 0% 0% 0%
2015 0% 0% 0% 0% 0% 0% 0% 0%
- ------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------
Bowen Harlee Branch Scherer Smith Wansley Flint Creek Welsh Morrow Allen (TN)
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 10% 23% 21% 52% 65% 65% 65% 100% 0%
1997 10% 23% 21% 52% 65% 65% 65% 100% 0%
1998 10% 23% 21% 52% 65% 65% 65% 100% 0%
1999 8% 17% 16% 100% 49% 49% 49% 75% 0%
2000 8% 17% 16% 100% 49% 49% 49% 75% 0%
2001 8% 17% 16% 100% 49% 49% 49% 75% 0%
2002 4% 8% 8% 100% 24% 24% 24% 38% 0%
2003 4% 8% 8% 100% 24% 24% 24% 38% 0%
2004 4% 8% 8% 50% 24% 24% 24% 38% 0%
2005 0% 0% 0% 50% 0% 0% 0% 0% 0%
2006 0% 0% 0% 50% 0% 0% 0% 0% 0%
2007 0% 0% 0% 0% 0% 0% 0% 0% 0%
2008 0% 0% 0% 0% 0% 0% 0% 0% 0%
2009 0% 0% 0% 0% 0% 0% 0% 0% 0%
2010 0% 0% 0% 0% 0% 0% 0% 0% 0%
2011 0% 0% 0% 0% 0% 0% 0% 0% 0%
2012 0% 0% 0% 0% 0% 0% 0% 0% 0%
2013 0% 0% 0% 0% 0% 0% 0% 0% 0%
2014 0% 0% 0% 0% 0% 0% 0% 0% 0%
2015 0% 0% 0% 0% 0% 0% 0% 0% 0%
- -----------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- -------------------------------------------------------------------------------------------------
Bull Run Colbert Gallatin Johnsonville Shawnee Widows Creek
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1996 19% 25% 26% 23% 40% 17%
1997 19% 25% 26% 23% 40% 17%
1998 19% 25% 26% 23% 40% 17%
1999 15% 19% 19% 18% 30% 12%
2000 15% 19% 19% 18% 30% 12%
2001 15% 19% 19% 18% 30% 12%
2002 7% 9% 10% 9% 15% 6%
2003 7% 9% 10% 9% 15% 6%
2004 7% 9% 10% 9% 15% 6%
2005 0% 0% 0% 0% 0% 0%
2006 0% 0% 0% 0% 0% 0%
2007 0% 0% 0% 0% 0% 0%
2008 0% 0% 0% 0% 0% 0%
2009 0% 0% 0% 0% 0% 0%
2010 0% 0% 0% 0% 0% 0%
2011 0% 0% 0% 0% 0% 0%
2012 0% 0% 0% 0% 0% 0%
2013 0% 0% 0% 0% 0% 0%
2014 0% 0% 0% 0% 0% 0%
2015 0% 0% 0% 0% 0% 0%
- -------------------------------------------------------------------------------------------------
</TABLE>
Exhibit IV-2: Southeast Coal "Over-Market" Cost Forecast
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
Barry Crist Gadsden Gaston Gorgas Greene County Miller White Bluff
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1996 204 216 191 212 180 153 190 186
1997 204 216 191 212 180 153 190 186
1998 204 216 191 212 180 153 190 186
1999 204 216 191 212 180 153 190 186
2000 204 216 191 212 180 153 190 186
2001 204 216 191 212 180 153 190 186
2002 204 216 191 212 180 153 190 186
2003 204 216 191 212 180 153 190 186
2004 204 216 191 212 180 153 190 186
2005 204 216 191 212 180 153 190 186
2006 204 216 191 212 180 153 190 186
2007 204 216 191 212 180 153 190 186
2008 204 216 191 212 180 153 190 186
2009 204 216 191 212 180 153 190 186
2010 204 216 191 212 180 153 190 186
2011 204 216 191 212 180 153 190 186
2012 204 216 191 212 180 153 190 186
2013 204 216 191 212 180 153 190 186
2014 204 216 191 212 180 153 190 186
2015 204 216 191 212 180 153 190 186
- -------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------
Bowen Harlee Branch Scherer Smith Wansley Flint Creek Welsh Morrow Allen (TN)
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 171 175 230 202 208 162 200 -- 132
1997 171 175 230 202 208 162 200 -- 132
1998 171 175 230 202 208 162 200 -- 132
1999 171 175 230 202 208 162 200 -- 132
2000 171 175 230 202 208 162 200 -- 132
2001 171 175 230 202 208 162 200 -- 132
2002 171 175 230 202 208 162 200 -- 132
2003 171 175 230 202 208 162 200 -- 132
2004 171 175 230 202 208 162 200 -- 132
2005 171 175 230 202 208 162 200 -- 132
2006 171 175 230 202 208 162 200 -- 132
2007 171 175 230 202 208 162 200 -- 132
2008 171 175 230 202 208 162 200 -- 132
2009 171 175 230 202 208 162 200 -- 132
2010 171 175 230 202 208 162 200 -- 132
2011 171 175 230 202 208 162 200 -- 132
2012 171 175 230 202 208 162 200 -- 132
2013 171 175 230 202 208 162 200 -- 132
2014 171 175 230 202 208 162 200 -- 132
2015 171 175 230 202 208 162 200 -- 132
- ------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- -------------------------------------------------------------------------------------------------
Bull Run Colbert Gallatin Johnsonville Shawnee Widows Creek
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1996 115 126 126 123 137 134
1997 115 126 126 123 137 134
1998 115 126 126 123 137 134
1999 115 126 126 123 137 134
2000 115 126 126 123 137 134
2001 115 126 126 123 137 134
2002 115 126 126 123 137 134
2003 115 126 126 123 137 134
2004 115 126 126 123 137 134
2005 115 126 126 123 137 134
2006 115 126 126 123 137 134
2007 115 126 126 123 137 134
2008 115 126 126 123 137 134
2009 115 126 126 123 137 134
2010 115 126 126 123 137 134
2011 115 126 126 123 137 134
2012 115 126 126 123 137 134
2013 115 126 126 123 137 134
2014 115 126 126 123 137 134
2015 115 126 126 123 137 134
- -------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit IV-3: Southeast Coal Market Cost Forecast
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
Barry Crist Gadsden Gaston Gorgas Greene County Miller White Bluff
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1996 134 141 130 142 142 122 134 158
1997 133 140 129 141 141 121 133 156
1998 131 138 128 139 139 120 131 155
1999 130 137 126 138 138 118 130 153
2000 129 135 125 136 136 117 129 152
2001 127 134 124 135 135 116 127 150
2002 126 133 123 134 134 115 126 149
2003 125 131 121 132 132 114 125 147
2004 124 130 120 131 131 113 124 146
2005 122 129 119 130 130 111 122 144
2006 121 128 118 128 128 110 121 143
2007 120 126 117 127 127 109 120 141
2008 119 125 115 126 126 108 119 140
2009 118 124 114 125 125 107 118 139
2010 116 122 113 123 123 106 116 137
2011 115 121 112 122 122 105 115 136
2012 114 120 111 121 121 104 114 135
2013 113 119 110 120 120 103 113 133
2014 112 118 109 119 119 102 112 132
2015 111 116 108 117 117 101 111 131
- -------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------------
Bowen Harlee Branch Scherer Smith Wansley Flint Creek Welsh Morrow Allen (TN)
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 136 149 159 141 145 108 135 134 110
1997 135 148 157 140 144 107 134 133 110
1998 134 146 156 138 142 106 132 131 110
1999 132 145 154 137 141 105 131 130 110
2000 131 143 153 135 139 104 130 129 110
2001 130 142 151 134 138 103 128 127 110
2002 128 140 149 133 137 102 127 126 110
2003 127 139 148 131 135 101 126 125 110
2004 126 137 147 130 134 100 125 124 110
2005 125 136 145 129 132 99 123 122 110
2006 123 135 144 128 131 98 122 121 110
2007 122 133 142 126 130 97 121 120 110
2008 121 132 141 125 129 96 120 119 110
2009 120 131 139 124 127 95 118 118 110
2010 119 129 138 122 126 94 117 116 110
2011 117 128 137 121 125 93 116 115 110
2012 116 127 135 120 123 92 115 114 110
2013 115 126 134 119 122 91 114 113 110
2014 114 124 132 118 121 90 113 112 110
2015 113 123 131 116 120 89 112 111 110
- ---------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- --------------------------------------------------------------------------------------------------
Bull Run Colbert Gallatin Johnsonville Shawnee Widows Creek
- --------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1996 107 112 113 114 117 110
1997 107 112 113 114 117 110
1998 107 112 113 114 117 110
1999 107 112 113 114 117 110
2000 107 112 113 114 117 110
2001 107 112 113 114 117 110
2002 107 112 113 114 117 110
2003 107 112 113 114 117 110
2004 107 112 113 114 117 110
2005 107 112 113 114 117 110
2006 107 112 113 114 117 110
2007 107 112 113 114 117 110
2008 107 112 113 114 117 110
2009 107 112 113 114 117 110
2010 107 112 113 114 117 110
2011 107 112 113 114 117 110
2012 107 112 113 114 117 110
2013 107 112 113 114 117 110
2014 107 112 113 114 117 110
2015 107 112 113 114 117 110
- --------------------------------------------------------------------------------------------------
</TABLE>
Exhibit IV-4: Southeast Coal "Over-Market" Plant Level Cost Forecast
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
