Filed pursuant to Rule 424(b)(3)
Registration Nos. 333-76526
333-76526-01
333-76526-02
PROSPECTUS
Elwood Energy LLC
Exchange Offer
8.159% Senior Secured Bonds due 2026
------------
Exchange Offer We are offering to exchange new bonds registered with
the SEC for existing bonds we previously issued in an
offering exempt from the SEC's registration
requirements. The terms and conditions of the exchange
offer are summarized below and more fully described in
the prospectus. We will not receive any proceeds from
this exchange offer, and we will pay all expenses
associated with registering the new bonds.
Expiration Date 5:00 p.m. (New York City time) on March 14, 2002.
Withdrawal Rights Any time before 5:00 p.m. (New York City time) on the
expiration date.
New Bonds The new bonds will have the same financial terms as the
existing bonds. Interest on the new bonds will be
payable on January 5 and July 5. The new bonds will not
contain transfer restrictions. We do not plan to list
the new bonds on any securities exchange.
U.S. Federal Income We believe the exchange of existing bonds for new bonds
Tax Considerations will not be a taxable event for U.S. federal income tax
purposes, but you should read "Federal Income Tax
Considerations" for more information.
Use of Prospectus by Each broker-dealer that receives new bonds for its own
Broker-Dealers account in this exchange offer must acknowledge that it
will deliver a prospectus in connection with any resale
of the new bonds. The letter of transmittal to be used
in connection with the exchange offer states that the
broker-dealer will not be deemed to admit that it is an
"underwriter" within the meaning of the Securities Act
of 1933 by so acknowledging and delivering a
prospectus. This prospectus, as amended and
supplemented from time to time, may be used by a
broker-dealer for resales of new bonds received in
exchange for existing bonds if the existing bonds were
acquired by the broker-dealer as a result of market-
making or other trading activities. We have agreed that
we will make this prospectus available to any broker-
dealer for use in connection with any such resale for
90 days after the expiration date. For more
information, see "Plan of Distribution".
Investing in the bonds involves risk. See "Risk Factors" beginning on page
24.
We are relying on the position of the SEC staff in certain interpretive
letters to third parties to remove transfer restrictions on the new bonds.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or passed upon the
adequacy or accuracy of this prospectus. Any representation to the contrary is
a criminal offense.
The date of this prospectus is January 31, 2002.
----------------
TABLE OF CONTENTS
Page
----
Prospectus Summary.................. 1
Risk Factors........................ 24
Cautionary Statements Regarding
Forward-Looking Information........ 31
The Exchange Offer.................. 32
Proceeds............................ 41
Capitalization...................... 41
Selected Historical Financial Data.. 42
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 43
Our Business and Regulatory
Environment........................ 45
Ownership and Management............ 54
Certain Relationships and Related
Transactions....................... 56
Description of the Principal Project
Documents.......................... 57
Page
----
Description of the New Bonds....... 95
Description of the Principal
Financing Documents............... 101
Federal Income Tax Considerations.. 117
Plan of Distribution............... 121
Legal Matters...................... 122
Experts ........................... 122
Independent Engineer............... 122
Independent Power Market and Fuel
Consultant........................ 122
Where You Can Find More
Information....................... 123
Elwood Energy LLC Financial
Statements........................ F-1
Annex A--Definitions
Annex B--Independent Engineer's
Report
Annex C-1--Power Market Report
Annex C-2--Fuel Consultant's Report
----------------
The bonds offered by this prospectus are obligations of Elwood Energy LLC
and are not guaranteed by anyone else. We are required by the financing
documents governing the bonds to maintain a debt service reserve account.
Instead of depositing cash to meet this requirement, we may furnish a letter of
credit or guaranty. For a more detailed discussion of this requirement, see
"Description of the Principal Financing Documents--Deposit and Disbursement
Agreement" beginning on page 110 in the prospectus. We have initially elected
to provide several guaranties of Dominion Resources, Inc. and Peoples Energy
Corporation to meet this requirement. This prospectus incorporates by reference
documents containing important business and financial information concerning
Dominion Resources and Peoples Energy. You may obtain this information without
charge from Dominion Resources or Peoples Energy by written or oral request as
described under "Where You Can Find More Information" on page 123. To obtain
timely delivery of this information, you should make your request by March 7,
2002.
PROSPECTUS SUMMARY
In this prospectus, the words "Company", "we", "our", "ours" and "us" refer
only to Elwood Energy LLC and not to any of our parent or sister companies or
anyone else. The following summary contains basic information about us and the
exchange offer. 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 bonds that we are offering, you should read carefully this entire
prospectus and the other documents that we will refer you to.
THE EXCHANGE OFFER
On October 23, 2001, we completed an offering of $402,000,000 of 8.159%
Senior Secured Bonds due 2026. That offering was exempt from the SEC's
registration requirements. In connection with that offering, we entered into a
registration rights agreement with the initial purchasers that obligated us to
use our reasonable best efforts to complete this exchange offer within 270
days.
Terms of the Exchange. Following the initial scheduled principal payment
date on January 5, 2002, $396,400,140 of the existing bonds remain outstanding.
We are offering to exchange equal principal amounts of 8.159% Senior Secured
Bonds due 2026 that have been registered under the Securities Act for all
currently outstanding bonds. The form and terms of the new bonds will be
identical to those of the existing bonds, except that the new bonds have been
registered under the Securities Act and will not bear legends restricting their
transfer. The new bonds will be issued under the same indenture and will be
secured by the same assets. The new bonds will be issued in a minimum amount of
$100,000 and in multiples of $100.00 in excess of $100,000, and may be
exchanged for existing bonds only in those amounts.
Interest on the Bonds. The new bonds will bear interest from January 5,
2002, the most recent date to which interest has been paid on the existing
bonds. If your existing bonds are accepted for exchange, then you will receive
interest on the new bonds and not on the existing bonds.
Resale of the New Bonds. Based on SEC staff interpretations in no-action
letters to third parties, we believe that the new bonds may be offered for
resale, resold or otherwise transferred by you without compliance with the
registration and prospectus delivery requirements of the Securities Act so long
as:
. you are acquiring the new bonds in the ordinary course of your business;
. you are not participating, do not intend to participate and have no
agreement or understanding with any person to participate, in a
distribution of the new bonds;
. you are not a broker or dealer who purchased existing bonds for resale
under Rule 144A or any other available exemption under the Securities
Act; and
. you are not our "affiliate" (as defined in Rule 405 under the Securities
Act).
If our belief is inaccurate and you transfer any new bond without delivering
a prospectus meeting the requirements of the Securities Act or without an
exemption from registration under the Securities Act, you may incur liability
under the Securities Act. We do not assume or indemnify you against that
liability.
Each broker-dealer that receives new bonds for its own account in this
exchange offer must acknowledge that it will deliver a prospectus in connection
with any resale of the new bonds. The letter of transmittal to be used in
connection with the exchange offer states that the broker-dealer will not be
deemed to admit that it is an "underwriter" within the meaning of the
Securities Act by so acknowledging and delivering a prospectus. This
prospectus, as amended and supplemented from time to time, may be used by a
broker-dealer for resales
1
of new bonds received in exchange for existing bonds if the existing bonds were
acquired by the broker-dealer as a result of market-making or other trading
activities. We have agreed that we will make this prospectus available to any
broker-dealer for use in connection with any such resale for 90 days after the
expiration date. For more information, see "Plan of Distribution".
Accepting the Exchange Offer. If you wish to exchange an existing bond, you
must properly tender it in accordance with the terms described in this
prospectus. We will exchange all existing bonds that are validly tendered, and
not validly withdrawn, before the expiration date, subject to the conditions
described under "The Exchange Offer--Conditions to the Exchange Offer". We will
issue new bonds on, or promptly after, the expiration date.
Expiration Date. The expiration date of the exchange offer will be 5:00 p.m.
(New York City time) on March 14, 2002.
Withdrawal Rights. You may withdraw your tender of existing bonds at any
time before the expiration date.
Conditions. The exchange offer is not contingent on any minimum amount of
existing bonds being tendered for exchange. We may terminate the exchange offer
or amend its terms if we determine at any time that the exchange offer may
violate any applicable law, regulation or interpretation of the SEC staff or if
the registration statement of which this prospectus is a part is subject to any
SEC stop order.
Procedures for Tendering Bonds. If you wish to tender your bonds, you must
forward to the exchange agent before the expiration date
. a properly completed and duly executed letter of transmittal, with any
required signature guarantees, including all documents required by the
letter of transmittal; or
. if the existing notes are tendered in accordance with the book entry
procedures described in this prospectus, an agent's message instead of a
letter of transmittal
together with
. your existing bonds; or
. a timely book entry confirmation of transfer of the existing notes into
the exchange agent's account at the Depositary Trust Company; or
. the documentation required by the guaranteed delivery procedures
described in this prospectus.
Note to Beneficial Owners. If you are a beneficial owner of existing bonds
that are held by or registered in the name of a broker, dealer, commercial
bank, trust company or other nominee or custodian, you must contact the record
holder promptly if you wish to participate in this exchange offer.
Guaranteed Delivery Procedures. If you wish to tender existing bonds and
. they are not immediately available; or
. time will not permit delivery of the existing bonds and all required
documentation to the exchange agent before the expiration date; or
. you cannot complete the procedures for book entry transfer on a timely
basis
you may nevertheless validly tender the existing bonds if you comply with all
the guaranteed delivery procedures set forth in "The Exchange Offer--Procedures
for Tendering Existing Notes".
2
U.S. Federal Income Tax Consequences. We believe the exchange of existing
bonds for new bonds will not be a taxable event for U.S. federal income tax
purposes. For additional information and a discussion of other U.S. federal
income tax consequences of exchanging, acquiring, owning and disposing of the
new bonds, see "Federal Income Tax Considerations".
Proceeds. We will not receive any proceeds from the issue of the new bonds
in the exchange offer. We will pay all costs of registering the new bonds and
all fees and expenses of our counsel, accountants and the exchange agent in
connection with the exchange offer.
Exchange Agent. The exchange agent is Bank One Trust Company, National
Association. Its address is 1 Bank One Plaza, Mail Code IL 1-0124, Chicago,
Illinois 60670-0124, Attention: Exchange Floor, Global Corporate Trust
Services.
THE COMPANY
Elwood Energy LLC. We are a Delaware limited liability company formed in
1998 for the purpose of developing, constructing, owning and operating a
natural gas-fired, electric generation peaking facility in Elwood, Illinois,
about 50 miles southwest of Chicago. We are indirectly owned in equal shares by
Dominion Energy, Inc. ("DEI") and Peoples Energy Resources Corp. ("PERC"). DEI
is the principal independent power subsidiary of Dominion Resources, Inc., a
fully integrated gas and electric holding company with nearly 4 million
customers, a 22,000 megawatt portfolio of electric power generation, 7,600
miles of gas transmission pipeline and an over 950 billion cubic foot natural
gas storage network. PERC is a wholly-owned subsidiary of Peoples Energy
Corporation, a diversified energy holding company which, through its
subsidiaries, engages principally in natural gas utility operations and other
energy businesses. Peoples Energy Corporation has assets of approximately $3.1
billion and serves approximately one million retail customers through a 6,000-
mile distribution system in the City of Chicago and 54 other communities in
northeastern Illinois.
Our Facility. Our facility is a 1,409 megawatt electric generation peaking
facility, consisting of nine natural gas-fired, simple-cycle units of
approximately 156.5 megawatts each. Natural gas-fired units use natural gas as
a fuel; simple-cycle units use natural gas-fired turbines to generate
electricity on a stand-alone basis. Units 1-4 were completed in 1999 and have
been in operation since then. Construction on Units 5-9 began in July 2000, and
they reached commercial operation between May and July 2001. All nine units
were built by General Electric Company under fixed price, turnkey contracts and
use GE-7FA combustion turbines. See "Our Business and Regulatory Environment--
Description of Facility."
3
Ownership Structure. The following chart details our ownership structure:
[OWNERSHIP STRUCTURE CHART]
Project Participants. The following table identifies some of the principal
customers and suppliers of, and participants in, our Facility:
[PROJECT PARTICIPANTS CHART]
Aquila/UtiliCorp............ Aquila Energy Marketing Corporation ("AEMC") and
UtiliCorp United, Inc. ("UtiliCorp"), which
together are responsible for the purchase of
energy and capacity of Units 5-8.
Cinergy..................... Cinergy Marketing & Trading LLC, with which we
have an agreement for fuel supply and management
for our facility.
4
ComEd....................... Commonwealth Edison Company, which supplies
interconnection services for electric
transmission for our facility.
DEI......................... Dominion Energy, Inc., one of our indirect
owners.
DELSCO...................... Dominion Elwood Services Company, Inc., a wholly-
owned subsidiary of DEI that provides operation
and maintenance services for us.
Dominion Elwood, Inc. ...... A wholly-owned subsidiary of DEI and the holder
of a 50% membership interest in us.
Elwood II Holdings.......... Elwood II Holdings, LLC, our wholly-owned
subsidiary, which is a party to two turbine
procurement agreements with GE and an equipment
sales agreement with us covering the turbines for
Units 5-6.
Elwood III Holdings......... Elwood III Holdings, LLC, our wholly-owned
subsidiary, which is a party to two turbine
procurement agreements with GE and two equipment
sales agreements with us covering the turbines
for Units 7-9.
Engage...................... Engage Energy America LLC, successor to the
original purchaser of energy and capacity of
Units 1-2. Engage has sold the energy and
capacity to Exelon and has appointed Exelon as
its agent to dispatch the units.
Exelon...................... Exelon Generation Company, LLC, which is
responsible for the purchase of energy and
capacity of Units 1-4 and 9.
GE.......................... General Electric Company, the engineering,
procurement and construction contractor for our
Facility.
Moody's..................... Moody's Investors Service, Inc.
Nicor....................... Northern Illinois Gas Company d/b/a Nicor Gas
Company, which supplies gas transportation and
balancing services for our Facility.
PERC........................ Peoples Energy Resources Corp., one of our
indirect owners.
PGL......................... The Peoples Gas Light and Coke Company, an
affiliate of PERC, which owns the 24-inch
pipeline through which natural gas is physically
delivered to us.
Pace........................ Pace Global Energy Services, LLC, the independent
power market and fuel consultant, which has
prepared the reports included as Annex C-1 and
Annex C-2 to this prospectus.
Peoples Elwood, LLC......... A wholly-owned subsidiary of PERC and the holder
of a 50% membership interest in us.
S&P......................... Standard & Poor's Ratings Group
Stone & Webster............. Stone & Webster Consultants, Inc., the
independent engineer, which has prepared the
report included as Annex B to this prospectus.
5
Selected Consolidated Financial Data
The following summary historical financial data was derived from the audited
historical consolidated financial statements of the Company.
Years Ended September 30,
-----------------------------------
2001 2000 1999 1998
-------- -------- -------- -------
Statement of Operations Data:
Operating Revenues....................... $ 96,467 $ 56,849 $ 25,593 $ --
Income before cumulative effect of a
change in accounting principle.......... 49,214 30,356 17,028 --
Balance Sheet Data:
Total assets............................. 581,398 350,913 220,953 28,409
Long-term obligations.................... 14,437 130,126 -- --
Other Data:
Ratio of earnings to fixed charges (1)... 4.1x 11.9x -- --
Intercompany transactions have been eliminated.
- --------
(1) In computing the ratio of earnings to fixed charges, "earnings" are
determined by adding total fixed charges (including interest capitalized)
and amortization of interest capitalized to income before cumulative effect
of a change in accounting principle. "Fixed charges" consist of interest
charges and interest capitalized. Since the bonds were not issued until
October 2001, historical ratio computations do not include debt service
obligations associated with them.
Power Sales. We have entered into four long-term power sales agreements with
three purchasers as shown in the table on the following page. The power sales
agreements provide for payment to us of (1) a monthly fixed fee "capacity
charge" based on the tested capacity of the units, as adjusted for the
performance reliability of our facility to meet dispatch; and (2) an energy
payment composed of a fuel charge based on a published index price of gas and
our facility's heat rate, plus certain variable operating and maintenance
expenses. The overall effect of these contracts is to index energy pricing to
the market price of natural gas, thereby mitigating our natural gas price risk.
6
Units Units 1-2 Units 1-4 & 9 Units 5-6 Units 7-8
- -----------------------------------------------------------------------------------------------------------
Summer Capacity 313 MW (sold 783 MW (includes 313 MW 313 MW
by Engage to 313 MW purchased
Exelon) from Engage through
2004)
- -----------------------------------------------------------------------------------------------------------
Term Through Units 1-2: 1/1/05 Through 08/31/16 Through 08/31/17
12/31/04 through 12/31/12
(During Units 3-4: Through
remaining 12/31/12
term, Engage Unit 9: Through
PSA is trued 12/31/12
up to the
economics of
Exelon PSA)
- -----------------------------------------------------------------------------------------------------------
Extension Term None None 09/01/16-08/31/21 09/01/17-08/31/22
(at (at
Aquila/UtiliCorp's Aquila/Utilicorp's
option) option)
- -----------------------------------------------------------------------------------------------------------
Rating/Security Parent Exelon (Baa1/A-) UtiliCorp UtiliCorp (Baa3/BBB)
Guarantee by (Baa3/BBB) is co- is co-obligor. If
Westcoast obligor. If UtiliCorp's rating
Energy, Inc UtiliCorp's rating falls below
(NR/A-) for falls below investment grade, a
$67 million investment grade, six month capacity
(tied to a six month charge LC is
capacity capacity charge LC required. More of a
payment is required. More downgrade requires a
obligations; of a downgrade 12 month LC.
declines over requires a 12
time) month LC.
- -----------------------------------------------------------------------------------------------------------
Key Terms
Dispatch limit (per 1,500 hours 1,500 hours per 2,500 hours per 2,500 hours per year
unit): per year year (Unit 9 @ year
1,400 for 2001)
Guaranteed availability: 95% Summer 97% Summer 97% Summer 97% Summer
Minimum load: 60% 60% 60% 60%
Contracted heat rate: N/A 10,900 Btu/kWh 10,787 Btu/kWh 10,787 Btu/kWh
Dispatch Notice: One hour/Jun- One hour/Jun-Sep One hour & 25 One hour & 25
Sep 0600-2200, 0600-2200, Mon-Fri minutes/Jun-Aug minutes/Jun-Aug
Mon-Fri Three Four hours/All 0600-2200, Mon-Sat 0600-2200, Mon-Sat
hours/All other periods Three hours/Sep Three hours/Sep Day
other periods Day ahead/All ahead/All other
other
- -----------------------------------------------------------------------------------------------------------
Capacity Charge $5.00/kW-m Jan-May: $2.72/kW-m Through Dec 2001: Through Dec 2001:
(in kW per month) Jun: $6.53/kW-m 7.90/kW-m $7.39/kW-m Jan 2002-
Jul-Aug: $9.79/kW-m Jan 2002-Aug 2016: Aug 2017: $5.11/kW-m
Sep: $4.35/kW-m $5.11/kW-m Sep 2017-Aug 2022:
Oct-Dec $2.72/kW-m Sep 2016-Aug 2021: $4.90/kW-m
$4.90/kW-m
- -----------------------------------------------------------------------------------------------------------
Energy Charge $30-$35 per Fuel Charge + Fuel Charge + Fuel Charge +
MWh $1.50/MWh $1.00/MWh $1.00/MWh (escalated)
(before Exelon (escalated) (escalated)
true-up)
- -----------------------------------------------------------------------------------------------------------
Fuel Charge
Base Fuel Charge: N/A Fuel Index Value + Fuel Index Value + Fuel Index Value +
32(cents)/MMBtu 10(cents)/MMBtu 10(cents)/MMBtu
Changes to day-ahead N/A Fuel Index Value + Fuel Index Value + Fuel Index Value +
schedule (Summer/Peak): 32(cents)/MM Btu 15(cents)/MMBtu 15(cents)/MMBtu
Changes to day-ahead N/A Base Fuel Charge + Base Fuel Charge + Base Fuel Charge +
schedule 32(cents)/MM Btu + Quoted applicable Quoted applicable
(Non-Summer/Non-Peak): applicable volumetric volumetric balancing
volumetric balancing cost cost
balancing cost
- -----------------------------------------------------------------------------------------------------------
Start-up Charge: $2,500 $3,250 (escalated) $2,500 (escalated) $2,500 (escalated)
- -----------------------------------------------------------------------------------------------------------
Fuel Index Value = Gas Daily, Daily Price Survey, Midpoint for Chicago-LDCs,
large end users
7
Our agreement with Engage covers Units 1-2 through December 31, 2004; our
agreement with Exelon covers Units 3, 4 and 9 through December 31, 2012 and
Units 1-2 from January 1, 2005 through December 31, 2012; and our two
agreements with Aquila/UtiliCorp cover Units 5-6 and 7-8 for terms expiring on
August 31, 2016 and August 31, 2017, respectively. Aquila/UtiliCorp may extend
the term of each of its contracts by an additional five years at its option. In
connection with its analysis of the Mid-America Interconnected Network ("MAIN")
electric power market, Pace has concluded that based on the payment structure
of the Aquila/UtiliCorp power sales agreements, our facility's forecast
dispatch profile, forecast market-clearing prices and the energy and capacity
revenues and volatility values for Aquila/UtiliCorp from reselling the output
and capacity of Units 5-8, it is likely that Aquila/UtiliCorp will have
economic incentives to exercise these extension options. See "Annex C-1--
Executive Summary--Power Sales Agreements--Extension of Aquila Power Sales
Agreements."
When our agreements with Exelon and Aquila/UtiliCorp expire, we plan to
enter into new long-term power sales agreements (by extending or renewing
contracts with our existing customers or entering into new third party
contracts). If we cannot enter into long-term power sales agreements, we will
sell the capacity and energy from our facility on a "merchant" basis. Merchant
marketing may involve the sale of the capacity and energy of the facility on a
shorter-term "spot" basis and/or the use of hedging products to manage
volatility.
Engage has sold the energy and capacity of Units 1 and 2 during the
remaining term of its contract with us to Exelon and has appointed Exelon as
its agent to dispatch the units. We have entered into a "true up" arrangement
with Exelon that puts both of us in essentially the same economic position as
would exist if Units 1 and 2 were currently part of the Exelon contract. The
"true up" calculates the differences between various pricing and operational
parameters of our agreement with Engage and those in our agreement with Exelon.
The difference will appear as an increase or a decrease to the monthly payment
calculation under the Exelon agreement such that the ultimate cost of Exelon's
purchase of energy and capacity from Engage for Units 1 and 2 is effectively
the same as if Exelon purchased the capacity and energy of Units 1 and 2
directly from us under its agreement with us. We continue to bill, and receive
payments from, Engage, in accordance with the terms of our agreement with
Engage. So long as all parties perform their obligations, we are in essentially
the same position we would be if the Exelon power sales agreement already
covered all five units.
Exelon and Aquila/UtiliCorp have exclusive rights to dispatch the units to
which their respective contracts apply, but they must provide advance notice
approximately one hour before start-up in the summer peak period hours and four
hours before start-up in all other periods. Once dispatched, the units must
generally run for no less than four hours. For a more complete description of
our power sales agreements, see "Description of the Principal Project
Documents--Power Sales Agreements."
Exelon is the largest competitive electric generation company in the United
States, as measured by owned and controlled megawatts. Exelon owns generation
assets in the Mid-Atlantic and Midwest regions with net capacity of 19,159 MW,
including 13,949 MW of nuclear capacity. Exelon also controls another 16,013 MW
of capacity in the Midwest, Southeast and South Central regions through long-
term power purchase agreements. Exelon has a 49.9% interest in Sithe Energies
which owns and operates generation facilities and currently has 9,879 MW of
capacity in operation, under construction or in advanced development. In
addition, Exelon owns a 50% interest in AmerGen Energy Company, LLC, which owns
three nuclear stations with a total generation capacity of 2,378 MW.
The Exelon Power Team division is a major wholesale marketer of energy that
uses Exelon's generation portfolio, transmission rights and expertise to
provide generation to wholesale customers under long and short-term contracts.
ComEd and Exelon are both units of Chicago-based Exelon Corporation, one of
the nation's largest electric utilities. ComEd provides electric service to
more than 3.4 million customers across Northern Illinois, covering 70 percent
of the state's population.
8
Exelon's long term unsecured debt is rated "Baa1" by Moody's Investors
Service, Inc. ("Moody's") and "A-" by Standard & Poor's Ratings Group ("S&P").
Engage Energy US, LP was originally formed in 1997 as a joint venture of the
Coastal Corporation of Houston, Texas and Westcoast Energy Inc. of Vancouver,
Canada. Engage Energy US, LP offered a range of energy services, including
natural gas marketing and trading, electricity trading and sales, energy
management services, structured storage and transportation related services.
The joint venture was terminated on September 25, 2000. Following the
termination, Westcoast Energy Inc. retained the right to use the Engage Energy
name and certain natural gas and electric power endeavors. Westcoast Energy
Inc. has substituted Engage Energy America LLC as the contract party in the
power sales agreement with us. Westcoast Energy's long-term unsecured debt is
rated "A-" by S&P and is unrated by Moody's.
AEMC is a subsidiary of Aquila, Inc. which is based in Kansas City.
UtiliCorp is the majority owner of Aquila, Inc. Aquila, Inc. is a leading
wholesale energy merchant with a geographically diverse asset base and
transportation network that includes electric power generation plants; natural
gas gathering, transportation, processing and storage assets; and a coal
blending and storage facility. UtiliCorp is a gas and electric utility serving
over four million customers. UtiliCorp's long term unsecured debt is rated
"Baa3" by Moody's and "BBB" by S&P.
Fuel Supply. We have contracted for the purchase of firm gas supplies, as
needed and generally only when our facility consumes gas, at a daily spot gas
price under a fuel supply and management agreement with Cinergy. Pricing under
this agreement references a published daily spot price, plus a nominal premium,
which corresponds to the rate we charge for energy sold under our power sales
agreements with Exelon and Aquila/UtiliCorp. Cinergy uses our retail gas
agreement with Nicor to acquire gas supplies from the interstate pipelines
described below, Nicor storage, Nicor supply or other sources at the Chicago
hub to deliver supplies to Nicor and PGL for our facility's account. Under the
Nicor contract, Cinergy may procure interstate supplies from Northern Border
Pipeline Company ("NBPL"), Alliance Pipeline Company ("APL") or Natural Gas
Pipeline Company of America ("NGPL"). These interstate pipelines allow Cinergy
to acquire supplies from an array of supply regions, including Western Canada,
the U.S. Rocky Mountains, the Mid-Continent region, and Gulf Coast sources, at
the Chicago hub.
The Cinergy contract terminates on April 30, 2002. The Cinergy service was
bid and awarded in February 2001 at a time when natural gas supply prices were
abnormally high. Natural gas prices have since declined and we have completed
our first summer of operations as an expanded facility. We therefore believe we
have the opportunity to enter into a contract on more favorable terms for a
multi-year period with Cinergy or another national energy marketing company.
For a more detailed description of our agreement with Cinergy, see "Description
of the Principal Project Documents--Fuel Agreements."
We believe we will have an ample supply of natural gas for our Facility. As
our independent fuel consultant, Pace, has noted, we currently have the
flexibility to acquire abundant gas supplies from numerous sources. A number of
high pressure, high deliverability gas pipelines interconnect near Chicago and
are linked to gas reserves in upstream basins. Pace expects that the gas
resources from these basins will continue to be available through the term of
the bonds. In addition, the development of liquid trading points throughout the
United States and Canada and the Midwest's favorable location on the natural
gas transportation grid should facilitate access to diverse sources and
flexibility in meeting specific supply requirements. See "Annex C-2 --Risks and
Risk Mitigation--Adequacy of Supply."
Cinergy Corp., Cinergy's parent company, is a leading diversified energy
company with year 2000 revenues of $8.4 billion. Cinergy Corp. has physical and
financial gas trading capabilities of 35 billion cubic feet per day, and its
regulated operations serve 500,000 gas customers. Cinergy's long term unsecured
debt is rated "Baa2" by Moody's and "BBB+" by S&P.
9
Gas Pipeline Interconnections and Fuel Transportation Services. PGL is the
owner and operator of the pipeline delivering gas to the Facility, but Nicor
holds the utility franchise for gas delivery services in the region where our
facility is located. We have entered into a long-term transportation and
storage balancing service agreement with Nicor for firm (non-interruptible)
hourly delivery of fuel supplies to meet the firm power dispatch obligations at
the Facility. Because Nicor only owns meters at our facility, Nicor renders
this service with the support of PGL, through a companion agreement that
contains substantially the same terms and conditions as our agreement with
Nicor. See "Description of the Principal Project Documents--Fuel Agreements--
Nicor Transportation & Balancing Agreement."
Nicor's year 2000 revenues were $2.3 billion. It provides natural gas
service to more than 5.7 million people through a 29,000 mile distribution
system. Nicor's long term unsecured debt is rated "A1" by Moody's and "AA" by
S&P.
Electric Interconnection. Interconnection to the electric power grid is
provided by ComEd via a switchyard that we have constructed. See "Description
of the Principal Project Documents--Interconnection Agreements." Transmission
service beyond the interconnection point is currently the responsibility of our
customers.
Water Supply. The water supply for the Facility comes from wells on adjacent
property owned by PERC. Our simple-cycle units require limited amounts of water
in connection with their operations. PERC also provides other facility support
and services to our Facility. See "Description of the Principal Project
Documents--Common Facilities Agreement."
Operations and Maintenance. We have no employees of our own. Operations and
maintenance support is furnished by DELSCO under an operation and maintenance
agreement which provides for the payment of an annual fee of $650,000, indexed
to inflation, plus reimbursement for out-of-pocket costs. See "Description of
the Principal Project Documents--Operations and Maintenance Agreement."
Regulation. We have been certified as an exempt wholesale generator by the
Federal Energy Regulatory Commission and are subject to its jurisdiction as to
wholesale electric rates and other matters. We engage solely in wholesale sales
of electricity to our power customers and are currently authorized to sell to
such customers at market-based rates. Because of the nature of our business, we
are subject to extensive environmental regulation. We are in material
compliance with all applicable federal, state and local environmental laws and
regulations. See "Our Business and Regulatory Environment--Competition and
Energy Regulation and --Environmental Regulation."
Risk Factors. We operate only a single facility in a heavily regulated
environment that is currently subject to intense public scrutiny because of the
volatile electric power market that prevailed in California during the past
year. We are dependent on a limited number of customers and suppliers of fuel
and services for the successful operation of our business. Investing in the
bonds therefore involves operating, market, regulatory, financial and
bankruptcy risks that are more fully described under "Risk Factors."
10
The New Bonds
Securities Offered...... $396,400,140 principal amount of 8.159% Senior Secured
Exchange Bonds due 2026.
Issuer.................. Elwood Energy LLC
Maturity Date........... July 5, 2026.
Interest Payment Dates.. January 5 and July 5
Scheduled Principal We will be required to pay principal of the bonds every
Payments................ six months on each January 5 and July 5, as follows:
Percentage
of Principal
Payment Date Amount Payable*
------------ ---------------
Jan 5, 2002.......................... 1.393%
Jul 5, 2002.......................... 0.632
Jan 5, 2003.......................... 2.903
Jul 5, 2003.......................... 0.530
Jan 5, 2004.......................... 2.998
Jul 5, 2004.......................... 0.669
Jan 5, 2005.......................... 3.194
Jul 5, 2005.......................... 0.978
Jan 5, 2006.......................... 3.478
Jul 5, 2006.......................... 1.100
Jan 5, 2007.......................... 3.460
Jul 5, 2007.......................... 1.179
Jan 5, 2008.......................... 3.644
Jul 5, 2008.......................... 1.361
Jan 5, 2009.......................... 3.801
Jul 5, 2009.......................... 1.542
Jan 5, 2010.......................... 4.007
Jul 5, 2010.......................... 1.639
Jan 5, 2011.......................... 4.139
Jul 5, 2011.......................... 1.833
Jan 5, 2012.......................... 4.443
Jul 5, 2012.......................... 2.313
Jan 5, 2013.......................... 5.061
Jul 5, 2013.......................... 0.093
Jan 5, 2014.......................... 1.949
Jul 5, 2014.......................... 0.014
Jan 5, 2015.......................... 1.852
Jul 5, 2015.......................... 0.018
Jan 5, 2016.......................... 2.057
Jul 5, 2016.......................... 0.013
Jan 5, 2017.......................... 1.421
Jul 5, 2017.......................... 0.064
Jan 5, 2018.......................... 3.212
Jul 5, 2018.......................... 0.081
Jan 5, 2019.......................... 3.592
11
Percentage
of Principal
Payment Date Amount Payable
------------ --------------
Jul 5, 2019........................... 0.042%
Jan 5, 2020........................... 3.846
Jul 5, 2020........................... 0.265
Jan 5, 2021........................... 4.879
Jul 5, 2021........................... 0.130
Jan 5, 2022........................... 6.410
Jul 5, 2022........................... 0.401
Jan 5, 2023........................... 4.991
Jul 5, 2023........................... 0.161
Jan 5, 2024........................... 2.366
Jul 5, 2024........................... 0.192
Jan 5, 2025........................... 2.991
Jul 5, 2025........................... 0.291
Jan 5, 2026........................... 1.943
Jul 5, 2026........................... 0.429
* Percentages are based on the initial aggregate principal amount of the
existing bonds ($402,000,000). New bonds will be issued in the same nominal
amounts and any payments of principal on the existing bonds before the
exchange offer is completed will be credited against the new bonds.
Initial Average Life........ Approximately 12.0 years.
Ratings..................... The existing bonds are rated "Baa3" by Moody's
and "BBB-" by S&P.
Denomination................ We will issue the bonds in minimum denominations
of $100,000 or any integral multiple of $100.00
in excess of that amount.
Ranking of the Bonds........ The bonds will be senior secured obligations and
will rank equally in right of payment with all of
our other existing and future senior secured
obligations. The new bonds and any existing bonds
that remain outstanding will be a single series.
Non-Recourse Obligations.... The obligations to pay principal of, premium, if
any, and interest on the bonds will be solely our
obligations. Neither our members, nor any of our
affiliates, employees, officers, or directors or
any other person or entity will guarantee the
bonds or have any other obligation to make
payments on the bonds.
Collateral.................. The bonds will be secured by:
. a first priority mortgage on our interest
(which includes a leasehold interest) in our
facility site, all fixtures thereon and all
related easements, rights-of-way, servitudes,
licenses and similar real property rights;
. a first priority security interest in all of
our personal property, including, all of our
equipment, inventory and other goods used in
connection with our facility, all of our
rights under the project documents to which
we are a party, all accounts established by
us under the deposit and disbursement
agreement (other than the distribution
account) and all funds on deposit therein,
and all assignable governmental approvals
obtained in connection with our facility;
12
. a pledge of all of the membership interests
held in us by our members; and
. a pledge of all of the membership interests
we hold in Elwood II Holdings and Elwood III
Holdings, our wholly-owned subsidiaries, and
a first priority security interest in
payments made by us to Elwood II Holdings and
Elwood III Holdings under the equipment sales
agreements.
Redemption at the Option of
the Issuer.................
We may redeem any or all of the 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 U.S. treasury securities having an
interpolated maturity equal to the remaining
average life of the bonds plus 50 basis
points.
Mandatory Redemption
Without Make-Whole
Premium.................... If our facility is damaged or destroyed or taken
by eminent domain, or if there is a defect in our
title to the facility site, 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 the facility or
fix the title defect to make the facility
operate on a commercially feasible basis,
then we must use the proceeds we receive in
excess of $5,000,000 to redeem bonds and
prepay our other senior secured obligations;
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
the facility or fixed the title defect to
make the facility operate on a commercially
feasible basis, then we must use the
remaining proceeds in excess of $5,000,000 to
redeem bonds and prepay our other senior
secured obligations.
If we receive more than $10,000,000 of proceeds
from involuntary buy-outs of our power sales
agreements, then we must use the proceeds in
excess of $10,000,000 to redeem bonds and prepay
our other senior secured obligations unless both
Moody's and S&P confirm that the buy-out will not
result in a downgrade of their then current
ratings of the bonds.
If we receive more than $5,000,000 of proceeds in
connection with a disposition of assets permitted
by the terms of the indenture, then we must use
the proceeds in excess of $5,000,000 to redeem
bonds and to prepay our other senior secured
obligations.
If we are required to redeem bonds with any of
the proceeds described above, 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.
13
Mandatory Redemption With
Make-Whole Premium.........