Year Barry Crist Gadsden Gaston Gorgas Greene Cty Miller White Bluff
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1996 176 216 182 202 161 131 166 182
1997 175 216 182 201 160 130 166 182
1998 175 216 181 201 160 130 165 181
1999 163 216 168 185 154 126 156 174
2000 163 216 167 185 153 125 155 174
2001 162 216 167 184 152 124 155 173
2002 144 216 144 159 142 119 140 161
2003 143 216 144 158 141 118 139 160
2004 142 173 143 157 140 117 138 159
2005 122 172 119 130 130 111 122 144
2006 121 172 118 128 128 110 121 143
2007 120 126 117 127 127 109 120 141
2008 119 125 115 126 126 108 119 140
2009 118 124 114 125 125 107 118 139
2010 116 122 113 123 123 106 116 137
2011 115 121 112 122 122 105 115 136
2012 114 120 111 121 121 104 114 135
2013 113 119 110 120 120 103 113 133
2014 112 118 109 119 119 102 112 132
2015 111 116 108 117 117 101 111 131
- -------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------
Year Bowen Harlee Branch Scherer Crist Wansley Flint Creek Welsh Morrow Allen (TN)
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 140 155 174 173 186 143 177 -- 110
1997 139 154 172 172 185 143 177 -- 110
1998 138 153 171 171 185 142 176 -- 110
1999 135 150 166 202 174 133 165 33 110
2000 134 149 165 202 173 132 164 32 110
2001 133 147 163 202 172 132 163 32 110
2002 130 143 156 202 154 116 145 79 110
2003 129 142 154 202 153 116 144 78 110
2004 128 141 153 166 152 115 143 77 110
2005 125 136 145 165 132 99 123 122 110
2006 123 135 144 165 131 98 122 121 110
2007 122 133 142 126 130 97 121 120 110
2008 121 132 141 125 129 96 120 119 110
2009 120 131 139 124 127 95 118 118 110
2010 119 129 138 122 126 94 117 116 110
2011 117 128 137 121 125 93 116 115 110
2012 116 127 135 120 123 92 115 114 110
2013 115 126 134 119 122 91 114 113 110
2014 114 124 132 118 121 90 113 112 110
2015 113 123 131 116 120 89 112 111 110
- ----------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- --------------------------------------------------------------------------------------------------
Year Bull Run Colbert Gallatin Johnsonville Shawnee Widows Creek
- --------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1996 109 116 116 116 125 114
1997 109 116 116 116 125 114
1998 109 116 116 116 125 114
1999 108 115 115 115 123 113
2000 108 115 115 115 123 113
2001 108 115 115 115 123 113
2002 108 113 114 114 120 112
2003 108 113 114 114 120 112
2004 108 113 114 114 120 112
2005 107 112 113 114 117 110
2006 107 112 113 114 117 110
2007 107 112 113 114 117 110
2008 107 112 113 114 117 110
2009 107 112 113 114 117 110
2010 107 112 113 114 117 110
2011 107 112 113 114 117 110
2012 107 112 113 114 117 110
2013 107 112 113 114 117 110
2014 107 112 113 114 117 110
2015 107 112 113 114 117 110
- --------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit IV-5: Southeast Coal Market Based Cost Forecast
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------
Year Lowman Big Cajun 2 Dolet Hills Rodemacher Independence Arkwright Hammond McDonough Mitchell
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1997 137 158 134 151 160 135 149 132 170
1998 136 156 133 149 158 134 148 131 168
1999 134 155 131 148 157 132 146 129 167
2000 133 153 130 147 155 131 145 128 165
2001 132 152 129 145 154 130 143 127 163
2002 130 150 127 144 152 128 142 126 162
2003 129 149 126 142 151 127 140 124 160
2004 128 147 125 141 149 126 139 123 158
2005 126 146 124 139 148 125 137 122 157
2006 125 144 122 138 146 123 136 121 155
2007 124 143 121 137 145 122 135 119 154
2008 123 141 120 135 143 121 133 118 152
2009 121 140 119 134 142 120 132 117 151
2010 120 139 118 133 140 118 131 116 149
2011 119 137 116 131 139 117 129 115 148
2012 118 136 115 130 138 116 128 114 146
2013 117 135 114 129 136 115 127 112 145
2014 115 133 113 127 135 114 126 111 143
2015 114 132 112 126 134 113 124 110 142
- -------------------------------------------------------------------------------------------------------------------------
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Year Yates Watson Daniel McIntosh Scholz Pirkey Cumberland John Sevier Kingston
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1997 151 130 143 144 140 111 105 125 121
1998 149 128 142 143 138 100 105 125 121
1999 148 127 140 141 137 100 105 125 121
2000 146 126 139 140 135 100 105 125 121
2001 145 125 138 138 134 100 105 125 121
2002 143 123 136 137 133 100 105 125 121
2003 142 122 135 136 131 100 105 125 121
2004 140 121 134 134 130 100 105 125 121
2005 139 120 132 133 129 100 105 125 121
2006 138 119 131 132 128 100 105 125 121
2007 136 117 130 130 126 100 105 125 121
2008 135 116 128 129 125 100 105 125 121
2009 134 115 127 128 124 100 105 125 121
2010 132 114 126 126 122 100 105 125 121
2011 131 113 124 125 121 100 105 125 121
2012 130 112 123 124 120 100 105 125 121
2013 128 111 122 123 119 100 105 125 121
2014 127 109 121 121 118 100 105 125 121
2015 126 108 120 120 116 100 105 125 121
- -------------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit IV-6: Southeast Nuclear Generation Plant Level Price Forecast - $/MWh
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
Farley Arkansas Waterford Hatch Vogtle Grand Gulf Browns Ferry Sequoyah Watts Bar
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1997 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
1998 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
1999 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2000 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2001 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2002 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2003 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2004 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2005 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2006 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2007 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2008 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2009 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2010 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2011 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2012 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2013 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2014 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
2015 4.96 5.45 5.56 6.20 4.78 5.27 6.16 5.40 3.18
- ----------------------------------------------------------------------------------------------------------
</TABLE>
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit IV-7 Delivered to Electric Utility Gas Costs -c/MMBtu
- ----------------------------------------------------------------------------
1994 1995 1996 *1997 Average
- ----------------------------------------------------------------------------
Alabama 244 203 287 314 262
Arkansas 172 169 272 234 212
Louisiana 214 184 294 258 237
Mississippi 219 174 289 259 235
Texas 210 182 251 246 222
- ----------------------------------------------------------------------------
*Avg through Aug. 1997
Exhibit IV-8: Average Electric Utility Delivered Gas Cost Basis Difference From
Henry Hub -c/MMBtu
- ----------------------------------------------------------------------------
1994 1995 1996 1997 Average
- ----------------------------------------------------------------------------
Henry Hub 186 180 276 257 N/A
- ----------------------------------------------------------------------------
Alabama 58 23 11 57 37
Arkansas (14) (11) (4) (23) (13)
Louisiana 28 4 18 1 13
Mississippi 33 (6) 13 2 10
Georgia* N.A. N.A. N.A. N.A. 25
Tennessee* N.A. N.A. N.A. N.A. 25
Texas 24 2 (25) (11) (3)
- ----------------------------------------------------------------------------
* Gas use for utility did not provide useable numbers for basis calculation.