If we receive more than $10,000,000 of proceeds
from voluntary buy-outs of our power sales
agreements, then we must use the proceeds in
excess of $10,000,000 to redeem bonds and prepay
our other senior secured obligations, unless both
Moody's and S&P confirm that the buy-out will not
result in a downgrade of their initial rating of
the bonds. If we are required to redeem bonds
with the proceeds of voluntary power sales
agreement 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, plus a make-whole
premium which is based on the rates of U.S.
treasury securities having an interpolated
maturity equal to the remaining average life of
the bonds plus 50 basis points.
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 decide to have the holders of the bonds
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 our other senior secured obligations.
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.
Change of Control........... If DEI (or Dominion Resources, Inc. or any
successor entity that is a majority-owned
subsidiary of Dominion Resources, Inc.) and PERC
(or Peoples Energy Corporation or any successor
entity that is a majority-owned subsidiary of
Peoples Energy Corporation), collectively, cease
to own, directly or indirectly, at least 50.1% of
the membership interests in us, then we will be
required, at the request of any holder of the
bonds, to purchase bonds held by such holder at a
purchase price equal to 101% of the aggregate
principal amount of the bonds being redeemed plus
accrued and unpaid interest unless this change of
ownership resulted from a transfer to a
"qualified transferee" or at least 66 2/3% of the
holders of the outstanding bonds approve the
change in ownership.
A "qualified transferee" is any person that
acquires membership interests in us after the
date of this offering so long as:
. such person has, or is controlled by a person
that has, significant experience in the
business of owning and operating facilities
similar to our facility and an investment
grade rating from both S&P and Moody's;
14
. the acquisition does not result in a default
or event of default under the indenture;
. the acquisition could not reasonably be
expected to result in a material adverse
effect on us, our business or our ability to
perform under the transaction documents;
. the collateral agent receives a pledge of and
lien on the acquired membership interests;
and
. each of S&P and Moody's confirms the then
current ratings on the bonds.
Operating Flow of Funds..... We will deposit all of our revenues into the
revenue account and the administrative agent will
disburse these revenues each month (except as
indicated below) in the following order of
priority:
. First, to the O&M account to pay operating
and maintenance expenses (including the
repayment of any working capital facility
used to pay operating and maintenance
expenses) expected to be incurred in the next
month;
. Second, on the last day of each quarter
beginning March 31, 2006 and ending on the
date final payment is due with respect to
certain sales tax obligations (which is
anticipated to occur in 2011), an amount
equal to the sales tax reserve requirement;
. Third, to the debt service payment account in
an amount equal to 1/6 of all senior debt
service (other than principal on debt service
reserve letter of credit loans, but including
principal on debt service reserve letter of
credit bonds) that will be due on the next
semi-annual bond payment date together with
the appropriate portion of senior debt
service payable more frequently than on a
semi-annual basis;
. Fourth, to the DSR letter of credit loan
principal account, in an amount (together
with amounts already on deposit therein)
equal to the appropriate portion of principal
of debt service reserve letter of credit
loans calculated based on the amortization
schedule for such loans;
. Fifth, to the debt service reserve account,
in an amount that, together with all amounts
then on deposit therein, is equal to the
senior debt service that will be due on the
next semi-annual bond payment date (or, in
certain circumstances beginning in 2013 an
amount equal to the aggregate senior debt
service that will be due on the next two bond
payment dates);
. Sixth, to the major maintenance reserve
account in an amount equal to 1/6 of the
difference between the scheduled balance in
the account as of the next bond payment date
(determined in annual consultation with the
independent engineer) and amounts already on
deposit therein or credited thereto as of the
preceding bond payment date;
15
. Seventh, beginning in December 2012 and
ending in December 2023, to the PSA
contingency reserve account, in an amount
that equals the then current PSA contingency
reserve requirement; and
. Eighth, to the distribution suspense account.
If the distribution conditions set forth in the
indenture are satisfied on any scheduled bond
payment date, funds in the distribution suspense
account may be transferred to the distribution
account for distribution to us (See "Description
of the Principal Financing Documents--Indenture--
Certain Covenants--Distributions").
12-Month Debt Service
Reserve Requirement........
Beginning in 2013, we will be required to fund
the debt service reserve account with an amount
equal to the senior debt service that will be due
on the next two scheduled bond payment dates
unless:
. we are party to power sales agreements
meeting requirements specified in the
indenture covering, in the aggregate, 75% or
more of our facility's capacity for the
consecutive period of four quarters following
any date of determination;
and either:
. we have provided a guaranty from an entity
that is rated at least "BBB" by S&P and
"Baa2" by Moody's that will guarantee the
difference between the amount of the debt
service reserve calculated for two bond
payment dates and the amount of the debt
service reserve calculated for one bond
payment date; or
. each of S&P and Moody's confirms that the
failure to provide such a guaranty will not
result in a downgrade of the then current
rating of the bonds.
Reserve Account Letters of
Credit and Guaranties......
We will be permitted to fund the sales tax
reserve account, the major maintenance reserve
account, the PSA contingency reserve account and
the debt service reserve account, with separate
acceptable letters of credit issued by a bank or
other financial institution rated at least "A" by
S&P and at least "A2" by Moody's. We will not be
the account party on any sales tax reserve letter
of credit, any major maintenance letter of credit
or any PSA contingency letter of credit, but will
be permitted to be the account party on any debt
service reserve letter of credit. However, we
will not be permitted to be the account party on
any debt service reserve letter of credit unless,
at the time of issuance, each of S&P and Moody's
confirms that there will be no downgrade in the
then current ratings on the bonds as a result of
indebtedness incurred in respect of the DSR
letter of credit or the underlying letter of
credit agreement. Each drawing under a debt
service reserve letter of credit will be
converted into a loan (which we refer to as a
debt service reserve letter of credit loan) that
will mature in not less than five years after
such drawing. Any such loan that is outstanding
five years after the bonds are initially issued
may be converted into a bond (which we refer to
as a debt service reserve letter of credit bond).
16
We will also be permitted to satisfy our sales
tax, major maintenance, PSA contingency and debt
service reserve requirements through the issuance
of one or more guaranties by entities whose long-
term senior unsecured debt is rated at least
"BBB" by S&P and "Baa2" by Moody's.
We initially plan to provide several guaranties
issued by Dominion Resources, Inc. and Peoples
Energy Corporation instead of depositing cash to
maintain the debt service reserve requirement.
Covenants................... We will agree to, among other things:
. maintain our existence,
. obtain and comply with applicable
governmental approvals,
. comply with applicable laws,
. maintain insurance for our 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 will agree not to, among other things:
. create any lien on our properties other than
permitted liens (see "Description of the
Principal Financing Documents--Indenture--
Certain Covenants--Limitation on Liens"),
. incur any indebtedness other than as
permitted under the indenture (see
"Description of the Principal Financing
Documents--Indenture--Certain Covenants--
Limitations on Indebtedness"),
. 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 facility,
. make any investment other than permitted
investments, or
. enter into certain non-arm's length
transactions with our affiliates.
These affirmative and negative covenants are
subject to a number of important qualifications
and exceptions.
Book-Entry Form............. The bonds will be issued in book-entry form only
through the Depository Trust Company. See
"Description of the Bonds--Book-Entry, Delivery
and Form." The new bonds and any existing bonds
that remain outstanding will be represented by
separate global bonds of the same series.
Trustee and Collateral
Agent...................... Bank One Trust Company, National Association.
17
Independent Engineer........ The independent engineer will be responsible for:
. consulting with us on the annual adjustment to
amounts required to be on deposit in or
credited to the major maintenance reserve
account;
. confirming that our entry into an agreement for
the purchase of replacement power will not
result in a material adverse effect;
. confirming projected debt service coverage
ratios;
. commenting on our proposed annual operating
budget;
. certifying that our modification of a major
project document which would change the pricing
or volume provisions of, or reduce the duration
of, such document, will not result in a
material adverse effect;
. certifying that our entry into any shared
facilities agreement in relation to new
generation facilities on land adjacent to our
facility site will not result in a material
adverse effect on the operation or technical
integrity of our facility;
. reviewing replacement project documents that we
enter into; and
. determining, upon our receipt of insurance or
condemnation proceeds, whether:
(1) it is commercially feasible to repair,
restore or replace our facility to permit
its operation on a commercially feasible
basis; or
(2) repairs, restoration or replacement of
our facility undertaken by us permit our
facility to operate on a commercially
feasible basis.
Risk Factors................ You should carefully consider all of the
information set forth in the prospectus and, in
particular, you should evaluate the specific
factors set forth under "Risk Factors" in making
investment decisions concerning the bonds.
18
The Independent Engineer's Report
Stone & Webster has prepared an Independent Technical Review (the
"Independent Engineer's Report") of our facility (referred to in its and Pace's
reports as the "Project"), which is attached as Annex B to this prospectus.
Stone & Webster is a leading consulting engineering firm, which devotes a
substantial portion of its resources to providing services related to the
technical, environmental and economic aspects of electric power projects. The
Independent Engineer's Report includes, among other things, a condition
assessment, asset life evaluation, performance assessment, review of the
significant project contracts, operation and maintenance review and a review of
the site environmental assessment performed by Woodward-Clyde International-
Americas. In addition, pro forma financial projections were prepared to examine
cash flows available to support debt service coverage for the Project during
the period the bonds are scheduled to remain outstanding.
During the performance of its work, Stone & Webster relied on certain
assumptions regarding material contingencies and other matters that are not
within the control of the Company, Stone & Webster or any other person. These
assumptions are inherently subject to significant uncertainties, and actual
results will differ, perhaps materially, from those projected.
Set forth below are the principal opinions that have been reached regarding
the review of the Project. For a complete understanding of the assumptions upon
which these opinions are based, the Independent Engineer's Report should be
read in its entirety. On the basis of Stone & Webster's review and the
assumptions set forth in the Independent Engineer's Report, Stone & Webster
provides the following opinions:
. The Project was found to be well maintained and in good condition. The
Project has been designed, constructed, operated, and maintained
according to good utility industry practice. The Project should function
beyond the period of the debt term, provided equipment is operated and
maintained in accordance with good utility industry practice. The
Company has proven experience operating and maintaining power plants.
. The Project participants have extensive corporate experience in the
development, design, procurement, construction, testing, and operation
of power plants and in procuring and transporting natural gas.
. Stone & Webster reviewed the technical assumptions that were used as
inputs to Pace's dispatch simulation model. The key input data in Pace's
model such as claimed capacity, scheduled and forced outage rates, and
heat rate are reasonable and are consistent with comparable units.
. The anticipated performance of the Project, given the condition and
capability of the units, is accurately reflected in the financial
projections.
. The Project is technically capable of performing at the capacity factors
projected by Pace.
. The operation and maintenance expenses forecasted for the Project are
consistent with the staffing and operating plan and recent historical
expenses for the Project. The operation and maintenance expenses appear
reasonable and adequate to meet the Project's operation, maintenance and
performance objectives.
. The Project staffing is reasonable for a peaking facility.
. The overhaul schedules developed for the Project are prudent and
consistent with current and forecasted operations. The overhaul expenses
forecasted in the financial model are consistent with the overhaul
schedules and should be adequate to support the continued operation of
the Project through 2026.
. The on-going repair/replacement expenses forecast for the Project are
reasonable and consistent with the design of the assets and the
projected capacity factors.
. The Project is in compliance with current permit requirements. Phase I
environmental site assessments, prepared by others, were provided for
the Project and reviewed.
19
. The technical assumptions assumed in the financial projections are
reasonable and are consistent with the agreements. The financial model
fairly presents, in Stone & Webster's judgment, projected revenues and
projected expenses under the Base Case assumptions. Therefore, the
financial projections are a reasonable forecast of the financial
results under the Base Case assumptions.
. The projected revenues are more than adequate to pay the annual
operating and maintenance expenses (including provisions for major
maintenance), other operating expenses, and debt service based on Stone
& Webster's studies and analyses and the assumptions set forth in the
Independent Engineer's Report. Contributions to major maintenance
reserves and debt service reserves are excluded from the calculation of
the cash flow available for debt service. The debt service requirements
for each year are the payments to be made on July 5 of that year and
January 5 the following year. The Base Case resulting minimum debt
service coverage ratio ("DSCR") is 1.51x, occurring in 2005 and 2006.
The Base Case resulting average DSCR is 3.60x. The following table
summarizes the Base Case and sensitivities:
Base Case and Sensitivity Summary
Minimum DSCR Average DSCR
------------ ------------
Base Case 1.51x 3.60x
Increased O&M Cost 1.49x 3.56x
Decreased Inflation Rate 1.51x 3.36x
High Gas Price Case 1.50x 3.58x
Overbuild Case 1.51x 3.55x
No Aquila Contract Extension 1.51x 3.83x
No Volatility Revenue 1.51x 2.97x
The Independent Power Market and Fuel Consultant's Reports
Pace, the independent power market and fuel consultant, has prepared two
reports. These reports provide (i) an assessment of the Project's power sales
agreements and the power market in which the Project operates (the "Power
Market Consultant's Report"), and (ii) an evaluation of the fuel supply,
transportation, storage/balancing and management arrangements for the Project
(the "Fuel Consultant's Report"), respectively. You should read the complete
copies of these reports, which are attached as Annex C-1 and Annex C-2,
respectively, to this prospectus. Pace is not affiliated with us or any of our
affiliates.
Subject to the information contained, and assumptions made, in its report,
Pace has expressed the following conclusions and key findings in the Power
Market Consultant's Report:
. The MAIN power market is emerging as a highly competitive market for
wholesale power. The market's competitiveness is evidenced by the
region's large volume of wholesale power transactions and the existence
of the "Into-ComEd" electricity-trading hub upon which a standardized
forward contract has been established. Overall, given the MAIN market's
sizable demand growth, Pace's market price forecast, and the Project's
competitive market position, the Project is expected to be highly
competitive and valuable throughout the term of the bonds.
. Pace anticipates that given the rapid pace of wholesale energy market
development, a commercially operating and deregulated environment for
retail customers' capacity and energy requirements will be implemented
on a near- to mid-term basis for MAIN. Retail access began in Illinois
for industrial consumers in October 1999, with full access scheduled to
commence by May 2002 per the enactment of the "Electric Service
Customer Choice and Rate Relief Act of 1997." The development of an
all-in capacity and energy market will allow for sales to the retail
marketplace and should provide additional flexibility and enhanced
marketability for the Project's capacity and energy.
20
. The market for power in MAIN is characterized by:
(a) Sustained energy demand growth expected to continue at a steady
annual average pace of 1.47% over the forecasting horizon in the
MAIN power market. This regional demand increase translates into
approximately 1,100 MW of annual average demand.
(b) Summer peak demand in the MAIN power market is forecast to increase
from 50,066 MW in 2000 to 73,131 MW by 2026. This regional peak
demand increase translates into the need for the addition of
approximately 700 MW of peaking capacity per year to the MAIN power
market through 2026.
(c) A well-developed electric transmission system capable of
transferring high volumes of electricity throughout the MAIN power
market and covering over 4 states and approximately 6% of the U.S.
power demand.
(d) An installed capacity base (MW) dominated by base-load coal-fired,
nuclear and hydro capacity representing 73% of installed generation
capacity in 2001 and 67% in 2009.
(e) Base-load coal-fired, nuclear and hydro capacity representing
approximately 94% of electrical generation (MWh) by fuel type in
2001 and 69% in 2025.
(f) Gas fired combined-cycle and combustion turbine capacity
representing the near universal choice for capacity additions,
driving gas-fired generation from a 6.2% share of generation in 2001
to 31.1% in 2025.
. The most significant factors affecting the electricity pricing in the
MAIN power market include fuel costs; the efficiency and replacement
rate of existing generating assets and capital costs of replacing
existing generating assets; the cost and efficiency of incremental
capacity additions which are undertaken to meet future energy
requirements and maintain system reliability; and increases in annual
peak demand and energy requirements.
. Pace's Base Case average market price forecasts for the Northern
Illinois sub-region of MAIN range between a maximum value of $37.60/MWh
in 2001 and a minimum value of $28.53/MWh in 2009 and average
$30.42/MWh (measured in 1998 real dollars) over the life of the bonds.
Pace expects that, while a high level of competitive capacity additions
and declining gas prices will lower electricity prices between 2001 and
2009, prices will remain relatively stable over the remainder of the
forecast period as sufficient capacity is constructed to meet demand
and efficiency improvements offset a modest natural gas real price
increase.
. The Project represents a relatively low cost, competitive, and much
needed resource for the growing MAIN market equaling only a small
fraction of the capacity required in the MAIN power market. The Project
is expected to be dispatched at an average annual capacity factor of
11.93%/1/ and realize average gross margins, including volatility
values, of $82.93/kW-year (measured in 1998 real dollars). Gross
margins range from a maximum of $104.30/kW-yr in 2001 to a minimum of
$76.82/kW-yr in 2009 over the life of the bonds.
. During the term of the Exelon power sales agreement which covers the
dispatch of Units 1-4 and 9 until December 31, 2012, the Exelon units
are expected to be dispatched at an average annual capacity factor of
3.39% and realize average gross margins including volatility values of
$78.63/kW-year (measured in 1998 real dollars). Gross margins range
from a maximum of $97.86/kW-yr in 2001 to a minimum of $71.93 kW-yr in
2009.
. During the term of the Aquila/UtiliCorp power sales agreements, which
cover the dispatch of Units 5-8 until August 31, 2022, the
Aquila/UtiliCorp units are expected to be dispatched at an average
capacity factor of 17.15% and realize average gross margins including
volatility values of $87.22/kW-year (measured in 1998 real dollars).
Gross margins range from a maximum of $112.43/kW-yr in 2001 to a
minimum of $81.10/kW-yr in 2004.
- --------------------
1 Results include the periods covered by the Exelon and Aquila/UtiliCorp
power sales agreements in addition to the merchant period, which
commences in 2022 after the expiry of the second extended
Aquila/UtiliCorp power sales agreement.
21
. Pace conducted a detailed evaluation of the potential volatility value
of the Project. Given Pace's assumptions of market reserve margins,
liquidity, and trading volatility, volatility value (net of insurance
costs) adds $20.33/kW-yr or $28.6 million per year to Base Case
revenues over the life of the bonds. Volatility value ranges from a
maximum of $27.26/kW-yr or $38.4 million in 2001 to a minimum of
$16.91/kW-yr or $23.8 million in 2004. Pace's Base Case revenue
forecast contained in this report includes these volatility values.
. Pace has determined that based upon the payment structure of the
Aquila/UtiliCorp power sales agreements, the Project's forecast
dispatch profile, forecast market-clearing prices and the energy and
capacity revenues and volatility values that Aquila/UtiliCorp is
forecast to earn by marketing the output and capacity of the
Aquila/UtiliCorp units, a compelling economic incentive is likely to
exist which would cause Aquila/UtiliCorp to exercise its option to
extend the term of the Aquila/UtiliCorp power sales agreements for an
additional 5-year period.
. Pace's assumptions provide a conservative forecast of the Project's
dispatch and resulting economics. Therefore, while the dispatch and
revenues of peaking capacity can be highly volatile from year to year,
Pace has removed much of the low side volatility through Pace's
modeling assumptions. These considerations provide a high level of
probability that Pace's Base Case forecast is likely to be more of a
downside case when compared with actual Project results.
For a more complete discussion of the methodology employed by Pace and the
assumptions underlying the foregoing conclusions, see "Annex C-1--The Power
Market Consultant's Report" and "Annex C-2--The Fuel Consultant's Report."
Subject to the information contained, and assumptions made, in its report,
Pace has expressed the following conclusions in the Fuel Consultant's Report:
. The robust spot market at the Chicago hub will provide the Project with
highly reliable gas supply at market-sensitive prices.
. Pace expects that natural gas supply and transportation market
liquidity will continue to grow in the Midwest United States with the
introduction of new pipeline capacity, the geographic availability of
aquifer storage capacity, the integration of new pipeline
interconnections, and the development of new interstate and utility
retail service offerings, thus enabling the Company to procure reliable
supply on the spot market at the Chicago hub for the Project. Trading
activity at the Chicago hub approximates 2 billion cubic feet per day,
or about ten times the threshold Pace uses to define a liquid trading
point.
. The Company will purchase all of the Project's gas supplies on a
delivered basis from Cinergy, a nationally recognized natural gas and
electricity marketer, under a one-year, executed fuel supply and
management agreement at a published Chicago daily spot price, plus a
nominal premium.
. The Company intends to negotiate a new multi-year fuel supply and
management agreement for the Project with Cinergy or another national
energy marketing company. A number of reputable and creditworthy
natural gas suppliers and marketers operate in the Midwest United
States natural gas markets that will be financially motivated to
provide fuel management and gas supply services at competitive prices
to the Company for the Project upon the expiration of the current fuel
supply and management agreement.
. Based on its experience in competitive power markets and regional
natural gas markets, Cinergy is highly qualified to provide adequate
fuel management and gas procurement expertise to match the Project's
gas and power dispatch requirements. Moreover, Cinergy's compensation
and required communications protocols identified in the executed fuel
supply and management agreement are appropriate and consistent with
industry norms.
22
. Potential gas commodity price risk to the Company for the Project is
fully mitigated by the energy payment terms contained in the executed
power sales agreements and the Cinergy fuel supply and management
agreement. The overall effect of these contracts is to index energy
pricing to the market price of the natural gas commodity obtained by
the Company for the Project.
. The Company has entered into a long-term transportation and storage
balancing service agreement for the Project with Nicor for firm (non-
interruptible) hourly delivery of fuel supplies to meet the firm power
dispatch obligations at the Facility. Initial terms under the gas
transportation and balancing agreement with Nicor range from 41 months
(Units 1-4) to 5 years (Units 5-9), but the Nicor transportation and
balancing agreement can be extended for up to 5 years by giving 180
days written notice prior to expiration of the respective initial
terms. The Nicor transportation and balancing agreement provides the
Company access to purchase, rights to transport, and rights to store
Chicago hub spot supplies for the Project.
. Access to the Chicago hub via the Nicor transportation and balancing
agreement is facilitated through the PGL system through a companion
agreement that contains substantially the same terms and conditions as
the Nicor transportation and balancing agreement.
. The Project benefits from existing access to APL and NBPL receipts
through PGL as well as the potential to establish direct connections
with high-pressure interstate pipelines in close proximity to the
Company such as Vector Pipeline, L.P. and ANR Pipeline Co.
23
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 in making
investment decisions concerning the Bonds.
Operating and Business Risks
The operation of our facility involves many risks, including operating risks
and the risk of events and competitive forces that are beyond our control.
The operation of power generation facilities like ours involves many risks,
including:
. performance below expected levels of output or efficiency;
. interruption in fuel supply or inadequate quality of supplied fuel;
. power shutdown due to the breakdown or failure of our equipment or
processes or shortages of replacement equipment or spare parts;
. disruptions in our ability to deliver electricity, whether because of
breakdowns or failures in electric grid transmission facilities and
equipment or otherwise;
. inability to operate within limits established by governmental permits
or current or future environmental regulations;
. labor disputes; and
. operator error or catastrophic events such as fires, earthquakes,
lightning, explosions, floods or other similar occurrences that could
result in personal injury, loss of life, environmental damage or severe
damage to or destruction of our facility and suspension of its
operations or disruption of the markets that it serves.
We have two years' operating history with Units 1-4 and began commercial
operations with Units 5-9 in the middle of 2001.
If we do not operate our units efficiently and as required under our power
sales agreements, we would experience reduced revenues (both with regard to the
sale of energy and because in certain circumstances we may receive reduced
capacity payments under our power sales agreements) and increased operating
costs. This, in turn, could impair our ability to pay amounts due on the bonds.
In addition, we are dependent primarily on internally generated cash flows
for future capital expenditures, since our members are not required to
contribute any more capital to us and our ability to issue additional
indebtedness is limited. If we do not operate efficiently, or if for some other
reason we are not able to generate sufficient funds, we may not be able to
obtain sufficient capital for improvements to keep our facility competitive and
to comply with environmental laws and regulations.
The insurance coverage that we have obtained may be inadequate to cover
potential liabilities and losses.
Although we maintain insurance consistent with industry standards to protect
against operating and other risks, not all risks are insured or insurable. We
cannot be sure that adequate insurance coverage for potential losses and
liabilities will be available in the future on commercially reasonable terms or
at commercially reasonable rates. In particular, the difficulty of obtaining
adequate insurance at reasonable cost for certain risks may increase following
the attacks on the World Trade Center and the Pentagon on September 11, 2001.
If we experience a total or partial loss of our operating units, the proceeds
of the applicable insurance policies may not be adequate to cover replacement
costs or our lost revenues or increased expenses or to satisfy our obligations
with respect to the bonds.
24
Changes in technology may significantly impact our business by making our power
plant less competitive.
Current state-of-the-art combustion technologies produce electric energy
more efficiently and with less cost than older technologies. While we believe
our facility is currently competitive, improvements in technology that we
cannot match because of capital constraints, technology licensing barriers or
otherwise may render it less competitive over time. In addition, a basic
premise of our business is that generating power at central power plants
achieves economies of scale and produces electricity at a low price. There are
other technologies, including fuel cells, microturbines and photovoltaic
(solar) cells, that can produce electricity, and research and development
activities in such alternate technologies are ongoing. It is possible that
advances will reduce the costs of alternative methods of electric generation to
levels that are equal to or below the combustion technology we use.
We depend on a number of other entities to operate and maintain our facility
and on a relatively small number of power purchasers to provide all of our
revenues.
We are highly dependent on other entities to operate our facility and
produce revenues, including the following:
. various entities for the supply of goods and services necessary for us
to generate capacity and electric energy;
. Cinergy and Nicor for the supply and transportation of natural gas;
. DELSCO for operation and maintenance;
. ComEd for our ability to deliver the electricity we generate to our
power purchasers; and
. Exelon, Aquila/UtiliCorp and Engage, during the term of our power sales
agreements with them, to buy electric generating capacity and energy
from us and to provide revenues.
If any of these entities breach their obligations to us, or terminate their
agreements with us, and if we cannot make adequate alternate arrangements, our
revenues could decrease materially, or our costs increase, and we could be
unable to make payments on the bonds or our other debt when due.
Market Risks
Our fuel agreements will expire before the maturity of the bonds. After these
agreements expire, we will have to find other sources of fuel supply that match
up with our power sales agreements.
Our fuel supply and management agreement with Cinergy is currently set to
expire on April 30, 2002, and our gas transportation and balancing agreement
with Nicor is set to expire in September 2004 for Units 1-4 and March 2006 for
Units 5-9 (although we may extend the Nicor agreement through March 2011).
Although Pace has concluded in its report that, based on the assumptions stated
therein, market-priced natural gas and interstate transportation will be
available in sufficient quantities to support our requirements throughout the
term of the bonds, we cannot be sure this will be the case. See Annex C-2 for a
fuller discussion of this issue.
In addition, the pricing under our fuel supply arrangements and our power
sales agreements are designed to work together so that we are effectively
"tolling" natural gas, thereby mitigating our natural gas price risk. Our
principal risk should therefore be adequacy of supply, but the liquidity of the
natural gas market at our location should work to mitigate this risk. As long
as the index we are using for both our fuel supply and power sales arrangements
(published price in Gas Daily, Daily Price Survey, Midpoint for Chicago-LDCs,
large end users (the "Gas Daily Average Price")) remains an effective market
measure and our current supply and power sales arrangements remain in effect,
we should have limited natural gas price risk. If there is a major market
fluctuation so that the existing market index is no longer reliable, or if our
power sales agreements were
25
to terminate and we could not find buyers on similar terms, we could become
subject to natural gas price risk in ways that could adversely affect our
ability to pay our obligations under the bonds.
Our power sales agreements will expire before maturity of the bonds.
Our power sales agreement with Exelon expires in December 2012 (as to Units
1-4 and 9) and our power sales agreements with Aquila/Utilicorp expire in
August 2016 (as to Units 5-6) and August 2017 (as to Units 7-8). While Pace has
concluded that there should be economic incentives for Aquila/UtiliCorp to
exercise its five-year extension options provided in the agreements covering
Units 5-8 (see "Annex C-1--Executive Summary--Power Sales Agreements--Extension
of Aquila Power Sales Agreements"), we cannot be sure that all, or any, of
these power sales agreements will be extended or renewed beyond these dates. We
plan, from time to time before the scheduled expiration dates, to review the
feasibility of extending or renewing our existing agreements or of entering
into other long-term power sales agreements with other customers covering some
or all of our capacity. If we cannot do so, either in whole or in part, we
would expect to operate on a "merchant" basis, selling our capacity and energy
on a shorter-term "spot" basis and/or using hedging products to manage
volatility. While Pace has concluded that, in general based on the assumptions
set forth in its power market assessment included in Annex C-1, we should be
able to continue to generate revenues on a "merchant" basis, and we believe
that the revenues projected by Pace would be sufficient to pay our obligations
under the bonds, the effect of such factors as competition, technology change
and economic conditions in the regional market we serve creates an inherent
degree of uncertainty. We therefore cannot assure you that the revenues
generated from future power sales agreements or merchant sales will be
sufficient to allow us to pay our obligations under the bonds.
Our status as an exempt wholesale generator ("EWG") under federal law
prohibits us from making retail sales of electricity in the United States,
although we may sell electricity to any power marketer, including one of our
affiliates, which may in turn make retail electricity sales. We currently
anticipate that electric capacity and energy we generate will be sold to our
existing purchasers in the wholesale market during the terms of the contracts
with them, and that we would continue thereafter to make sales into the
wholesale market. 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 "Our Business and Regulatory Environment--Energy
Regulation."
We will need access to the electric transmission grid after our current power
sales agreements expire.
Although we have entered into agreements with ComEd to interconnect our
facility to its transmission systems, we do not have any agreements in place
for the transmission of electricity beyond that point. As long as our current
power sales agreements stay in place, the purchasers must obtain transmission
service for the power purchased by them. If we need to find substitute
purchasers at some point, we may have to obtain this service ourselves. The
current regulatory framework does not allow transmission providers to deny
access to electric generators on a discriminatory basis. We cannot be sure,
however, that either 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. If we were unable to obtain electric
transmission service at competitive rates when needed, it could adversely
affect our ability to pay our obligations under the bonds.
Regulatory Risks
Our business is subject to substantial regulation and permitting requirements
and may be adversely affected by changes in regulations or in the requirements.
There are many federal, state and local laws that relate 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 generating units and the related infrastructure. For example, we must
obtain and comply with permits for air emissions, wastewater discharges, and
other regulated activities. Each permit
26
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 do not comply with these requirements, we could be prevented from
operating some or all of the units, and we could be subject to civil or
criminal liability and the imposition of liens or fines. Moreover,
modifications to the units to comply with these requirements as they change
over time could be required and could be expensive.
In addition, the structure of federal and state energy regulation is
currently, and likely will continue to be, subject to changes and restructuring
proposals. It is difficult to predict what form these changes may take and what
the impact may be on our operations. In particular, the volatile electric power
market in California has brought heightened political attention to the area,
which may result in additional regulatory controls on pricing (including price
caps or other forms of price control) or operations of independent electric
power producers. Furthermore, although we believe that we have obtained all
material energy-related approvals currently required for our operations, 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.
Our power purchasers and our suppliers are also subject to extensive
regulation. Their operations could be adversely affected by the application of
existing or future regulations to them, which could in turn make it difficult
for them to fulfill their obligations to us.
Laws and regulations affecting us may change in ways that could cause us to
be unable to make payments on the bonds when due. For example, changes in laws
or regulations (or in judicial or administrative interpretations of them) could
impose more stringent or comprehensive requirements on the operation and
maintenance of our facility, 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. We may not be able to obtain or maintain
from time to time all required regulatory approvals and permits. If there is a
delay in obtaining any required regulatory approvals or permits, or if we fail
to obtain and comply with any required regulatory approvals or permits, the
operation of our facility or the sale of electricity to third parties could be
prevented or become subject to additional costs.
In addition, we could be responsible for the costs of remediating
contamination from existing or future off-site sources that are subsequently
identified as affecting, or having been affected by, our site. Any payment by
us of such remediation costs could cause us to be unable to make payments on
the bonds when due.
Financing Risks
If we default on the bonds, your recourse will be limited to the assets and
cash flows of our facility.
We are the sole issuer of the bonds and will be responsible for making
payments on the bonds. No one else (including our members, affiliates,
directors, officers or the people who own or work for them or us) will be
responsible for making payments on the bonds or will in any way guarantee the
payment of the bonds. Our ability to make payments on the bonds will be
entirely dependent on our ability to operate our facility at levels which will
provide sufficient revenues, after payment of our operations and maintenance
costs, to make payments on the bonds and our other obligations when due.
The bonds will be secured only by our assets and a lien on the membership
interests in our company. We cannot assure you that, if we default on the bonds
and you foreclose on and sell our assets, you will receive sufficient proceeds
to pay all amounts that we owe you on the bonds. In addition, you may not be
able to effectively foreclose upon some of our assets, such as permits, without
the consent of a third party, such as a governmental authority. We cannot be
sure that if you try to foreclose on our assets, you will get all of the third
party approvals that you need to do so effectively. Furthermore, if you
exercise your right to foreclose on the collateral, transferring required
government approvals to a purchaser or a new operator of our facility may
require additional government approvals or proceedings, with consequent delays.
27
We may incur additional debt that could adversely affect you.
Under the terms of the bonds, we may incur additional indebtedness to pay
for letter of credit reimbursement obligations, certain capital improvements
and modifications (more fully described as "required modifications" and
"optional modifications" under "Description of the Bonds--Limitations on
Indebtedness"), for working capital, and for other purposes. Some permitted
indebtedness may rank equally in payment with the bonds and could result in
lower debt service coverage ratios and cash available to pay amounts due on the
bonds. We cannot be sure that the revenues of our facility would be sufficient
to cover such increases in debt service payments. In addition, some types of
additional indebtedness may share in the collateral that secures the bonds.
This may reduce the benefits of the collateral to you and your ability to
control actions taken with respect to the collateral.
We are relying on projections of the future performance of our facility, and
these projections may not prove to be accurate.
The independent engineer's report contains projections of our operating
results based on assumptions and forecasts of our ability to generate revenue
and of our expected costs. The independent engineer's report contains numerous
qualifications and assumptions with regard to the information presented and the
circumstances under which the analyses were performed. You should review the
independent engineer's report, as well as these qualifications and assumptions,
carefully. We have reviewed and accepted these projections on the basis of
present knowledge and assumptions that we believe to be reasonable. The
financing has been structured on the basis of these assumptions and
projections, which relate to our expected revenues and expenses over the term
of the bonds.
For purposes of preparing the projections for the independent engineer's
report, we made assumptions with respect to material contingencies and other
matters that are not within our control. Accordingly, we cannot accurately
predict the outcome of the events on which the projections were developed.
These assumptions and the other assumptions used in the projections are
inherently subject to significant uncertainties, and actual results may differ,
perhaps materially, from those projected. Accordingly, the projections are not
necessarily an indication of our future performance. Therefore, we assume no
responsibility for their accuracy or for the accuracy of the independent
engineer's report or the projections therein. No representation is made or
intended, nor should any be inferred, with respect to the likely existence of
any particular future set of facts or circumstances. Investors are cautioned
not to place undue reliance on the projections. You should also note that our
independent accountants have neither examined nor compiled the projections
included in this prospectus and do not express any opinion or any other form of
assurance about the projections. If actual results are less favorable than
those shown in the projections or if the assumptions used in formulating the
projections prove to be incorrect, our ability to pay amounts due on the bonds
may be adversely affected.
We do not intend to ask the independent engineer to provide any revised or
updated projections or analysis of the differences between the projections and
actual operating results.
There is no existing market for the bonds, and we cannot assure you that an
active market will develop.
Following completion of the exchange offer, the new bonds will be freely
tradeable by most holders. See "The Exchange Offer--Resales of the New Bonds."
We do not intend to apply for listing of the bonds on any securities exchange
or on the Nasdaq National Market. There can be no assurance as to the liquidity
of any market that may develop for the bonds, the ability of bondholders to
sell their bonds, or the price at which bondholders will be able to sell their
bonds. Future trading prices of the bonds will depend on many factors
including, among other things, prevailing interest rates, our operating results
and credit ratings, and the market for similar securities.
The initial purchasers have informed us that they intend to make a market in
the bonds after the completion of this offering. However, the initial
purchasers are not required to make a market in the bonds, and
28
they may cease market-making activities at any time without notice. In
addition, any market-making activity will be subject to the limits of the
Securities Act and the Securities Exchange Act of 1934, as amended (the
"Exchange Act"). We cannot be sure that an active market for the bonds will
develop. Even if a market for the bonds does develop, there is necessarily
uncertainty about the price at which you might be able to sell your bonds. If a
market for the bonds does not develop, you may be unable to sell your bonds for
an extended period of time, if at all. Consequently, you may not be able to
liquidate your investment readily, and lenders may not readily accept the bonds
as collateral for loans.
Under current Exchange Act rules, we may only be required to file reports
under the Exchange Act for one year after the registration statement of which
this prospectus is a part was declared effective if we have fewer than 300
recordholders of the bonds. If we are not otherwise required to file Exchange
Act reports after that time, any filing of reports with the SEC would be at our
discretion. Although we would still be obligated to provide holders of the
bonds with equivalent information, a decision not to file those reports would
result in a lack of publicly available information and may affect the liquidity
and marketability of the bonds.
Credit ratings assigned to the bonds do not necessarily mean they are a
suitable investment for you and may change over time.
Moody's and S&P have assigned ratings to the new bonds of Baa3 and BBB-,
respectively. A rating is not a recommendation to purchase, hold or sell the
bonds, because a rating does not address market price or suitability for a
particular investor. There can be no assurance that a rating will remain in
effect for any given period of time. If, in its judgment, circumstances so
warrant, a rating agency may lower or withdraw a rating entirely. In addition,
because we are dependent on the creditworthiness of a limited number of
customers and suppliers, changes in their credit outlook could adversely affect
our credit rating.
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 and/or the security
documents could be voided or subordinated to all of our other debts if, among
other things, at the time 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
4) intended to incur, or believed that we would incur, debts beyond our
ability to pay such debts as they mature.
In addition, any payment that we made on the bonds could be voided and
required to be returned to us or to a fund for the benefit of our creditors.
The measures for 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
29
3) we could not pay our debts as they became due.
We do not believe that we will have received less than reasonably equivalent
value or fair consideration for issuing the bonds. Also, we believe that, after
giving effect to the issuance of the bonds, we will not be insolvent, we will
not have unreasonably small capital for the business in which we are engaged,
and we will not have incurred debts beyond our ability to pay those debts as
they mature. However, we cannot be sure that a court would apply this standard
or agree with our conclusions.
If we or 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 seek the protection of the bankruptcy laws, or if one of our creditors
begins a bankruptcy proceeding against us, your rights to foreclose upon our
assets 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. 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, the
counterparty or a trustee appointed in our or the counterparty's bankruptcy
case could choose to reject the contract. If that occurred, you could not
specifically enforce the rejected contract.
30
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This prospectus includes forward-looking statements. Statements that address
activities, events or developments that may or will occur in the future,
including such matters as projections, future capital expenditures, business
strategy, competitive advantages and disadvantages, goals and market or
industry developments, are forward-looking statements. We have based these
forward-looking statements on our current expectations, and our and the
independent consultants' and advisors' projections, about future events based
upon our knowledge of facts as of the date of this prospectus and our and our
independent consultants' assumptions about future events. These forward-looking
statements are only expressions of intent, belief or expectations, and they are
subject to 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, including
state or federal rate regulations and legislative and regulatory
initiatives regarding deregulation and restructuring of the electric
utility industry;
. operating risks, including equipment failure, environmental compliance
issues, availability of our power plant, dispatch levels for our power
plant, heat rate and output, electric transmission access and the
amounts and timing of revenues and expenses;
. market or business conditions and fluctuations in demand for energy or
capacity in the markets in which we operate;
. the enforceability of the long-term power sales agreements for our power
plant;
. the ongoing creditworthiness of our power purchasers;
. the cost and availability of fuel and gas transmission service for our
power plant;
. our ability to find replacement sources for fuel and purchasers of our
power as our existing fuel supply and power sales agreements expire;
. political, legal and economic conditions in the United States, including
changes in commodity prices and interest rates and financial market
conditions;
. weather and other natural phenomena; and
. competition from other power plants, including new plants that may be
developed in the future.
In some cases, words like "anticipate," "estimate," "project," "plan,"
"expect" and similar expressions can help identify forward-looking statements
in this prospectus.
For additional factors that could affect the validity of our forward-looking
statements, you should read "Risk Factors" on page 24. 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. We cannot and do not guarantee
future results, events, levels of activity, performance or achievements. We do
not undertake to publicly update or revise any forward-looking statement after
the date of this prospectus, whether as a result of new information, future
events or otherwise.
31
THE EXCHANGE OFFER
Purpose and Terms of the Exchange Offer
The existing bonds were originally sold on October 23, 2001 in an offering
that was exempt from the registration requirements of the Securities Act. As of
the date of this prospectus, $396,400,140 in principal amount of existing bonds
are outstanding. In connection with the sale of the existing bonds, we entered
into a registration rights agreement in which we agreed to file with the SEC a
registration statement covering the exchange of existing bonds for new bonds
and to use our reasonable best efforts to cause the registration statement to
become effective within 270 days. We also agreed to pay additional interest at
a rate of 0.50% per annum on the existing bonds if the exchange offer were not
completed within the specified period for so long as that failure continued.
The additional interest would be payable on the existing bonds on the regular
interest payment date.
We are offering, upon the terms and subject to the conditions set forth in
this prospectus and in the accompanying letter of transmittal, to exchange all
the outstanding existing bonds for new bonds that have been registered under
the Securities Act. We will accept for exchange existing bonds that you
properly tender before the expiration date and do not withdraw in accordance
with the procedures described below. You may tender your existing bonds in
whole or in part in minimum amounts of $100,000 and multiples of $100.00 in
excess of $100,000 (in each case, based on original issue amount).
The exchange offer is not conditioned upon the tender for exchange of any
minimum aggregate principal amount of existing bonds. We reserve the right in
our sole discretion to purchase or make offers for any existing bonds that
remain outstanding after the expiration date or, as detailed under the caption
"--Conditions to the Exchange Offer," to terminate the exchange offer and, to
the extent permitted by applicable law, purchase existing 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.
There will be no fixed record date for determining the registered holders of
the existing bonds entitled to participate in the exchange offer.
Only a registered holder of the existing bonds (or the holder's legal
representative or attorney-in-fact) may participate in the exchange offer.
Holders of existing bonds do not have any appraisal or dissenters' rights in
connection with the exchange offer. Existing bonds that are not tendered in, or
are tendered but not accepted in connection with, the exchange offer will
remain outstanding. 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, the Exchange Act and SEC rules and
regulations.
If we do not accept any existing bonds that you tender for exchange because
of an invalid tender, the occurrence of other events set forth in this
prospectus or otherwise, we will return the unaccepted existing bonds to you,
without expense, after the expiration date.
If you tender existing bonds in connection with the exchange offer, you will
not be required to pay brokerage commissions or fees or, subject to the
instructions in the letter of transmittal, transfer taxes with respect to the
exchange of existing bonds. We will pay all charges and expenses, other than
certain applicable taxes described below, in connection with the exchange
offer. See "--Fees and Expenses."
Each broker-dealer that receives new bonds for its own account in exchange
for existing bonds, if such existing bonds were acquired by the broker-dealer
as a result of market making or other trading activities, must acknowledge that
it will deliver a prospectus in connection with any resale of the new bonds.
See "Plan of Distribution."
32
We make no recommendation to you as to whether you should tender or refrain
from tendering all or any portion of your existing bonds into the exchange
offer. In addition, no one has been authorized to make this recommendation. You
must make your own decision whether to tender into the exchange offer and, if
so, the aggregate amount of existing bonds to tender after reading this
prospectus and the letter of transmittal and consulting with your advisors, if
any, based on your financial position and requirements.
Expiration Date, Extension and Amendments
The term "expiration date" means 5:00 p.m., New York City time, on March 14,
2002 unless we extend the exchange offer, in which case the term "expiration
date" will mean the latest date and time to which we extend the exchange offer.
We expressly reserve the right, at any time or from time to time, so long as
applicable law allows, to
(1) delay our acceptance of existing bonds for exchange;
(2) terminate or amend the exchange offer if, in the opinion of our
counsel, completing the exchange offer would violate any applicable
law, rule or regulation or any SEC staff interpretation; or
(3) extend the expiration date and retain all existing bonds tendered into
the exchange offer, subject, however, to your right to withdraw your
tendered existing bonds as described under "--Withdrawal Rights."
If the exchange offer is amended in a manner that we think constitutes a
material change, or if we waive any material condition of the exchange offer,
we will promptly disclose the amendment by means of a prospectus supplement
that will be distributed to the registered holders of the existing bonds, and
we will extend the exchange offer to the extent required by Rule 14e-1 under
the Exchange Act.
We will promptly follow any delay in acceptance, termination, extension or
amendment by oral or written notice of the event to the exchange agent followed
promptly by oral or written notice to the registered holders. Should we choose
to delay, extend, amend or terminate the exchange offer, we will have no
obligation to publish, advertise or otherwise communicate this announcement to
the public, other than by making a timely release to an appropriate news
agency.
Procedures for Tendering the Existing Bonds
Upon the terms and conditions of the exchange offer, we will exchange, and
we will issue to the exchange agent, new bonds for existing bonds that have
been validly tendered, and not validly withdrawn, promptly after the expiration
date. The tender by a holder of any existing bonds and our acceptance of that
holder's existing bonds will constitute a binding agreement between us and that
holder subject to the terms and conditions set forth in this prospectus and the
accompanying letter of transmittal.
Valid Tender
We will deliver new bonds in exchange for existing bonds that have been
validly tendered and accepted for exchange under the exchange offer. Except as
set forth below, you will have validly tendered your existing bonds under the
exchange offer if the exchange agent receives, before the expiration date, at
the address listed under the caption "--Exchange Agent":
(1) a properly completed and duly executed letter of transmittal, with any
required signature guarantees, including all documents required by the
letter of transmittal; or
33
(2) if the existing bonds are tendered in accordance with the book entry
procedures set forth below, an agent's message (described below)
instead of a letter of transmittal.
In addition, on or before the expiration date:
(1) the exchange agent must receive the existing bonds along with the
letter of transmittal; or
(2) the exchange agent must receive a timely book-entry confirmation
(described below) of a book-entry transfer of the tendered existing
bonds into the exchange agent's account at The Depository Trust
Company, along with a letter of transmittal or an agent's message in
lieu of the letter of transmittal; or
(3) the holder must comply with the guaranteed delivery procedures
described below.
Accordingly, we may not make delivery of new bonds to all tendering holders
at the same time, because the time of delivery will depend upon when the
exchange agent receives the existing bonds, book entry confirmations with
respect to existing bonds and the other required documents.
The term "book-entry confirmation" means a timely confirmation of a book-
entry transfer of existing bonds into the exchange agent's account at The
Depository Trust Company. The term "agent's message" means a message,
transmitted by The Depository Trust Company to and received by the exchange
agent and forming a part of a book-entry confirmation, which states that The
Depository Trust Company has received an express acknowledgement from the
tendering participant stating that the participant has received and agrees to
be bound by the letter of transmittal and that we may enforce the letter of
transmittal against the participant.
If you tender less than all of your existing bonds, you should fill in the
amount of existing bonds you are tendering in the appropriate box on the letter
of transmittal or, in the case of a book entry transfer, so indicate in an
agent's message if you have not delivered a letter of transmittal. The entire
amount of existing bonds delivered to the exchange agent will be deemed to have
been tendered unless otherwise indicated.
If any letter of transmittal, endorsement, bond power, power of attorney or
any other document required by the letter of transmittal is signed by a
trustee, executor, administrator, guardian, attorney in fact, officer of a
corporation or other person acting in a fiduciary or representative capacity,
that person should so indicate when signing, and, unless waived by us, you must
submit evidence satisfactory to us, in our sole discretion, of that person's
authority to so act.
If you are a beneficial owner of existing bonds that are held by or
registered in the name of a broker, dealer, commercial bank, trust company or
other nominee or custodian, we urge you to contact this entity promptly if you
wish to participate in the exchange offer.
The method of delivery of the existing bonds, the letter of transmittal and
all other required documents is at your option and at your sole risk, and
delivery will be deemed made only when actually received by the exchange agent.
Instead of delivery by mail, we recommend that you use an overnight or hand
delivery service. In all cases, you should allow sufficient time to assure
timely delivery and you should obtain proper insurance. Do not send any letter
of transmittal or existing bonds to the Company. You may request your broker,
dealer, commercial bank, trust company or nominee to effect these transactions
for you.
Book-Entry Transfer
Holders who are participants in The Depository Trust Company tendering by
book-entry transfer must execute the exchange through the Automated Tender
Offer Program of The Depository Trust Company on or before the expiration date.
The Depository Trust Company will verify this acceptance and execute a book-
entry transfer of the tendered existing bonds into the exchange agent's account
at The Depository Trust Company. The Depository Trust Company will then send to
the exchange agent a book-entry confirmation including an
34
agent's message confirming that The Depository Trust Company has received an
express acknowledgement from the holder that the holder has received and agrees
to be bound by the letter of transmittal and that the exchange agent and we may
enforce the letter of transmittal against such holder. The book-entry
confirmation must be received by the exchange agent in order for the exchange
to be effective.
The exchange agent will make a request to establish an account with respect
to the existing bonds at The Depository Trust Company for purposes of the
exchange offer within two business days after the date of this prospectus
unless the exchange agent already has established an account with The
Depository Trust Company suitable for the exchange offer.
Any financial institution that is a participant in The Depository Trust
Company's book-entry transfer facility system may make a book-entry delivery of
the existing bonds by causing The Depository Trust Company to transfer these
existing bonds into the exchange agent's account at The Depository Trust
Company in accordance with The Depository Trust Company's procedures for
transfers.
If the tender is not made through the Automated Tender Offer Program, you
must deliver the existing bonds and the applicable letter of transmittal, or a
facsimile of the letter of transmittal, properly completed and duly executed,
with any required signature guarantees, or an agent's message in lieu of a
letter of transmittal, and any other required documents to the exchange agent
at its address listed under the caption "--Exchange Agent" before the
expiration date, or you must comply with the guaranteed delivery procedures set
forth below in order for the tender to be effective.
Delivery of documents to The Depository Trust Company does not constitute
delivery to the exchange agent and book-entry transfer to The Depository Trust
Company in accordance with its procedures does not constitute delivery of the
book-entry confirmation to the exchange agent.
Signature Guarantees
Signature guarantees on a letter of transmittal or a notice of withdrawal,
as the case may be, are only required if:
(1) existing bonds are registered in a name other than that of the person
submitting a letter of transmittal or a notice of withdrawal; or
(2) a registered holder completes the section entitled "Special Issuance
Instructions" or "Special Delivery Instructions" in the letter of
transmittal. See "Instructions" in the letter of transmittal.
In the case of (1) or (2) above, you must duly endorse the existing bonds or
they must be accompanied by a properly executed bond power, with the
endorsement or signature on the bond power and on the letter of transmittal or
the notice of withdrawal, as the case may be, guaranteed by a firm or other
entity identified in Rule 17Ad-15 under the Exchange Act as an "eligible
guarantor institution" that is a member of a medallion guarantee program,
unless these existing bonds are surrendered on behalf of that eligible
guarantor institution. An "eligible guarantor institution" includes the
following:
. a bank;
. a broker, dealer, municipal securities broker or dealer or government
securities broker or dealer;
. a credit union;
. a national securities exchange, registered securities association or
clearing agency; or
. a savings association.
Guaranteed Delivery
If you desire to tender existing bonds into the exchange offer and:
(1) the existing bonds are not immediately available;
35
(2) time will not permit delivery of the existing bonds and all required
documents to the exchange agent on or before the expiration date; or
(3) the procedures for book entry transfer cannot be completed on a timely
basis;
you may nevertheless tender the existing bonds, if you comply with all of the
following guaranteed delivery procedures:
(1) tender is made by or through an eligible guarantor institution;
(2) before the expiration date, the exchange agent receives from the
eligible guarantor institution a properly completed and duly executed
Notice of Guaranteed Delivery, substantially in the form accompanying
the letter of transmittal. This eligible guarantor institution may
deliver the Notice of Guaranteed Delivery by hand or by facsimile or
deliver it by mail to the exchange agent; and
(3) within three New York Stock Exchange trading days after the date of
execution of the Notice of Guaranteed Delivery, the exchange agent
must receive:
. the existing bonds, or book entry confirmation, representing all
tendered existing bonds, in proper form for transfer;
. a properly completed and duly executed letter of transmittal or
facsimile of the letter of transmittal or, in the case of a book
entry transfer, an agent's message in lieu of the letter of
transmittal, with any required signature guarantees; and
. any other documents required by the letter of transmittal.
Determination of Validity
. We have the right, in our sole discretion, to determine all
questions as to the form of documents, validity, eligibility,
including time of receipt, and acceptance for exchange of any
tendered existing bonds. Our determination will be final and binding
on all parties.
. We reserve the absolute right, in our sole and absolute discretion,
to reject any and all tenders of existing bonds that we determine
are not in proper form.
. We reserve the absolute right, in our sole and absolute discretion,
to refuse to accept for exchange a tender of existing bonds if our
counsel advises us that the tender is unlawful.
. We also reserve the absolute right, so long as applicable law
allows, to waive any of the conditions of the exchange offer or any
defect or irregularity in any tender of existing bonds of any
particular holder whether or not similar defects or irregularities
are waived in the case of other holders.
. Our interpretation of the terms and conditions of the exchange
offer, including the letter of transmittal and the instructions
relating to it, will be final and binding on all parties.
. We will not consider the tender of existing bonds to have been
validly made until all defects or irregularities with respect to the
tender have been cured or waived.
. We, our affiliates, the exchange agent, and any other person will
not be under any duty to give any notification of any defects or
irregularities in tenders and will not incur any liability for
failure to give this notification, nor do we have any duty to
provide notice of acceptance of the tender of existing bonds.
Acceptance for Exchange for the New Bonds
For each existing bond accepted for exchange, the holder of the existing
bond will receive a new bond having a principal amount equal to that of the
surrendered existing bond. The new bonds will bear interest from
36
the most recent date to which interest has been paid on the existing bonds.
Accordingly, registered holders of new bonds on the relevant record date for
the first interest payment date following the completion of the exchange offer
will receive interest accruing from the most recent date to which interest has
been paid. Existing bonds accepted for exchange will cease to accrue interest
from and after the date of completion of the exchange offer.
Upon satisfaction or waiver of all of the conditions of the exchange offer,
we will accept, promptly after the expiration date, all existing bonds properly
tendered and will issue the new bonds promptly after acceptance of the existing
bonds. See "--Conditions to the Exchange Offer." Subject to the terms and
conditions of the exchange offer, we will be deemed to have accepted for
exchange, and exchanged, existing bonds validly tendered and not withdrawn as,
if and when we give oral or written notice to the exchange agent, with any oral
notice promptly confirmed in writing by us, of our acceptance of these existing
bonds for exchange in the exchange offer. The exchange agent will act as our
agent for the purpose of receiving tenders of existing bonds, letters of
transmittal and related documents, and as agent for tendering holders for the
purpose of receiving existing bonds, letters of transmittal and related
documents and transmitting new bonds to holders who validly tendered existing
bonds. The exchange agent will make the exchange promptly after the expiration
date. If for any reason whatsoever:
. the acceptance for exchange or the exchange of any existing bonds
tendered in the exchange offer is delayed, whether before or after our
acceptance for exchange of existing bonds;
. we extend the exchange offer; or
. we are unable to accept for exchange or exchange existing bonds tendered
in the exchange offer;
then, without prejudice to our rights set forth in this prospectus, the
exchange agent may, nevertheless, on our behalf and subject to Rule 14e-1(c)
under the Exchange Act, retain tendered existing bonds and these existing bonds
may not be withdrawn unless tendering holders are entitled to withdrawal rights
as described under "--Withdrawal Rights."
Interest
For each existing bond that we accept for exchange, the existing bond holder
will receive a new bond having a principal amount and final distribution date
equal to that of the surrendered existing bond. Interest on the new bonds will
accrue from January 5, 2002, the last interest payment date on which interest
was paid on the existing bonds tendered for exchange. The next interest payment
date will be July 5, 2002.
Resales of the New Bonds
Based on interpretations by the staff of the SEC set forth in no-action
letters issued to third parties, we believe that the new bonds may be offered
for resale, resold and otherwise transferred by you without compliance with the
registration and prospectus delivery requirements of the Securities Act
provided that:
. you acquire any new bond in the ordinary course of your business;
. you are not participating, do not intend to participate and have no
arrangement or understanding with any person to participate, in the
distribution of the new bonds;
. you are not a broker-dealer who purchased existing bonds directly from us
for resale under Rule 144A or any other available exemption under the
Securities Act; and
. you are not an "affiliate" (as defined in Rule 405 under the Securities
Act) of our company.
If our belief is inaccurate and you transfer any new bond without delivering
a prospectus meeting the requirements of the Securities Act or without an
exemption from registration of your bonds from these requirements, you may
incur liability under the Securities Act. We do not assume any liability or
indemnify you against any liability under the Securities Act.
37
Each broker-dealer that is issued new bonds for its own account in exchange
for existing bonds must acknowledge that it will deliver a prospectus meeting
the requirements of the Securities Act in connection with any resale of the new
bonds. A broker-dealer that acquired existing bonds for its own account as a
result of market making or other trading activities may use this prospectus for
an offer to resell, resale or other retransfer of the new bonds.
Withdrawal Rights
Except as otherwise provided in this prospectus, you may withdraw your
tender of existing bonds at any time before the expiration date.
In order for a withdrawal to be effective, you must deliver a written,
telegraphic or facsimile transmission of a notice of withdrawal to the exchange
agent at any of its addresses listed under the caption "--Exchange Agent"
before the expiration date.
Each notice of withdrawal must specify:
(1) the name of the person who tendered the existing bonds to be withdrawn;
(2) the aggregate principal amount of existing bonds to be withdrawn; and
(3) if existing bonds have been tendered, the name of the registered holder
of the existing bonds as set forth on the existing bonds, if different
from that of the person who tendered these existing bonds.
If you have delivered, or otherwise identified to the exchange agent,
existing bonds, the notice of withdrawal must specify the serial numbers on the
particular bonds to be withdrawn and the signature on the notice of withdrawal
must be guaranteed by an eligible guarantor institution, except in the case of
existing bonds tendered for the account of an eligible guarantor institution.
If you have tendered existing bonds in accordance with the procedures for
book entry transfer listed in "--Procedures for Tendering the Existing Bonds--
Book Entry Transfer," the notice of withdrawal must specify the name and number
of the account at The Depository Trust Company to be credited with the
withdrawal of existing bonds and must otherwise comply with the procedures of
The Depository Trust Company.
You may not rescind a withdrawal of your tender of existing bonds.
We will not consider existing bonds properly withdrawn to be validly
tendered for purposes of the exchange offer. However, you may retender existing
bonds at any subsequent time before the expiration date by following any of the
procedures described above in "--Procedures for Tendering the Existing Bonds."
We, in our sole discretion, will determine all questions as to the validity,
form and eligibility, including time of receipt, of any withdrawal notices. Our
determination will be final and binding on all parties. Neither we, our
affiliates, the exchange agent and any other person have any duty to give any
notification of any defects or irregularities in any notice of withdrawal and
will not incur any liability for failure to give any such notification.
We will return to the holder any existing bonds that have been tendered but
which are withdrawn promptly after the withdrawal.
Conditions to the Exchange Offer
Notwithstanding any other provisions of the exchange offer or any extension
of the exchange offer, we will not be required to accept for exchange, or to
exchange, any existing bonds. We may terminate the exchange offer, whether or
not we have previously accepted any existing bonds for exchange, or we may
waive any conditions to or amend the exchange offer, if we determine in our
sole and absolute discretion that the exchange offer would violate applicable
law or regulation or any applicable interpretation of the staff of the SEC.
38
Exchange Agent
We have appointed Bank One Trust Company, National Association as exchange
agent for the exchange offer. You should direct all deliveries of the letters
of transmittal and any other required documents, questions, requests for
assistance and requests for additional copies of this prospectus or of the
letters of transmittal to the exchange agent as follows:
By Facsimile: By Registered or By Hand/Overnight
(312) 407-8853 Certified Mail: Delivery:
Bank One Trust Company, Bank One Trust Company,
N.A. N.A.
1 Bank One Plaza One North State Street
Mail Suite IL1-0124 9th Floor
Chicago, Illinois 60670- Chicago, Illinois 60602
0124 Attention: Exchanges
Attention: Exchange
Floor Global Corporate
Trust Services
Confirm by telephone:
(800) 524-9472
For additional information, you may call (800) 524-9472.
Delivery to other than the above addresses or facsimile number will not
constitute a valid delivery.
Fees and Expenses
We will bear the expenses of soliciting tenders of the existing bonds. We
will make the initial solicitation by mail; however, we may decide to make
additional solicitations personally or by telephone or other means through our
officers, agents, directors or employees.
We have not retained any dealer-manager or similar agent in connection with
the exchange offer and we will not make any payments to brokers, dealers or
others soliciting acceptances of the exchange offer. We have agreed to pay the
exchange agent and trustee reasonable and customary fees for its services and
will reimburse it for its reasonable out of pocket expenses in connection with
the exchange offer. We will also pay brokerage houses and other custodians,
nominees and fiduciaries the reasonable out of pocket expenses they incur in
forwarding copies of this prospectus and related documents to the beneficial
owners of existing bonds, and in handling or tendering bonds for their
customers.
Transfer Taxes
Holders who tender their existing bonds will not be obligated to pay any
transfer taxes in connection with the exchange, except that if:
. you want us to deliver new bonds to any person other than the registered
holder of the existing bonds tendered;
. you want us to issue the new bonds in the name of any person other than
the registered holder of the existing bonds tendered; or
. a transfer tax is imposed for any reason other than the exchange of
existing bonds in connection with the exchange offer;
then you will be liable for the amount of any transfer tax, whether imposed on
the registered holder or any other person. If you do not submit satisfactory
evidence of payment of such transfer tax or exemption from such transfer tax
with the letter of transmittal, the amount of this transfer tax will be billed
directly to the tendering holder.
39
Consequences of Exchanging or Failing to Exchange Existing Bonds
Holders of existing bonds who do not exchange their existing bonds for new
bonds in the exchange offer will continue to be subject to the provisions of
the indenture regarding transfer and exchange of the existing bonds and the
restrictions on transfer of the existing bonds set forth on the legend on the
existing bonds. In general, the existing bonds may not be offered or sold,
unless registered under the Securities Act, except under an exemption from, or
in a transaction not subject to, the registration requirements of the
Securities Act and applicable state securities laws.
Based on interpretations by the staff of the SEC, as detailed in no-action
letters issued to third parties, we believe that new bonds issued in the
exchange offer in exchange for existing bonds may be offered for resale, resold
or otherwise transferred by you (unless you are an "affiliate" of our company
within the meaning of Rule 405 under the Securities Act) without compliance
with the registration and prospectus delivery provisions of the Securities Act,
provided that the new bonds are acquired in the ordinary course of your
business, you have no arrangement or understanding with any person to
participate in the distribution of these new bonds and you are not a broker-
dealer who purchased existing bonds directly from us for resale under Rule 144A
or any other available exemption under the Securities Act. However, we do not
intend to request the SEC to consider, and the SEC has not considered, the
exchange offer in the context of a no-action letter and we cannot guarantee
that the staff of the SEC would make a similar determination with respect to
the exchange offer.
Each holder must acknowledge that it is not engaged in, and does not intend
to engage in, a distribution of new bonds and has no arrangement or
understanding to participate in a distribution of new bonds. If any holder is
an affiliate of our company, is engaged in or intends to engage in or has any
arrangement or understanding with respect to the distribution of the new bonds
to be acquired under the exchange offer, the holder:
. cannot rely on the applicable interpretations of the staff of the SEC;
and
. must comply with the registration and prospectus delivery requirements
of the Securities Act.
Each broker-dealer that receives new bonds for its own account in exchange
for existing bonds, if its existing bonds were acquired as a result of market
making or other trading activities, must acknowledge that it will deliver a
prospectus in connection with any resale of the new bonds. See "Plan of
Distribution."
In addition, to comply with state securities laws, the new bonds may not be
offered or sold in any state unless they have been registered or qualified for
sale in the state or an exemption from registration or qualification is
available and is complied with. The offer and sale of the new bonds to
"qualified institutional buyers" (as defined under Rule 144A of the Securities
Act) is generally exempt from registration or qualification under the state
securities laws. We currently do not intend to register or qualify the sale of
the new bonds in any state where an exemption from registration or
qualification is required and not available.
40
PROCEEDS
We will not receive any cash proceeds from the issuance of the new bonds. We
used the net proceeds of the existing bonds together with available cash, for
the following purposes:
. working capital;
. financing, legal, and consulting fees and expenses associated with the
transaction;
. required funding of the major maintenance reserve account;
. payments for residual construction costs, principally payments under our
contracts with GE; and
. repayment in full of indebtedness outstanding under existing
intercompany loans provided by our owners and partial reimbursement of
our owners for advances or capital contributions to us that we had used
to pay the costs of developing, constructing and financing our facility.
CAPITALIZATION
The following table sets forth our capitalization as of September 30, 2001,
and as adjusted to give effect to the issuance of the existing bonds and
related transactions:
Actual As Adjusted
----------- -------------
(amounts in thousands)
Cash and equivalents (including restricted
cash)........................................... $ 74 $ 16,855
=========== ===========
Intercompany debt................................ $ 275,843 $ -0-
Senior Secured Bonds............................. -0- 402,000
----------- -----------
Total debt..................................... $ 275,843 $ 402,000
Members' capital................................. 229,528 132,462
----------- -----------
Total capitalization........................... $ 505,371 $ 534,462
41
SELECTED HISTORICAL FINANCIAL DATA
Until August 2001, Elwood Energy LLC owned only Units 1-4, and Units 5-9
were held in separate companies. On August 3, 2001, completion of the merger of
the other companies into Elwood Energy LLC occurred so that Elwood Energy LLC,
together with its subsidiaries, now owns the entire facility. The merger has
been accounted for on the historical cost basis and the financial information
for all periods presented has been combined.
Year Ended September 30,
--------------------------
2001 2000 1999
-------- -------- -------
(In thousands)
Selected Income Statement Data:
Operating Revenues
Electric sales.................................... $ 88,270 $ 56,849 $25,593
Gain on settlement of derivative.................. 8,197
-------- -------- -------
Total operating revenues........................ 96,467 56,849 25,593
-------- -------- -------
Operating Expenses
Fuel.............................................. 23,779 16,045 4,439
Operations........................................ 3,750 2,470 1,248
General and administrative........................ 882 371 504
Other taxes....................................... 201 288 61
Depreciation...................................... 15,837 8,233 3,085
-------- -------- -------
Total operating expenses........................ 44,207 27,407 9,337
-------- -------- -------
Operating income.................................. 52,018 29,442 16,256
-------- -------- -------
Interest expense.................................. (3,937) -- --
Interest income................................... 1,132 913 51
Other income...................................... 1 1 721
Cumulative effect of change in accounting
principle........................................ 158 -- --
-------- -------- -------
Net income........................................ $ 49,372 $ 30,356 $17,028
======== ======== =======
As of September 30,
-------------------
2001 2000
--------- ---------
(In thousands)
Selected Balance Sheet Data:
Cash and cash equivalents................................ $ 74 $ 8,533
Note receivable from affiliate........................... 32,406 17,704
Property, plant & equipment, net......................... 514,289 313,625
Total assets............................................. 581,398 350,913
Notes payable to affiliates.............................. 275,843 130,126
Total liabilities........................................ 351,870 138,857
Total members' capital................................... 229,528 212,056
42
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion should be read in conjunction with our audited financial
statements contained in this registration statement, as well as "Selected
Historical Financial Data".
General
The Company owns a 1,409 megawatt electric generation peaking facility,
consisting of nine natural gas-fired, simple-cycle units of approximately 156.5
megawatts each. Units 1-4, totaling 626 megawatts, were completed and achieved
commercial operation in July 1999. Construction on Units 5-9, totaling 783
megawatts, began in July 2000 and the units reached commercial operation
between May and July 2001. Our revenues are primarily derived from, and costs
are incurred in connection with, the generation and sale of electricity under
long-term power sales agreements.
In August 2001, Elwood Energy LLC merged with Elwood Energy II, LLC and
Elwood Energy III, LLC, with Elwood Energy LLC as the surviving entity. All of
the entities that participated in the merger were owned 50% by Dominion Elwood,
Inc. and affiliates and 50% by Peoples Elwood LLC and affiliates. The merger
has been accounted for on the historical cost basis and the results of
operations for all periods presented have been combined.
Results of Operations
2001. In fiscal year 2001 we earned net income of $49,372,000 on electric
sales of $88,270,000 and total revenues of $96,467,000. As in 2000, electric
sales revenues consisted of payments under the Engage and Exelon power sales
agreements. In addition, Units 5-9 achieved commercial operation in May/June of
2001, so revenues included approximately three months of payments under the
Aquila power sales agreements. Electric sales revenues consisted of capacity,
energy and start-up payments of $69,135,000, $18,269,000 and $866,000,
respectively. Net income was higher than in fiscal 2000 primarily due to the
addition of Units 5-9 and a gain from closing all open hedge positions in
February 2001. These open positions were closed in conjunction with the
execution of an amended power sales agreement with Exelon as of March 1, 2001
that mitigated our natural gas risk.
The increase in net income was partially offset by higher depreciation,
operating expenses and interest expense. Revenues were higher due to the $8
million gain recognized as a result of closing our open hedge positions and
increased energy sales due to the additional units being available. Increased
capacity revenues, resulting from Units 5-9 achieving commercial operation,
were partially offset by the higher capacity rates in effect for Units 1-4
during portions of the 2000 period. Increased fuel costs for the period prior
to the execution of the amended Exelon agreement generally offset the increased
electric revenues. Depreciation expense increased due to Units 5-9 achieving
commercial operation. Other operating expenses increased primarily due to
additional start-up, training and unit check out costs attributable to the new
units. Interest expense increased due to the financing of Units 5-9 through the
issuance of intercompany debt.
2000. Fiscal year 2000 was our first full year of operation of Units 1-4. We
earned net income of $30,356,000 on electric sales of $56,849,000, which was
consistent with expectations. As in 1999, electric sales revenues consisted of
capacity, energy and start-up payments of $42,051,000, $14,047,000 and
$751,000, respectively, under the Engage and Exelon power sales agreements.
Capacity payments reflected the scheduled reduction in capacity rates mentioned
above.
Fuel costs in 2000 reflected higher natural gas commodity prices. We entered
into commodity natural gas hedges as a means to control fluctuations in natural
gas prices. A $4 million gain on the hedges was recognized as a reduction to
fuel expense.
43
Interest income of $913,000 reflects our credit agreement with DEI under
which the Company loaned excess funds to DEI at competitive interest rates
pending distribution to members.
1999. Because Units 1-4 achieved commercial operation in July 1999, the
Company had approximately 2 1/2 months of commercial operation in the fiscal
year ending September 30, 1999. The Company earned net income of $17,028,000 on
electric sales of $25,593,000. Electric sales revenues consisted of capacity,
energy and start-up payments of $18,721,000, $6,544,000 and $328,000,
respectively, under the Engage and Exelon power sales agreements.
Capacity revenues and net income were relatively high due to two factors.
The first was the higher capacity rates in effect under our power sales
agreements during the first partial contract year ending December 31, 1999. We
received capacity payments of $9.00/kW-month and $10.85/kW-month from Engage
and Exelon, respectively, during that year, after which the capacity payments
reduced to $5.00kW-month for the remaining term of both agreements. The second
was our recording of capacity revenues based on estimated operating hours of
the plant, in accordance with Emerging Issues Task Force (EITF) Issue 91-6,
Revenue Recognition of Long-Term Power Sales Contracts. This accounting
treatment allocated a large portion of annual capacity revenue to the summer
months when the highest level of generation activity occurred.
Operations and general and administrative expenses were relatively high
during that year due to the need to have operating staff in place for
approximately eight months to provide for start-up, training, contractor
support and unit check out.
All funding for the Company was provided by advances and capital
contributions from its members and from cash flow from operations after
commencement of commercial operations in July 1999. There was thus no interest
expense in fiscal 1999.
Liquidity and Capital Resources
Internal Sources of Liquidity. Cash flows from operating activities provided
$90 million, $32 million and $24 million during the years ended September 30,
2001, 2000 and 1999, respectively. Short-term cash requirements not met by the
timing or amount of cash flows from operations were generally satisfied with
proceeds from short-term borrowings from DEI and PERC. Long-term cash needs
were met through additional capital contributions and borrowings from members.