25 c/MMBtu represents C.C. Pace's transportation cost estimate to these states
Proprietary & Confidential
5-13-99
<PAGE>
Exhibit IV-9 Southeast Average Distillate Fuel Oil Costs - Cents/MMBtu
- ----------------------------------------------------------------------------
1994 1995 1996 *1997 Average
- ----------------------------------------------------------------------------
Alabama 415 318 439 421 398
Arkansas 395 398 447 444 421
Georgia 395 393 413 466 417
Louisiana 399 359 434 349 385
Mississippi 385 369 373 443 393
Tennessee 428 418 453 449 437
- ----------------------------------------------------------------------------
*Avg through Aug. 1997
Exhibit IV-10: Average Price Relationship of Refined Oil Products - Cents/Gallon
- --------------------------------------------------------------------------------
[GRAPH OMITTED]
- --------------------------------------------------------------------------------
Exhibit IV-11: Southeast Average Imputed Residual Fuel Oil Costs - Cents/MMBtu
- -----------------------------------------------------------
Average Average
Average Residual Imputed
Distillate Difference Residual
State Prices Price Price
- -----------------------------------------------------------
Alabama 398 169 229
Arkansas 421 169 252
Georgia 417 169 248
Louisiana 385 169 216
Mississippi 393 169 224
Tennessee 437 169 268
- -----------------------------------------------------------
Proprietary & Confidential
5-13-99
<PAGE>
ANNEX D
FORM OF REQUEST FOR INFORMATION FROM THE TRUSTEE
The Bank of New York
101 Barclay Street
Floor 21 West
New York, New York 10286
Attention: Corporate Trust Administration
Pursuant to Section 15.1 of that certain Trust Indenture, dated as of
May 21, 1999 (as amended, modified or supplemented from time to time in
accordance with the terms thereof, the "Indenture"), among LSP Energy Limited
Partnership (the "Partnership"), LSP Batesville Funding Corporation (the
"Funding Corporation" and, together with the Partnership, the "Issuers") and The
Bank of New York, as Trustee (the "Trustee"), [NAME OF HOLDER], as beneficial
holder, hereby requests, which request is a continuing request until further
notice to the contrary, that you deliver to us at [ADDRESS OF HOLDER] all
information and copies of all documents that the Issuers are required to deliver
to you pursuant to Rule 144A(d) under the Securities Act of 1933, as amended, or
pursuant to those sections of the Indenture which state that specified
information will be provided to holders or beneficial owners of the bonds issued
under the Indenture upon their request. [NAME OF HOLDER] hereby certifies that
it is a beneficial holder of Series [ ] Senior Secured Bonds issued under the
Indenture.
[NAME OF HOLDER]
<TABLE>
<S> <C>
- ------------------------------------ ------------------------
Authorized Signature Date
</TABLE>
D-1
<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
No dealer, salesperson, or other person has been authorized to give any
information or to make any representations in connection with the offer
contained herein other than those contained in this prospectus, and, if given or
made, such information or representations must not be relied upon as having been
authorized by LSP Energy Limited Partnership or LSP Batesville Funding
Corporation. This prospectus does not constitute an offer to sell, or the
solicitation of an offer to buy, any security other than those to which it
relates nor does it constitute an offer to sell, or the solicitation of an offer
to buy, to any person in any jurisdiction in which the offer or solicitation is
not authorized, or in which the person making such offer or solicitation is not
qualified to do so, or to any person to whom it is unlawful to make such offer
or solicitation. Neither the delivery of this prospectus nor any sale made
hereunder shall, under any circumstances, create any implication that there has
been no change in the affairs of LSP Energy Limited Partnership or LSP
Batesville Funding Corporation since the date hereof or that the information
contained herein is correct as of any time subsequent to the date of this
prospectus.
---------------------
PROSPECTUS
---------------------
LSP ENERGY LIMITED PARTNERSHIP
LSP BATESVILLE FUNDING CORPORATION
, 2000
Until , 2000, all dealers effecting transactions in the exchange
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.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
PART II
INFORMATION NOT REQUIRED IN THE PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Section 145 of the General Corporation Law of the State of Delaware ("DGCL")
provides that a corporation has the power to indemnify any director or officer,
or former director or officer, who was or is a party or is threatened to be made
a party to any threatened, pending or completed action, suit or proceeding,
whether civil, criminal, administrative or investigative (other than an action
by or in the right of the corporation) against the expenses (including
attorney's fees), judgments, fines and amounts paid in settlement actually and
reasonably incurred by him in connection with the defense of any action by
reason of being or having been directors or officers, if such person has acted
in good faith and in a manner reasonably believed to be in or not opposed to the
best interests of the corporation, and, with respect to any criminal action or
proceeding, provided that such person had no reasonable cause to believe his
conduct was unlawful, except that, if such action will be in the right of the
corporation, no such indemnification will be provided as to any claim, issue or
matter as to which such person will have been judged to have been liable to the
corporation unless and only to the extent that the Court of Chancery of the
State of Delaware (the "Court of Chancery"), or any court in such suit or action
was brought, will determine upon application that, despite the liability
judgment, but in view of all of the circumstances of the case, such person is
fairly and reasonably entitled to indemnity for such expenses as the Court of
Chancery or such other court will deem proper.
Accordingly, the Certificate of Incorporation and the amendments thereto
dated August 3, 1998 and May 18, 1999 of the Funding Corporation (filed herewith
as Exhibit 3.1) provide that no director will be personally liable to LSP
Batesville Funding Corporation (the "Funding Corporation") or any of its
stockholders for monetary damages for breach of fiduciary duty as a director,
except for liability (i) for any breach of the director's duty of loyalty to the
Funding Corporation or its stockholders, (ii) for acts or omissions not in good
faith or which involve intentional misconduct or a knowing violation of law,
(iii) pursuant to Section 174 of the DGCL (director liability for unlawful
payment of dividends, stock purchaser or redemption), or (iv) for any
transaction from which the director derived an improper personal benefit.
Furthermore, the By-Laws of the Funding Corporation dated August 3, 1998
(filed herewith as Exhibit 3.3) provide for the indemnification by the Funding
Corporation of any person who was or is a party or is threatened to be made a
party to any threatened, pending or completed action, suit or proceeding,
whether civil, criminal, administrative or investigative (other than an action
by or in the right of the Funding Corporation) by reason of the fact that he is
or was a director or officer of the Funding Corporation, or is or was a director
or officer of the Funding Corporation serving at the request of the Funding
Corporation as a director or officer, employee or agent of another corporation,
partnership, joint venture, trust, employee benefit plan or other enterprise,
against expenses (including attorney's fees) judgments, fines and amounts paid
in settlement actually and reasonably incurred by him in connection with such
action, suit or proceeding, or the defense or settlement of such action or suit,
if he acted in good faith and in a manner he reasonably believed to be in or not
opposed to the best interests of the Corporation, and, with respect to any
criminal action or proceeding, had no reasonable cause to believe his conduct
was unlawful. The termination of any action, suit or proceeding by judgment,
order, settlement, conviction or upon a plea of nolo contendere or its
equivalent will not, of itself, create a presumption that the person did not act
in good faith and in a manner which he reasonably believed to be in or not
opposed to the best interests of the Funding Corporation, and, with respect to
any criminal action or proceeding, had reasonable cause to believe that his
conduct was unlawful. With respect to any such defense or settlement of such
action or suit, no indemnification will be made in respect of any claim, issue
or matter as to which such person will have been adjudged to be liable to the
Funding Corporation unless and only to the extent that the Court of Chancery or
the court in which such action or suit was brought determines upon application
that, despite the
II-1
<PAGE>
adjudication of liability but in view of all the circumstances of the case, such
person is fairly and reasonably entitled to indemnity for such expenses which
the Court of Chancery or such other court deems proper.
Expenses incurred by a director or officer defending or investigating a
threatened or pending action, suit or proceeding will be paid by the Funding
Corporation in advance of the final disposition of such action, suit or
proceeding upon receipt of an undertaking by or on behalf of such director or
officer to repay such amount if it will ultimately be determined that he is not
entitled to be indemnified by the Funding Corporation. The indemnification or
advancement of expenses provided by the Funding Corporation will not be deemed
exclusive of any other rights to which those seeking indemnification or
advancement of expenses may be entitled under any By-Law, agreement, contract,
vote of stockholders or disinterested directors or pursuant to the direction of
any court of competent jurisdiction or otherwise, both as to action in his
official capacity and as to action in another capacity while holding such
office, it being the policy of the Funding Corporation that the indemnification
of such directors and officers be made to the fullest extent permitted by law.
The Funding Corporation may purchase and maintain insurance on behalf of any
person who is or was a director or officer of the Funding Corporation, or is or
was a director or officer of the Funding Corporation serving at the request of
the Funding Corporation as a director, officer, employee or agent of another
corporation, partnership, joint venture, trust, employee benefit plan or other
enterprise, against any liability asserted against him and incurred by him in
any such capacity, or arising out of his status as such, whether or not the
Funding Corporation would have the power or the obligation to indemnify him
against such liability.