Plant Financing. Units 1-4, constructed during years 1999 and 2000, were
financed primarily using member contributed capital of $175,000,000. In
connection with the construction of Units 5-9 during years 2000 and 2001, the
Company borrowed funds under separate notes payable from both DEI and PERC. The
total amounts borrowed from DEI and PERC were $135,950,000 and $138,893,000,
respectively. Interest on related party advances and notes payable was
calculated using DEI's internal borrowing rate. These notes were repaid using
bond proceeds.
Future Liquidity. The Company's generating facilities have been constructed
within the last four years; no major plant additions relating to the existing
units are planned. The Company does not have any existing revolving line of
credit with DEI, PERC or a commercial bank, although the bond documents permit
the Company to incur indebtedness to finance working capital. The Company's
ability to incur other indebtedness will be limited as described under
"Description of the Bonds--Indenture--Limitations on Indebtedness." In
addition, the Company's members are not required to make any additional capital
contributions to fund operations or capital expenditures. The Company will
therefore be primarily dependent upon cash flows from operations to cover
operating expenses, maintenance and routine capital expenditures, and debt
service on the bonds.
44
OUR BUSINESS AND REGULATORY ENVIRONMENT
Elwood Energy LLC is a Delaware limited liability company formed in 1998 to
develop, finance, construct, own and operate a natural gas-fired, electric
generation peaking facility (the "Facility") in Elwood, Illinois, about 50
miles southwest of Chicago. Construction began on Units 1-4 in 1998, and these
units entered commercial operation in July 1999. Construction began on Units 5-
9 in July 2000, and they entered commercial operation between May and July
2001.
Indirect Owners. We are indirectly owned by DEI and PERC.
DEI is a wholly-owned subsidiary of Dominion Resources, Inc. ("Dominion
Resources"), a fully integrated gas and electric holding company with nearly 4
million customers, a 22,000 megawatt portfolio of electric power generation,
7,600 miles of gas transmission pipeline and an over 950 billion cubic foot
natural gas storage network. DEI is Dominion Resources' principal independent
power subsidiary and is also the parent corporation of a number of subsidiaries
engaged in oil and gas exploration and production. DEI currently has assets of
approximately $4.4 billion and operates generation facilities in Connecticut,
West Virginia, and Illinois. Dominion Resources also owns Virginia Electric and
Power Company ("Virginia Power"), an electric utility with generation
facilities in Virginia, West Virginia and North Carolina and a 30,000 square
mile service territory in Virginia and northeastern North Carolina.
PERC is a wholly-owned subsidiary of Peoples Energy Corporation, a
diversified energy holding company which, through its subsidiaries, engages
principally in natural gas utility operations and other energy businesses.
Peoples Energy Corporation's business operations are grouped in the following
segments: gas distribution; power generation; midstream services; retail energy
services; and oil and gas production. Peoples Energy Corporation's regulated
subsidiaries purchase, store, distribute, sell and transport natural gas to
approximately one million retail customers through a 6,000-mile distribution
system serving the City of Chicago and 54 communities in northeastern Illinois.
Peoples Energy Corporation has assets of approximately $3.1 billion. PERC was
formed by Peoples Energy Corporation to engage in various unregulated wholesale
energy-related businesses, including midstream services and power generation.
PERC is engaged in the development, construction, operation and ownership of
natural gas-fired electric generation facilities for the sale of electricity to
electric utilities and marketers. PERC is actively pursuing power generation
opportunities both regionally and throughout the country in addition to the
further expansion of its existing facilities.
Description of Facility. With the completion of Units 5-9, our Facility is a
1,409 megawatt electric generation peaking facility, consisting of nine natural
gas-fired, simple-cycle units of approximately 156.5 megawatts each. Natural
gas-fired units use natural gas as fuel; simple-cycle units use natural gas-
fired turbines to generate electricity on a stand-alone basis. The Facility was
constructed in two phases. The first phase began in 1998 and consisted of the
installation of four GE-7FA combustion turbines, with GE as our engineering,
procurement and construction contractor ("Phase I"). Phase I achieved
commercial operation in July 1999. Based on the success of Phase I and
continued demand for peaking power in the region, we broke ground on
construction of the second phase of the Facility in July 2000 ("Phase II").
Phase II, which included an additional five GE-7FA combustion turbines,
achieved commercial operation between May and July of 2001. All nine units can
be operated from a common control room located in our general services
building, or locally at the unit electrical control enclosures.
Our Facility contains the following major equipment and systems:
. General Electric GE-7FA gas combustion turbines with dry low NOx
combustion technology;
. General Electric 7FH2 hydrogen cooled electric generators;
. Speedtronic(TM) Mark V turbine control systems;
. fuel gas, compressed gas, exhaust, turning gear and starting, and
compressor wash water systems;
45
. air quality control and monitoring systems; and
. various auxiliary plant systems and associated equipment and buildings,
including water systems, fire protection systems, and administration,
training and maintenance buildings.
The Facility is located on two adjoining parcels of land. The first, on
which Units 1-4 are located, is an 21.5 acre parcel north of Noel Road and west
of Patterson Road held by us under a ground lease with PERC. See "Description
of the Principal Project Documents--Ground Lease." Units 5-9 are located on
approximately 49.5 acres of land north of Noel Road and east of Patterson Road
held by us in fee.
Power Generation Equipment and Cycle. We purchased all nine GE-7FA gas
combustion turbines from GE. All units generate power at 18 KV, which is
stepped up with transformers to a nominal 345 KV for delivery to the
interconnection point at the TSS-900 switching station. The TSS-900 switching
station is located on approximately 8.5 acres of land at the corner of Noel
Road and Patterson Road. This substation was constructed and commissioned by us
and then conveyed to ComEd in accordance with Federal Energy Regulatory
Commission ("FERC") regulations. Synchronizing of the units is performed via a
low side generator breaker. The ComEd 345 KV system is divided into two systems
for increased reliability, which are known as the "Red" system and the "Blue"
system. Our units are connected to two distinct interconnection points in the
TSS-900 switching station. Units 1-4 are connected to a ring bus configuration
designated for the Red system, and Units 5-9 are connected to a ring bus
designated for the Blue system. The Red and Blue systems operate on separate
345 KV lines. As a further enhancement to system reliability, the Red system
can be cross-connected to the Blue system at TSS-900 to allow any of our
generators to connect to either system should a single system be down for
maintenance.
Gas is supplied to our units through separate gas measurement and pressure
reduction stations operated by Nicor. Units 1-4 have separate metering from
Units 5-9. Phase II is further divided into a system that supplies gas to Units
5-8 and a system that supplies gas to Unit 9. The gas is passed through
scrubbers, filters, and preheaters before arriving at the operating unit.
Stone & Webster 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 Stone & Webster report in its entirety.
Completion of Construction of our Facility. Construction of our Facility was
completed in two phases: Units 1-4 achieved commercial operation in July 1999
and Units 5-9 all reached commercial operation by July 3, 2001. Construction
was performed by GE on a fixed price, turnkey basis under five separate
engineering, procurement and construction contracts covering the various units.
We believe the warranty periods from GE are typical of those in projects
similar to ours. For a more detailed discussion, see "Description of the
Principal Project Documents--EPC Contracts."
Power Sales. We have entered into four long-term power sale agreements with
three purchasers. The power sales agreements provide for payment to us of (1) a
monthly fixed fee "capacity charge" based on the tested capacity of the units,
as adjusted for the performance reliability of the Facility to meet dispatch;
and (2) an energy payment composed of a fuel charge based on a published index
price of gas and the Facility's heat rate, plus certain variable operating and
maintenance expenses. The overall effect of these contracts is to index energy
pricing to the market price of natural gas, thereby mitigating our natural gas
price risk.
We have an agreement with Engage that covers Units 1-2 through December 31,
2004; an agreement with Exelon that covers Units 3, 4 and 9 through December
31, 2012 and Units 1-2 from January 1, 2005 through December 31, 2012; and two
agreements with Aquila/UtiliCorp that cover Units 5-6 and 7-8, respectively,
for terms expiring on August 31, 2016 and August 31, 2017. Aquila/UtiliCorp may
extend the term of each of its contracts by an additional five years at its
option. In connection with its analysis of the MAIN electric power market, Pace
has concluded that based on the payment structure of the Aquila/UtiliCorp power
sales agreements, our Facility's forecast dispatch profile, forecast market-
clearing prices and the energy and capacity revenues and
46
volatility values for Aquila/UtiliCorp from reselling the output and capacity
of Units 5-8, it is likely that Aquila/UtiliCorp will have economic incentives
to exercise these extension options. See "Annex C-1--Executive Summary--Power
Sales Agreements--Extension of Aquila Power Sales Agreements."
Engage has sold the energy and capacity of Units 1 and 2 during the
remaining term of its contract with us to Exelon and has appointed Exelon as
its agent to dispatch the units. We have entered into a "true up" arrangement
with Exelon that puts both of us in essentially the same economic position as
would exist if Units 1 and 2 were currently part of the Exelon contract. The
"true up" calculates the differences between various pricing and operational
parameters of the Engage agreement and those in the Exelon agreement with us.
The difference will appear as an increase or a decrease to the monthly payment
calculation under the Exelon agreement such that the ultimate cost of Exelon's
purchase of energy and capacity from Engage for Units 1 and 2 is effectively
the same as if Exelon purchased the capacity and energy of Units 1 and 2
directly from us under the Exelon agreement. We continue to bill, and receive
payments from, Engage, in accordance with the terms of our agreement with
Engage. So long as all parties perform their obligations, we are in essentially
the same position we would be if the Exelon power sales agreement already
covered all five units.
Exelon and Aquila/UtiliCorp have exclusive rights to dispatch the units to
which their respective contracts apply, but they must provide advance notice
approximately one hour before start-up in the summer peak period hours and four
hours before start-up in all other periods. Once dispatched, the units must
generally run for no less than four hours.
We describe the power sales agreements discussed above in greater detail
under the caption "Description of the Principal Project Documents--Power Sales
Agreements." We encourage you to read that section in its entirety.
Fuel Supply. We have contracted for the purchase of firm gas supplies, as
needed and generally only when the Facility consumes gas, at a daily spot gas
price under a fuel supply and management agreement with Cinergy. Because our
Facility is designed as a peaking facility, it is expected to operate on short
notice and will experience significant hourly, daily and seasonal variations in
fuel requirements. If we run all nine turbines for a full 16-hour period, we
will require approximately 240,000 MMBtu/day to 285,000 MMBtu/day, depending on
the season, to satisfy our full fuel requirement. Because our run times are
unknown, purchasing fuel in advance would create a risk of having to sell the
purchased fuel at market prices if our units are not dispatched. Accordingly,
we purchase our fuel requirements on an as-needed basis under the fuel supply
and management agreement with Cinergy. This agreement provides for the firm
delivery of gas supplies as needed, and is priced at a daily spot price, plus a
nominal premium, which corresponds to the rate we charge for energy sold under
our contracts with Exelon and Aquila/UtiliCorp.
The Cinergy contract terminates on April 30, 2002. The Cinergy service was
bid and awarded in February 2001 at a time when natural gas supply prices were
abnormally high. Natural gas prices have since declined and we have completed
our first summer of operations as an expanded facility. We therefore believe we
have the opportunity to enter into a contract on more favorable terms for a
multi-year period with Cinergy or another national energy marketing company.
For a more detailed description of our agreement with Cinergy, see "Description
of the Principal Project Documents--Fuel Agreements."
We believe we will have an ample supply of natural gas for our Facility. As
our independent fuel consultant, Pace, has noted, we currently have the
flexibility to acquire abundant gas supplies from numerous sources. A number of
high pressure, high deliverability gas pipelines interconnect near Chicago and
are linked to gas reserves in upstream basins. Pace expects that the gas
resources from these basins will continue to be available through the term of
the bonds. In addition, the development of liquid trading points throughout the
United States and Canada and the Midwest's favorable location on the natural
gas transportation grid should facilitate access to diverse sources and
flexibility in meeting specific supply requirements. See "Annex C-2--Risks and
Risk Mitigation--Adequacy of Supply."
47
Gas Pipeline Interconnections and Fuel Transportation Services. We have
entered into a long-term transportation and storage balancing service with
Nicor for firm (non-interruptible) hourly delivery of fuel supplies to meet the
firm power dispatch obligations at the Facility. PGL is the owner and operator
of the pipeline delivering gas to the Facility but Nicor holds the utility
franchise to gas utility services in the region where the Facility is located.
Because Nicor only owns meters at the Facility, Nicor renders this service with
the support of PGL, through a companion agreement that contains substantially
the same terms and conditions as our agreement with Nicor.
Gas transportation and balancing is provided on a firm, short-notice basis
to meet the hourly dispatches of our power sales customers. Nicor furnishes
transportation and balancing service to facilitate the delivery of supplies in
a "just in time" manner. Transportation service under the Nicor agreement
allows for the purchase and receipt of gas from interstate supplies delivered
to Nicor in Chicago by NBPL (Western Canadian supplies), APL (Western Canadian
supplies), and NGPL (MidContinent, Gulf Coast, U. S. Rocky Mountain and
Canadian supplies). The Nicor firm transportation service also allows us to
receive gas from our own inventories that were previously delivered and stored.
Our site is also connected indirectly to PGL's Mahomet line, offering a source
of back-up supplies if Nicor suffers a supply disruption.
In addition to our firm transportation service options, the local market has
substantial storage capacity. Both local distribution companies, Nicor and PGL,
own and operate large local storage fields near our Facility and also contract
for significant capacity from interstate pipelines and from other sources. Much
of this contract storage is also located near our site in a geological region
that supports aquifer storage of gas. The abundance of local storage and the
convergence of numerous interstate pipelines form an array of supply options,
are the foundation for the local market's ability to maintain liquidity, and
should provide a constant market for natural gas spot supplies.
We describe our agreement with Nicor in greater detail under "Description of
the Principal Project Documents--Fuel Agreements." We encourage you to read
that section in its entirety.
Electric Interconnection. Interconnection to the electric power grid is
provided by ComEd via a switchyard that we have constructed. Transmission
service beyond the interconnection point is currently the responsibility of our
customers. Our interconnection agreements with ComEd run until they are
terminated in accordance with their terms or we or our permitted assigns no
longer operate the Facility. See "Description of the Principal Project
Documents--Interconnection Agreements."
Water Supply. The water supply for the Facility, including service water and
water for fire protection, comes from wells on adjacent property owned by PERC.
PERC also provides other support and services to our Facility under a Common
Facilities Agreement. These services include disposal of storm water discharge
and blowdown water from Units 1-4 of our Facility. See "Description of the
Principal Project Documents--Common Facilities Agreement."
Operation and Maintenance. DELSCO, a wholly-owned subsidiary of DEI,
provides operation and maintenance services for us under an operations and
maintenance agreement covering all nine units. DELSCO is responsible for, among
other things, hiring and supervising properly trained personnel, maintaining
facility standards and safety, performing routine maintenance, developing
annual budgets and maintaining facility performance levels. We pay DELSCO a
fixed annual fee of $650,000, which is adjusted annually for inflation, and we
reimburse DELSCO for labor costs, spare and replacement parts, materials, tools
and equipment, chemicals and lubricants, instrumentation, equipment overhauls,
insurance costs and facility-related office expenses. For a more detailed
discussion, see "Description of the Principal Project Documents--Operation and
Maintenance Agreement." DELSCO has an employee incentive plan tied to our
meeting our performance requirements under our power sales agreements. In
addition, DEI, of which DELSCO is a subsidiary, and its affiliates have
approximately 47 combustion turbines similar to ours in operation or on order,
which provides both a base of experience for the management of our operations
and an opportunity for synergies in obtaining maintenance and spare parts.
48
Employees. We do not have any employees. DELSCO employs a total of 16
employees to work at our Facility. No DELSCO employees who work at our Facility
are union employees. Because we do not have any employees, we are dependent
upon a number of third parties, including DELSCO, for the provision of
substantially all the services that we require. See "Risk Factors--Operating
Risks."
Insurance. We currently maintain and intend to continue to maintain a
comprehensive insurance program underwritten by recognized insurance companies
licensed to do business in Illinois. This insurance program includes general
liability, automobile liability, workers' compensation, employer's liability,
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 electric generating facilities of similar size.
Legal Proceedings. We are not currently a party to any material pending or
threatened legal proceedings.
Competition and Energy Regulation
The Energy Policy Act of 1992 laid the groundwork for a competitive
wholesale market for electricity. Among other things, the Energy Policy Act
expanded the FERC's authority to order electric utilities to transmit, or
"wheel," third-party electricity over their transmission lines. In addition, in
1996 the FERC 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 whole generators ("EWGs"), a new category of generating entity
created by the Energy Policy Act, to compete more effectively in the wholesale
market.
At this time we cannot predict how changing industry conditions may affect
our future operations. However, because we have long-term contracts for the
sale of our capacity and output to Engage, Exelon and Aquila/UtiliCorp, we do
not expect competitive forces to have a significant effect on our business
during the terms of these contracts, unless they affect the ability of these
purchasers to perform their obligations under the contracts. After the
termination of these power sales agreements, we may be subject to market
competition for the sale of all or part of our electric generating capacity and
electrical output.
When our agreements with Exelon and Aquila/UtiliCorp expire, we plan to
enter into new long-term power sales agreements (by extending or renewing
contracts with our existing customers or entering into new third party
contracts). If we cannot enter into long-term power sales agreements, we will
sell the capacity and energy from our Facility on a "merchant" basis. Merchant
marketing may involve the sale of the capacity and energy of the Facility on a
shorter-term "spot" basis and/or the use of hedging products to manage
volatility.
While we cannot predict future market developments with any certainty, Pace,
our independent power market and fuel consultant, has concluded that MAIN is
emerging as a highly competitive market for wholesale power and that given the
MAIN market's expected demand growth, Pace's market price forecast and our
Facility's competitive market position, our Facility is expected to be
competitive during the term of the bonds. See Annex C-1 to this prospectus.
We were initially certified by the FERC as an EWG on March 5, 1999. We
intend to continue to operate as an EWG. An EWG must be engaged exclusively in
the business of owning or operating an eligible facility and selling
electricity at wholesale. An eligible facility is a generating facility used
solely to produce electricity exclusively for sale at wholesale. An EWG is
exempt from the Public Utility Holding Company Act of 1935, and no company
becomes a holding company under the Public Utility Holding Company Act because
it holds membership interests in us. There is no restriction on the proportion
of equity interest in an EWG that may be held by electric utilities and
electric utility holding companies. If at any time there is a "material change"
in facts that might affect our continued eligibility for EWG status, we must
within 60 days (1) file with the FERC a written explanation of why the material
change does not affect our status, (2) file a new application for EWG status,
or (3) notify the FERC that we no longer wish to maintain EWG status.
49
We are a public utility under the Federal Power Act and subject to the
jurisdiction of the FERC with respect to our wholesale electric rates and other
matters. We have applied to the FERC for, and received authority to, make
wholesale sales of electricity to our wholesale customers at market-based
rates. The FERC's order, as is customary with market-based rate schedules,
reserved the right to revoke our market-based rate authority if it is
subsequently determined that we or our affiliates possess excessive market
power.
Proposals have been introduced in Congress to repeal the Public Utility
Holding Company Act. The FERC and the SEC have publicly indicated support for
such repeal. If the repeal of the Public Utility Holding Company Act occurs,
either separately or as part of legislation designed to encourage the broader
introduction of wholesale and retail competition, the competitive advantage
that independent electric power generators currently enjoy over certain
regulated utility companies or other potential competitors may be eliminated or
sharply curtailed. Deregulation may not only continue to fuel the current trend
toward consolidation among domestic utilities, but may further encourage the
trend toward disaggregation of vertically-integrated utilities into separate
generation, transmission and distribution businesses.
As an EWG, we are permitted to sell capacity and electricity in the
wholesale markets, but not in the retail markets. Accordingly, under current
law, after termination of the Engage, Exelon and Aquila/UtiliCorp power sales
agreements, we may sell our capacity and electrical output in the wholesale
markets or to power marketers (who could be our affiliates) who can in turn
make retail sales.
Under the Illinois Public Utilities Act, the Illinois Commerce Commission
("ICC") regulates "public utilities" operating in Illinois. A "public utility"
is anyone that "controls, operates or manages, within [Illinois], directly or
indirectly, for public use, any plant, equipment or property used or to be used
in or in connection with the production, storage, transmission, sale, delivery
or furnishing of electricity." There is not a specific exemption from the
Public Utilities Act for entities such as the Company selling electricity at
wholesale within Illinois. We have, however, received an opinion of counsel
that we will not be deemed to be a public utility under existing Illinois law
as a result of our operation of our Facility and sales of power as contemplated
under the power sales agreements. The opinion is based on Illinois court
decisions involving gas utilities that hold that an entity does not become a
public utility unless it holds itself out to the public generally as a supplier
of utility service. Because we will not serve the public generally, counsel has
concluded that we will not be subject to regulation as an Illinois public
utility.
If we were deemed to be an Illinois public utility, the ICC could
retroactively apply certain provisions of the Illinois Public Utilities Act to
us, including requirements for approval from the ICC for operation of our
Facility. If these requirements were applied to us, we might be required to
discontinue operations until we received the necessary approvals. In addition,
although our rates would remain subject to FERC regulation, we might become
subject to other Illinois non rate-related laws and regulations.
At present, Illinois is in a process of transition to full retail access.
Retail open access for some industrial and other commercial customers began in
October 1999. Open access was extended to all non-residential customers by
January 2001, and all consumers are to be phased in by May 2002. In Michigan,
Detroit Edison and Consumers Energy, which serve 90% of Michigan's electricity
customers, have voluntarily begun the implementation of retail choice in their
service areas, with retail access to all consumers scheduled to be fully
implemented in 2002. No timetable for transition to retail competition exists
at present in Missouri and Wisconsin. For a fuller discussion of the state
regulatory and competitive environment in the MAIN region, see "Annex C-1--
Regulatory Status."
Environmental Regulation
We are in material compliance with all applicable federal, state and local
environmental regulatory requirements. We have obtained all of the material
permits required for the construction and commencement of operation of our
Facility. A summary of the material permits currently issued for our Facility
and those anticipated as necessary in the future is included in the Independent
Engineer's Report. See "Annex B--Permits, Approvals and Certifications" to this
prospectus.
50
Sulfur Dioxide. The Clean Air Act provides for SO\\2\\ emission reductions
to be achieved through a total national cap on SO\\2\\ emissions from affected
utility units and an allocation of SO\\2\\ "allowances" equal to that total
national cap (each allowance authorizes the holder to emit one ton of SO\\2\\).
Units that need to cover SO\\2\\ emissions above their allowance allocations
can buy allowances from sources with excess allowances through a national
trading program established by the U.S. Environmental Protection Agency ("U.S.
EPA"). Since our Facility is comprised of new units, it will not receive any
allocation of SO\\2\\ allowances. Because we use natural gas for fuel, however,
the SO\\2\\ emissions from all our Units is small compared with SO\\2\\
emissions from electric utility units using other types of fossil fuels such as
coal or oil. We intend to comply with the SO\\2\\ allowance requirement by
purchasing additional allowances from other sources or from allowance brokers.
The financial projections in the Independent Engineer's Report assume that we
will have minimal requirements for purchased allowances because of low
emissions and do not take into account any costs for such allowances. See
"Annex B--Operating Expenses--Emission Compliance Costs." There is some risk
that the price for allowances will be considerably higher or that they will
become difficult to obtain at any price. Because of the relatively small
quantity of allowances we need, however, we do not expect a material impact on
our operations even if this occurs.
Nitrogen Oxides. On September 24, 1998, the U.S. EPA issued a final rule to
address regional transport of ground-level ozone in the Eastern United States
through reductions in nitrogen oxides ("NO\\x\\") in 22 states, including
Illinois, and the District of Columbia ("the NO\\x\\ SIP Call"). The NO\\x\\ SIP
Call establishes an Ozone Season from May through September, sets forth an
annual NO\\x\\ emissions "budget" or cap in the form of tons of NO\\x\\
emissions allowed for each affected jurisdiction, and requires each affected
jurisdiction to submit to the U.S. EPA a revised State Implementation Plan that
demonstrates how the jurisdiction will reduce NO\\x\\ emissions enough to meet
its budget. Illinois has promulgated initial NO\\x\\ regulations to implement
the SIP Call in Illinois, and the program is expected to take effect starting on
May 1, 2004. Like many states, Illinois issued regulations that would achieve
the required NO\\x\\ emission reductions through a cap and trade program. The
program would allocate a certain number of NO\\x\\ emission allowances to
existing and new sources and require sources that need more NO\\x\\ emission
allowances to either reduce NO\\x\\ emissions or purchase available NO\\x\\
emission allowances from others. Elements of the NO\\x\\ SIP Call are currently
under review by state and federal regulatory officials as a result of a court
remand of part of the final U.S. EPA NO\\x\\ SIP Call regulations. Changes to
the NO\\x\\ SIP Call, including the size of the NO\\x\\ budgets allocated to
particular states and the regulation's compliance date, may be necessary once
that review is complete. Any changes to the U.S. EPA's NO\\x\\ SIP Call
regulations may in turn require changes to the Illinois regulations. We cannot
be sure how U.S. EPA or Illinois may ultimately resolve the remaining NO\\x\\
SIP Call issues.
The regulations Illinois has promulgated set forth formulas for allocation of
NO\\x\\ emission "allowances" to NO\\x\\ emission sources within the state, with
each allowance representing an authorization for a source to emit one ton of
NO\\x\\ during the Ozone Season. The allowances can be bought and sold through a
trading program that is expected to eventually include all of the 23
jurisdictions covered by the NO\\x\\ SIP Call. Under the Illinois regulations,
all of our units will be considered "new" sources, and will be obligated to
obtain NO\\x\\ allowances from a limited pool set aside for "new" sources
constructed after 1994. While we cannot predict the exact disposition of the
NO\\x\\ allowances that will be made available, we expect that the number of
allowances available for allocation to new sources will not be sufficient to
cover all of the allowance requests. We therefore will likely receive some
lesser pro rata share of the amount of allowances necessary to cover all of our
expected NO\\x\\ emissions. If necessary, we intend to comply with the NO\\x\\
SIP Call requirements limiting NO\\x\\ emissions by purchasing additional
allowances or by relying upon our power purchasers to supply us with the
necessary allowances. There is no existing NO\\x\\ allowance market and we
cannot be sure that an active trading market will develop to offer NO\\x\\
allowances for sale at reasonable prices. Under our power sales agreement with
Exelon, Exelon is required to provide us with allowances to the extent they are
not otherwise allocated to us. We do not have similar arrangements with our
other power purchasers.
Public Policy Relating to NO\\x\\ and SO\\2\\ Emissions. The United States
Congress has considered in the past "multi-pollutant" legislation that would
require electric utilities to comply with more stringent pollution
51
control standards for NO\\x\\ and SO\\2\\. Similar legislation was introduced in
Congress in 2001, and further proposals are expected under the Bush
Administration's National Energy Policy. Many of the legislative proposals under
consideration would rely upon flexible cap and trade programs for compliance.
Such legislation could apply to our units and could require additional
reductions in NO\\x\\ and SO\\2\\ emissions. We cannot predict whether such
legislation will pass this year or in the future, what it might require or
whether it would apply to our units. The extent of investment we may need to
make in additional pollution control technologies, operational changes and/or
pollution allowance or emission credit purchases required to comply with any new
legislative requirements would be directly related to the level of emission
reductions required and the mechanisms provided for compliance and to the
operation of our facilities.
Illinois Governor Ryan recently signed "multipollutant" legislation that
establishes a rulemaking process that could lead to emission reduction
requirements for NO\\x\\, SO\\2\\ and mercury from electric utilities. The
legislation allows, but does not require, the Illinois Environmental Protection
Agency ("IEPA") to adopt "as appropriate" regulations for the reduction of
NO\\x\\, SO\\2\\ and mercury after consideration of a number of factors,
including energy supply impacts and developments in federal multipollutant law.
The IEPA is also to establish a voluntary program for reducing electric utility
greenhouse gas emissions. Specifically, the IEPA is to issue findings on the
"potential need" for reducing electric utility emissions of NO\\x\\, SO\\2\\ and
mercury in light of various factors, and deliver that report to the Illinois
House and Senate Environment and Energy Committees no earlier than September 30,
2003 and no later than September 30, 2004. Any time after ninety days of
submission of that report, the IEPA "may" submit proposed regulations to
implement its findings for approval by the Illinois Pollution Control Board. The
Board must take action on the proposed regulations, if any, within one year. The
extent of investment we may need to make in additional pollution control
technologies, operational changes and/or pollution allowance or emission credit
purchases required to comply with any new state regulatory requirements will be
directly related to the level of emission reductions required and the mechanisms
provided for compliance and to the operation of our Facility.
Particulate Matter. A new ambient air quality standard was adopted by U.S.
EPA in July 1997 to address emissions of fine particulate matter ("PM 2.5"). It
was widely understood at that time that attainment of the fine particulate
matter standard might require NO\\x\\ and SO\\2\\ emission reductions from many
emission sources, perhaps on a multi-state regional scale. Under the
implementation schedule announced by the U.S. EPA when the new standard was
adopted, non-attainment areas were not to have been designated until 2002 and
control measures to meet the standard were not to have been identified until
2005, with implementation of control measures by sources to follow sometime
after that. However, in a May 14, 1999 decision, a federal appellate court
remanded the new fine particulate standard to U.S. EPA for further
justification. U.S. EPA obtained Supreme Court review of that decision, and the
Court generally upheld the agency's authority to promulgate the new standard.
However, U.S. EPA must determine how to proceed with implementing the new
standards, and will likely have to address additional court challenges to the
specifics of the standard and its implementation. As a result, the impact, if
any, of future revisions to the fine particulate matter standard on our
Facility is uncertain at this time.
Hazardous Air Pollutants. U.S. EPA recently issued an interpretive rule
declaring that the agency will proceed with development of standards to
regulate emissions of hazardous air pollutants from stationary combustion
turbines like the ones at our Facility under Title III of the Clean Air Act.
EPA's interpretive rule indicated that a proposed rule governing hazardous air
pollutant emission reduction standards for gas turbines was expected to be
issued by late 2000, and a final rule to be issued in 2002. U.S. EPA has yet to
issue a proposed rule. Because we do not know when U.S. EPA will issue its rule
or what U.S. EPA may require of existing gas turbines like ours, if anything,
we are not able to evaluate the impacts of potential hazardous air pollutant
regulations on our turbines.
Greenhouse Gases. Since the adoption of the United Nations Framework on
Climate Change in 1992, there has been a worldwide effort to reduce greenhouse
gas ("GHG") emissions to 1990 levels or below. In December 1997, the United
States participated in the Kyoto, Japan negotiations, where the basis of a
Climate Change treaty was formulated. Under the treaty, known as the Kyoto
Protocol, the United States would be
52
obligated to meet an overall GHG emissions reduction target of 7% below 1990
GHG emissions by 2008-2012. Gas-fired combustion turbines like ours are a
source of GHG emissions, although emissions from gas-fired combustion turbines
tend to be significantly lower than emissions from oil or coal-fired electric
generation facilities. The Kyoto Protocol does not come into effect until the
United States Senate ratifies it. To date, the Senate has not done so. In 1997,
the Senate passed a resolution indicating that it would not ratify a GHG
emissions reduction treaty that did not involve commitments from developing
nations to limit GHG emissions or a treaty that would damage the U.S. economy.
Recently, the Bush Administration has announced that the United States will not
abide by the Kyoto Protocol. However, Congress has considered in the past, and
is currently considering, "multi-pollutant" legislation that could require
electric generating facilities, including gas-fired turbines like ours, to
reduce or offset their GHG emissions. Illinois has also considered in the past,
and is currently considering, legislation that could result in GHG emission
control requirements for electric generation facilities. Because we do not know
whether the United States will adopt the Kyoto Protocol or whether Congress or
Illinois will otherwise pass legislation that would mandate regulation of GHG
emissions from electric generation facilities, or what the particular
requirements for gas-fired electric generation facilities might be, we are not
able to evaluate the impact of potential GHG emission reduction obligations on
our Facility.
Environmental Site Assessment. Woodward-Clyde International-Americas
prepared an environmental investigation report, dated August 3, 1998, for PGL
(which owned the property at the time) with respect to a portion of the
property on which our Facility is located. Our Facility is located in an
industrial area and is adjacent to a spray irrigation area that is used to
dispose of treated storm water. It has been used in the past for agricultural
purposes. The report noted that arsenic, benzene and Dieldrin were detected in
site soils. The concentrations did not exceed Tier I remediation objectives for
direct contact for construction workers and thus were not believed to pose a
health and safety concern for construction activities. For a fuller assessment,
see "Annex B--Site Assessment--Environmental Site Assessment."
53
OWNERSHIP AND MANAGEMENT
Our owners. We are a limited liability company, and ownership rights in us
are represented by membership interests. 50% of our membership interests are
owned by Dominion Elwood, Inc., a subsidiary of DEI, and 50% by Peoples Elwood,
LLC, a subsidiary of PERC. Membership interests may be transferred to
affiliates without restriction; otherwise, except for certain specified
transactions, members may not transfer their ownership interests to a third
party (either directly or through a change in control of a member) without
first offering to sell their interest to the other member.
Our management. Our Management Committee, which consists of one
representative from DEI and one representative from PERC, oversees the overall
management of our project. The General Manager has overall responsibility for
our daily operations and is selected by and reports directly to the Management
Committee. The General Manager's authority is limited to entering into
contracts or commitments of $100,000 or less. Any commitments greater than
$100,000 must receive Management Committee consent. The Commercial Manager is
responsible for managing the commercial aspects of the business under the
direction of the General Manager. We have delegated some management functions
to DELSCO under the O&M Agreement. See "Description of the Principal Project
Documents--Operation and Maintenance Agreement."
The following individuals are, respectively, members of our Management
Committee and senior executives of our Company:
Name Age Company Position
---- --- ----------------
Edward J. Rivas............... 57 Management Committee
William E. Morrow............. 45 Management Committee
Tony Belcher.................. 51 General Manager
Robert F. Harrington.......... 44 Commercial Manager
Gary L. Edwards............... 52 Risk Manager
Lee Katz...................... 38 Principal Financial and Accounting Officer
Edward J. Rivas. Mr. Rivas is Senior Vice President, Fossil & Hydro
Operations for Dominion Energy. He is responsible for overseeing the operation
of over 14,000 MW of Dominion Energy's assets. He has 24 years of power
generation experience with a concentration in operations and engineering. He
holds a Bachelor of Science degree in Mechanical Engineering from Central New
England College.
William E. Morrow. Mr. Morrow is President of PERC and Executive Vice
President of Peoples Energy Corporation and its utilities, PGL and North Shore
Gas Company. His diversified energy responsibilities include all corporate
electric generation, wholesale gas marketing, and gas peaking services. His
utility responsibilities include gas supply acquisition, transmission and
storage operations, gas control and hub services. Since joining the corporation
in 1979, Mr. Morrow has had experience in distribution and service departments,
engineering, gas control, synthetic natural gas plant and corporate
headquarters. He holds a Bachelor of Science degree in Mechanical Engineering
from Bradley University and a Master's degree in Business Administration from
the University of Chicago. He is a registered Professional Engineer in the
State of Illinois.
Tony Belcher. Mr. Belcher, Director of Operations for the Unregulated
Operations of Dominion Energy, is responsible for management of Dominion
Energy's unregulated assets. Mr. Belcher has over 29 years of experience in the
power generation business with emphasis on operation, maintenance and asset
management. He holds a Bachelor of Science degree in Electrical Engineering
from Virginia Tech and a Masters degree in Business Administration from
Virginia Commonwealth University. He is a registered Professional Engineer in
the Commonwealth of Virginia.
Robert F. Harrington. Mr. Harrington, our Commercial Manager, is responsible
for directing the marketing of power, the procurement of fuel supply and other
administrative duties at our Facility.
54
Mr. Harrington is Managing Director--PERC Power and manages the activities of
the Chicago office of PERC in other power developments, including the Calumet
site now under development with Exelon. Mr. Harrington has more than 20 years
of experience in gas and power, including roles in marketing, energy trading,
regulatory and finance. He holds a Bachelor of Science degree from Western
Illinois University and is a certified public accountant registered with the
State of Illinois.
Gary L. Edwards. Mr. Edwards, the Director--Risk Management of Dominion
Energy Services Company, is responsible for risk management and the
administration of contracts for our company. Mr. Edwards began his career with
Virginia Power in 1970. Since joining the company in 1970, he has had
responsibilities for sales and marketing of electric heating and development of
both gas and electric rates in the jurisdictions of Virginia, North Carolina,
and West Virginia. Before his current assignment, Mr. Edwards was responsible
for the development of solicitations and the associated contract negotiations
for the procurement of capacity to meet company native load. He has negotiated
in excess of fifty power purchase agreements with capacity payment requirements
over the contract life in excess of $40 billion. He received a Bachelor of
Science degree in Mathematics from Milligan College, Johnson City, Tennessee.
Lee Katz. Mr. Katz is Controller of Dominion Energy, which provides
financial and accounting services for Elwood under his supervision. Mr. Katz
has been with Dominion for five years. Before that, he was employed by public
accounting and consulting firms. He has a Bachelor's degree in Accounting from
the University of South Carolina and a Master's degree in Business
Administration from Virginia Commonwealth University and is a certified public
accountant.
Compensation. All of our managers and officers are full-time employees of
either Dominion or Peoples. They are paid salaries by Dominion or Peoples and
participate in the various employee benefit plans of those companies. They are
not paid directly by us for their services.
55
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
DELSCO, which provides operation, maintenance and management services to us
under an operation and maintenance agreement, is a wholly-owned subsidiary of
DEI. Under the O&M Agreement, we pay DELSCO an aggregate annual fee of
$650,000, subject to adjustment for inflation, and we reimburse DELSCO for
costs incurred in connection with its services as described under "Description
of the Principal Project Documents--Operation and Maintenance Agreement--
Compensation."
Under the Common Facilities Agreement, we are provided with certain services
and with our water supply by PERC. We pay PERC approximately $100,000 annually
for these services as described under "Description of the Principal Project
Documents--Common Facilities Agreement."
The fees for services and the reimbursable expenses payable under the O&M
Agreement and the Common Facilities Agreement are designated as O&M Costs and
thus will be paid before the payment of principal and interest on the bonds.
See "Description of the Principal Financing Documents--Deposit and Disbursement
Agreement--Deposit and Disbursement of Funds."
PERC is the lessor under the ground lease covering the land on which Units
1-4 are located. The basic rent under the ground lease is $283,380 for the
entire term, and has been fully paid. We remain responsible for taxes,
assessments, water rates and other impositions on the property. Within 45 days
after the issuance to us of an operating permit by the Illinois Environmental
Protection Agency under Title V of the Clean Air Act, PERC will sell, and we
will purchase, the property subject to the ground lease. The purchase price
will have been satisfied by payment of the basic rent under the ground lease.
Although Nicor is the contractual provider of natural gas transportation and
balancing services to our Facility, physical transportation of gas is provided
through PGL's 24-inch pipeline. Nicor also has a companion agreement with PGL
for transportation and balancing services, which contains substantially the
same terms and conditions as our agreement with Nicor.
56
DESCRIPTION OF THE PRINCIPAL PROJECT DOCUMENTS
The following is a summary of selected provisions of agreements with third
parties related to our operations and should not be considered a full statement
of the terms and provisions of those agreements. Copies of the power sale
agreements, the fuel agreements, the operation and maintenance agreement, the
common facilities agreement and the ground lease are included as exhibits to
the registration statement of which this prospectus is a part. All references
to time in these summaries are to Central Time.
POWER SALES AGREEMENTS
Exelon Power Sales Agreement
We are party to a second amended and restated power sales agreement (the
"Exelon PSA"), under which Exelon purchases capacity and electricity generated
by Units 3, 4 and 9 (and Units 1 and 2 after expiration of the Engage power
sales agreement), with a price "true up" for capacity and energy from Units 1
and 2 during the term of the Engage agreement.
Term. The Exelon PSA runs until December 31, 2012, unless terminated earlier
in accordance with its terms.
Capacity Payments. The capacity payments we receive from Exelon average
$4.35 per kW of net dependable capacity per month over a calendar year. "Net
dependable capacity" under the Exelon PSA is the level of MW per unit based
upon demonstrated output (net of station service and auxiliaries) achieved
during capacity testing of the unit, as adjusted to conditions of 85 degrees
Fahrenheit and 60% relative humidity at 610 feet above sea level. The capacity
payments are based on a fixed monthly capacity price schedule as follows (in
$/kW month):
$/kW of Net
Dependable
Month Capacity
----- -----------
January-May................................................. $2.71875
June........................................................ $6.525
July-August................................................. $9.7875
September................................................... $4.35
October-December............................................ $2.71875
Average..................................................... $4.35
Capacity payments may be reduced due to certain force majeure events that
restrict the output of the Facility and for the reasons discussed under "--
Performance Adjustments" below.
Energy Charge. The energy charge for electric energy sold to Exelon under
the Exelon PSA is designed to pass through our variable cost of generation to
Exelon. The energy charge per MWh consists of two components: (i) a variable
operation and maintenance charge of $1.50/MWh which escalates annually with
inflation and (ii) a fuel charge which is composed of a fixed rate per MMBtu
($0.32/MMBtu) and a variable rate that floats with an index price. The index
price is the Gas Daily Average Price and is either day of burn or next day,
principally depending upon notice times.
The contract heat rate for energy payments is 10,900 Btu/kWh if the unit is
dispatched at 100% of net dependable capacity and 12,900 Btu/kWh if the unit is
dispatched at 60% of net dependable capacity. The energy charges for load
amounts between 60% and 100% are pro-rated between these two heat rates.
Start-Up Charge. Except for Units 1 and 2 during the term of the Engage
agreement, for each start-up of a unit in which the applicable unit achieves
the dispatched generation level for a minimum of four hours (which do not need
to be consecutive) during the dispatch period, Exelon must pay us a sum of
$3,250, subject to an annual inflation escalator.
57
Dispatch Cancellation Charges. Exelon may cancel start-up of a unit anytime
before the initiation of the start-up sequence and ignition of a unit. However,
if cancellation occurs less than one hour before start-up during summer on-peak
hours, a dispatch cancellation charge of $3,250 (adjusted annually for
inflation) applies. During non-summer on peak and summer off peak hours, a fuel
adjustment charge is added to dispatch cancellation charges, together with a
$1,000 charge if the cancellation is more than two and less than four hours
before start-up or a $4,000 charge if the cancellation is less than two hours
before start-up.
Performance Adjustments. The Exelon PSA provides for availability and
reliability bonuses and penalties designed to encourage optimal plant
performance. These availability bonuses and penalties vary by time and season.
During the summer months, they are highest during "Super Peak" hours (11 a.m.
to 7 p.m. Monday through Friday), lower in "Partial Peak" hours (6 a.m. to 11
a.m. and 7 p.m. to 10 p.m. Monday through Friday) and lower still in "Off-Peak"
hours (all other hours). "Summer" is defined as June through September in the
Exelon PSA. During the non-Summer months, availability bonuses and penalties
only apply during "On-Peak" hours (6 a.m. to 10 p.m.).
"Equivalent Availability" (or "EA") is calculated using the equation: [1-
(FOH + EFDH)/PH], where FOH is equal to Forced Outage Hours (i.e. the number of
hours that the units experienced a forced outage in the month), EFDH is equal
to Equivalent Forced Derated Hours (i.e. the equivalent number of hours that
the units experienced a forced derating during the month, taking into account
the size of the derating), and PH is Period Hours (i.e. the total number of
Summer Super Peak, Summer Partial Peak, Summer Off-Peak and non-Summer On-Peak
hours, as applicable, in the month). Forced outages and forced deratings do not
count in the above calculation to the extent substitute energy was provided.
The target Equivalent Availability is 97% in the Summer months and 93% the rest
of the year. If the Equivalent Availability is greater than target, we receive
a bonus; if less, we must pay a penalty.
EA calculations are performed monthly for the Summer months for Super Peak,
Partial Peak and Off-Peak hours, and a single calculation is performed for the
On-Peak hours for the remainder of the year. Penalties can never require us to
lose more than the capacity payment actually paid during the applicable year
and are only assessed when a unit is dispatched.
The following tables show the bonus or penalty per a 1% change in EA for 1MW
of capacity.
Super Peak Summer Bonus and Penalty
EA Condition June July Aug Sep
------------ ------- -------- -------- -------
(greater than or =)97% $ 71.43 $ 107.14 $ 107.14 $ 47.62
(less than) 97%, (greater than or =)70% -74.95 -113.75 -113.75 -47.44
(less than) 70%, (greater than or =)44% -80.79 -121.19 -121.19 -53.86
Partial Peak Summer Bonus and Penalty
EA Condition June July Aug Sep
------------ ------- -------- -------- -------
(greater than or =)97% $ 23.81 $ 35.71 $ 35.71 $ 15.87
(less than) 97%, (greater than or =)70% -24.98 -37.91 -37.91 -15.81
(less than) 70%, (greater than or =)44% -26.93 -40.39 -40.39 -17.95
Off Peak Summer Bonus and Penalty
EA Condition June July Aug Sep
------------ ------- ------- ------- -------
(greater than or =)97% $ 0 $ 0 $ 0 $ 0
(less than) 97%, (greater than or =)70% -14.27 -21.67 -21.67 -9.03
(less than) 70%, (greater than or =)44% -15.39 -23.08 -23.08 -10.25
58
Non Summer On-Peak Bonus and Penalty
Non-Summer
EA Condition Period
------------ ----------
(greater than or =)93% $ 47.62
(less than) 93%, (greater than or =)86% -95.24
(less than) 86%, (greater than or =)80% -2,811.11
(less than) 80%, (greater than or =)44% -117.13
In addition, we are paid a reliability bonus for unit performance during the
Summer months. This bonus is calculated using the unit availability for the
four highest peak power price days during each of the Summer months. The
average of all five units' reliability is then measured against an 80%
reliability threshold. The bonus is paid according to the formula: (monthly
reliability bonus in $ per 1%) X (facility reliability - 80%) X 100 X 5 units.
The following are the monthly reliability bonuses for each unit for each
percent above the 80% target reliability threshold by month:
June $1,250 per 1%
July $5,000 per 1%
August $5,000 per 1%
September $1,250 per 1%
Unit 1 and Unit 2 True Up. Exelon has purchased the rights to the off-take
from Units 1 and 2 from Engage through the term of the Engage agreement. The
Exelon PSA contains a pricing true-up to provide Exelon with the same financial
and operational parameters for Units 1 and 2 that exist in the Exelon PSA with
regards to Units 3, 4 and 9. The "true up" calculates the differences between
various pricing and operational parameters of the Engage agreement and those
outlined in the Exelon PSA. The difference will appear as an increase or a
decrease to the monthly payment calculation under the Exelon PSA such that the
ultimate cost of Exelon's purchase of energy and capacity from Engage for Units
1 and 2 is effectively the same as if Exelon purchased the capacity and energy
of Units 1 and 2 directly from us under the Exelon PSA.
Billing. As soon as practicable after the end of each calendar month, we
must provide Exelon with a statement setting forth the amounts due for such
month. Billings for electric energy are based on revenue meter information. The
amount due to us as shown on the monthly statement must be paid by Exelon
within 15 business days after the statement is received by Exelon. Any amount
not paid by Exelon when due bears interest at the "Prime Rate" plus 2.5% until
the payment is made.
Dispatch of the Units. Subject to the restrictions described below, Exelon
may dispatch the delivery of electric energy from each of the committed units
at a rate up to the net dependable capacity of the units. We have the sole
discretion as to which units are operated to meet Exelon's dispatch order or to
meet the dispatch order with delivery of substitute electric energy produced by
other units at our Facility.
By 8:30 a.m. each day, Exelon must provide estimates of its requirements for
electric energy and start-ups for each hour of the following day. Changes to
this schedule made after this time are subject to cancellation penalties
previously discussed in the "Dispatch Cancellation Charges" section. By noon of
each day, we must notify Exelon of the estimated level of power output from the
committed units available for the following three days. We may subsequently
alter these estimates as necessary.
We must cause any dispatched units to be started within one hour of receipt
of a dispatch order from Exelon during the Summer on-peak period. However, for
a dispatch request for four units simultaneously, we have one hour and fifteen
minutes and for all five units simultaneously, we have one hour and twenty-five
minutes to start up the units. For all other hours (i.e. Summer non-peak and
non-Summer hours), we have four hours after receipt of the dispatch
notification to start up the units. Once a unit is started, we must ramp to a
base load of 60% of net dependable capacity within twenty minutes.
59
Dispatch Restrictions. Exelon's dispatch rights are subject to several
restrictions set forth in the Exelon PSA. First, Exelon-dispatched run time is
limited to 1,500 hours per year for each of the units (except for Unit 9, which
is limited to 1,400 dispatched hours in the first contract year), regardless of
load. We must make reasonable efforts to allocate Exelon's dispatch equally
across the designated units over the course of a contract year. Second, Exelon
may only dispatch load from 60% to 100% of the net dependable capacity of each
unit. Third, under the terms of our agreement, we are not required to operate
the units more than 60 unit hours (number of units operating times the total
number of hours operating) per day during non-Summer months and 80 unit hours
per day during Summer months. Fourth, units must be run for a minimum of 4
hours, and there must be a 2-hour downtime period before a unit may be started
again. Finally, Exelon may not dispatch a unit during any planned outage or
maintenance outage, during a force majeure event or during times when our
Facility is acting at the direction of the interconnected utility.
Dispatch is at the direction of Exelon. Our rights to run a unit other than
to comply with Exelon dispatch are limited to test and maintenance related
items or under instruction from the interconnected utility.
Substitute Energy. We have the right to arrange for the purchase and
delivery of substitute energy to fulfill our dispatch orders, at no additional
cost to Exelon. The transportation of the substitute energy must be firm and
the point of delivery location must be agreeable to both parties. The provision
of substitute energy counts as operating hours for the performance adjustment
calculation and is also included in any determination of the equivalent
availability and reliability bonuses. However, we are not obligated to provide
substitute electric energy to Exelon at any time. Exelon is only required to
buy substitute energy from outside the Facility if certain communications
procedures under the Exelon PSA are followed.
Standard of Operation. Under the Exelon PSA, we are required to use
reasonable efforts to operate the units in accordance with (i) the practices,
methods, acts, guidelines, standards and criteria of MAIN, North American
Electric Reliability Council ("NERC"), and the independent system operator,
regional transmission organization or control area, (ii) the requirements of
the Interconnection Agreements with ComEd (see "Interconnection Agreements"
below), and (iii) all applicable requirements of law. We must obtain all
certifications, permits, licenses and approvals necessary to operate and
maintain each unit and to perform our obligations under the Exelon PSA.
Fuel and Emissions. We must use any emission allowances, credits or
authorizations we receive for the units for the reduction of emissions of air
pollutants to support generation under the Exelon PSA. If the number of
allowances necessary to meet Exelon's dispatch orders exceeds the amount of
NO\\x\\ and/or SO\\2\\ allocated to us for the units, Exelon must provide us
with the required allowances at no cost to us. If Exelon fails to provide us
with any necessary NO\\x\\ and/or SO\\2\\ allowances as required by the Exelon
PSA, Exelon indemnifies us from any losses, claims, fines, costs and expenses
resulting from such failure.
A separate provision applies to any taxes, fees, assessments or charges
(other than those associated with the NO\\x\\ and/or SO\\2\\ allowances
described above) that are assessed by any governmental entity against emissions
of air pollutants or the consumption of fossil fuels for electric generation
under any state, regional or federal program that applies to the units, or if
obligations are imposed upon the units under any state, regional or national
program for the reduction in the emissions of air pollutants of any kind. Under
that provision, we and Exelon will use reasonable efforts to implement a
mutually acceptable compliance plan that minimizes our costs of compliance.
Exelon will pay for all compliance costs, up to an annual aggregate cost of
$562,000 (in 2001 dollars). If compliance costs exceed that amount, we may
absorb such costs or ask that Exelon pay such costs. If we ask Exelon to pay the
additional costs, Exelon will have the option to (i) pay such costs, (ii)
terminate the Exelon PSA without any further liability or (iii) reopen the
pricing under the Exelon PSA subject to the agreement's dispute resolution
provisions.
Outages. No later than September 30th of each year, we must propose a
schedule of planned outages to Exelon for the following calendar year. Exelon
may request any reasonable modifications to the proposed outage schedule. No
planned outage may be scheduled to cover any portion of May or the Summer
period. If
60
we need to schedule an unplanned maintenance outage, we must notify Exelon and
plan the outage to mutually accommodate our reasonable requirements and the
service obligations of Exelon. Penalties for outages only accrue when we fail
to supply energy dispatched by Exelon.
If there is an unplanned event that affects the ability of the units to be
available, we must promptly notify Exelon and indicate the amount of capacity
that will not be available because of the event and the expected return date of
the lost capacity.
In addition, we are permitted to shut down each unit for a compressor wash
at a mutually agreeable time approximately once per month. The lesser of five
hours or actual compressor wash time per shut down per unit will not count as a
forced outage or maintenance outage for calculation of Equivalent Availability.
Title and Risk of Loss. We must deliver the electric energy sold to Exelon
at the delivery point (i.e. the metering station in the Switchyard (as defined
below) for energy produced at our Facility). Title to the electric energy will
pass from us to Exelon upon delivery at the delivery point. Exelon is
responsible for any transmission costs beyond the delivery point.
Taxes. Each party is responsible for its own income taxes. We are
responsible for the payment of all present or future federal, state, municipal
or other lawful taxes applicable by reason of the operation of our Facility or
assessable on our property or operations. Exelon must pay for all sales, use,
excise and similar taxes imposed on the sale or use of or payments for the
electric energy, ancillary services and capacity sold and delivered under the
Exelon PSA arising at or after the point of delivery.
Force Majeure. If either party is rendered unable by a force majeure event
to carry out some or all of its obligations under the Exelon PSA (other than
obligations to pay money) despite all reasonable efforts of the affected party
to prevent or mitigate its effects, then, during the continuance of the force
majeure event, the obligation of the affected party to perform the obligations
is suspended. These force majeure events include: explosion and fire, flood,
earthquake, storm, acts of God, strike or labor dispute, war, action or failure
to act by governmental entities or officials, failure to obtain governmental
permits or approvals despite timely application and our due diligence, changes
in law affecting the operation of the units, or lack of fuel caused by a force
majeure event experienced by our fuel supplier or transporter.
Events specifically identified as non-force majeure events in the Exelon PSA
are:
. a planned outage;
. a maintenance outage;
. the loss of Exelon's markets;
. Exelon's inability to economically use or resell the electrical energy
or capacity purchased under the Exelon PSA;
. our economic hardship (which includes our ability to sell the capacity
or electrical energy at a price greater than the price in the Exelon PSA
or to reduce costs by not operating the units as dispatched by Exelon);
or
. causes or events affecting the performance of third-party suppliers of
goods or services, including natural gas suppliers and providers of
natural gas transportation service, except to the extent caused by an
event that fits the definition of a force majeure event under the Exelon
PSA.
Exelon is required to continue making the capacity payments if a force
majeure event occurs as a result of flood, earthquake, storm, or other natural
calamity or act of God, or war, insurrection or riot. During any force majeure
event resulting from other circumstances, Exelon is relieved of its monthly
capacity payment obligation (prorated daily) solely to the extent the unit is
available at a level less than the net dependable capacity as a result of the
force majeure event. We are generally relieved of Equivalent Availability
adjustment penalties and delay damages during force majeure periods.
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Our Events of Default. The occurrence and continuation of any of the
following events at any time during the term of the Exelon PSA, except to the
extent caused by Exelon, constitute an event of default by us:
. our failure to pay any sum due under the Exelon PSA that is not remedied
within 15 days after receipt of notification from Exelon;
. our failure to have qualified operators available either on-site or on
call for operation of the Facility for a period of seven consecutive
days;
. our bankruptcy; or
. our failure to perform or comply with any material obligation of the
Exelon PSA which adversely affects Exelon, but only if such failure is
not cured within 60 days after notice from Exelon or a longer period if
the failure cannot be cured in 60 days and we are diligently proceeding
to cure the default.
Exelon Events of Default. The occurrence and continuation of any of the
following events at any time during the term of the Exelon PSA, except to the
extent caused by us, constitute an event of default by Exelon:
. failure to pay any sum due under the Exelon PSA that is not remedied
within 15 days after receipt of notification from us;
. the bankruptcy of Exelon; or
. Exelon's failure to perform or comply with any material obligation of
the Exelon PSA which adversely affects us, but only if such failure is
not cured within 60 days after notice from us or a longer period if the
failure cannot be cured in 60 days and Exelon is diligently proceeding
to cure the default.
If Exelon defaults under the Exelon PSA and such default is continuing, we
may sell electric energy represented by the net dependable capacity on a daily
basis to third parties during the continuance of Exelon's default.
Termination Rights. Each party may terminate the Exelon PSA upon 30 days
written notice after an event of default by the other party. Exelon may also
terminate the Exelon PSA with regard to any committed unit (other than Unit 9)
upon 30 days notice if an outage that is not excused by a force majeure event
at such unit substantially prevents us from performing under the Exelon PSA for
120 days; provided, however, that if we have taken significant steps toward
remediating the circumstances that led to the outage and we certify in writing
that the outage will end within 365 days of commencement (and the outage in
fact ends within the 365 days), then Exelon may not terminate the Exelon PSA.
To the extent we provide substitute energy and capacity in accordance with the
terms of the Exelon PSA, the 120 or 365 day periods in the foregoing sentence
will be extended on a day to day basis. In addition, Exelon may terminate the
Exelon PSA if we request that Exelon pay for the annual costs of an air
emissions compliance plan developed by the parties in excess of the amounts
described under "--Fuel and Emissions."
Indemnification. Each party must indemnify the other party and its officers,
directors, agents and employees from and against all losses caused by the gross
negligence or willful misconduct of the indemnifying party that arise out of or
are connected with the performance of the Exelon PSA. Likewise, each party must
indemnify the other party from all claims and damages arising out of the
indemnifying party's ownership, possession or control of electric energy up to
or from the delivery point, as the case may be.
Limitation of Liability. In no event will either party or its affiliates (or
such party's or such affiliate's directors, officers, employees and agents) be
liable to the other party for any special, incidental, exemplary, indirect,
punitive or consequential damages or damages in the nature of lost profits. A
party's liability under the Exelon PSA is limited to direct actual damages and
all other damages at law or in equity are waived.
Exclusive Remedies. Except as provided below, Exelon's sole remedies and our
sole liabilities for our failure to meet the Equivalent Availability targeted
under the agreement and for failure to deliver electric energy as dispatched by
Exelon is the adjustment to the capacity payments based upon the Equivalent
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Availability adjustment, subject to certain limitations on our liability in the
Exelon PSA. If our failure to comply with a dispatch order from Exelon is not
caused by a forced outage, forced derating, force majeure event or our
negligence or error, Exelon may recover from us the cost of cover for
replacement energy obtained by Exelon and seek specific performance by us of
the Exelon PSA.
Assignment. Except as specifically provided in the Exelon PSA, neither party
may assign its rights under the Exelon PSA without the prior written consent of
the other party. Either party may assign the Exelon PSA to an affiliate without
consent, but the assigning party is not released from its obligations under the
agreement. A transfer of a majority of the outstanding voting interests of a
party (or a parent of a party) to a non-affiliate is deemed to be an assignment
of the Exelon PSA. Exelon has also consented to the assignment of a security
interest in the Exelon PSA to our lenders, including the holders of the bonds.
Governing Law. The Exelon PSA is governed by the laws of the State of
Illinois without regard to its conflicts of laws provisions.
Engage Power Sales Agreement
We are party to an amended and restated power sales agreement (the "Engage
PSA") under which Engage agreed to purchase capacity and electricity generated
from Units 1 and 2. We receive a fixed per kW monthly capacity charge and a per
MWh energy charge for actual production.
Engage has sold the energy and capacity of Units 1 and 2 during the
remaining term of its contract with us to Exelon and has appointed Exelon as
its agent to dispatch the units. We have entered into a "true up" arrangement
with Exelon that puts both of us in essentially the same economic position as
would exist if Units 1 and 2 were currently part of the Exelon PSA. The "true
up" calculates the differences between various pricing and operational
parameters of the Engage PSA and those in the Exelon PSA. The difference will
appear as an increase or a decrease to the monthly payment calculation under
the Exelon PSA such that the ultimate cost of Exelon's purchase of energy and
capacity from Engage for Units 1 and 2 is effectively the same as if Exelon
purchased the capacity and energy of Units 1 and 2 directly from us under the
Exelon PSA. We continue to bill, and receive payments from, Engage, in
accordance with the terms of our agreement with Engage. So long as all parties
perform their obligations, we are in essentially the same position we would be
if the Exelon PSA already covered all five units.
Term. The Engage PSA runs until December 31, 2004.
Capacity Payments. The capacity charge under the Engage PSA is $5.00 per kW
month for the remainder of the term.
Energy Payments. The energy charge for electricity sold to Engage under the
Engage PSA depends on the percentage of available capacity of the applicable
unit dispatched by Engage. It is not priced off an index, as is the case with
the power sales agreements with Exelon and Aquila/UtiliCorp. Accordingly, if
the Exelon PSA terminated while the Engage PSA were still in effect, and the
"true-up" were no longer applicable, we would be exposed to natural gas price
risk under the Engage PSA. The charges for energy at various dispatch levels
under the Engage PSA are as follows:
Dispatch Level Variable Energy Charge
-------------- ----------------------
60% $35.00 per MWh
70% $33.50 per MWh
80% $32.00 per MWh
90% $31.00 per MWh
100% $30.00 per MWh
For dispatch levels between the above percentages, the energy charges are
prorated to the proportionate level between the points in the table. The
calculation of the dispatch level is done on an hourly basis.
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Start Up Charge. For each start up of a unit from zero generation under a
dispatch order from Engage (other than after a forced outage or force majeure
event), Engage must pay us $2,500. No start up charge is payable if the unit
fails to reach at least 90% of the dispatch level requested by Engage.
Performance Adjustments. The Engage PSA contains an annual adjustment to
Engage's capacity payments based on the performance of Units 1 and 2 during the
year. The target Forced Outage Adjustment Factor ("FOAF"), which is the
percentage of on-peak summer hours in which a unit experiences a forced outage
or an equivalent forced derating, for Units 1 and 2 is 5%. We receive a bonus
of 1% of the aggregate capacity payments received from Engage during the prior
year for every 1% that the units are under the target FOAF, and must pay Engage
(as a credit against future capacity payments) 1% of the aggregate capacity
payments paid by Engage during the prior year in penalties for every 1% that
the units are over the target FOAF.
For purposes of calculating the FOAF, periods of curtailment, reduction or
interruption by ComEd (or its successor) under the interconnection agreements
will not count as forced outages or deratings if the units are otherwise
available during such periods.
Our Events of Default. The following are our events of default, which could
lead to the termination of the Engage PSA or the exercise of other remedies by
Engage:
. our failure to pay any sum due that is not remedied within 15 days after
notice from Engage;
. our bankruptcy or the bankruptcy of any of our guarantors;
. our failure to furnish the guaranties of DEI and Peoples Energy
Corporation, as required under the Engage PSA; and
. our failure to perform or comply with any material provision of the
Engage PSA, but only if such failure is not cured within 60 days after
notice from Engage or a longer period if the failure cannot be cured in
60 days and we are diligently proceeding to cure the default.
Engage's Events of Default. Engage's events of default include:
. Engage's failure to pay any sum due that is not remedied within 15 days
after notice from us;
. the bankruptcy of Engage or any guarantor of Engage;
. Engage's failure to post security as required under the Engage PSA; and
. Engage's failure to perform or comply with any material provision of the
Engage PSA, but only if such failure is not cured within 60 days after
notice from us or a longer period if the failure cannot be cured in 60
days and Engage is diligently proceeding to cure the default.
Termination Rights. We may terminate the Engage PSA with 30 days notice
after the occurrence and continuation of an event of default by Engage. Upon
any such termination, and a concurrent termination of Exelon's agreement with
Engage, the Exelon PSA would cover Units 1-2.
Engage may terminate the Engage PSA with 30 days notice after the occurrence
and continuation of an event of default by us. Engage may also terminate the
Engage PSA with regard to Unit 1 or 2 with 30 days notice if a forced outage or
force majeure event at such unit will last more than 120 days; provided, that
if we have taken significant steps toward remediating the circumstances that
led to the forced outage or force majeure event and we certify in writing that
the outage will end within 240 days of commencement (and the outage in fact
ends within the 240 days), then Engage may not terminate the Engage PSA.
Indemnification. Each party must indemnify the other party and its officers,
directors, agents and employees from and against all claims, demands, actions,
losses, liabilities, expenses (including reasonable legal fees and expenses),
suits and proceedings for personal injury, death or property damage caused by
the
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gross negligence or willful misconduct of the indemnifying party that arise out
of or are connected with the performance of the Engage PSA. Likewise, each
party must indemnify the other party from all claims and damages arising out of
the indemnifying party's ownership, possession or control of electric energy up
to or from the delivery point, as the case may be.
Guaranties. As required by the Engage PSA, Engage has posted a parent
guaranty by Westcoast Energy Inc. in our favor to ensure timely payment by
Engage of its financial obligations under the Engage PSA. The maximum amount
payable under the guaranty was $66,621,667 as of June 25, 2001, and it is
reduced by the amount of capacity payments under the Engage PSA from time to
time.
As required by the Engage PSA, both DEI and Peoples Energy have posted
parent guaranties to support the performance of our obligations under the
Engage PSA. These guaranties are several, not joint and several, and are each
limited to $12,500,000.
Assignment. Except as specifically provided in the Engage PSA, neither
Engage nor we may assign our rights under the Engage PSA without the prior
written consent of the other party, which consent can not be unreasonably
withheld. Either party may assign the Engage PSA to an affiliate without
consent, but the assigning party is not released from its obligations under the
agreement. A transfer of a majority of the outstanding voting interests of a
party (or a parent of a party) to a non-affiliate is deemed to be an assignment
of the Engage PSA. Engage has consented to the assignment of a security
interest in the Engage PSA to our lenders.
Governing Law. The Engage PSA is governed by the laws of the State of
Illinois without regard to its conflicts of laws provisions.
Aquila Power Sales Agreements
We are party to two power sales agreements with AEMC and UtiliCorp, the
parent company of AEMC, under which Aquila/UtiliCorp will purchase capacity and
electricity generated from Units 5 and 6 (the "Aquila PSA I") and Units 7 and 8
(the "Aquila PSA II," and together with the Aquila PSA I, the "Aquila PSAs").
Term. The Aquila PSAs will continue until August 31, 2016, in the case of
the Aquila PSA I, and August 31, 2017, in the case of the Aquila PSA II (the
"Initial Terms"), unless otherwise extended or terminated in accordance with
their terms. Aquila/UtiliCorp has the unilateral right to extend the Initial
Terms for an additional five-year period (the "Extension Terms") provided that
Aquila/UtiliCorp notifies us in writing by September 1, 2014, in the case of
the Aquila PSA I, and September 1, 2015, in the case of the Aquila PSA II. In
connection with its analysis of the MAIN electric power market, Pace has
concluded that based on the payment structure of the Aquila/UtiliCorp power
sales agreements, our Facility's forecast dispatch profile, forecast market-
clearing prices and the energy and capacity revenues and volatility values for
Aquila/UtiliCorp from reselling the output and capacity of Units 5-8, it is
likely that Aquila/UtiliCorp will have economic incentives to exercise these
extension options. See "Annex C-1--Executive Summary--Power Sales Agreements--
Extension of Aquila Power Sales Agreements."
Aquila/UtiliCorp's Dispatch Rights. Aquila/UtiliCorp may dispatch the
delivery of electric energy and replacement power (if applicable) up to the
total net dependable capacity of the units. "Net dependable capacity" is
defined in the Aquila PSAs as the aggregate net generating capacity measured in
kWs of the applicable units of the Facility, based upon demonstrated output
(net of station service and auxiliaries for the Aquila/UtiliCorp units)
achieved during capacity testing of the Facility, as adjusted by degradation
curves and to ambient atmospheric temperature of 95 degrees Fahrenheit, 60%
relative humidity, adjusted for elevation above mean sea level. We may, in our
sole discretion (but subject to prudent utility practices), operate any
combination of Units 5 and 6 or Units 7 and 8, as applicable, to meet
Aquila/UtiliCorp's dispatch requirements. Aquila/UtiliCorp has the sole right
to dispatch the units with the exceptions that we may dispatch the units
without Aquila/UtiliCorp authorization for testing, in the event of an
Aquila/UtiliCorp default and at the
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direction of ComEd or its successors and assigns under the Interconnection
Agreements. We are not required to dispatch the units when performing a
scheduled maintenance outage or compressor wash, or when a force majeure
condition exists (see below "--Force Majeure"). We are also required to
increase, curtail, or interrupt power generation during emergency conditions at
the direction of the interconnected utility.
Aquila/UtiliCorp is limited to dispatching 2,500 hours per unit per year.
Dispatch levels must be between 60% and 100% of the capacity of the turbine. In
addition, Aquila/UtiliCorp may dispatch "Incremental Energy" (i.e. capacity in
excess of 100% of net dependable capacity) if and to the extent that it is
available in an amount of up to 250 hours per contract year under each of the
Aquila PSAs.
The Aquila PSAs establish communications protocols between the parties
regarding dispatch of the units. Aquila/UtiliCorp will provide to us by 9:00
a.m. each day an hourly dispatch for the following day. This dispatch is
binding during non-Summer periods except for September on-peak hours.
Aquila/UtiliCorp may request changes to the binding dispatch schedule, and we
will quote a fuel surcharge for the change, at which point Aquila/UtiliCorp may
decide to make the dispatch change or stay with the original dispatch order. We
must provide to Aquila/UtiliCorp by noon each day an estimate of the capacity
(taking into account the effect of any expected deratings) that will be
available for the following three days.
During September on-peak hours, Aquila/UtiliCorp can modify the day ahead
schedule up until five hours before dispatch of the unit and thereafter is
subject to a cancellation fee and the payment of gas balancing costs.
For purposes of the Aquila PSAs, "Summer" is defined as June through August.
During on-peak hours in Summer, Aquila/UtiliCorp may dispatch Units 5 and 6 or
Units 7 and 8, as applicable, with as little as 1 hour and 25 minutes notice (1
hour and 35 minutes notice if also dispatching units under the other Aquila
PSA), again subject to payment of a cancellation fee and the payment of gas
balancing costs.
Failure to Provide Replacement Power and Substitute Power. If there is a
failure to deliver energy to Aquila/UtiliCorp under either a substitute power
arrangement or a replacement power arrangement by the entity that is the source
of that substitute or replacement power, then for the period of such failure,
we must pay Aquila/UtiliCorp the greater of (i) the cost of cover damages that
we actually receive from the provider of the power under those arrangements or
(ii) the amount of any Availability Adjustment (as defined below) due as a
result of such failure.
Capacity Charge. Aquila/UtiliCorp pays us a fixed monthly capacity payment,
which is calculated according to the following formula:
(Capacity Rate X Net Dependable Capacity) - Availability Adjustment.
The Capacity Rate for 2001 was $7.90 per kW per month for Units 5 and 6 and
$7.39 per kW per month for Units 7 and 8, and is $5.11 per kW per month for the
remainder of the Initial Term and $4.90 per kW per month for the Extension
Term. The net dependable capacity of the units is determined through mutually
agreed upon industry standard tests of turbine equipment, and is currently
306,358 kW for Units 5 and 6 combined and 304,959 kW for Units 7 and 8
combined. The "Availability Adjustment" is discussed extensively in the
"Performance Adjustments" section below.
Energy Charge. The energy charge for electricity (other than Incremental
Energy) sold to Aquila/UtiliCorp under each Aquila PSA is calculated on a per
MWh basis, based on the following formula:
Variable O&M Rate + (Fuel Charge X Actual Heat Rate/1000)
The "Variable O&M Rate" is equal to $1.00 per MWh and is escalated annually
using the GDP Implicit Price Deflator. If Aquila/UtiliCorp does not alter its
day ahead dispatch schedule, the "Fuel Charge" is equal to the Gas Daily
Average Price + $0.10 per MMBtu. If Aquila/UtiliCorp makes a change to the day
ahead
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dispatch schedule for Summer On-Peak hours or for September On-Peak hours, the
Fuel Charge is equal to the Gas Daily Average Price + $0.15 per MMBtu. If a
change is made to the day ahead dispatch schedule for non-Summer and Summer
Off-Peak hours, a surcharge is applied to cover the costs of gas purchase
adjustments.