Section 17-108 of the Delaware Revised Uniform Limited Partnership Act (the
"Partnership Act") provides that a limited partnership may indemnify and hold
harmless any partners or other persons from and against any and all claims and
demands whatsoever, subject to such standards and restrictions set forth in the
partnership agreement.
Accordingly, the Limited Partnership Agreement and the amendments thereto
dated February 8, 1996, August 24, 1998 and May 19, 1999 of the Partnership
(filed herewith as Exhibit 3.2) provide that the partners and their respective
officers, directors, shareholders, constituent partners, trustees, agents,
employees and other representatives will be indemnified and held harmless by the
Partnership from and against any and all losses, claims, damages, liabilities,
whether joint or several, expenses (including legal fees and disbursements),
judgments, fines, settlements and other amounts suffered by them in connection
with or arising from any and all claims, demands, actions, suits or proceedings,
whether civil, criminal, administrative or investigative, in which they may be
involved, or threatened to be involved, as a party or otherwise, by reason of
their status as a partner or an officer, director, shareholder, constituent
partner, trustee, employee or other representative of a partner except when they
result from fraud, willful misconduct, gross negligence or breach of any
fiduciary duty. This indemnification will be in addition to any other rights to
which such party may be entitled to, as a matter of law or otherwise, in such
person's capacity as a partner or as an officer, director, shareholder,
constituent partner, trustee or other representative of a partner and will inure
to the benefit of the heirs, successors, assigns and administrators of such
person. Furthermore, any indemnification will be satisfied solely out of the
assets of the Partnership. In no event will such person subject the Partnership
to personal liability by reason of these indemnification provisions.
II-2
<PAGE>
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ----------- ------------------------------------------------------------
<C> <C> <S>
**3.1 -- Amended and Restated Certificate of Incorporation of LSP
Batesville Funding Corporation.
**3.2 -- Amended and Restated Limited Partnership Agreement of LSP
Energy Limited Partnership.
**3.3 -- By-Laws of LSP Batesville Funding Corporation.
**4.1 -- Indenture, dated as of May 21, 1999, among LSP Batesville
Funding Corporation, LSP Energy Limited Partnership and The
Bank of New York, as Trustee.
**4.2 -- First Supplemental Indenture, dated May 21, 1999 among LSP
Batesville Funding Corporation, LSP Energy Limited
Partnership and The Bank of New York, as Trustee, relating
to $150,000,000 aggregate principal amount of 7.164% Series
A Senior Secured Bonds due 2014.
**4.3 -- Second Supplemental Indenture, dated May 21, 1999 among LSP
Batesville Funding Corporation, LSP Energy Limited
Partnership and The Bank of New York, as Trustee, relating
to $176,000,000 aggregate principal amount of 8.160% Series
B Senior Secured Bonds due 2025.
**4.4 -- Form of Third Supplemental Indenture among LSP Batesville
Funding Corporation, LSP Energy Limited Partnership and The
Bank of New York, as Trustee, relating to $150,000,000
aggregate principal amount of 7.164% Series C Senior Secured
Bonds due 2014.
**4.5 -- Form of Fourth Supplemental Indenture among LSP Batesville
Funding Corporation, LSP Energy Limited Partnership and The
Bank of New York, as Trustee, relating to $176,000,000
aggregate principal amount of 8.160% Series D Senior Secured
Bonds due 2025.
**4.6 -- Specimen Certificate of 7.164% Series A Senior Secured Bonds
due 2014.
**4.7 -- Specimen Certificate of 8.160% Series B Senior Secured Bonds
due 2025.
**4.8 -- Form of Specimen Certificate of 7.164% Series C Senior
Secured Bonds due 2014.
**4.9 -- Form of Specimen Certificate of 8.160% Series D Senior
Secured Bonds due 2025.
**4.10 -- Registration Rights Agreement, dated as of May 21, 1999,
among LSP Batesville Funding Corporation, LSP Energy Limited
Partnership, Credit Suisse First Boston Corporation, Scotia
Capital Markets (USA) Inc. and TD Securities (USA) Inc.
**4.11 -- Second Amended and Restated Common Agreement, dated as of
May 21, 1999, among LSP Batesville Funding Corporation, LSP
Energy Limited Partnership and The Bank of New York, as
Collateral Agent, Administrative Agent and Intercreditor
Agent.
**4.12 -- Intercreditor Agreement, dated as of May 21, 1999, among LSP
Batesville Funding Corporation, LSP Energy Limited
Partnership, Credit Suisse First Boston, as VEPCO L/C Agent,
and The Bank of New York, as Collateral Agent, Trustee,
Administrative Agent and Intercreditor Agent.
</TABLE>
II-3
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ----------- ------------------------------------------------------------
<C> <C> <S>
**4.13 -- Second Amended and Restated Equity Contribution Agreement,
dated as of May 21, 1999, among LSP Batesville Holding, LLC,
LSP Energy Limited Partnership and The Bank of New York, as
Collateral Agent.
**4.14 -- Second Amended and Restated Collateral Agency Agreement,
dated as of May 21, 1999, among LSP Batesville Funding
Corporation, LSP Energy Limited Partnership, the Senior
Secured Parties party thereto from time to time, The Bank of
New York, as Administrative Agent, Collateral Agent and
Intercreditor Agent and Credit Suisse First Boston, as
Additional Collateral Agent.
**4.15 -- Pledge and Security Agreement, dated as of May 21, 1999
(Funding Corporation's Stock), between LSP Batesville
Holding, LLC and The Bank of New York, as Collateral Agent.
**4.16 -- Second Amended and Restated Pledge and Security Agreement
(LSP Energy, Inc.'s Stock), dated as of May 21, 1999,
between LSP Batesville Holding, LLC and The Bank of New
York, as Collateral Agent.
**4.17 -- Second Amended and Restated Pledge and Security Agreement
(Limited Partnership Interest in the Partnership), dated as
of May 21, 1999, between LSP Batesville Holding, LLC and The
Bank of New York, as Collateral Agent.
**4.18 -- Second Amended and Restated Pledge and Security Agreement
(General Partnership Interest in the Partnership), dated as
of May 21, 1999, between LSP Energy, Inc. and The Bank of
New York, as Collateral Agent.
**4.19 -- Second Amended and Restated Security Agreement, dated as of
May 21, 1999, between LSP Energy Limited Partnership and The
Bank of New York, as Collateral Agent.
**4.20 -- Security Agreement, dated as of May 21, 1999, between LSP
Batesville Funding Corporation and The Bank of New York, as
Collateral Agent.
**4.21 -- Deed of Trust, Security Agreement, Assignment of Leases and
Rents and Fixture Filing, dated as of May 21, 1999, by LSP
Energy Limited Partnership, as trustor, to James W. O'Mara,
as trustee, for the benefit of The Bank of New York, as
Collateral Agent.
**4.22 -- Second Amended and Restated Securities Account Control
Agreement, dated as of May 21, 1999, among LSP Batesville
Funding Corporation, LSP Energy Limited Partnership and The
Bank of New York, as Collateral Agent and Securities
Intermediary.
5.1 -- Opinion of Latham & Watkins regarding the validity of the
exchange bonds.
**10.1 -- Purchase Agreement, dated May 13, 1999, among LSP Energy
Limited Partnership, LSP Batesville Funding Corporation,
Credit Suisse First Boston Corporation, Scotia Capital
Markets (USA) Inc. and TD Securities (USA) Inc.
**10.2 -- Power Purchase Agreement and amendments thereto, dated May
18, 1998, July 22, 1998 and August 11, 1998, between LSP
Energy Limited Partnership and Virginia Electric and Power
Company.
**10.3 -- Power Purchase Agreement and amendments thereto, dated May
21, 1998, July 14, 1998, July 16, 1998 and August 27, 1998,
among LSP Energy Limited Partnership, Aquila Energy
Marketing Corporation and Utilicorp United Inc.
</TABLE>
II-4
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ----------- ------------------------------------------------------------
<C> <C> <S>
**10.4 -- Interconnection Agreement, dated July 22, 1998, between LSP
Energy Limited Partnership and the Tennessee Valley
Authority.
**10.5 -- Interconnection and Operating Agreement and amendments
thereto, dated May 18, 1998 and August 18, 1998, between LSP
Energy Limited Partnership and Entergy Mississippi, Inc.
**10.6 -- Interconnection Agreement, dated July 28, 1998, between LSP
Energy Limited Partnership and ANR Pipeline Company.