The unit's "Actual Heat Rate" is determined based on the actual performance
of the Facility during the relevant period and is calculated by dividing the
aggregate gas energy consumption in Btus for Units 5-8 (excluding gas consumed
to generate test energy, gas consumed to generate Incremental Energy to the
extent used to offset what would otherwise be a forced derating and gas
consumed during failed starts) by the electric energy output in kWh produced
during the same period by Units 5-8. We have guaranteed a heat rate of 10,787
Btu/kWh at base load as a composite average for Units 5-8 and with allowance
for GE degradation (the "Guaranteed Heat Rate"). If the results of periodic
heat rate testing indicate that Units 5-8 fail to meet the Guaranteed Heat Rate
as a composite average, an adjustment is provided to Aquila/UtiliCorp by the
ratio of the Guaranteed Heat Rate to the tested heat rate in calculating the
monthly energy charge. We are allowed to accrue heat rate credits when the
tested heat rate surpasses a threshold heat rate of 10,759 Btu/KWh for use to
offset occurrences when the heat rate exceeds the Guaranteed Heat Rate.
The energy charge for Incremental Energy under each Aquila PSA is the sum of
$100 per MWh of Incremental Energy delivered to Aquila/UtiliCorp plus (i) with
respect to the first 100 hours per unit of Incremental Energy dispatched by
Aquila/UtiliCorp in any year, twenty percent of the gross margin resulting from
the transaction and (ii) with respect to the next 150 hours per unit of
Incremental Energy dispatched by Aquila/UtiliCorp in any year, 35% of the gross
margin resulting from the transaction.
Start Up Charge. Aquila/UtiliCorp pays a start-up charge of $2,500 per
start. The start-up charge is adjusted annually for inflation. We must pay for
any gas consumed during any start-up that does not result in the units
generating at least 60% of net dependable capacity.
Performance Adjustments. Each Aquila PSA provides for penalties and bonuses
depending on the availability of the applicable units. The basis from which
this determination is made is the Equivalent Availability factor ("EA"),
calculated as follows:
(1 - (FOH + EFDH)/PH),
where FOH is equal to Forced Outage Hours (i.e. the number of hours that the
units experienced a forced outage in the month), EFDH is equal to Equivalent
Forced Derated Hours (i.e. the equivalent number of hours that the units
experienced a forced derating during the month, taking into account the size of
the derating), and PH is Period Hours (i.e. the total number of Summer Super
Peak, Summer Partial Peak and non-Summer On Peak hours, as applicable, in the
month).
The penalty provisions related to availability are in the form of the
Availability Adjustment, which is deducted from the monthly capacity payment.
Availability Adjustments are capped annually, but it is possible in certain
months to have a higher Availability Adjustment than capacity payment,
amounting to a payment that we make to Aquila/UtiliCorp via an offset against
future payments.
There are three availability periods specified in the contract, namely
Summer Super Peak, Summer Partial Peak, and Non-Summer Peak. "Super Peak" hours
are 11 a.m. to 7 p.m., Monday through Saturday. "Partial Peak" hours are 6 a.m.
to 11 a.m. and 7 p.m. to 10 p.m., Monday through Saturday. "Non-Summer Peak"
hours are defined as 6 a.m. to 10 p.m., Monday through Friday, during non-
Summer periods. The following are the seasonal Availability Adjustment
calculations:
Summer Super Peak Availability Adjustment
Annual Capacity Payments X Monthly Adjustment Factor X 0.75 X
(0.97 - EA)
Summer Partial Peak Availability Adjustment
Annual Capacity Payments X Monthly Adjustment Factor X 0.25 X
(0.97 - EA)
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Non-Summer Peak Availability Adjustment
Annual Capacity Payments X 0.18 X (0.97 - EA)
The "Monthly Adjustment Factors" used in the above equations are 18% for
June, and 32% for July and August. If the EA during Super Peak Hours in any
month is less than or equal to 80%, then for purposes of calculating the
Availability Adjustment during the Partial Peak hours in the same month, the EA
during Partial Peak hours is deemed to be equal to the EA during Super Peak
hours for the month.
Availability Adjustments are capped at $24,000,000 for the first contract
year under Aquila PSA I and $21,215,800 under Aquila PSA II, $12,000,000 for
the final contract year, and $18,000,000 for all other contract years.
We are entitled to a capacity bonus for the units. All bonus payments are
conditioned on Summer Super Peak availability being higher than 80%. We receive
a bonus for unit availability which exceeds 97%, which is the guaranteed
availability of the units in the Aquila PSAs. Calculation of the capacity bonus
is as follows:
Summer Super Peak Capacity Bonus
$250,000 X 0.75 X (EA during Super Peak Hours - 0.97)/0.03
plus
Summer Partial Peak Capacity Bonus
$250,000 X 0.25 X (EA during Partial Peak hours - 0.97)/0.03
The maximum capacity bonus we can receive annually is $250,000 under each
Aquila PSA. The capacity bonus is divided by 12 and paid over the 12-month term
beginning with September of each year.
Buyer Remedies For Seller Failure to Deliver. Aquila/UtiliCorp's sole remedy
for our failure to meet our guaranteed on-peak availabilities, to deliver
electric energy, replacement power, or substitute power as dispatched by
Aquila/UtiliCorp, or failure to comply with any performance related provisions
including, standards of operation, minimization of outages and timeliness of
information related to outages, is the Availability Adjustment and is subject
to the limit on our liability for such adjustment.
Forced Outages; Replacement and Substitute Power. Each of the Aquila PSAs
outlines the requirements of the parties relating to unscheduled outages of the
units. First, we must notify Aquila/UtiliCorp within 15 minutes after
discovering that a unit is (i) unable to deliver all or part of the electric
energy required during a dispatch schedule or (ii) unavailable for future
dispatch. Aquila/UtiliCorp must respond within 15 minutes of receipt of our
notice indicating the amount it will charge us to release us from our
applicable energy supply obligations for the remainder of the day (the "Outage
Book Out Charge"). We must then either pay Aquila/UtiliCorp the Outage Book Out
Charge or provide replacement power to Aquila/UtiliCorp. In paying the Outage
Book Out Charge, we are released from any further obligation or liability
(including any availability adjustment) associated with the applicable dispatch
order and the outage notice.
We must further notify Aquila/UtiliCorp, within two hours after the start of
the forced outage, of (a) the cause of the forced outage (if known), (b) the
proposed corrective action, and (c) our best estimate of the expected duration
of the forced outage. In this notice we may also elect to either provide
replacement power on our own behalf from other units at our Facility (if
available) or request Aquila/UtiliCorp to procure substitute power in
accordance with the applicable Aquila PSA. If we provide substitute or
replacement power to Aquila in accordance with the applicable Aquila PSA, these
periods are not counted as forced outages in the Equivalent Availability
calculation. If we fail to timely notify Aquila/UtiliCorp of our election or
fail to supply substitute or replacement power, the incident will be included
as a forced outage for purposes of the calculation of the availability
adjustment.
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If we determine that an incident is expected to extend beyond 11:00 p.m. of
the third business day after the day in which the forced outage or derating
began, then we may make, as soon as practicable, an election to either provide
replacement power on our own behalf from other units at our Facility (if
available) or request Aquila/UtiliCorp to procure substitute power in
accordance with the applicable Aquila/UtiliCorp PSA for the remainder of the
incident.
Standard of Operation. We must manage, control, operate and maintain the
units in a manner consistent with prudent utility practice, in accordance with
(i) the practices, methods, acts, guidelines, standards and criteria of MAIN,
NERC, and the independent system operator, regional transmission organization
or control area, (ii) the requirements of the interconnection agreement with
ComEd, (iii) all applicable requirements of law and (iv) permits taking into
account Aquila/UtiliCorp's dispatch rights under the Aquila PSAs. We must
obtain all certifications, licenses and approvals necessary to operate and
maintain each unit and to perform our obligations under the Aquila PSAs. We
must also obtain and maintain fuel supply and transportation arrangements in a
manner consistent with prudent utility practice, taking into account
Aquila/UtiliCorp's dispatch rights under the Aquila PSAs. We must obtain and
maintain appropriate insurance coverages typical for plants similar to our
Facility, in accordance with prudent utility practice.
Scheduled Maintenance. On March 31st and September 30th of each year, we
must propose a schedule of planned outages to Aquila/UtiliCorp for the twelve
months following such date. Aquila/UtiliCorp may request any reasonable
modifications to the proposed outage schedule. No maintenance outage may be
scheduled to cover the period from May 15 to September 15.
Performance Tests. We must conduct a test to determine the units' net
dependable capacity and net heat rate on or about June 1 of every year at a
mutually agreeable time. All tests must be performed in accordance with prudent
utility practice. Aquila/UtiliCorp has the right, at its expense, to request
that we perform a performance test if Aquila/UtiliCorp believes, based on the
operation of our Facility over a 30-day period, that the net dependable
capacity of the units is more than 2% below the then current level of net
dependable capacity or that the net heat rate exceeds the guaranteed heat rate.
We also have a right to reestablish net dependable capacity and net heat rate
under a capacity test.
Taxes. Each party is responsible for its own income taxes. We are
responsible for the payment of all present or future federal, state, municipal
or other lawful taxes applicable by reason of the operation of our Facility or
assessable on our property or operations. Aquila/UtiliCorp must pay for all
sales, use, excise and similar taxes imposed on the sale or use of or payments
for the electric energy, ancillary services and capacity sold and delivered
under the Aquila PSAs arising at or after the point of delivery.
Title and Risk of Loss. We must deliver the electric energy sold to
Aquila/UtiliCorp at the delivery point (i.e. the metering station in the
Switchyard for energy produced at our Facility). Title to the electric energy
will pass from us to Aquila/UtiliCorp upon delivery at the delivery point.
Aquila/UtiliCorp is responsible for any transmission costs beyond the delivery
point.
Guaranties. DEI and PERC are each obligated to provide a payment guaranty
under each Aquila PSA commensurate with its membership interest. Under each
guaranty, the guarantor irrevocably, absolutely and unconditionally guarantees
the timely payment of all our financial obligations that become due and payable
to Aquila/UtiliCorp under the applicable Aquila PSA. Each guaranty provides for
payment, as a result of an unfulfilled financial obligation by us, to be made
within 10 business days after the guarantor receives written notice. The
guarantee of each of DEI and PERC is limited to 50% of the obligations and in
no event may the maximum aggregate liability for either exceed $10,000,000 plus
amounts for collecting or enforcing the guaranty.
Under each Aquila PSA, Aquila/UtiliCorp must issue a letter of credit equal
to 6 months capacity payments if UtiliCorp's Moody's and S&P rating falls one
rating category below investment grade (i.e. Baa3 for Moody's and BBB- for S&P)
and equal to 12 months of capacity payments if its rating falls two or more
rating categories below investment grade.
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Force Majeure. If a force majeure event renders either party unable to carry
out some or all of its obligations under either Aquila PSA (other than
obligations to pay money) despite all reasonable efforts of the affected party
to prevent or mitigate its effects, then, during the continuance of the force
majeure event, the obligation of the affected party to perform its obligations
is suspended. Under the Aquila PSAs, a force majeure event is an event,
condition or circumstance beyond the reasonable control of and without the
fault or negligence of the affected party, including explosion and fire,
lightning, flood, earthquake, storm, acts of God, strike or labor dispute
(other than a labor dispute or strike by our employees or the employees of our
contractors and subcontractors), war, sabotage, failure to obtain governmental
approvals as a result of a change in law, changes in law materially adversely
affecting the operation of our Facility, lack of fuel caused by a force majeure
event (as defined in the Aquila PSAs) experienced by our fuel supplier or
transporter or curtailment of firm gas transportation service to our Facility
by governmental order, the failure of performance of any third party with which
we have a contract as a result of a force majeure event (as defined in the
Aquila PSAs), mechanical equipment breakdown caused by certain force majeure
events, or interruption of acceptance by ComEd of delivery of electric energy
from our Facility into the ComEd system. Changes in market conditions do not
constitute force majeure events under the Aquila PSAs. If a force majeure event
affects Units 5 and 6 or Units 7 and 8, as applicable, and the other units at
our Facility, we are required to equitably allocate the burdens of the effects
of the force majeure event over all of the affected units.
Aquila/UtiliCorp is required to pay us 50% of its capacity payments for the
first 15 days of a force majeure event. An extended force majeure event (i.e.
one not overcome within five months) that cannot be overcome in some other
manner can give the other party grounds for cancellation of the applicable
Aquila PSA. Any periods of forced outage or forced derating caused by force
majeure events are not included as forced outage hours or forced derating hours
for purposes of calculating the availability adjustment.
Our Events of Default. The following are our events of default (unless cured
within the applicable cure period), which could lead to the termination of the
applicable Aquila PSA or the exercise of other remedies by Aquila/UtiliCorp:
. we fail to make payments when due, or our guarantors fail to pay for
substitute power or an Outage Book Out Charge (if we previously failed
to make such payments) and by the procedure specified in the Aquila PSA,
unless the failure is cured within seven days after receipt of written
notice of such failure from Aquila/UtiliCorp;
. one of our guaranties ceases to remain in full force and effect in
accordance with its terms, one of our guarantors fails to make a payment
upon a proper drawing against the guarantee by Aquila/UtiliCorp, or we
fail to deliver a letter of credit as required by the Aquila PSA upon a
"downgrade event" (which occurs when a guarantor's debt rating falls
below investment grade or if one of our guarantors that is not rated has
a value below $600,000,000 in owner's equity, or a ratio of total
liabilities to total assets for DEI that exceeds 72%) with respect to
one of our guarantors, unless cured within 21 days after receipt of
written notice from Aquila/UtiliCorp;
. our dissolution or liquidation, unless cured within 60 days after
receipt of written notice from Aquila/UtiliCorp;
. our bankruptcy;
. our assignment of the Aquila PSA or any other of our rights under the
Aquila PSA or the sale and transfer of any interest in us, in each case
not in compliance with the provisions of the Aquila PSA, unless cured
within 60 days after receipt of written notice from Aquila/UtiliCorp;
. we sell electric energy or capacity that is committed to
Aquila/UtiliCorp to a third party other than as permitted in the Aquila
PSA, unless cured within 60 days after receipt of written notice from
Aquila/UtiliCorp;
. any false representation made by us under the certain provisions in the
Aquila PSA, unless cured within 60 days after receipt of written notice
from Aquila/UtiliCorp; or
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. our Facility experiences chronic poor availability (i.e. generally less
than 80% availability for three years or 70% availability for two years)
under the provisions of the Aquila PSA.
Aquila/UtiliCorp Events of Default. Aquila/UtiliCorp events of default under
each Aquila PSA include:
. Aquila/UtiliCorp fails to pay any sum due from it under the Aquila PSA,
unless cured within seven days after receipt of our written notice;
. the bankruptcy of Aquila/UtiliCorp, unless cured within 60 days after
receipt of our written notice;
. the dissolution or liquidation of Aquila/UtiliCorp (except in connection
with a change in control of AEMC in accordance with the Aquila PSA),
unless cured within 60 days after receipt of our written notice;
. Aquila/UtiliCorp's failure to post or maintain security at levels
specified in the Aquila PSA in connection with a downgrade event with
regard to Aquila/UtiliCorp, unless cured within 60 days after receipt of
our written notice;
. Aquila/UtiliCorp's assignment of the Aquila PSA or any of its rights
under the Aquila PSA or the sale or transfer of any interest in
Aquila/UtiliCorp not in compliance with the Aquila PSA, unless cured
within 60 days after receipt of our written notice; or
. Any false representation made by Aquila/UtiliCorp under certain
provisions in the Aquila PSA, unless cured within 60 days after receipt
of our written notice.
Termination Rights. Aquila/UtiliCorp may terminate either Aquila PSA with 30
days written notice if we default and the default is continuing.
Aquila/UtiliCorp may also terminate the applicable Aquila/UtiliCorp PSA if the
units have chronically poor availability (i.e. generally less than 80%
availability for three years or 70% availability for two years).
Aquila/UtiliCorp may also terminate if we experience an extended force majeure
event.
We may sell energy and capacity to third parties if Aquila/UtiliCorp
defaults in its payment obligations during the continuance of such default. We
may cancel the applicable Aquila PSA with 30 days written notice if
Aquila/UtiliCorp defaults and the default is not cured. We may also terminate
if Aquila/UtiliCorp experiences an extended force majeure event.
Appointment of AEMC as UtiliCorp's Agent. UtiliCorp appointed AEMC as its
agent with full power to act on UtiliCorp's behalf with respect to the Aquila
PSAs as AEMC deems appropriate, including with respect to any notices, claims,
consents, elections, waivers, agreements or instruments. However, AEMC may not
agree to amend either Aquila PSA on behalf of UtiliCorp.
Indemnification. Each party must indemnify the other party, and its
officers, directors, agents and employees from and against all claims, demands,
actions, liabilities, expenses and losses (including reasonable legal fees and
expenses) for personal injury, death or property damage caused by the
negligence or willful misconduct of the indemnifying party that arise out of or
are connected with the performance of the Aquila PSAs, except to the extent
caused by the gross negligence or willful misconduct of, or breach of the
applicable Aquila PSA by, the party seeking indemnification. Likewise, each
party must indemnify the other party from all claims and damages arising out of
the indemnifying party's ownership, possession or control of electric energy up
to or from the delivery point, as applicable. In no event will either party be
liable to the other party for any special, incidental, exemplary, indirect,
punitive or consequential damages, including loss of profits.
Assignment. Except as provided below, neither party may assign its rights
under either Aquila PSA without the prior written consent of the other party.
Either party may assign the Aquila PSAs to an affiliate without consent, but
the assigning party is not released from its obligations under the agreement. A
transfer of a majority of the outstanding voting interests of a party (or a
parent of a party) to a non-affiliate is deemed to
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be an assignment of the Aquila PSAs. Aquila/UtiliCorp has consented to the
assignment of a security interest in the Aquila PSAs to our lenders. If there
is a change in ownership or control of AEMC and the successor entity has a
credit rating equal to or higher than UtiliCorp, we must consent to the
assignment of the Aquila PSAs to such successor entity and release UtiliCorp
from its obligations under the Aquila PSAs arising from and after the change in
control.
Governing Law. The Aquila PSAs are governed by the laws of the State of
Illinois without regard to its conflicts of laws provisions.
FUEL AGREEMENTS
Cinergy Fuel Management Agreement
We are party to a fuel supply and management agreement (the "FSMA"), which
establishes the terms and conditions under which Cinergy will serve as our fuel
manager by taking on the exclusive rights and obligations to procure, schedule
and deliver to Nicor and/or PGL volumes of gas sufficient to meet our gas
requirements, including the management and administration of the Nicor
Transportation and Balancing Agreement (the "Nicor T&B Agreement"). The FSMA
provides Cinergy with agency authority to purchase and arrange for deliveries
of gas sufficient to serve our production requirements.
Term. The term of the FSMA runs from May 1, 2001 through April 30, 2002,
unless terminated earlier in accordance with its terms or extended by agreement
of the parties.
Duties of Cinergy. Cinergy will supply and arrange for delivery to us
(through the Nicor or PGL system) at its own expense on a firm basis our full
gas requirements up to the applicable Firm Maximum Daily Quantity and Maximum
Hourly Quantity (as set forth in the table below) and on a reasonable efforts
basis for any excess beyond those quantities, subject to the limitations of the
Nicor T&B Agreement (see below). Unless Cinergy fails to provide the amount of
gas required to be delivered under the FSMA and such default is likely to
prevent us from meeting our obligations to provide power to our power
customers, Cinergy is our sole supplier of gas during the term of the FSMA. In
discharging its responsibilities under the FSMA, Cinergy must manage fuel
supply volumes within the defined parameters in the Nicor T&B Agreement and is
responsible for all charges assessed by Nicor associated with its failure to
manage fuel supply volumes.
Cinergy must supply gas from the following sources: (i) the NBPL, APL or
NGPL interstate pipelines, (ii) inventory storage under the Nicor T&B Agreement
or (iii) purchased from Nicor as "Requested Authorized Use" or "Unauthorized
Use Volumes" under the Nicor T&B Agreement. In addition, all gas delivered by
Cinergy under the FSMA must be merchantable natural gas, free of liens and
encumbrances of any kind, and must comply with the fuel specifications in the
FERC approved tariff of the interstate pipeline on which the gas is being
transported.
Maximum Daily Quantity Summer 362,400 MMBtu (241,600 firm and 120,800
non-firm)
Maximum Daily Quantity Non-Summer 426,600 MMBtu (lesser of 213,300, or
88,875 plus Cinergy's nominated volumes,
is firm; remainder is non-firm but
Cinergy must use reasonable efforts to
sell and deliver non-firm quantities)
Maximum Hourly Quantity Summer 15,100 MMBtu per hour
Maximum Hourly Quantity Non-Summer 17,775 MMBtu per hour
"Summer" is defined as June through September in the FSMA.
Facility Consumption Charges. For any day that is not a Special Day (as
defined below under "--Special Days"), we pay Cinergy for fuel supplies at the
Gas Daily Average Price plus four cents per MMBtu.
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Fuel Management Fee. As compensation for its performance of its duties as
Fuel Manager for our Facility, we pay Cinergy $65,000 per month for each of the
Summer months and $10,000 per month for each of the non-Summer months.
Special Days. Fuel quantities and prices on "Special Days" (i.e. days for
which Cinergy's ability to use transportation and storage capacity has been
curtailed) are negotiated by the parties. Any volumes delivered by Cinergy but
not consumed by us on a Special Day are injected into storage under the Nicor
T&B Agreement. Up to 20,000 MMBtu per day of these "Deferred Special Day
Volumes" will be withdrawn and delivered to the Facility as the "first gas
through the meter" on the immediately succeeding non-Special Days at no
additional cost to us, until the balance of the Deferred Special Day Volumes
are reduced to zero.
Summary of Reimbursable Charges. Although we remain responsible for paying
all charges under the Nicor T&B Agreement, unless we fail to meet certain
conditions set forth in the FSMA, we receive reimbursement from Cinergy for the
following charges under the Nicor T&B Agreement: forecast variance charges (up
to 241,600 MMBtu and 67,400 MMBtu, for summer and non-summer months
respectively); delivery variance charges (except to the extent attributable to
volumes consumed by our Facility in excess of the Firm Maximum Daily Quantity);
excess storage or storage inventory overrun charges (limited to those assessed
because the highest daily quantity in storage exceeds 951,500 MMBtus); and
charges for requested authorized use and unauthorized use.
Forecast Variance Charges. Under the FSMA, we must pay Cinergy an "Elwood
Forecast Variance" charge on the difference each day between our projected gas
consumption (the "Elwood Forecast Burn") and the actual amount of gas consumed
by our Facility during the day. The Elwood Forecast Variance charges under the
FSMA are related to the Nicor T&B Agreement. Under the Nicor T&B Agreement,
Nicor levies a Forecast Variance charge on us for the difference each day
between the Forecast Burn it receives from Cinergy and the actual amount of gas
consumed by us during the day. The following tables show the Forecast Variance
charges (which here are translated from units in therms, as presented in the
Nicor T&B Agreement, to MMBtu for ease of comparison to the FSMA provisions).
The applicable Forecast Variance charges differ for Summer and non-Summer
months.
Summer Months
Nicor T&B Agreement Forecast Variance Charges per day
20,000 MMBtu (less than) Forecast Variance (less than or =) 120,800 MMBtu $0.05/MMBtu
120,800 MMBtu (less than) Forecast Variance (less than or =) 181,200 MMBtu $0.10/MMBtu
181,200 MMBtu (less than) Forecast Variance (less than or =) 241,600 MMBtu $0.48/MMBtu
241,600 MMBtu (less than) Forecast Variance Negotiable
Under the FSMA, we must pay Cinergy $0.05/MMBtu/d for the Elwood Forecast
Variance for each day, up to 241,600 MMBtu/d during the Summer months. Cinergy,
in turn, reimburses us for the Forecast Variance charges under the Nicor T&B
Agreement, unless we have failed to meet certain conditions set forth in the
FSMA, up to the charges for a Forecast Variance that exceeds 241,600 MMBtu/d.
We are obligated to pay the Nicor Forecast Variance charges attributable to
volumes exceeding 241,600 MMBtu/d.
Non-Summer Months
Nicor T&B Agreement Forecast Variance Charges per day
20,000 MMBtu (less than) Forecast Variance (less than or =) 47,400 MMBtu $0.05/MMBtu
47,400 MMBtu (less than) Forecast Variance (less than or =) 88,875 MMBtu $0.55/MMBtu
88,875 MMBtu (less than) Forecast Variance (less than or =) 118,000 MMBtu $0.55/MMBtu
(non-firm)
118,000 MMBtu (non-firm) (less than) Forecast Variance Negotiable
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Under the FSMA, we pay Cinergy $0.05/MMBtu/d for the Elwood Forecast
Variance for each day up to 67,400 MMBtu/d during the non-Summer period.
Cinergy in turn reimburses us for the Forecast Variance charges set forth in
the Nicor T&B Agreement up to the charges for a Forecast Variance that exceeds
67,400 MMBtu/d. We are obligated to pay Forecast Variance charges attributable
to volumes exceeding 67,400 MMBtu/d.
Under the FSMA, we communicate our Elwood Forecast Burn for the next day to
Cinergy at 6:45 a.m. each day. Using its judgment, and certain other
information provided by us, Cinergy develops its own Forecast Burn for the day
and communicates it to Nicor by 7:00 a.m. The FSMA contains a communications
protocol governing these and other communications.
Sale of Power by Cinergy. Cinergy may offer to sell power to us from time to
time so that we may forego running our units and taking gas under the FSMA. We
have no obligation to accept Cinergy's offer, and our acceptance is subject to
the consent of our power customers. If we accept the offer, all obligations
under the FSMA relating to gas are suspended during the power sales period.
Failure to Deliver. Failure to provide firm supply and delivery will result
in Cinergy paying our reasonable incremental cost of cover, including gas cost
and any associated services. This is our sole remedy for Cinergy's failure to
provide firm supply and delivery of gas.
Our Responsibilities Under the FSMA. We are required by the FSMA to perform
the following activities:
. operate and maintain the on-site equipment for receiving and handling
gas;
. use reasonable efforts to provide Cinergy with notice regarding startups
or shutdowns of the units and our estimated gas requirements in
accordance with the FSMA;
. make available to Cinergy a Loaned Gas Balance for its use of 725,000
MMBtu, to be returned on termination of the Agreement;
. maintain the Nicor T&B Agreement in full force and effect and not agree
to any changes to the Nicor T&B Agreement that alter the rights or
obligations of Cinergy without Cinergy's express consent; and
. operate the units in accordance with the standards of the FSMA.
Metering. For the purpose of measuring quantities of gas delivered to us,
gas will be metered and measured by Nicor at its meters located at the delivery
point under the Nicor T&B Agreement.
Guaranties. The FSMA requires that Cinergy Corp. execute a guaranty of
Cinergy's financial obligations for our benefit. The Cinergy Corp. guaranty is
limited to a cap amount of $13 million.
The FSMA also requires us to deliver the parent guaranties of DEI and
Peoples Energy Corporation. Each of the guaranties is capped at $6.5 million.
Agency of Cinergy. Under the FSMA, we appoint Cinergy to act as agent on our
behalf for the purposes of (i) taking actions at our direction, (ii) making
payments of all charges in accordance with the FSMA and (iii) acting on our
behalf and for our benefit in managing and administering the Nicor T&B
Agreement. Cinergy may not, without our permission, (w) enter into any
agreements on our behalf unless consistent with its purposes as agent; (x)
enter into any physical or financial hedging or speculative transactions on our
behalf; (y) agree to any amendment of, or waive any right under, the Nicor T&B
Agreement or our other agreements; or (z) enter into any agreement in violation
of applicable law, the FSMA or the Nicor T&B Agreement. Cinergy must pay, from
its own funds, all expenses it incurs in the course of performing its duties
and obligations under the FSMA.
If the FSMA is terminated with or without cause, Cinergy's agency
immediately ceases and Cinergy will no longer be entitled to act on our behalf
under the Nicor T&B Agreement or any other agreement.
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Cinergy Events of Default. Cinergy's events of default include:
. a default in the performance of any of its covenants or obligations
under the FSMA (other than a payment default or a default in the
obligation to supply and deliver gas) that is not cured within 5 days of
our written notice;
. a default under the guaranty of Cinergy Corp.;
. the liquidation, dissolution, receivership, insolvency or bankruptcy of
Cinergy or Cinergy Corp.;
. Cinergy's failure to make any payment when due or cure such failure in
the lesser of 10 days or such time period as would result in loss of gas
supply or delivery to us if not cured within such period; and
. any representation or warranty made by Cinergy or Cinergy Corp. (in
Cinergy Corp.'s guaranty) should prove to be materially untrue or be
breached as of May 1, 2001.
Except as provided below, if Cinergy defaults under the FSMA, we may do any
or all of the following: (i) cure the default and seek reimbursement of any
costs we incur in effecting the cure, or offset such costs against any amounts
payable by us in the future under the FSMA; (ii) terminate the FSMA; and/or
(iii) exercise all other rights and remedies available to us at law or in
equity. However, if Cinergy defaults in the performance of any of its
obligations to deliver the Firm Maximum Daily Quantity on any non-Special Day
or the quantity of gas agreed upon by the parties for a Special Day, and the
default is reasonably likely to prevent us from meeting our power supply
obligations, then we have the right, as our sole remedy for the default, to
procure replacement gas for our Facility on commercially reasonable terms.
Cinergy must reimburse us for any reasonable incremental costs incurred in
purchasing the replacement gas and related services, plus interest.
Our Events of Default. Our events of default include:
. a default in the performance of any of our obligations under the FSMA
that is not cured within 5 days after receiving written notice from
Cinergy;
. a default under either of the guaranties of DEI or Peoples Energy
Corporation;
. the liquidation, dissolution, receivership, insolvency or bankruptcy of
us or either of our guarantors; and
. any representation or warranty made by our guarantors or us should prove
to be materially untrue or be breached as of May 1, 2001.
If we default under the FSMA, Cinergy may, upon seven days notice to us, do
any or all of the following: (i) terminate the FSMA; (ii) terminate the agency
granted to Cinergy under the FSMA; and (iii) exercise all other rights or
remedies available at law or in equity, including, without limitation,
recovering from us any future management fees due under the FSMA. If Cinergy
terminates the FSMA in the event of our default, then Cinergy must use its
reasonable efforts to minimize the costs associated with unwinding gas purchase
agreements; provided, however, Cinergy may not, without our consent, unwind or
terminate any gas purchase agreements entered into as our agent under the FSMA
with respect to which we have financial exposure. We must reimburse Cinergy for
all costs incurred by Cinergy to unwind any and all agreements entered into by
Cinergy as our agent under the FSMA.
Force Majeure. Except for payment obligations due under the FSMA, neither
party is liable for its failure to perform any obligation under the FSMA, nor
may it be deemed in breach of the FSMA, to the extent the failure to perform is
due to a force majeure event, provided that: (i) the non-performing party gives
notice of the event, (ii) the suspension of performance is limited in scope and
duration as required by the force majeure event, (iii) the non-performing party
uses its reasonable efforts to remedy its inability to perform, (iv) the non-
performing party notifies the other party when it is able to resume performance
and (v) the force majeure event was not caused by or connected with any
negligent or intentional acts, errors or omissions, or failure to comply with
any law or regulation by the non-performing party.
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For purposes of the FSMA, the definition of force majeure events differs for
the parties. For us, a force majeure event is any delay in the performance of
our obligations under the FSMA due solely to circumstances beyond our
reasonable control and that could not have been prevented by our due diligence,
including: acts of God, weather-related events affecting an entire geographic
region, strikes or other labor difficulties, war, riots, requirements, acts or
omissions of governmental authorities, changes in law after the date of the
FSMA preventing performance, inability despite due diligence to obtain or renew
required licenses, accident, earthquake, sabotage or fire. For Cinergy, a force
majeure event is limited to declarations of force majeure by Nicor under the
Nicor T&B Agreement, by any of NBPL, APL, NGPL or any pipeline upstream of
these pipelines under its tariff or transportation agreement, or by PGL under
the its transportation and balancing agreement with Nicor, or a default by
Nicor under the Nicor T&B Agreement not due to Cinergy's failure to fulfill its
responsibilities under the FSMA, and then only to the extent that the force
majeure events directly impact Cinergy's ability to execute its
responsibilities under the FSMA and are beyond Cinergy's control. If a
declaration of force majeure by any of NBPL, APL or NGPL is based on an outage
of its pipeline system upstream of its interconnection facilities with PGL or
Nicor or if a declaration of force majeure by Nicor is based on an outage of
its pipeline system used to provide service to us, then Cinergy must use
reasonable efforts to provide gas during the outage and we must pay pre-
approved costs relating to Cinergy's performance during the outage condition.
If, despite Cinergy's reasonable efforts during the outage condition, Cinergy
is unable to provide firm gas supply due to the outage condition, then the
event qualifies as a force majeure event for Cinergy.
Under the FSMA, the following are not considered force majeure events: (i)
changes in market conditions that affect the cost of gas or any alternate
supplies of gas, or (ii) gas supply or transportation interruptions, except to
the extent that gas is unavailable generally on the NBPL, APL, NGPL, Nicor Gas
or Peoples Gas systems at any price.
If a force majeure event delays a party's performance under the FSMA for
greater than 30 days (or if the force majeure event cannot be overcome within
30 days with reasonable diligence, a reasonably longer period granted by the
non-delayed party not to exceed 3 months), the non-delayed party may terminate
the FSMA without further obligation.
Termination upon Cinergy's Deficient Performance. If Cinergy's performance
under the FSMA results in written notice from Nicor that service may or will be
suspended under the Nicor T&B Agreement, we may immediately suspend or
terminate the FSMA if Cinergy does not cure the conditions that caused such
notice to issue in time to prevent any suspension or termination.
Termination upon Enforcement Action. If the FERC or any other federal or
state agency or authority asserts or determines that any of the terms of the
FSMA or the conduct of the parties under the FSMA is in violation of the
Natural Gas Act, any other federal or state law or the terms of any applicable
FERC gas tariff, then either party may terminate the FSMA upon the earlier to
occur of the date required by applicable law or 30 days after notice given to
the other party. In the event of termination, all costs associated with
unwinding or terminating the gas purchase, transportation or storage agreements
relating to our Facility are shared equally by the parties.
Indemnification. Cinergy must indemnify us, and our members, officers,
directors, employees and agents, for third party claims, penalties, expenses
and liabilities (including reasonable attorneys' fees and expenses) arising
from: (i) claims associated with title to gas or liens on title to gas, (ii)
balancing, storage or transportation costs, charges, penalties or fees
resulting from sales of gas from Cinergy to persons other than us, (iii)
governmental fines and penalties on account of Cinergy's actions, (iv)
Cinergy's failure to comply with the provisions of the FSMA governing Cinergy's
agency, (v) Cinergy's purchases of gas or entry into other agreements, on its
own behalf or as our agent, (vi) taxes for which Cinergy is responsible and
(vii) injury and property damage to third parties caused by the negligence or
willful misconduct of Cinergy that arise out of Cinergy's performance of the
FSMA (except to the extent attributable to our gross negligence or willful
misconduct, or our breach of the FSMA).
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We must indemnify Cinergy, its members, officers, directors, employees and
agents for third-party claims, penalties, expenses and liabilities (including
reasonable attorneys' fees and expenses) arising from: (i) claims associated
with the consumption of gas by us, including any environmental claims, (ii)
governmental fines and penalties on account of our actions, (iii) our failure
to comply with the provisions of the FSMA regarding Cinergy's agency, (iv) our
purchases of gas entered into on our own behalf, (v) taxes for which we are
responsible, and (vi) injury or property damage to third parties caused by our
negligence or willful misconduct that arise out of our performance of the FSMA
(except to the extent attributable to the gross negligence or willful
misconduct of, or breach of the FSMA by, Cinergy).
The indemnification provisions of the FSMA survive the expiration of the
term or the termination of the FSMA. Under the FSMA, neither party is liable
for consequential, punitive, exemplary or special damages.
Assignment. Except as provided below, neither party may assign its rights
under the FSMA without the prior written consent of the other party, which
consent cannot be unreasonably withheld. As long as we have not defaulted under
the FSMA, we may assign the FSMA without Cinergy's consent to (i) any affiliate
of DEI or PERC, or (ii) to any party succeeding in ownership to the units,
provided that the proposed assignee is creditworthy. As long as Cinergy has not
defaulted under the FSMA, Cinergy may assign the FSMA without our consent to a
creditworthy affiliate that is at least as well qualified to fulfill Cinergy's
obligations under the FSMA as Cinergy. Cinergy has also consented to the
assignment of the FSMA or a security interest in the FSMA to our lenders,
provided the assignment does not adversely affect Cinergy's rights under the
FSMA.
Governing Law. The FSMA is governed by the laws of the State of Texas,
without regard to principles of conflicts of laws. The parties irrevocably
submit to the jurisdiction of the state and federal courts sitting in Houston,
Texas.
Nicor Transportation & Balancing Agreement
The Nicor T&B Agreement establishes the terms and conditions under which
Nicor will provide firm gas transportation services and no-notice balancing
services that allow us to receive delivery of gas supplies at hourly rates and
on short notice, to meet the peaking requirements of our generation units.
The Nicor T&B Agreement is designed to ensure that we have the right to
receive interstate gas supplies delivered from APL, NBPL and NGPL. While Nicor
is the local distribution company and the contractual provider of services to
our Facility, the physical transportation of gas is provided by PGL's 24-inch
pipeline, which is connected to the interstate pipelines of APL and NBPL. Nicor
and PGL physically manage gas storage balancing needed to accommodate changes
in the scheduled gas supplies and generator loads.
Term. The term of the Nicor T&B Agreement, including any extensions, is
bifurcated to reflect the fact that our Facility was constructed in several
phases. The first phase of the Nicor T&B Agreement ("Phase I Term") relates to
Units 1 - 4 and covers a 41-month period commencing on May 1, 2001 and ending
September 30, 2004. The second phase of the Nicor T&B Agreement ("Phase II
Term") relates to generating Units 5 - 9 and covers a five-year period
commencing on May 1, 2001 and ending March 31, 2006. The Nicor T&B Agreement
provides for three elective extensions of the Phase I and Phase II Terms as
follows:
Commencement Expiration Notice
Extension Term Date Date Units Requirement
- --------- ------- ------------- -------------- ----- -----------
Phase I Primary Term
Extension 18 mos. Oct. 1, 2004 March 31, 2006 1 - 4 180 days
Phase II Term Extension 5 yrs. April 1, 2006 March 31, 2011 5 - 9 180 days
Phase I and Phase II
Term Extension 5 yrs. April 1, 2006 March 31, 2011 1 - 9 180 days
Volume Terms. Under the Nicor T&B Agreement, we have the right to firm
transportation service of gas supply within our minimum and maximum daily
nomination allowances. Our maximum daily contract quantity of gas is 241,600
MMBtu/day in the Summer months (i.e. June through September) and 284,400
MMBtu/day in the non-Summer months (i.e. October through May). In addition,
Nicor is not obligated to deliver gas to us
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at an hourly rate in excess of 15,100 MMBtu/hour in the Summer months and
17,775 MMBtu/day in the non-Summer months. If we request gas at an hourly or
daily rate greater than the above-mentioned limits, Nicor will use reasonable
efforts to deliver gas at our requested rate. Subject to certain exceptions in
the Nicor T&B Agreement, if Nicor's operational conditions require Nicor to
restrict our purchases from interstate pipelines, we receive a $0.48 per MMBtu
credit for the quantity affected.
The Nicor T&B Agreement explicitly recognizes the hourly needs of a peaking
facility and gives us the flexibility to take gas as needed, limited only to
the hourly, daily and seasonal limits of the contract. We have firm storage
rights to inject or withdraw on a no-notice basis up to 181,200 MMBtu per day
during the Summer months and up to 88,875 MMBtu per day during the Non-Summer
months. Additionally, we can exceed these limits, but are subjected to
additional volumetric charges for volumes in excess of the limits (see "--
Excess Storage Charges" below). At no time can the amount of gas in our
balancing account exceed 725,000 MMBtu (approximately 3-4 days of the
Facility's maximum daily usage). The storage account is intended to absorb over
or underages in delivery caused by the no-notice, hourly and intraday needs of
the Facility and is not intended to be a gas supply reserve.
The following is a summary of our contractual volume limitations under the
Nicor T&B Agreement:
Contractual Volumes
-------------------
Max. Balancing Service Account Balance: 725,000 MMBtu
Max. Firm Balancing Quantity Summer: 181,200 MMBtu
Max. Firm Balancing Quantity Non-Summer: 88,875 MMBtu
Max. Daily Contract Quantity Summer: 241,600 MMBtu/day
Max. Daily Contract Quantity Non-Summer: 284,400 MMBtu/day
Max. Hourly Quantity Summer: 15,100 MMBtu/hour
Max. Hourly Quantity Non-Summer: 17,775 MMBtu/hour
The Nicor T&B Agreement contains a communications protocol setting forth the
notification process relating to gas supply. We must notify Nicor of the
projected next day consumption ("Forecast Burn") at 7 a.m. on the business day
before the day for which the projection is given. Nicor must then provide to us
by 8 a.m. the minimum and maximum quantities of gas that we may nominate.
Finally, we must provide to Nicor by 9 a.m. amounts of pipeline gas to be
nominated the following day; however, through May 31, 2002 (unless extended by
mutual agreement), on non-Critical Days during non-Summer months, we may submit
a "revised forecast burn" to Nicor by 9:15 a.m. for changes attributable to an
increased electrical dispatch by Aquila under the Aquila PSAs. The order of
delivery for gas used is Requested Authorized Use (as defined below) gas,
customer owned gas nominated from pipeline, balancing services gas, and
Unauthorized Use (as defined below) gas.
Critical Days. Nicor's service is firm, but the no-notice balancing service
available from storage may be curtailed during extreme weather conditions. When
Nicor's load for its gas heating requirements is expected to exceed sixty
heating degree days (an average daily temperature of five degrees Fahrenheit or
less), Nicor may limit deliveries to us to firm transportation service and the
gas received for our account from NBPL, APL and NGPL on such days. During days
when Nicor is projected to exceed 65 heating degree days or during a declared
"Critical Day" weather emergency under its tariff, deliveries to us may be
further restricted by Nicor in any hour to the transportation gas received in
the corresponding hour from NBPL, APL and NGPL, as applicable, for our account.
On Critical Days, our power customers must designate in advance if the units
may be called upon. Gas supplies will then be purchased to meet the designated
needs of the power customers and will be delivered via firm transportation
service to the plant.
Reservation and Volumetric Charges. We must pay Nicor a Reservation Charge
for each Summer month of $0.45 per MMBtu for the 241,600 MMBtu per day of
Maximum Daily Contract Quantity reserved for the Facility. We must also pay
Nicor a Volumetric Charge at a rate of $0.037 per MMBtu for gas delivered
during the Summer months and $0.092 per MMBtu for non-Summer month delivery. A
Balancing and Storage Service Reservation Charge is assessed for each Summer
month at a rate of $3.35 per MMBtu for the 181,200 MMBtu per day of Summer
Maximum Firm Balancing Quantity.
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Forecast Variance Charges. A discussion of Forecast Variance charges under
the Nicor T&B Agreement is contained in the discussion of the Cinergy FSMA.
Delivery Variance Charges. Nicor charges us to the extent daily consumption
by our Facility is greater than the maximum or less than the minimum quantity
nominated for delivery on NBPL, APL or NGPL, in total, for that day. This
variance is called the "Delivery Variance," and the charge is limited to
Delivery Variances that exceed 5,000 MMBtu on any day that is not a Critical
Day or a day on which pipeline deliveries have been curtailed. This charge is
waived for the first six billable Delivery Variance events unless the
cumulative volume of such events exceeds 60,000 MMBtu in a contract year. If
the 60,000 MMBtu threshold is exceeded, all prior and subsequent Delivery
Variances are assessed. On Critical Days and days on which pipeline deliveries
have been curtailed, the charge applies without limitation.
Excess Storage Charges. We must pay a Storage Inventory Overrun Charge to
Nicor at the rate of $0.50 per MMBtu for each occurrence where the highest
daily quantity in storage is in excess of 725,000 MMBtu but less than 951,500
MMBtu. An Excess Storage Charge is applied monthly at a rate of $1.00 per MMBtu
for each occurrence where the highest daily quantity in storage exceeds 951,500
MMBtu. The Excess Storage Charge is also assessed daily when balancing and
storage service on any Summer month day is greater than 241,600 MMBtu per day
and less than 302,000 MMBtu per day and on any non-Summer month day when
balancing and storage service exceeds 118,000 MMBtu per day but is less than
147,500 MMBtu per day.
Upstream Transportation Charges. We must pay Upstream Transportation
Charges, which are in effect passed on to PGL through the Transportation and
Balancing Service Agreement between Nicor and PGL. The Upstream Transportation
Charges consist of two components: (i) a reservation charge for each Summer
month at a rate of $0.737 per MMBtu of Maximum Daily Contract Quantity (241,600
MMBtu per day) and (ii) a volumetric charge for each month at a rate of $0.044
per MMBtu on all gas delivered by Nicor to the Facility.
Requested Authorized Use and Unauthorized Use Charges. Nicor and we may
agree to negotiate authorized overrun levels of daily balancing and storage
service for injection or withdrawal of gas and/or Forecast Variance Charges; or
for purchase of Nicor-owned gas. An agreement before use of these services
constitutes "Requested Authorized Use." Requested Authorized Use of Nicor's gas
supplies when approved is charged at the higher of Nicor's cost of gas or
market price plus $0.20 per MMBtu. Use of Nicor's gas supplies without
requested authorization and approval is considered "Unauthorized Use" and is
charged at the Requested Authorized Use charge plus $60.00 per MMBtu.
Minimum Annual Charges. While the actual amount to be paid each year will
vary depending on the volumes transported and stored, the Nicor T&B Agreement
states that the minimum annual bill which we will pay to Nicor is $4.35
million, excluding any Storage Inventory Overrun, Excess Storage, Delivery
Variance, Requested Authorized Use and Unauthorized Use charges, buy-out
amounts, incremental global point agreement/operational balance agreement
charges and applicable taxes. Phase I and Phase II contract term extensions
result in a pro-rata increase in monthly and annual minimum payments.
Rebate of Charges. We receive a 25% rebate of charges billed to us
(excluding any Storage Inventory Overrun, Excess Storage, Delivery Variance,
Requested Authorized Use and Unauthorized Use charges, buy-out amounts,
incremental global point agreement/operational balance agreement charges and
applicable taxes) which exceed $5.75 million in any contract year and a 50%
rebate of charges billed to us (subject to the same exclusions) which exceed
$6.75 million in any contract year.
Delivery Terms. Gas supplies that we nominate for delivery to us or into
storage must be transported on the NBPL, NGPL or APL interstate pipelines.
Limitation of Liability. Neither party will be liable to the other for
consequential, punitive, exemplary, and other special damages.
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Nicor Non-Performance. Nicor may not suspend its performance for any reason
other than our nonpayment of invoices. We agreed not to bypass Nicor's local
distribution system while the Nicor T&B Agreement is effective, but reserved
the right, in the event of Nicor's non-performance and at our option, either to
obtain and receive gas from other suppliers or receive from Nicor the market
value of any gas not delivered. In addition, if Nicor suspends performance for
any reason other than force majeure, Nicor will hold us harmless from any
damages from Nicor's failure to perform under the Nicor T&B Agreement.
Force Majeure. If any obligation of either party under the Nicor T&B
Agreement, except for the payment of money when due, cannot be performed due to
an act of God, strike, labor dispute, fire, war, civil disturbances, explosion,
breakage or accident to machinery or pipelines, quarantine, epidemic, severe
storms, act or interference of governmental authorities including failure to
grant a permit, or by any similar cause reasonably beyond the control of the
non-performing party: (i) the non-performing party must use reasonable efforts
to remove the cause of the interference, (ii) during the continuance of the
interference, the obligation of the non-performing party is suspended to the
extent that the interference prohibits such performance, and (iii) any directly
corresponding obligation of the other party is also suspended. Scheduled
equipment outages and normal maintenance are not considered force majeure
events under the Nicor T&B Agreement.
If we incur an unauthorized overrun of our contract quantities due to a non-
economic force majeure event, we must reimburse Nicor for an amount equal to
the higher of (i) the actual interstate pipeline penalties incurred by Nicor
that were directly related to our unauthorized overrun of contract quantities
or (ii) a volumetric charge of $0.48 per MMBtu during the Summer months or
$0.55 per MMBtu during the non-Summer months multiplied by the quantity of the
unauthorized overrun.
Buy-Out of Nicor. If less costly supply options become available, we may,
upon one years' notice, buy out Nicor and terminate the Nicor T&B Agreement on
September 30th of 2002, 2003 or 2004 by paying Nicor a lump sum "Buy-Out
Amount." The Buy-Out Amount is $4,112,000 for 2002, $2,789,000 for 2003 and
$1,420,000 for 2004, subject to change depending on the unamortized fixed cost
of other global point and operational balancing agreements in place at the time
of termination. In the event of a buy-out, we may purchase from Nicor on-site
meters and related equipment located or to be located at the inlet phalanges of
our Facility.
Assignment. Except as provided below, neither party may assign, pledge or
otherwise transfer its rights under the Nicor T&B Agreement without the prior
written consent of the other party, which consent cannot be unreasonably
withheld. Nicor may assign the Nicor T&B Agreement without our consent to any
successor to or transferee of the direct or indirect ownership or operation of
all or part of the pipeline system to which our Facility is connected that can
fully perform Nicor's obligations under the Nicor T&B Agreement, provided that
the proposed assignee is creditworthy. Upon any such assignment, Nicor will be
released from its obligations under the Nicor T&B Agreement. As long as we have
not materially defaulted under the Nicor T&B Agreement, we may assign the Nicor
T&B Agreement without Nicor's consent to any party succeeding in ownership to
the units, provided that the proposed assignee is creditworthy. Upon any such
assignment, we will be released from our obligations under the Nicor T&B
Agreement. Nicor has also consented to the assignment of the Nicor T&B
Agreement or a security interest in the Nicor T&B Agreement to our lenders,
provided the assignment does not adversely affect Nicor's rights under the
Nicor T&B Agreement.
Governing Law. The Nicor T&B Agreement is governed by the laws of the State
of Illinois without regard to principles of conflicts of laws.
EPC CONTRACTS
Construction of our Facility was performed by GE under five separate
engineering, design, procurement and construction contracts ("EPC Contracts")
covering the various units.
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Warranties. The warranty remedy period under the EPC Contracts for Units 5-
9 and the GE supplied materials and equipment associated with each unit lasts
until the earlier to occur of (i) 150 starts of a unit (ii) 1,250 fired hours
after Provisional Acceptance (described below) of a unit or (iii) 24 months
after Provisional Acceptance of a unit. The comparable warranty periods for
Units 1-4 have expired.
Under the EPC Contracts for Units 5-9, GE warrants that:
. work and equipment supplied by GE under the EPC Contracts ("Work") will
be performed to high professional standards;
. Work will conform to the requirements of the EPC Contracts and
applicable permits, will be new and will be free from defects in
materials and workmanship and will be designed and fit for generating,
transmitting and delivering electricity to the Switchyard when operated
in accordance with GE's specific operating instructions and, in the
absence thereof, in accordance with prudent utility practice;
. engineering work will have been performed in accordance with sound
engineering practice, prudent utility practice and applicable laws and
permits;
. control systems will be year 2000 compatible; and
. title to all services and GE supplied materials and equipment will be
free and clear of all liens.
GE's warranty does not include (i) normal wear and tear of equipment and
materials, (ii) defects that arise as a result of improper operation and/or
maintenance, or (iii) our modifications of GE supplied materials and equipment
unless made under GE specifications and with GE's approval.
Warranty Work. With respect to Units 5-9, GE must repair, replace or
reperform Work that fails to conform to its warranties at its own expense.
Warranty work is warranted for one year after its performance but in no event
beyond three years after Provisional Acceptance. GE must commence warranty
work within 24 hours for an emergency condition (i.e., when continued
operation of our Facility at rated output would result in severe mechanical or
electrical damage to the units; danger to personnel; damage to property;
and/or a material loss or potential material loss of our net revenues
resulting from curtailed operation, excess fuel consumption, or inability to
operate that can be remedied within 48 hours). For non-emergencies, GE must
commence work within ten days of notice from us. If GE fails to comply with
its warranty obligations, we may have the necessary work performed by others
at GE's expense.
Provisional Acceptance. Under Units 5-9, Provisional Acceptance under the
EPC Contracts occurs after the following:
. The unit has had 5 consecutive successful starts under various initial
conditions;
. Changes in load occur at a rate that is within operating and maintenance
characteristics;
. The unit's overspeed protection circuits have been proven on two
occasions by a tripping of the unit;
. The unit will be able to accept a load rejection at or near full load
without resulting in an overspeed trip;
. The unit performs within specifications at minimum (60%) load;
. The unit's emissions are no greater than 105% of the emission guarantee;
. The fire protection system has demonstrated proper performance;
. The unit's output is capable of at least 95% of the guaranteed output;
and
. The unit's heat rate is no greater than 5% above the guaranteed heat
rate.
Final Acceptance. Under Units 5-9, Final acceptance of the Work is
conditioned upon the following:
. Work is 100% complete and a certificate to such effect has been provided
by GE;
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. Units meet 100% of the air emission and noise level guarantees;
. Performance guarantees have been met as demonstrated by performance
testing, and/or all liquidated damages associated with failure to meet
performance tests have been paid by GE;
. GE has delivered a final lien waiver; and
. No GE event of default exists.
Final acceptance for Units 1-4 occurred in 1999. Provisional acceptance of
Units 5, 6 and 9 occurred in May 2001 and of Units 7 and 8 in June and July
2001.
Assignment. Under the EPC Contracts for Units 1-4, we may, without GE's
consent, assign any or all of our right, title or interest under the contracts
to a lender as security in connection with obtaining or arranging financing for
the work under the contract, and any such right, title or interest may in turn
be assigned by the lender in connection with the exercise of remedies under
such financing. At our or a lender's request, GE has agreed to execute and
deliver from time to time consents to assignment that are typical in project
finance transactions. Except as permitted above, neither party may assign any
of its right, title or interest under the contract without the prior written
consent of the other party.
Under the EPC Contracts for Units 5-6, 7-8, and 9, each party, without
consent, may assign all or a portion of its rights and obligations under the
contract to an affiliate, and such affiliate may assign the contract back to
the assigning party without consent provided that, in either case, the
assigning party provides a guarantee of the assignee's performance satisfactory
to the non-assigning party. We may, without GE's consent, assign all or part of
our rights and obligations under the contract to a lender for the purpose of
financing or refinancing the purchase or operation of the units. GE has agreed
to enter consents to assignment with such lender that acknowledge the creation
of a security interest in our rights and that acknowledge that upon a breach of
the contract or any loan document or our insolvency, the lender will have a
reasonable cure period to cure the breach and, upon the payment of all
outstanding amounts due and payable to GE, be entitled to all of the rights and
be subject to all of the obligations under the contract. GE agrees to provide,
at our expense, information reasonably requested by a lender in connection with
a financing and to cooperate with us to satisfy the requirements of our
financing documents. Except as provided above, neither party may assign any of
its rights, titles, or interests under the contract without the prior written
consent of the other party.
Under an assignment of warranties agreement among GE, ComEd and us, we
irrevocably assigned to ComEd the warranties applicable to the Switchyard.
Turbine Procurement Agreements. Our wholly-owned subsidiaries, Elwood II
Holdings and Elwood III Holdings have each entered into two Combustion Turbine
Power Plant and Balance of Plant Equipment Procurement Agreements (the "Turbine
Procurement Agreements") with GE covering, respectively, Unit 5, Unit 6, Units
7 and 8, and Unit 9. The warranties provided under these agreements are
substantially similar to those provided by GE under the EPC Contracts.
EQUIPMENT SALE AGREEMENTS
We are party to an equipment sales agreement with Elwood II Holdings for
Units 5 and 6 and two equipment sale agreements with Elwood III Holdings for
Units 7-9 (collectively, the Equipment Sales Agreements), under which we
purchased Units 5-9 and related equipment from Elwood II Holdings and Elwood
III Holdings for use at our Facility. Both Elwood II Holdings and Elwood III
Holdings are wholly-owned subsidiaries of ours. Under the Equipment Sales
Agreements, we pay for the units and related equipment in monthly installments
through June 2011. We pay interest on the unpaid principal at an annual rate of
7.75%. At the completion of the payment period, we will pay a balloon payment
equal to 50% of the cost of each of the turbines and related equipment.
Ownership and title in the units and related equipment remain with Elwood II
Holdings and Elwood III Holdings, as applicable, until we make the final
balloon payment. Elwood
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II Holdings and Elwood III Holdings have assigned to us all warranties, rights
to liquidated damages and other rights to services that they obtained from GE
for the units and related equipment. Neither Elwood II Holdings nor Elwood III
Holdings may incur any indebtedness other than currently existing intercompany
indebtedness owed to us or engage in any other business. Any funds paid to them
under the equipment sales agreements will be repaid or distributed to us, net
of sales tax obligations owed by them.
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INTERCONNECTION AGREEMENTS
We have entered into three Interconnection Agreements (each, an "IA") with
ComEd that provide for the construction, ownership, operation and maintenance
of the facilities (the "Interconnection Facilities") necessary to interconnect
Units 1-4, 5-6, and 7-9 of our Facility to the ComEd transmission system (the
"ComEd System").
Term. The term of each IA continues until our cancellation, abandonment or
termination of the development, construction or operation of our Facility or
our Interconnection Facilities.
Interconnection Facilities. We built a 345 kV switchyard ("Switchyard") and
installed transformers, breakers, and auxiliary transformers. The Switchyard
was conveyed to ComEd after its completion. ComEd has agreed not to allow third
parties to use the Switchyard if such use would adversely affect ComEd's
ability to accept the net electric output of our Facility.
At our expense, ComEd is responsible for the construction, operation and
maintenance of the transmission line connecting the Switchyard to the ComEd
System and the related support structures (the "ComEd Interconnection
Facilities").
Interconnection and Transmission. ComEd interconnects our Facility with the
ComEd System at the interconnection point. Transmission service beyond the
interconnection point is arranged separately by us or our customers. (Under our
existing power sales agreements, all such arrangements are the responsibility
of our customers.)
Interconnection Costs. We are responsible for the cost of operation and
maintenance of our Interconnection Facilities (i.e., those on our side of the
interconnection point). We reimburse ComEd on a monthly basis for all
Interconnection Costs incurred by ComEd, which include direct or indirect costs
reasonably incurred for the design, engineering, construction, testing,
ownership, operation and maintenance of the ComEd Interconnection Facilities.
Facility Control and Dispatch. At all times that our Facility is generating
energy, we must have operators on duty either on-site or at a remote operation
location. If one of our units is synchronized to the ComEd System during an
emergency, ComEd may require us to raise or lower the generating level of the
unit during the emergency. ComEd's right to dispatch our units during an
emergency is subject to the design limits of the units and applicable laws and
regulations, including air permits. During an emergency, ComEd may not unduly
discriminate between the dispatch of our units and the dispatch of other
generating facilities interconnected to the ComEd System including those owned
by ComEd or its affiliates. ComEd compensates us for the redispatch of our
units during an emergency under our emergency dispatch tariffs filed with FERC,
or if none, according to rates agreed to by us and ComEd. If we have a customer
for the electricity resulting from an increase in the generating level of a
unit during an emergency, ComEd has no right to such electricity.
Voltage Schedule. We must operate the units, within their capabilities,
according to the voltage schedule provided by ComEd. The voltage schedule
provides for high and low ComEd system load periods that specify maximum and
minimum voltage levels as measured on the high side of our transformer. Except
during an emergency, we do not have to adjust our MW output levels to provide
voltage support to the ComEd system.
Disconnection of the Facility. ComEd has the right to disconnect our
Facility if, in its sole judgment, (i) operating equipment interferes or could
interfere with ComEd's service to its other customers or with the operation of
ComEd's system; (ii) the energy we deliver to the interconnection point fails
to meet the requirements of the IA; (iii) our control and protective equipment
causes or contributes to a hazardous condition or an emergency; (iv)
disconnection is necessary to verify the proper operation of the protective
equipment; (v) continued parallel operation is hazardous to, or could have an
adverse effect on, us, the ComEd System or the general public; (vi)
disconnection is necessary to provide ComEd personnel clearance for dead or
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live line maintenance; or (vii) an emergency has occurred. ComEd has agreed to
use commercially reasonable efforts to schedule inspection and maintenance
related disconnections to avoid disrupting our operation.
Defaults and Remedies. Any of the following constitutes an event of default
under an IA: (i) failure to make a payment which continues for 15 days after
receipt of written notice; (ii) material failure to comply with or perform any
covenant or obligation under the IA or the failure of a representation or
warranty in the IA to be true and correct in all material respects which is not
cured within 30 days of written notice; (iii) appointment by a court of a
receiver, liquidator or trustee of a party or its property or the entry of a
decree adjudging a party to be bankrupt which is not cured within 60 days; or
(iv) the filing of a voluntary petition in bankruptcy by a party. If the non-
defaulting party reasonably determines with respect to (ii) that the breach
cannot be cured in 30 days and the defaulting has diligently begun to cure the
breach, the cure period may be extended for a mutually agreeable period not to
exceed 60 days. If with respect to (ii), ComEd has exercised its right to
disconnect our Facility due to our breach and our breach may adversely affect
the ComEd System, ComEd's Interconnection Facilities or ComEd's ability to
maintain service to its customers, no such additional cure period will be
applicable.
If an event of default occurs and continues beyond the applicable cure
period, the non-defaulting party may terminate the IA, or if the non-defaulting
party is ComEd, ComEd may disconnect our Facility from the ComEd System. In
addition to the rights and remedies under the IA, the non-defaulting party may
exercise any right or remedy it may have at law or in equity.
Limitation on Damages and Indemnification. A party's liability for damages
under the IA is limited to direct actual damages. Neither party has any
liability to the other for any special, indirect, punitive, exemplary or
consequential damages, including lost profits.
We have agreed to indemnify ComEd for losses resulting from our (i) breach
of any of our representations or warranties or failure to perform any of our
obligations under the IA; and (ii) our or our contractors' negligence or
willful misconduct as to the design, installation, construction, ownership,
operation, repair, relocation, replacement, removal or maintenance of, or the
failure of, our Facility, our Interconnection Facilities, or the Switchyard
before its conveyance to ComEd. With regard to Units 5-9, we have also agreed
to indemnify ComEd for losses resulting from liens filed on ComEd's property by
our contractors relating to work performed on our behalf on ComEd's property
under the IA.
ComEd has agreed to indemnify us for losses resulting from (i) ComEd's
breach of any of its representations or warranties or failure to perform any of
its obligations under the IA; and (ii) bodily injury to or death of, or damage
to property of, persons resulting from the negligence or willful misconduct of
ComEd as to the design, installation, construction, ownership, operation,
repair, relocation, replacement, removal or maintenance of, or the failure of,
any of ComEd's Interconnection Facilities. With regard to Units 5-9, ComEd has
also agreed to indemnify us for losses resulting from liens filed on our
property relating to work performed on ComEd's behalf on our property under the
IA.
Each party has agreed to indemnify the other for environmental liabilities
resulting from the violation of environmental laws or the use, release or
cleanup of hazardous materials on its property that affects the other party or
its property or causes personal injury.
Force Majeure. Force majeure under the IAs means any unforeseeable cause
(including, but not limited to, acts of God, strikes, storms, floods, fire,
lightning and civil disturbances) beyond the reasonable control of and without
the fault or negligence of the party claiming force majeure. If a force majeure
event occurs, the parties are excused from performing their obligations (except
for obligations to make payments) under the relevant IA if the non-performing
party gives the other party written notice of the event in seven days of its
occurrence, the suspension of performance is not greater than required by the
force majeure event, the non-performing party uses all reasonable efforts to
remedy its inability to perform, and the non-performing party notifies the
other party when it is able to resume performance.
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Dispute Resolution. The parties have agreed to resolve disputes arising
under the IAs according to a three-step process, which begins with executive
level discussions, proceeds to mediation and finally to binding arbitration.
Either party, however, may petition the FERC to resolve any arbitrable dispute
over which the FERC has jurisdiction.
Assignments. ComEd may assign or transfer the IAs or any of its rights or
obligations under the IAs without our consent to (i) an independent system
operator or (ii) any successor to or transferee of the direct or indirect
ownership or operation of all or part of the ComEd System to which our Facility
is connected. ComEd will provide us with copies of initial FERC or Illinois
filings seeking approval of the sale or transfer of its system.
So long as we are not in default, we may assign or transfer the IAs without
ComEd's consent to any assignee succeeding to the ownership of our Facility
which has a credit rating for its unsecured senior debt of not less than "BBB"
by S&P and at least "Baa2" by Moody's.
ComEd has consented to our collateral assignment of the IA or the grant of
liens and security interests in our Facility and our rights under the IAs to
lenders for the purpose of financing or refinancing our Facility.
Except for the assignments discussed above, neither party may assign, pledge
or otherwise transfer the IAs or any right or obligation under the IAs without
first obtaining the written consent the other party, which shall not be
unreasonably withheld.
ELECTRIC SERVICES CONTRACTS
We are party to two electric services contracts with ComEd (the "Electric
Services Contracts") establishing the terms and conditions under which ComEd
will provide start-up and auxiliary power to our Facility and the terms and
conditions under which we will purchase that power. Under the Electric Services
Contracts, ComEd will supply all start up power and auxiliary power required by
our Facility for power, lighting, ventilation, air conditioning, heating and
miscellaneous purposes other than self-generated energy that we use for the
same purposes. The terms of the Electric Services Contracts run through April
30, 2002 and September 30, 2002, respectively. Our strategy has been to enter
into these agreements on an annual basis until we have more complete experience
with the requirements of our units in operation. We expect to enter into new
agreements with ComEd when the current agreements expire.
COMMON FACILITIES AGREEMENT
We are party to a common facilities agreement with PERC, as assignee of PGL
(the "Facilities Agreement"), governing the shared use by PERC and us of
certain facilities on property owned by PERC and the sharing of costs and
expenses with respect to such shared use.
Term. The term of the Facilities Agreement continues until December 31,
2028.
Summary of Basic Services. Subject to the terms and conditions of the
Facilities Agreement, PERC will use best efforts to provide the following
services to our Facility:
. supply potable and non-potable service water (i.e. untreated well water)
to our service water systems meeting the quality, quantity and other
specifications in the Facilities Agreement;
. supply water meeting the quality, quantity and other specifications in
the Facilities Agreement for the operation of our fire protection
system;
. accept and dispose of storm water collected in our storm water discharge
system for Units 1-4 that meets the specifications set forth in the
Facilities Agreement;
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. accept and dispose of blowdown water from Units 1-4 (i.e. water
discharged from our units' inlet air coolers) that meets the
specifications set forth in the Facilities Agreement and obtain and
maintain all permits necessary for the disposal of our blowdown water;
PERC may terminate any of the foregoing services on twelve months' notice
in the case of service water supply and 18 months notice in all other
cases. In addition, if our discharges of storm water or blowdown water do
not conform to the specifications of the Facilities Agreement, PERC may
discontinue service until it is reasonably satisfied that the non-
conforming discharge has ceased.
. grant easements to us for the construction, use and maintenance of water
lines and a retention pond if the water supply or disposal services
described above are terminated;
. manage and dispose of all solid, special and hazardous waste and used
oil generated at our Facility in compliance with all laws (at our sole
cost and expense);
. comply with all applicable notification requirements of the Emergency
Planning and Community Right-to-Know Act if the quantity of extremely
hazardous substances or chemicals on PERC's land and our Facility site
exceeds the threshold reporting requirement;
. permit us to operate our Facility under an existing operating permit
issued under Title V of the Clean Air Act until the underlying land is
transferred under the Ground Lease; provided, however, that we comply
with the air permit requirements at our sole cost and expense;
. provide janitorial services to our Facility on an as-needed basis (at an
hourly charge);
. provide security services to our Facility (PERC may discontinue
janitorial and security services on 45 days' notice);
. maintain and monitor our underground fuel gas piping; and
. manage our response to requests to locate certain of our underground
structures within the Patterson Road utility easements.
In addition to the costs for services indicated above, we are responsible
for paying all sales, use or other transfer taxes related to these services.
The fees for the services are adjusted annually for inflation. If, for any
reason, PERC is required to expand its existing facilities to provide the
services to us, we must cooperate with PERC to develop a revised cost-sharing
plan or elect not to have such services provided by PERC.
At current service levels, we expect to make payments of approximately
$100,000 annually under the Facilities Agreement to PERC, plus any incremental
charges for janitorial and snow removal services.
Defaults; Termination. If PERC defaults in providing its services under the
Facilities Agreement, we may, in addition to other remedies, assume operation
and control of the facilities and equipment of PERC (excluding any facilities
and equipment used exclusively in the purchase, storage, distribution, sale and
transportation of natural gas) necessary for the continuation of the services
that PERC was supposed to provide under the Facilities Agreement. We may deduct
any expenses we incur during the exercise of our step-in rights from payments
due to PERC under the Facilities Agreement.
PERC has the right to terminate the Facilities Agreement if we fail to make
payments or fail to perform material obligations and do not cure our breach
within specified periods after notice is given. So long as the bonds are
outstanding, PERC may not exercise its termination rights without providing
notice and an opportunity to cure to the Trustee on behalf of the bondholders.
We may terminate the Facilities Agreement or any specific services on 90
days' notice.
Force Majeure. Each party is excused from performance under the Facilities
Agreement (except for payment obligations) to the extent that its failure of,
or delay in, performance is due to a force majeure event.
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For purposes of the Facilities Agreement, force majeure events include any
cause beyond the reasonable control of, and not due to the fault or negligence
of, the affected party, and which could not have been avoided by due diligence
and use of reasonable efforts, including, but not limited to, drought, flood,
earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance,
sabotage, explosions, public utility outages, subsurface aquifer depletion,
failure of equipment or of suppliers, contractors or shippers to furnish labor,
equipment, goods or services and strikes or labor disputes.
Indemnification. Unless due to the intentional misconduct or gross
negligence of PERC, we must indemnify PERC, its directors, officers, employees
and agents from any and all liabilities arising from (i) any personal injury or
property damage related to our use of PERC's land or its facility (i.e. the
McDowell Energy Center) or the operation of our Facility, (ii) our possession,
operation, use or misuse of our Facility, (iii) the imposition or enforcement
of any liens on PERC's property resulting from our performance under the
Facilities Agreement, (iv) the discharge of hazardous substances by us or our
employees, agents, contractors and subtenants, or the disposal, release,
threatened release, discharge or generation of hazardous substances on PERC's
property (including our Facility site) by us or our related parties, or (v) our
failure to comply with any environmental laws, permits or licenses relating to
our Facility.
Under the Facilities Agreement, PERC must indemnify us, our directors,
officers, employees and agents from any claims arising from (i) any pre-
existing hazardous substances on PERC's land (including our Facility site),
(ii) any violation by PERC or its employees and agents of any environmental
laws, licenses or permits unless caused by us or our representatives, (iii) the
discharge of hazardous substances in or from the McDowell Energy Center by PERC
or its representatives, or the disposal, release, threatened release, discharge
or generation of hazardous materials at the McDowell Energy Center by PERC or
its representatives, or (iv) the imposition or enforcement of any liens on our
Facility or on PERC's property near our Facility resulting from its performance
under the Facilities Agreement.
In no event will either party be liable to the other for lost revenues, lost
profits, or punitive, incidental or consequential damages of any nature.
OPERATION AND MAINTENANCE AGREEMENT
We have entered into an Operation and Maintenance Agreement (the "O&M
Agreement") with DELSCO that provides for the operation, maintenance and
management of our Facility.
Term. The agreement will remain in effect as long as the bonds are
outstanding, subject to earlier termination in accordance with its terms.
Scope of Services. The scope of the services DELSCO will provide includes:
. operating and maintaining our Facility and hiring and supplying all
labor and professional, supervisory and managerial personnel to perform
the services;
. operating our Facility according to the administrative procedures manual
prepared by DELSCO, which includes procedures for organization and
reporting; correspondence and review; procurement and contracting; and
accounting, bookkeeping and record-keeping;
. maintaining operating logs, records and reports documenting the
operation and maintenance of the Facility;
. developing the annual budget and operating plan, which must set forth
anticipated operations, repairs and capital improvement, routine
maintenance and overhaul schedules, procurement, staffing, personnel and
labor activities, administrative activities and other work to be
undertaken by DELSCO;
. monitoring and recording all operating data and information regarding
performance of the Facility that we have to report to any government
agency or other person under any applicable laws and that we reasonably
request;
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. furnishing monthly progress and reimbursable costs reports and annual
reports detailing the activities of the Facility;
. obtaining from sellers of equipment, materials or services (other than
services provided by DELSCO to us) warranties against defects in
materials and workmanship;
. providing notice of any event of default under third party agreements;
any litigation concerning the Facility; any refusal to grant, renew or
extend any license, permit, warranty, approval authorization or consent
relating to our Facility; and any dispute with any governmental
authority concerning our Facility; and
. communicating certain events to us according to the established
communication protocols.