**10.7 -- Facilities Agreement, dated June 23, 1998, between Tennessee
Gas Pipeline Company and LSP Energy Limited Partnership.
**10.8 -- Turnkey Engineering, Procurement and Construction Agreement
and amendments thereto, dated July 22, 1998, October 22,
1998, November 2, 1998, November 5, 1998, December 10, 1998,
February 1, 1999 and April 12, 1999, between LSP Energy
Limited Partnership and BVZ Power Partners--Batesville.
**10.9 -- Engineering Services Agreement, dated July 24, 1998, between
LSP Limited Partnership and Black & Veatch, LLP.
**10.10 -- Guaranty Agreement, dated July 22, 1998, by Black & Veatch,
LLP in favor of LSP Energy Limited Partnership.
**10.11 -- Management Services Agreement, dated August 24, 1998,
between LSP Energy Limited Partnership and LS Power
Management, LLC.
**10.12 -- Operation and Maintenance Agreement, dated August 24, 1998,
between LSP Energy Limited Partnership and Cogentrix
Batesville Operations, LLC.
**10.13 -- Water Supply Storage Agreement and amendments thereto, dated
June 8, 1998 and March 15, 1999, between LSP Energy Limited
Partnership and the United States of America.
**10.14 -- Letter Agreement/Blanket Purchase Order, dated July 23,
1998, between LSP Energy Limited Partnership and Siemens
Westinghouse Power Corporation.
**10.15 -- Ad Valorem Tax Contract, dated August 24, 1998, among LSP
Energy Limited Partnership, Panola County, Mississippi, the
City of Batesville, Mississippi, the Department of Economic
and Community Development and the Panola County Tax
Assessor/Collector.
**10.16 -- Letter of Credit Agreement, dated August 28, 1998, among LSP
Energy Limited Partnership, Credit Suisse First Boston, as
the VEPCO L/C Agent and the VEPCO L/C Issuer, and the VEPCO
L/C Banks.
**10.17 -- Infrastructure Use Agreement (Gasline Use), dated
August 12, 1999, among LSP Energy Limited Partnership, the
Industrial Development Authority of the Second Judicial
District of Panola County, Mississippi, the Mississippi
Major Economic Impact Authority, Panola County, Mississippi
and the City of Batesville, Mississippi.
**10.18 -- Inducement Agreement, dated August 12, 1999, among LSP
Energy Limited Partnership, the Industrial Development
Authority of the Second Judicial District of Panola County,
Mississippi, the Mississippi Department of Economic and
Community Development, the Mississippi Major Economic Impact
Authority, Panola County, Mississippi and the City of
Batesville, Mississippi.
</TABLE>
II-5
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ----------- ------------------------------------------------------------
<C> <C> <S>
**10.19 -- Panola Partnership, dated August 12, 1999, among LSP Energy
Limited Partnership and Panola Partnership, Inc.
**10.20 -- Infrastructure Use Agreement (Water Use), dated August 12,
1999, among LSP Energy Limited Partnership, the Industrial
Development Authority of the Second Judicial District of
Panola County, Mississippi, the Mississippi Major Economic
Impact Authority, Panola County, Mississippi.
**10.21 -- Yalobusha County Agreement, dated February 16, 1999, among
LSP Energy Limited Partnership, Yalobusha County,
Mississippi and the Coffeeville School District.
**10.22 -- Performance Bond and Payment Bond, dated August 13, 1998, of
United States Fidelity and Guaranty Company, as surety.
12.1 -- Statement re: Computation of Ratio of Earnings to Fixed
Charges.
23.1 -- Consent of Latham & Watkins (included in their opinion filed
as Exhibit 5.1).
23.2 -- Consent of KPMG LLP.
23.3 -- Consent of R.W. Beck, Inc.
23.4 -- Consent of C.C. Pace Consulting, L.L.C.
**23.5 -- Consent of Butler, Snow, O'Mara, Stevens & Cannada, PLLC.
**25.1 -- Statement of Eligibility and Qualification (Form T-1) under
the Trust Indenture Act of 1939 of The Bank of New York.
27.1 -- Financial Data Schedule (LSP Energy Limited Partnership).
27.2 -- Financial Data Schedule (LSP Batesville Funding Corporation)
27.3 -- Financial Data Schedule (LSP Energy, Inc.)
**99.1 -- Form of Letter of Transmittal to tender unregistered 7.164%
Series A Senior Secured Bonds due 2014 and unregistered
8.160% Series B Senior Secured Bonds of LSP Energy
Partnership and LSP Batesville Funding Corporation.
**99.2 -- Form of Letter to Registered Holders and DTC Participants
from LSP Energy Limited Partnership and LSP Batesville
Funding Corporation regarding the exchange offer.
**99.3 -- Form of Instruction to Registered Holder or DTC Participant
from Beneficial Owner of 7.164% Senior Secured bonds due
2014 and/or 8.160% Senior Secured bonds due 2025 of LSP
Energy Limited Partnership and LSP Batesville Funding
Corporation.
**99.4 -- Form of Letter to Clients from Registered Holder or DTC
Participant regarding the exchange offer.
**99.5 -- Form of Notice of Guaranteed Delivery
</TABLE>
- ------------------------
* To be filed by amendment.
** Previously filed
(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.
II-6
<PAGE>
ITEM 22. UNDERTAKINGS.
The undersigned Registrants hereby undertake:
(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 prosectus any facts or events arising after
the effective date of this 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
this 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
Securities and Exchange Commission puruant to Rule 424(b) if, in the
aggregate, the changes in volume and price represent no more than 20
percent change in the maximum aggregate offering price set forth in the
"Calculation of Registration Fee" table in the effective registration
statement.
(iii) To include any material information with respect to the plan of
distribution not previously disclosed in this registration statement or
any material change to such information in this registration statement.
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed
to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed to
be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the
termination of the offering.
The undersigned Registrants hereby undertake 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.
The undersigned Registrants hereby undertake: that prior to any public
reoffering of the securities registered hereunder through use of a prospectus
which is a part of this Registration Statement, by any person or party who is
deemed to be an underwriter within the meaning of Rule 145(c), such reoffering
prospectus will contain the information called for by the applicable
registration form with respect to reofferings by persons who may be deemed
underwriters, in addition to the information called for by the other Items of
the application form.
The undersigned Registrants hereby undertake that every prospectus (i) that
is filed pursuant to the immediately preceding paragraph or (ii) that purports
to meet the requirements of Section 10(a)(3) of the Securities Act of 1933 and
is used in connection with an offering of securities subject to Rule 415, will
be filed as a part of an amendment to the registration statement and will not be
used until such amendment is effective, and that, for purposes of determining
any liability under the Securities Act of 1933, each such post-effective
amendment will be deemed to be a new registration statement relating to the
securities offered therein, and the offering of such securities at that time
will be deemed to be the initial bona fide offering thereof.
The undersigned Registrants hereby undertake to file an application of the
purpose of determining the eligibility of the trustee to act under subsection
(a) of section 310 of the Trust Indenture Act in accordance with the rules and
regulations prescribed by the Commission under section 305(b)(2) of the Trust
Indenture Act.
II-7
<PAGE>
Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers and controlling persons of the
Registrants pursuant to the foregoing provisions, or otherwise, the Registrants
have been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the Registrants of expenses incurred
or paid by a director, officer or controlling person of the Registrants in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the Registrants will, unless in the opinion of its counsel the
matter has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Act and will be governed by the final
adjudication of the issue.
II-8
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, AS AMENDED, THE
REGISTRANTS HAVE DULY CAUSED THIS AMENDMENT TO THIS REGISTRATION STATEMENT TO BE
SIGNED ON THEIR BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE
CITY OF NEW YORK, STATE OF NEW YORK, ON FEBRUARY 9, 2000.
<TABLE>
<S> <C> <C>
LSP BATESVILLE FUNDING CORPORATION
By: /s/ MIKHAIL SEGAL
-----------------------------------------
Name: Mikhail Segal
Title: President
LSP ENERGY LIMITED PARTNERSHIP
By: LSP ENERGY, INC.,
its general partner
By: /s/ MIKHAIL SEGAL
----------------------------------------
Name: Mikhail Segal
Title: President
</TABLE>
II-9
<PAGE>
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, THIS AMENDMENT
TO THIS REGISTRATION STATEMENT HAS BEEN SIGNED BY THE FOLLOWING PERSONS IN THE
CAPACITIES AND AS OF THE DATES INDICATED.
LSP ENERGY LIMITED
PARTNERSHIP
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
President (Principal Executive
/s/ MIKHAIL SEGAL Officer) and Director of LSP
-------------------------------------- Energy, Inc. (General Partner February 9, 2000
Mikhail Segal Director)
Senior Vice President and
/s/ FRANK E. HARDENBERGH Secretary and Director of LSP
-------------------------------------- Energy, Inc. (General Partner February 9, 2000
Frank E. Hardenbergh Director)
Treasurer (Principal Financial
/s/ MARK BRENNAN Officer and Principal
-------------------------------------- Accounting Officer) of LSP February 9, 2000
Mark Brennan Energy, Inc.
</TABLE>
II-10
<PAGE>
LSP BATESVILLE FUNDING
CORPORATION
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ MIKHAIL SEGAL
-------------------------------------- President and Director (Principal February 9, 2000
Mikhail Segal Executive Officer)
/s/ FRANK E. HARDENBERGH
-------------------------------------- Senior Vice President, Secretary February 9, 2000
Frank E. Hardenbergh and Director
/s/ MARK BRENNAN Treasurer (Principal Financial
-------------------------------------- Officer and Principal February 9, 2000
Mark Brennan Accounting Officer)
</TABLE>
II-11
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ----------- ------------------------------------------------------------
<C> <C> <S>
**3.1 -- Amended and Restated Certificate of Incorporation of LSP
Batesville Funding Corporation.
**3.2 -- Amended and Restated Limited Partnership Agreement of LSP
Energy Limited Partnership.
**3.3 -- By-Laws of LSP Batesville Funding Corporation.
**4.1 -- Indenture, dated as of May 21, 1999, among LSP Batesville
Funding Corporation, LSP Energy Limited Partnership and The
Bank of New York, as Trustee.
**4.2 -- First Supplemental Indenture, dated May 21, 1999 among LSP
Batesville Funding Corporation, LSP Energy Limited
Partnership and The Bank of New York, as Trustee, relating
to $150,000,000 aggregate principal amount of 7.164% Series
A Senior Secured Bonds due 2014.
**4.3 -- Second Supplemental Indenture, dated May 21, 1999 among LSP
Batesville Funding Corporation, LSP Energy Limited
Partnership and The Bank of New York, as Trustee, relating
to $176,000,000 aggregate principal amount of 8.160% Series
B Senior Secured Bonds due 2025.
**4.4 -- Form of Third Supplemental Indenture among LSP Batesville
Funding Corporation, LSP Energy Limited Partnership and The
Bank of New York, as Trustee, relating to $150,000,000
aggregate principal amount of 7.164% Series C Senior Secured
Bonds due 2014.
**4.5 -- Form of Fourth Supplemental Indenture among LSP Batesville
Funding Corporation, LSP Energy Limited Partnership and The
Bank of New York, as Trustee, relating to $176,000,000
aggregate principal amount of 8.160% Series D Senior Secured
Bonds due 2025.
**4.6 -- Specimen Certificate of 7.164% Series A Senior Secured Bonds
due 2014.
**4.7 -- Specimen Certificate of 8.160% Series B Senior Secured Bonds
due 2025.
**4.8 -- Form of Specimen Certificate of 7.164% Series C Senior
Secured Bonds due 2014.
**4.9 -- Form of Specimen Certificate of 8.160% Series D Senior
Secured Bonds due 2025.
**4.10 -- Registration Rights Agreement, dated as of May 21, 1999,
among LSP Batesville Funding Corporation, LSP Energy Limited
Partnership, Credit Suisse First Boston Corporation, Scotia
Capital Markets (USA) Inc. and TD Securities (USA) Inc.
**4.11 -- Second Amended and Restated Common Agreement, dated as of
May 21, 1999, among LSP Batesville Funding Corporation, LSP
Energy Limited Partnership and The Bank of New York, as
Collateral Agent, Administrative Agent and Intercreditor
Agent.
**4.12 -- Intercreditor Agreement, dated as of May 21, 1999, among LSP
Batesville Funding Corporation, LSP Energy Limited
Partnership, Credit Suisse First Boston, as VEPCO L/C Agent,
and The Bank of New York, as Collateral Agent, Trustee,
Administrative Agent and Intercreditor Agent.
**4.13 -- Second Amended and Restated Equity Contribution Agreement,
dated as of May 21, 1999, among LSP Batesville Holding, LLC,
LSP Energy Limited Partnership and The Bank of New York, as
Collateral Agent.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ----------- ------------------------------------------------------------
<C> <C> <S>
**4.14 -- Second Amended and Restated Collateral Agency Agreement,
dated as of May 21, 1999, among LSP Batesville Funding
Corporation, LSP Energy Limited Partnership, the Senior
Secured Parties party thereto from time to time, The Bank of
New York, as Administrative Agent, Collateral Agent and
Intercreditor Agent and Credit Suisse First Boston, as
Additional Collateral Agent.
**4.15 -- Pledge and Security Agreement, dated as of May 21, 1999
(Funding Corporation's Stock), between LSP Batesville
Holding, LLC and The Bank of New York, as Collateral Agent.
**4.16 -- Second Amended and Restated Pledge and Security Agreement
(LSP Energy, Inc.'s Stock), dated as of May 21, 1999,
between LSP Batesville Holding, LLC and The Bank of New
York, as Collateral Agent.
**4.17 -- Second Amended and Restated Pledge and Security Agreement
(Limited Partnership Interest in the Partnership), dated as
of May 21, 1999, between LSP Batesville Holding, LLC and The
Bank of New York, as Collateral Agent.
**4.18 -- Second Amended and Restated Pledge and Security Agreement
(General Partnership Interest in the Partnership), dated as
of May 21, 1999, between LSP Energy, Inc. and The Bank of
New York, as Collateral Agent.
**4.19 -- Second Amended and Restated Security Agreement, dated as of
May 21, 1999, between LSP Energy Limited Partnership and The
Bank of New York, as Collateral Agent.
**4.20 -- Security Agreement, dated as of May 21, 1999, between LSP
Batesville Funding Corporation and The Bank of New York, as
Collateral Agent.
**4.21 -- Deed of Trust, Security Agreement, Assignment of Leases and
Rents and Fixture Filing, dated as of May 21, 1999, by LSP
Energy Limited Partnership, as trustor, to James W. O'Mara,
as trustee, for the benefit of The Bank of New York, as
Collateral Agent.
**4.22 -- Second Amended and Restated Securities Account Control
Agreement, dated as of May 21, 1999, among LSP Batesville
Funding Corporation, LSP Energy Limited Partnership and The
Bank of New York, as Collateral Agent and Securities
Intermediary.
5.1 -- Opinion of Latham & Watkins regarding the validity of the
exchange bonds.
**10.1 -- Purchase Agreement, dated May 13, 1999, among LSP Energy
Limited Partnership, LSP Batesville Funding Corporation,
Credit Suisse First Boston Corporation, Scotia Capital
Markets (USA) Inc. and TD Securities (USA) Inc.
**10.2 -- Power Purchase Agreement and amendments thereto, dated May
18, 1998, July 22, 1998 and August 11, 1998, between LSP
Energy Limited Partnership and Virginia Electric and Power
Company.
**10.3 -- Power Purchase Agreement and amendments thereto, dated May
21, 1998, July 14, 1998, July 16, 1998 and August 27, 1998,
among LSP Energy Limited Partnership, Aquila Energy
Marketing Corporation and Utilicorp United Inc.
**10.4 -- Interconnection Agreement, dated July 22, 1998, between LSP
Energy Limited Partnership and the Tennessee Valley
Authority.
**10.5 -- Interconnection and Operating Agreement and amendments
thereto, dated May 18, 1998 and August 18, 1998, between LSP
Energy Limited Partnership and Entergy Mississippi, Inc.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ----------- ------------------------------------------------------------
<C> <C> <S>
**10.6 -- Interconnection Agreement, dated July 28, 1998, between LSP
Energy Limited Partnership and ANR Pipeline Company.
**10.7 -- Facilities Agreement, dated June 23, 1998, between Tennessee
Gas Pipeline Company and LSP Energy Limited Partnership.
**10.8 -- Turnkey Engineering, Procurement and Construction Agreement
and amendments thereto, dated July 22, 1998, October 22,
1998, November 2, 1998, November 5, 1998, December 10, 1998,
February 1, 1999 and April 12, 1999, between LSP Energy
Limited Partnership and BVZ Power Partners--Batesville.
**10.9 -- Engineering Services Agreement, dated July 24, 1998, between
LSP Limited Partnership and Black & Veatch, LLP.
**10.10 -- Guaranty Agreement, dated July 22, 1998, by Black & Veatch,
LLP in favor of LSP Energy Limited Partnership.
**10.11 -- Management Services Agreement, dated August 24, 1998,
between LSP Energy Limited Partnership and LS Power
Management, LLC.
**10.12 -- Operation and Maintenance Agreement, dated August 24, 1998,
between LSP Energy Limited Partnership and Cogentrix
Batesville Operations, LLC.
**10.13 -- Water Supply Storage Agreement and amendments thereto, dated
June 8, 1998 and March 15, 1999, between LSP Energy Limited
Partnership and the United States of America.
**10.14 -- Letter Agreement/Blanket Purchase Order, dated July 23,
1998, between LSP Energy Limited Partnership and Siemens
Westinghouse Power Corporation.
**10.15 -- Ad Valorem Tax Contract, dated August 24, 1998, among LSP
Energy Limited Partnership, Panola County, Mississippi, the
City of Batesville, Mississippi, the Department of Economic
and Community Development and the Panola County Tax
Assessor/Collector.
**10.16 -- Letter of Credit Agreement, dated August 28, 1998, among LSP
Energy Limited Partnership, Credit Suisse First Boston, as
the VEPCO L/C Agent and the VEPCO L/C Issuer, and the VEPCO
L/C Banks.
**10.17 -- Infrastructure Use Agreement (Gasline Use), dated
August 12, 1999, among LSP Energy Limited Partnership, the
Industrial Development Authority of the Second Judicial
District of Panola County, Mississippi, the Mississippi
Major Economic Impact Authority, Panola County, Mississippi
and the City of Batesville, Mississippi.
**10.18 -- Inducement Agreement, dated August 12, 1999, among LSP
Energy Limited Partnership, the Industrial Development
Authority of the Second Judicial District of Panola County,
Mississippi, the Mississippi Department of Economic and
Community Development, the Mississippi Major Economic Impact
Authority, Panola County, Mississippi and the City of
Batesville, Mississippi.
**10.19 -- Panola Partnership, dated August 12, 1999, among LSP Energy
Limited Partnership and Panola Partnership, Inc.
**10.20 -- Infrastructure Use Agreement (Water Use), dated August 12,
1999, among LSP Energy Limited Partnership, the Industrial
Development Authority of the Second Judicial District of
Panola County, Mississippi, the Mississippi Major Economic
Impact Authority, Panola County, Mississippi.
**10.21 -- Yalobusha County Agreement, dated February 16, 1999, among
LSP Energy Limited Partnership, Yalobusha County,
Mississippi and the Coffeeville School District.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ----------- ------------------------------------------------------------
<C> <C> <S>
**10.22 -- Performance Bond and Payment Bond, dated August 13, 1998, of
United States Fidelity and Guaranty Company, as surety.
12.1 -- Statement re: Computation of Ratio of Earnings to Fixed
Charges.
23.1 -- Consent of Latham & Watkins (included in their opinion filed
as Exhibit 5.1).
23.2 -- Consent of KPMG LLP.
23.3 -- Consent of R.W. Beck, Inc.
23.4 -- Consent of C.C. Pace Consulting, L.L.C.
**23.5 -- Consent of Butler, Snow, O'Mara, Stevens & Cannada, PLLC.
**25.1 -- Statement of Eligibility and Qualification (Form T-1) under
the Trust Indenture Act of 1939 of The Bank of New York.
27.1 -- Financial Data Schedule (LSP Energy Limited Partnership).
27.2 -- Financial Data Schedule (LSP Batesville Funding Corporation)
27.3 -- Financial Data Schedule (LSP Energy, Inc.)
**99.1 -- Form of Letter of Transmittal to tender unregistered 7.164%
Series A Senior Secured Bonds due 2014 and unregistered
8.160% series B Senior Secured Bonds of LSP Energy
Partnership and LSP Batesville Funding Corporation.
**99.2 -- Form of Letter to Registered Holders and DTC Participants
from LSP Energy Limited Partnership and LSP Batesville
Funding Corporation regarding the exchange offer.
**99.3 -- Form of Instruction to Registered Holder or DTC Participant
from Beneficial Owner of 7.164% Senior Secured Bonds due
2014 and/or 8.160% Senior Secured Bonds due 2025 of LSP
Energy Limited Partnership and LSP Batesville Funding
Corporation.
**99.4 -- Form of Letter to Clients from Registered Holder or DTC
Participant regarding the exchange offer.
**99.5 -- Form of Notice of Guaranteed Delivery
</TABLE>
- ------------------------
* To be filed by amendment.
** Previously filed.
<PAGE>
EXHIBIT 5.1
[LETTER OF LATHAM & WATKINS]
February 9, 2000
LSP Energy Limited Partnership
Two Tower Center, 20th Floor
East Brunswick, New Jersey 08816
LSP Batesville Funding Corporation
Two Tower Center, 20th Floor
East Brunswick, New Jersey 08816
Re: Registration Statement on Form S-4;
$326,000,000 Aggregate Principal Amount
of Senior Secured Bonds
Ladies and Gentlemen:
In connection with the registration of $150,000,000 7.164% Series C Senior
Secured Bonds due January 15, 2014 (the "SERIES C BONDS") and $176,000,000
8.160% Series D Senior Secured Bonds due July 15, 2025 (the "SERIES D BONDS"
and, together with the Series C Bonds, the "SECURITIES") by LSP Energy Limited
Partnership, a Delaware limited partnership (the "PARTNERSHIP"), and LSP
Batesville Funding Corporation, a Delaware corporation (the "FUNDING
CORPORATION" and, together with the Partnership, the "COMPANIES"), under the
Securities Act of 1933, as amended (the "ACT"), on Form S-4 filed with the
Securities and Exchange Commission (the "COMMISSION") on August 2, 1999, as
amended by Amendment No. 1 thereto filed with the Commission on December 21,
1999 and Amendment No. 2 thereto filed with the Commission on February 9, 2000
(the "REGISTRATION STATEMENT"), you have requested our opinion with respect to
the matters set forth below.
In our capacity as your special counsel in connection with such
registration, we are familiar with the proceedings taken by the Companies in
connection with the authorization and issuance of the Securities. In addition,
we have made such legal and factual examinations and inquiries, including an
examination of originals or copies certified or otherwise identified to our
satisfaction of such documents, corporate records and instruments, as we have
deemed necessary or appropriate for purposes of this opinion.
In our examination, we have assumed the genuineness of all signatures, the
authenticity of all documents submitted to us as originals, and the conformity
to authentic original documents of all documents submitted to us as copies.
<PAGE>
We are opining herein as to the effect on the subject transaction only of
the internal laws of the State of New York, the General Corporation Law of the
State of Delaware and the Revised Uniform Limited Partnership Act of the State
of Delaware, including statutory and reported decisional law thereunder, and we
express no opinion with respect to the applicability thereto, or the effect
thereon, of the laws of any other jurisdiction or, in the case of Delaware, any
other laws, or as to any matters of municipal law or the laws of any local
agencies within any state.
Capitalized terms used herein without definition have the meanings ascribed
to them in the Registration Statement.
Subject to the foregoing and the other matters set forth herein, it is our
opinion that as of the date hereof:
The Securities have been duly authorized by all necessary partnership action
of the Partnership and all necessary corporate action of the Funding
Corporation, and when executed, authenticated and delivered by or on behalf of
the Companies will constitute legally valid and binding obligations of the
Companies, enforceable against the Companies in accordance with their terms.
The opinions rendered in the preceding paragraph relating to the
enforceability of the Securities are subject to the following exceptions,
limitations and qualifications: (i) the effect of bankruptcy, insolvency,
reorganization, moratorium or other similar laws now or hereafter in effect
relating to or affecting the rights and remedies of creditors and (ii) the
effect of general principles of equity, whether enforcement is considered in a
proceeding in equity or law, and the discretion of the court before which any
proceeding therefor may be brought.
We have not been requested to express, and with your knowledge and consent
do not render, any opinion as to the applicability to the obligations of the
Companies under the Indenture and the Securities of Section 548 of the United
States Bankruptcy Code or applicable state law (including, without limitation,
Article 10 of the New York Debtor and Creditor Law) relating to fraudulent
transfers and obligations.
To the extent that the obligations of the Companies under the Indenture may
be dependent upon such matters, we assume for purposes of this opinion that the
Trustee is duly organized, validly existing and in good standing under the laws
of its jurisdiction of organization; that the Trustee is duly qualified to
engage in the activities contemplated by the Indenture; that the Indenture has
been duly authorized, executed and delivered by the Trustee and constitutes the
legally valid, binding and enforceable obligation of the Trustee enforceable
against the Trustee in accordance with its terms; that the Trustee is in
compliance, generally and with respect to acting as a trustee under the
Indenture, with all applicable laws and regulations; and that the Trustee has
the requisite organizational and legal power and authority to perform its
obligations under the Indenture.
We consent to your filing this opinion as an exhibit to the Registration
Statement and to the reference to our firm contained under the heading "Validity
of the Exchange Bonds."
Very truly yours,
/s/ Latham & Watkins
2
<PAGE>
EXHIBIT 12.1
Computation of ratio of earning to fixed charges
<TABLE>
<CAPTION> For the Period
from Inception
For the Years Ended December 31, (February 7, 1996)
-------------------------------- to
1999 1998 1997 December 31, 1996
----------- ------------ ------------ -----------------
<S> <C> <C> <C> <C>
Net income (loss) (1,504,644.00) (443,725.00) 5,219,879.00 154,461.00
Fixed Charges:
Interest expensed and capitalized 15,196,000.00 1,581,000.00 -- --
Amortized premiums, discounts and
capitalized expenses related to
indebtedness 3,812,139.00 234,000.00 -- --
Interest factor of operating rents -- -- -- --
Preference security dividend -- -- -- --
------------- ------------ ------------ -------------
Total Fixed Charges 19,008,138.00 1,815,000.00 -- --
------------- ------------ ------------ -------------
Amortization of capitalized interest -- -- -- --
Distributed Income of equity investments -- -- -- --
Sub-total 17,503,445.00 1,371,275.00 5,219,879.00 154,461.00
Interest capitalized 19,008,139.00 1,815,000.00 -- --
-------------- ------------- ------------- ------------
Earnings (1,504,694.00) (443,725.00) 5,219,879.00 154,461.00
-------------- ------------- ------------- ------------
Fixed Charges 19,008,139.00 1,815,000.00 -- --
(0.08) (0.24) N/A N/A
Deficiency 20,512,833.00 2,258,725.00 (5,219,879.00) (154,461.00)
</TABLE>
<PAGE>
EXHIBIT 23.2
INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS' CONSENT
LSP Energy Limited Partnership,
LSP Batesville Funding Corporation and
LSP Energy, Inc.:
We consent to the use of our reports included herein and to the reference to
our firm under the heading "Experts" in the registration statement.
KPMG LLP
Billings, Montana
February 7, 2000
<PAGE>
EXHIBIT 23.3
INDEPENDENT ENGINEER'S CONSENT
February 9, 2000
LSP Energy Limited Partnership
LSP Batesville Funding Corporation
Two Tower Center, 20th Floor
East Brunswick, New Jersey 08816
This letter is furnished relating to (1) the exchange of $150,000,000
principal amount of 7.164% Series A Senior Secured Bonds due January 15, 2014
(the "SERIES A BONDS") for $150,000,000 principal amount of 7.164% Series C
Senior Secured Bonds due January 15, 2014 (the "SERIES C BONDS"), and (2) the
exchange of $176,000,000 principal amount of 8.160% Series B Senior Secured
Bonds due July 15, 2025 (the "SERIES B BONDS" and, together with the Series A
Bonds, the "INITIAL BONDS") for $176,000,000 principal amount of 8.160% Series D
Senior Secured Bonds due July 15, 2025 (the "SERIES D BONDS" and, together with
the Series C Bonds, the "EXCHANGE BONDS").
We were retained as the Independent Engineer to LSP Energy Limited
Partnership, a Delaware limited partnership (the "PARTNERSHIP"), and LSP
Batesville Funding Corporation, a Delaware corporation (the "FUNDING
CORPORATION" and, together with the Partnership, the "ISSUERS"), in connection
with the issuance by the Issuers of the Initial Bonds pursuant to the Trust
Indenture, dated as of May 21, 1999, among the Issuers and The Bank of New York,
as Trustee. We prepared an Independent Engineers' Report dated May 13, 1999 (the
"REPORT"), which is included as Annex B to the Registration Statement, as
amended by Amendment No. 2 thereto, being filed by the Issuers in respect of the
Exchange Bonds (the "REGISTRATION STATEMEMT"). Such Report contains facts,
opinions and conclusions of R.W. Beck, Inc. and is subject to various
qualifications, assumptions and conditions applicable thereto. Further, such
report is valid as of May 13, 1999.
On the basis of the foregoing, we consent to the inclusion of the Report in
the Registration Statement and to the other references to us contained in the
Prospectus which is part of the Registration Statement.
<TABLE>
<S> <C> <C>
R.W. BECK, INC.
By: /s/ KENNETH V. MARINO
-----------------------------------------
Name: Kenneth V. Marino
Title: Principal
</TABLE>
<PAGE>
EXHIBIT 23.4
[LETTERHEAD OF C.C. PACE CONSULTING, L.L.C.]
POWER MARKET CONSULTANT'S CONSENT
February 9, 2000
LSP Energy Limited Partnership
LSP Batesville Funding Corporation
Two Tower Center, 20th Floor
East Brunswick, New Jersey 08816
This letter is furnished relating to (1) the exchange of $150,000,000
principal amount of 7.164% Series A Senior Secured Bonds due January 15, 2014
for $150,000,000 principal amount of 7.164% Series C Senior Secured Bonds due
January 15, 2014 (the "SERIES C BONDS"), and (2) the exchange of $176,000,000
principal amount of 8.160% Series B Senior Secured Bonds due July 15, 2025 for
$176,000,000 principal amount of 8.160% Series D Senior Secured Bonds due July
15, 2025 (the "SERIES D BONDS" and, together with the Series C Bonds, the
"EXCHANGE BONDS").
We consent to the inclusion of our report dated May 13, 1999 regarding the
southeastern power market in the Registration Statement, as amended by Amendment
No. 2 thereto, being filed by LSP Energy Limited Partnership and LSP Batesville
Funding Corporation in respect of the Exchange Bonds and to the other references
to us contained in the Prospectus which is part of such Registration Statement.
<TABLE>
<S> <C> <C>
C.C. PACE CONSULTING, L.L.C.
By: /s/ MARK A. PETERSON
-----------------------------------------
Name: Mark A. Peterson
Title: President
</TABLE>
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION FROM THE BALANCE SHEETS AND
STATEMENTS OF OPERATIONS OF LSP ENERGY LIMITED PARTNERSHIP AS OF ANF FOR THE
PERIOD ENDED DECEMBER 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0001092435
<NAME> LSP ENERGY LIMITED PARTNERSHIP
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 203
<SECURITIES> 53,547
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 734
<CURRENT-ASSETS> 54,658
<PP&E> 296,509
<DEPRECIATION> 0
<TOTAL-ASSETS> 361,266
<CURRENT-LIABILITIES> 37,214
<BONDS> 326,000
0
0
<COMMON> 0
<OTHER-SE> (1,947)
<TOTAL-LIABILITY-AND-EQUITY> 361,266
<SALES> 0
<TOTAL-REVENUES> 0
<CGS> 0
<TOTAL-COSTS> 1,505
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (1,505)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,505)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,505)
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTANS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE BALANCE
SHEETS AND STATEMENTS OF OPERATIONS OF LSP BATESVILLE FUNDING CORPORATION AS OF
AND FOR THE PERIOD ENDED DECEMBER 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINAINCIAL STATEMENTS.
</LEGEND>
<CIK> 0001092435
<NAME> LSP BATESVILLE FUNDING CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 1
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1
<PP&E> 0
<DEPRECIATION> 0
<TOTAL-ASSETS> 0
<CURRENT-LIABILITIES> 6
<BONDS> 0
0
0
<COMMON> 1
<OTHER-SE> (6)
<TOTAL-LIABILITY-AND-EQUITY> 1
<SALES> 0
<TOTAL-REVENUES> 0
<CGS> 0
<TOTAL-COSTS> 6
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (6)
<INCOME-TAX> 0
<INCOME-CONTINUING> (6)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (6)
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE BALANCE
SHEETS AND STATEMENTS OF OPERATIONS OF LSP ENERGY, INC. AS OF AND FOR THE PERIOD
ENDED DECEMBER 31, 1999 AND IS QULAIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0001092436
<NAME> LSP ENERGY, INC.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 1
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1
<PP&E> 0
<DEPRECIATION> 0
<TOTAL-ASSETS> 1
<CURRENT-LIABILITIES> 32
<BONDS> 0
0
0
<COMMON> 1
<OTHER-SE> (32)
<TOTAL-LIABILITY-AND-EQUITY> 1
<SALES> 0
<TOTAL-REVENUES> 0
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 0
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