If an unplanned outage of the Facility occurs or DELSCO believes one will
occur, and DELSCO has tried unsuccessfully to contact us regarding the outage,
DELSCO may take action to prevent or mitigate the outage to minimize the costs.
DELSCO will continue to attempt to notify us and may expend no more than
$500,000 for remedial action.
Limitation on Authority. DELSCO may not do any of the following without our
prior written approval or approval in the annual budget:
. sell, lease, pledge, mortgage, convey, or make any license, exchange or
other transfer or disposition of any of our property or assets;
. enter a contract on our behalf or in our name or that binds us or
prohibits or restricts DELSCO's right to assign the contract to us at
any time;
. make any expenditures, which would be a reimbursable cost for us, not in
conformity with the annual budget, except for certain emergency actions
described above under "--Scope of Services";
. take any action that materially varies from the annual operating plan,
annual budget or any material agreements relating to the Facility;
. settle, compromise or assign any claim, suit, debt, demand or judgement
against or due by us or DELSCO, the cost of which, in the case of
DELSCO, would be a reimbursable cost under the O&M Agreement, or submit
any such claim, dispute or controversy to arbitration or judicial
process;
. create, incur or assume any lien upon the Facility;
. engage in any other transaction not expressly authorized by the O&M
Agreement or that violates applicable federal, state or local laws; or
. enter any agreements to do any of the above.
Compensation. We pay DELSCO a fee of $650,000 annually under the O&M
Agreement. The annual fee is adjusted each year to reflect changes in the GDP
Implicit Price Deflator.
We also reimburse DELSCO for, among other things, labor costs; spare and
replacement parts; materials, tools and equipment; major equipment overhauls;
taxes (excluding income); and insurance costs for activities performed on our
behalf and for performance of the contracted services by DELSCO's employees.
Budgeting and Reports. At least ninety days before the end of each calendar
year, DELSCO must prepare and submit a proposed annual budget for the following
year, which includes a separate operating budget and capital budget and sets
forth anticipated operations, repairs and capital improvements, routine
maintenance and overhaul schedules, procurement, staffing, personnel and labor
activities, administrative activities and other work to be performed by DELSCO,
together with an itemized estimate of reimbursable costs to be incurred in the
performance of these activities. The proposed budget must be accompanied by a
proposed annual operating plan setting forth the underlying assumptions and
implementation plans in
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connection with the proposed annual budget. After reviewing the proposed annual
budget from DELSCO, DELSCO and we will meet to discuss and agree on a final
annual budget and plan. DELSCO must promptly notify us of any significant
deviations or discrepancies from the projections contained in the annual budget
or operating plan.
In addition to the annual budget and operating plan, the parties undertake a
similar process to develop a five-year budget for the operation and maintenance
of the Facility. The five-year budget is used only for planning and comparison
purposes and does not constrain DELSCO in its actions or expenditures.
DELSCO must also provide us with the following reports or notices:
. monthly progress reports covering all of the Facility activities for
such month relating to the operation and maintenance of the Facility
(including information regarding amount of electric energy generated,
hours of operation, fuel consumed, heat rate, availability, outages,
accidents and emergencies), capital improvements, labor relations and
other significant matters;
. monthly statements setting forth all reimbursable costs paid or incurred
in such month by DELSCO and stating whether or not the Facility
operations have conformed to the applicable annual budget and operating
plan during such month and if not, the extent and reasons for such
deviation and any remedial action therefor;
. annual reports of the Facility activities in detail comparable to the
monthly progress reports, together with a comparison of such activities
with the goals set forth in the annual budget and operating plan;
. notices of any event of default under the project agreements; any
litigation claims (threatened or filed); any refusal or threatened
refusal to grant, renew or extend any license, permit, warranty,
approval, authorization or consent relating to the Facility or DELSCO's
services; and any dispute with a governmental authority relating to the
Facility or DELSCO's services; and
. notices of any other material information concerning new or significant
aspects of the Facility's activities.
Obligations of the Company. We have agreed to provide DELSCO with all vendor
manuals, spare parts lists, data books and drawings relating to the Facility
which are provided to us under any project agreement or by any contractor. In
addition, we are responsible for (i) the cost of all major equipment teardowns
and overhauls and all capital improvements to the Facility; provided, however,
that if such equipment teardowns, overhauls and capital improvements have been
incorporated in the applicable annual budget, then DELSCO must schedule,
coordinate, contract and oversee the performance of such activities, and (ii)
reviewing and approving each annual budget and annual facility operating plan.
Default and Termination. We may terminate the O&M Agreement:
. immediately upon DELSCO's bankruptcy or the occurrence of a force
majeure event (see "--Force Majeure" below) which is not cured within
120 days of its initial occurrence;
. with ten days notice if (i) DELSCO violates any laws applicable to the
services or the Facility, and the violation may have a material adverse
effect on the operation or maintenance of the Facility and is not cured
in 30 days (or up to 90 days if not curable within 30 days) or (ii)
DELSCO commits a material breach of its performance of the services
which is not cured in 30 days (or up to 90 days if not curable within 30
days);
. with two months notice upon the occurrence of (i) a sale or transfer of
our rights in the Facility or a sale or transfer of all or substantially
all of our assets or membership interests in our company, (ii) DELSCO's
reimbursable costs exceeding 110% of the annual budget for any two
consecutive contract years, provided, however, that such overruns are
the fault of, or due to the negligent operation of the Facility by,
DELSCO, (iii) our determination that, for any reason, we no longer
intend to continue to
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operate the Facility, or (iv) our determination, at any time after the
renewal date, that we desire to terminate the O&M Agreement; and
. upon 90 days notice to DELSCO for any reason at any time.
Depending on which of the above termination methods we exercise, we may be
required to (i) compensate DELSCO for all reimbursable costs incurred up to and
including the termination date, (ii) pay DELSCO all unpaid annual operating
fees up to and including the termination date, and/or (iii) pay a termination
payment for DELSCO's demobilization and cancellation costs, including
relocation and severance costs of DELSCO's employees.
DELSCO may terminate the O&M Agreement if we become bankrupt or if we fail
to perform in a timely manner any material obligation we are required to
perform, and our failure is not cured in 30 days.
Indemnification. We and DELSCO each agree to indemnify the other against all
losses arising out of our respective negligence, fraud or willful misconduct in
connection with the O&M Agreement and our obligations under the O&M Agreement.
We must indemnify DELSCO against environmental claims relating to the
existence, use, storage and removal of hazardous materials at the units and/or
adjacent areas that arise before the provisional acceptance date, except to the
extent such claims arise from DELSCO's grossly negligent or intentional acts.
DELSCO must indemnify us against environmental claims which arise after the
provisional acceptance date and are due to the grossly negligent or intentional
acts of DELSCO.
Force Majeure. Under the O&M Agreement, a "force majeure event" is an event,
condition or circumstance beyond the reasonable control of, and not due to the
fault or negligence of, the party affected, which prevents the performance by
such affected party of its obligations under the O&M Agreement, including, as
to DELSCO, a shortage of fuel of appropriate quality or quantity, and as to
either party, explosion or fire, flood, earthquake, acts of God, strike or
labor dispute, war, actions or failures to act by governmental entities,
failures to obtain governmental permits or approvals (despite timely
application therefor and due diligence) and changes in laws, rules,
regulations, orders or ordinances affecting operation of the Facility not
pending on the effective date of the O&M Agreement. In order for a force
majeure event to occur and continue, (i) the affected party must give the other
party written notice of the event as soon as is reasonably practicable, (ii)
the suspension of performance may be of no greater scope and of no longer
duration than is reasonably required for such event, (iii) no obligations
arising before such event may be excused as a result of such event, and (iv)
the affected party must use all reasonable efforts to prevent, overcome and/or
mitigate the effects of such event.
Limitation of Liability. We and DELSCO each agree not to assert any claims
against the other for consequential, incidental, indirect or special damages
arising from the performance or non-performance of the other party or any third
party engaged by such other party under the O&M Agreement. DELSCO's aggregate
liability to us in any year is limited to its annual operating fee under the
O&M Agreement plus certain indemnification responsibilities under the O&M
Agreement.
Dispute Resolution. Disputes which arise under the O&M Agreement will be
referred to the responsible senior management of each party for resolution. If
referral does not resolve the dispute, the parties will submit the dispute to
binding arbitration.
Assignment. In general, neither we nor DELSCO may assign our rights or
obligations under the O&M Agreement without the prior written consent of the
other party, except that we may assign the O&M Agreement without consent to our
successor, to a person acquiring all or substantially all of the units, to a
wholly-owned subsidiary of ours or to a lender or any purchaser of the Facility
upon the exercise of remedies by a lender. DELSCO may assign the O&M Agreement
to any of its affiliates.
Governing Law. The O&M Agreement is governed by and construed in accordance
with the laws of the State of Illinois, without regard to its conflicts of law
rules.
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Administrative Services Agreements. DELSCO has also contracted to provide
administrative services to our subsidiaries Elwood II Holdings and Elwood III
Holdings for an additional fee of $1,000 each per year.
ANNEXATION AGREEMENTS
We have entered into three Annexation Agreements with the Village of Elwood,
Illinois (the "Village") that provide for the annexation by the Village of our
property and adjoining property owned by our affiliates. PGL, which then owned
the property, entered into an Annexation Agreement with the Village for the
property covered by the Ground Lease under similar terms as those below for an
I-3 Heavy Industrial District.
Rezoning. The Village adopted amendments to its zoning ordinance which
created an I-3 Heavy Industrial District covering the land on which our
Facility is located.
Applicable Municipal Ordinances. All Village ordinances, regulations and
codes will apply to our property and its development for 20 years. Any
amendments, repeals or additional regulations which relate to our zoning
classifications will not be applied to the development or use of our property
except on the mutual consent of the parties. Any ordinances under consideration
respecting storm water drainage and retention, stream and wetland protection,
soil erosion and sediment control, flood way, flood plain and flood fringe
regulation will apply only in the following manner: (i) the proposed ordinances
will not apply to the use of a simple cycle power plant; (ii) any proposed
stormwater management ordinances will not contain any features which are
inconsistent with the Village's acknowledgement that no part of our property is
located in or near the ordinary high water mark of a stream, lake, pond or
wetland; and (iii) any proposed ordinances must be no more restrictive than
those recommended by the Northeastern Illinois Planning Commission, and must
not restrict the construction, operation, maintenance or expansion of our
property in a manner more restrictive than other property zoned I-3 in the
Village.
Roadway and Easement Dedications and Improvements. We dedicated by quit
claim to the Village portions of the right of way for Brandon Road and
Patterson Road and a 20 foot wide non-exclusive underground utility easement.
If the existing condition of Patterson Road, Noel Road or Brandon Road is
damaged by our construction activity, we will repair the roads, at our expense
and with notice from the Village, to the condition which existed before our
construction activity.
If the Village decides to upgrade the existing condition of Noel Road and
Brandon Road, it may do so only on the following conditions: (i) an upgrade may
consist of re-surfacing or reconstruction, but may not include construction or
installation of sidewalks, street lighting or utilities, any work respecting
Patterson Road, which will remain a gravel road, and any maintenance or repair
costs; (ii) before any upgrade, the Village will convene a meeting with us to
discuss the upgrade; (iii) we will contribute $500,000 towards the cost of the
upgrade, in ten equal installments, beginning on December 1, 2003; each
installment will be placed in a special fund, and costs incurred by the Village
for the upgrade will be paid directly from the fund to Village contractors; if
the Village has not disbursed all amounts from the fund on or before December
1, 2013 for the upgrade, the Village must, on or before December 31, 2013,
disburse all remaining amounts in the fund to us; (iv) our obligation will not
exceed $500,000; and (v) the Village will not permit our property to be subject
to any special assessment taxation for any purpose.
Annexation and Other Fees. The Village agrees that it will not increase or
establish any annexation fees, building permit fees, occupancy permit fees,
subdivision fees, tax on or connection fees, zoning, variance or special use
permit fees or other fees or charges required to be paid in connection with the
annexation, zoning and development of our property other than the fees existing
as of the date of the Agreement unless we consent by written waiver. Fees and
charges may be increased for inflation.
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Stop Orders. The Village will not issue stop orders on buildings or other
developments unless in writing setting forth the section of the Village
ordinance violated, and we may correct the violation.
POINT OF SALE SALES-TAX SHARING AGREEMENTS
Elwood II Holdings and Elwood III Holdings (together, "Holdings") have each
entered into a Point of Sale Sales-Tax Sharing Agreement (each, a "Sharing
Agreement" and together, the "Sharing Agreements") with the Village.
Sales Tax Returns and Monthly Distribution Disbursements. The Sharing
Agreements acknowledge that expansion of Holdings' activities in the Village
will generate new revenue for the Village, and the Village will enjoy an
increase in the amount of monthly distributions it receives from the State of
Illinois' Local Government Tax Fund and Home Rule Retailer's Occupation Tax
Fund. As an incentive for Holdings to expand its activities in the Village, the
Village has agreed to share the benefits realized by the Village as a result of
Holdings' sales and other activities in the Village. The portion of the monthly
distributions from the Home Rule Retailer's Occupation Tax Fund (the "Monthly
Distributions") that are attributable to Holdings' sales in the Village will be
shared by the Village and Holdings as follows: (i) on a monthly basis,
beginning September 1, 2001, Holdings will furnish the Village with copies of
its sales and use tax returns filed with the state and a disbursement request;
(ii) on March 31, June 30, September 30 and December 31, within 15 days after
the Village's receipt of the last of its three previous Monthly Distributions,
the Village will disburse to Holdings an amount equal to that shown on the
disbursement request; and (iii) the portion of the Monthly Distribution that is
disbursed to Holdings is 100% of the amount of the Monthly Distribution
received by the Village from the Home Rule Retailer's Occupation Tax Fund.
Notification of Proposed New Tax. If the Village is considering imposing a
tax on the operations or activities of Holdings or an affiliate of Holdings
(including us), the Village will not take any action without providing Holdings
with at least 45 days prior written notice.
Restriction on Other Agreements. Holdings will not enter any agreement like
the Sharing Agreement with any other Illinois local government unit during the
term of the Sharing Agreements.
Term. The term of each Sharing Agreement extends for 20 years. The rights,
responsibilities and obligations of the parties under each Sharing Agreement
will be terminated if Holdings' occupation tax ceases to apply to sales made by
Holdings.
Dispute Resolution. All disputes arising under the Sharing Agreements will
be resolved by binding arbitration. In lieu of or in addition to arbitration,
the parties have the right to bring an action under the Sharing Agreements for
injunctive relief, specific performance or similar equitable relief.
Assignment. Holdings may assign the Sharing Agreements only with the consent
of the Village, which will not be unreasonably withheld.
GROUND LEASE
The 21.5 acre parcel in the Village of Elwood north of Noel Road and west of
Patterson Road on which Units 1-4 are located is held by us under a Ground
Lease entered into as of September 30, 1998 with PGL as lessor, and
subsequently assigned by PGL to PERC. The property is subject to drainage,
utility and pipeline easements and makes use of common utility facilities,
shared roadways and access and a common waste treatment facility with adjacent
PERC facilities, but is otherwise free of encumbrances, except that PERC has
retained the right to use a 3,000 square foot metal storage building located on
the property.
Term. The term of the Ground Lease is 99 years.
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Rent. Basic rent under the Ground Lease consisted of a single, lump-sum
payment of $283,380, which has been fully paid. In addition, we must pay all
taxes, assessments, water rates and other impositions on the property or upon
PERC's interest under the Ground Lease.
Use; Other Obligations. During the term of the Ground Lease, we may only use
the property for a gas or liquid fuel electric power generation facility. We
must keep the property in a good state of repair; comply with laws and
regulations applicable to the property and any buildings we construct on it;
maintain insurance including the lessor as a named insured; and not permit any
condition to exist that would interfere with the lessor's use of adjacent
properties. Subject to these limitations, we are entitled to construct,
maintain and remove buildings and facilities on the property as we deem
necessary.
Defaults. Defaults under the Ground Lease include our failure to pay rent;
breach of other covenants and failure to cure the breach within specified
periods; our bankruptcy; or abandonment of the property. Upon any such default,
the lessor may elect to declare the Ground Lease term ended and require us to
vacate the premises, subject to the cure rights described under "Assignments
and Mortgages."
Assignments and Mortgages. We may not assign the Ground Lease without the
lessor's consent, but such consent may not be unreasonably withheld. We may,
however, mortgage our leasehold interest to an Institutional Mortgagee (a term
which would include the Trustee), and any assignment upon or in lieu of
foreclosure of such a mortgage would not require the lessor's consent. If we
enter into a leasehold mortgage and provide notice of it to the lessor, we
cannot surrender or modify the Ground Lease without the Institutional
Mortgagee's consent. In addition, if the lessor wishes to terminate the Ground
Lease because of a default by us, it must give notice and an opportunity to
cure the default to the Institutional Mortgagee. Alternatively, at the request
of the Institutional Mortgagee, and upon payment of any amounts due to the
lessor and cure of any non-monetary defaults that can be cured by such party,
the lessor will enter into a new lease with the Institutional Mortgagee or its
nominee.
Indemnities. We have agreed to indemnify the lessor in connection with any
claims asserted against it (unless such claims were due to the intentional
misconduct or gross negligence of the lessor's employees or agents) arising
from our use of the property; accidents on the property; or any breach of the
Ground Lease by us. In addition, we have agreed to indemnify the lessor against
any claims caused by discharges of hazardous materials on or from the property
or breach of any environmental laws by us or our agents or employees. The
lessor has agreed to indemnify us against any claims arising from hazardous
materials existing on or discharged from the property on or before the
commencement of the Ground Lease; any discharges of hazardous materials from
the lessor's retained properties; and any breach of environmental laws by the
lessor or its agents and employees with respect to the lessor's retained
properties.
Purchase of Property. Within 45 days after the issuance to us of an
operating permit by the Illinois Environmental Protection Agency under Title V
of the Clean Air Act, the lessor will sell, and we will purchase, the property
subject to the Ground Lease. Subject to adjustments and prorations, the
purchase price will have been satisfied by the payment of basic rent under the
Ground Lease. We will acquire insurable fee simple title to the property,
subject only to the taxes, easements and conditions described above. An
application for the operating permit has been filed, but given the existing
backlog of similar applications under regulatory review, there is likely to be
a considerable delay before it is issued.
Easement Agreements. We have been granted a non-exclusive easement in
certain common utility facilities on the property covered by the Ground Lease
and, upon our request, the lessor must grant us easements for the purpose of
constructing, using and maintaining an underground gas main and an underground
pipeline for the discharge of water.
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DESCRIPTION OF THE NEW BONDS
General
We will issue the new bonds under the indenture between us and Bank One
Trust Company, National Association, as trustee. The new bonds and any existing
bonds that remain outstanding will be a single series. The following
description is a summary of the material provisions of the bonds and the
indenture. It does not restate the bonds and the indenture in their entirety.
Certain of the provisions of the indenture are also described under the caption
"Description of the Principal Financing Documents--Indenture." Certain terms
that are given special meanings in the indenture and the other financing
documents are used as defined in Annex A to this prospectus.
Principal, Maturity and Interest
The series including the new bonds is limited in aggregate principal amount
to $402,000,000 (of which $5,599,860 in principal has already been repaid) and
will mature on July 5, 2026.
The new bonds will bear interest at an annual rate of 8.159% from January 5,
2002, the most recent interest payment date on the existing bonds. We will pay
interest on the bonds semiannually in arrears on each January 5 and July 5 to
the holders of record on the fifteenth day preceding the applicable bond
payment date. 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
issuance. Interest will be computed on the basis of a 360-day year consisting
of twelve 30-day months.
The principal of the bonds is payable in semiannual installments on each
January 5 and July 5 to the registered holder of the bonds on the immediately
preceding regular record date, so that the initial weighted average life of the
bonds is approximately 12.0 years. Scheduled principal payments on the bonds
are as follows (rounded to the third decimal place):
Amortization Schedule
Percentage of Initial
Scheduled Payment Dates Balance of Bonds*
----------------------- ---------------------
January 5, 2002....................................... 1.393%
July 5, 2002.......................................... 0.632
Jan 5, 2003........................................... 2.903
July 5, 2003.......................................... 0.530
Jan 5, 2004........................................... 2.998
July 5, 2004.......................................... 0.669
Jan 5, 2005........................................... 3.194
July 5, 2005.......................................... 0.978
Jan 5, 2006........................................... 3.478
July 5, 2006.......................................... 1.100
Jan 5, 2007........................................... 3.460
July 5, 2007.......................................... 1.179
Jan 5, 2008........................................... 3.644
July 5, 2008.......................................... 1.361
Jan 5, 2009........................................... 3.801
July 5, 2009.......................................... 1.542
Jan 5, 2010........................................... 4.007
July 5, 2010.......................................... 1.639
Jan 5, 2011........................................... 4.139
July 5, 2011.......................................... 1.833
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Percentage of Initial
Scheduled Payment Dates Balance of Bonds
----------------------- ---------------------
Jan 5, 2012........................................... 4.443%
July 5, 2012.......................................... 2.313
Jan 5, 2013........................................... 5.061
July 5, 2013.......................................... 0.093
Jan 5, 2014........................................... 1.949
July 5, 2014.......................................... 0.014
Jan 5, 2015........................................... 1.852
July 5, 2015.......................................... 0.018
Jan 5, 2016........................................... 2.057
July 5, 2016.......................................... 0.013
Jan 5, 2017........................................... 1.421
July 5, 2017.......................................... 0.064
Jan 5, 2018........................................... 3.212
July 5, 2018.......................................... 0.081
Jan 5, 2019........................................... 3.592
July 5, 2019.......................................... 0.042
Jan 5, 2020........................................... 3.846
July 5, 2020.......................................... 0.265
Jan 5, 2021........................................... 4.879
July 5, 2021.......................................... 0.130
Jan 5, 2022........................................... 6.410
July 5, 2022.......................................... 0.401
Jan 5, 2023........................................... 4.991
July 5, 2023.......................................... 0.161
Jan 5, 2024........................................... 2.366
July 5, 2024.......................................... 0.192
Jan 5, 2025........................................... 2.991
July 5, 2025.......................................... 0.291
Jan 5, 2026........................................... 1.943
July 5, 2026.......................................... 0.429
* Percentages are based on the initial aggregate principal amount to the
existing bonds ($402,000,000). New bonds will be issued in the same nominal
amounts and any payments of principal on the existing bonds before the
exchange offer is completed will be credited against the new bonds.
Issuance of Additional Bonds
We may issue additional bonds under the indenture, which we refer to as the
additional bonds, in accordance with the conditions described therein. 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
Bonds," references to the bonds include any existing bonds that remain
outstanding, as they have identical terms to the new bonds, but 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. For a description of the conditions under which we may issue
additional bonds, see "Description of the Principal Financing Documents--
Indenture--Certain Covenants--Limitation on Indebtedness of the Partnership."
Nature of Recourse and Security
The obligations to pay principal of, premium, if any, and interest on the
bonds will be solely our obligations. Neither our members, nor any of our
affiliates, employees, officers, or directors or any other person or entity
will guarantee the bonds or have any other obligation to make payments on the
bonds. Holders will
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have no claims against or recourse to, whether by operation of law or
otherwise, those entities or persons or their respective affiliates except as
specifically provided in (and then only to the extent so provided in) the
transaction documents to which our affiliates our parties.
The bonds will be secured by:
. a first priority mortgage on our interest (which includes a leasehold
interest) in the Facility site, all fixtures thereon and all related
easements, rights-of-way, servitudes, licenses and similar real property
rights, provided that the mortgage will contain a covenant of non-
disturbance with respect to Shared Facilities;
. a first priority security interest in all of our personal property,
including, without limitation, all our equipment, inventory and other
goods used in connection with the Facility, all of our rights under the
project documents to which we are a party, all accounts established by
us under the Deposit and Disbursement Agreement (other than the
distribution account) and all funds on deposit therein, and all
assignable governmental approvals obtained in connection with the
Facility;
. a pledge of all of the membership interests held in us by our members;
and
. a pledge of all of the membership interests we hold in Elwood II
Holdings and Elwood III Holdings, our wholly-owned subsidiaries and a
first priority security interest in payments made by us to Elwood II
Holdings and Elwood III Holdings under the equipment sales agreements.
Any additional bonds issued will share equally and ratably in the collateral
with the bonds. Certain other Indebtedness may also share equally and ratably
in the collateral with the bonds. See "Description of the Principal Financing
Documents--Indenture--Limitation on Liens."
Ranking
The bonds:
. will be our Senior Secured Obligations;
. will rank equivalent in right of payment to all of our other Senior
Secured Obligations; and
. will rank senior in right of payment to all our existing and future
subordinated debt.
Optional Redemption
The bonds and additional 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 the bonds or additional bonds, on any
date before maturity, which we refer to as a redemption date, 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 to 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 bonds being redeemed plus accrued and unpaid interest
thereon to the redemption date.
Mandatory Redemption Without Make-Whole Premium
The bonds will be subject to mandatory redemption without a Make-Whole
Premium, and we will be required to prepay our other Senior Secured
Obligations, in the following circumstances:
Loss Events
If:
. a Loss Event occurs,
. we receive more than $5,000,000 of proceeds because of the Loss Event,
and
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. either:
. we decide not to rebuild, repair or restore the Facility after the Loss
Event, or
. the Facility cannot be rebuilt, repaired or restored to operate on a
Commercially Feasible Basis and the independent engineer confirms this
fact,
then we will have to use the proceeds that we receive in connection with that
Loss Event in excess of $5,000,000 to redeem bonds and prepay the other Senior
Secured Obligations. The redemption price for the bonds being redeemed will be
equal to 100% of the principal amount of the bonds being redeemed plus accrued
interest.
If:
. a Loss Event occurs,
. we receive proceeds because of the Loss Event,
. we decide to rebuild, repair or restore the Facility and the independent
engineer confirms that it can be rebuilt, repaired or restored to
operate on a Commercially Feasible Basis and the independent engineer
confirms this fact,
. more than $5,000,000 of proceeds from the Loss Event are left over after
we finish rebuilding, repairing or restoring the Facility,
then, after giving effect to the cost of such rebuilding, repairing or
restoring the Facility, we will have to use the remaining proceeds that we
receive because of the Loss Event in excess of $5,000,000 to redeem bonds and
prepay the other Senior Secured Obligations. The redemption price for the bonds
being redeemed will be equal to 100% of the principal amount of the bonds being
redeemed plus accrued interest.
Involuntary Buy-Outs of Power Sales Agreements
If we receive more than $10,000,000 of proceeds from Involuntary Buy-Outs,
we will have to use those proceeds in excess of $10,000,000 to redeem bonds and
prepay the other Senior Secured Obligations, unless we receive a confirmation
of the then current ratings of the bonds from both S&P and Moody's. The
redemption price for the bonds being redeemed will be equal to 100% of the
principal amount of the bonds being redeemed plus accrued interest.
Permitted Asset Sales
If we receive more than $5,000,000 of proceeds from a disposition of assets
permitted under the indenture (as set forth under the caption "Description of
the Principal Financing Documents--Indenture--Certain Covenants--Fundamental
Changes and Disposition of Assets"), we will have to use those proceeds in
excess of $5,000,000 to redeem bonds and prepay the other Senior Secured
Obligations. The redemption price for the bonds being redeemed will be equal to
100% of the principal amount of the bonds being redeemed plus accrued interest.
Mandatory Redemption with Make-Whole Premium
If we receive more than $10,000,000 of proceeds from Voluntary Buy-Outs, we
will have to use these proceeds in excess of $10,000,000 to redeem bonds and
prepay the other Senior Secured Obligations, unless Moody's and S&P confirm
that the buy-out will not result in a downgrade of their initial rating of the
bonds. The redemption price for the bonds being redeemed will be equal to 100%
of the principal amount of the bonds being redeemed plus accrued interest plus
a Make-Whole Premium.
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Redemption at the Option of the Bondholders
Change of Control
If a Change of Control occurs, any bondholder can request that we redeem all
or a portion of the bonds held by that bondholder. In response to any such
request, we will be required to redeem all bonds which are subject to the
request at a redemption price equal to 101% of the principal amount of the
bonds being redeemed plus accrued interest.
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 decide to have the bondholders vote on whether we should use these
funds to redeem bonds, and
. bondholders holding at least 66 2/3% of the principal amount of the
outstanding bonds vote to have us use these 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.
The redemption price for the bonds being redeemed will be equal to 100% of the
principal amount of the bonds being redeemed plus accrued interest.
Terms of Redemption
If the bonds are redeemed under any of the foregoing provisions, the
proceeds used to redeem the bonds will be applied pro rata to the bonds and
other Senior Secured Obligations which require redemption or repayment. We will
mail a notice of redemption to each holder of bonds or additional bonds being
redeemed at such holder's address of record. Interest will cease to accrue on
the bonds or additional bonds on and after the redemption date.
Book-Entry, Delivery and Form
Upon issuance, the new bonds will be represented by one or more fully
registered global certificates. Each global certificate will be deposited with
Depositary Trust Corporation ("DTC") or its custodian and will be registered in
the name of DTC or a nominee of DTC. DTC will thus be the only registered
holder of the new bonds. Any existing bonds that remain outstanding will be
represented by a separate global certificate.
DTC has advised us as follows: DTC is a limited purpose trust company
organized under the laws of the State of New York, a "banking organization"
within the meaning of the New York Banking Law, a member of the Federal Reserve
System, a "Clearing corporation" within the meaning of the New York Uniform
Commercial Code and a "clearing agency" registered under the provisions of
Section 17A of the Exchange Act. DTC was created to hold securities for its
participants and to facilitate the clearance and settlement of securities
transactions, such as transfers and pledges, among participants in deposited
securities through electronic book-entry charges to accounts of its
participants, thereby eliminating the need for physical movement of securities
certificates. Participants include securities brokers and dealers, banks, trust
companies, clearing corporations and certain other organizations. Certain of
such participants (or other representatives), together with other entities, own
DTC. The rules applicable to DTC and its participants are on file with the SEC.
Purchases of bonds under the DTC system must be made by or through
participants, which will receive a credit for the bonds on DTC's records. The
ownership interest of each actual purchaser of each bond is in turn to be
recorded on the participants' and indirect participants' records. Beneficial
owners will not receive written confirmation from DTC of their purchase, but
beneficial owners are expected to receive written confirmations
99
providing details of the transactions, as well as periodic statements of their
holdings, from the participant or indirect participant through which the
beneficial owner entered into the transaction. Transfers of ownership interests
in the bonds are to be accomplished by entries made on the books of
participants acting on behalf of beneficial owners. Beneficial owners will not
receive certificates representing their ownership interests in bonds, except in
the event that use of the book-entry system for the bonds is discontinued.
The deposit of bonds with a custodian for DTC and their registration in the
name of Cede effects no change in beneficial ownership. DTC has no knowledge of
the actual beneficial owners of the bonds; DTC's records reflect only the
identity of the participants to whose accounts such bonds are credited, which
may or may not be the beneficial owners. The participants will remain
responsible for keeping account of their holdings on behalf of their customers.
Principal and interest payments on the bonds will be made to DTC by wire
transfer of immediately available funds. DTC's practice is to credit
participants' accounts on the payable date in accordance with the respective
holdings shown on DTC's records unless DTC has reason to believe that it will
not receive payment on the payable date. Payments by participants to beneficial
owners will be governed by standing instructions and customary practices, as is
the case with securities held for the accounts of customers in bearer form or
registered in "Street name," and will be the responsibility of such participant
and not of DTC or us, subject to any statutory or regulatory requirements as
may be in effect from time to time. Payment of principal and interest to DTC,
and disbursement of such payments to the beneficial owners will be the
responsibility of participants and indirect participants. Neither we nor the
trustee will have any responsibility or liability for any aspect of the records
relating to or payments made on account of beneficial ownership interests in
the global bonds or for maintaining, supervising or reviewing any records
relating to such beneficial ownership interest.
DTC may discontinue providing its services as securities depositary with
respect to the bonds at any time by giving reasonable notice to us.
Bonds represented by a global bond will be exchangeable for bonds issued in
certificated form with the same terms in authorized denominations only if:
. DTC notifies us that it is unwilling or unable to continue as depositary
or if DTC ceases to be a clearing agency registered under applicable law
and a successor depositary is not appointed by us within 90 days;
. We determine not to require all of the bonds to be represented by a
global bond and notify the trustee of our decision; or
. there shall have occurred and be continuing an Event of Default or any
event which after notice or lapse of time or both would be an Event of
Default with respect to the bonds.
If the bonds are issued in certificated form to a holder other than DTC,
payments of principal and interest will be made by check mailed to such holder
at such holder's registered address or, upon written application by a holder of
$1,000,000 or more in aggregate principal amount of bonds to the trustee in
accordance with the terms of the indenture, by wire transfer of immediately
available funds to an account maintained by such holder with a bank or other
financial institution.
Transfer and Exchange
A bondholder may transfer or exchange bonds in accordance with the
Indenture. The security registrar and the trustee may require a bondholder,
among other things, to furnish appropriate endorsements and transfer documents
and we may require a bondholder to pay any taxes and fees required by law or
permitted by the indenture. We are not required to transfer or exchange any
bond for a period of 15 days before a selection of bonds be redeemed.
The registered holder of a bond will be treated as the owner of it for all
purposes.
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DESCRIPTION OF THE PRINCIPAL FINANCING DOCUMENTS
We refer to the documents described below, along with the security documents
and certain ancillary documents, as the financing documents. Certain terms that
are given special meanings in the indenture and the other financing documents
are used as defined in Annex A to this prospectus.
Indenture
General
We will issue the new bonds under an indenture between us and Bank One Trust
Company, National Association, as trustee.
Certain Covenants
We will be subject to the following covenants, among others, set forth in
the indenture:
Limitations on Indebtedness
We will not, nor will we permit any of our subsidiaries to, create, incur,
assume or suffer to exist any Indebtedness, other than the following
Indebtedness (which we refer to as permitted indebtedness):
. existing intercompany Indebtedness between us and our subsidiaries;
. the Senior Secured Obligations (other than Indebtedness referred to
below and incurred in respect of required modifications and/or optional
modifications);
. purchase money debt 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;
. Indebtedness which is fully subordinated in right of payment to the
Senior Secured Obligations and which is not secured by the collateral;
. working capital loans up to $20,000,000, as escalated in accordance with
the consumer price index;
. surety bonds, performance bonds or similar arrangements with third-party
sureties or indemnitors or similar persons (which we refer to
collectively as bonding arrangements) in connection with a good faith
contest or as otherwise permitted by the indenture or any other
transaction document;
. reimbursement obligations under any debt service reserve letter of
credit;
. indemnities and similar obligations arising under the transaction
documents;
. Indebtedness incurred in respect of non-speculative hedging agreements;
and
. Indebtedness incurred for modifications and improvements to the Facility
that are reasonably necessary to maintain our status as an "exempt
wholesale generator" or for the Facility to maintain its status as an
"eligible facility" or that are reasonably necessary, or that we believe
(with the concurrence of the independent engineer) are appropriate for
the Facility, to remain in substantial compliance with applicable laws
and governmental approvals (including enacted or anticipated changes in
applicable laws or the interpretation thereof), which we refer to
collectively as required modifications, as long as each of the following
conditions is satisfied:
(1) no default or event of default has occurred and is continuing, or
will result from the incurrence of the Indebtedness;
101
(2) each of S&P and Moody's confirms that the incurrence of the
Indebtedness will not result in a downgrade of their then current
ratings for the bonds, or (x) the Debt Service Coverage Ratio for
the two quarter period preceding the date such Indebtedness is
incurred, which we refer to as the incurrence date, and (y) the
Projected Debt Service Coverage Ratio for the four quarter period
succeeding the incurrence date (after taking into account the
incurrence of the Indebtedness) are each greater than or equal to:
(a) 1.5 to 1.0; or
(b) 1.4 to 1.0, if as of the incurrence date, we are party to
Permitted PPAs covering, in the aggregate, at least 25% of the
capacity of the Facility for the consecutive period of eight
full quarters, taken as a whole, following the incurrence date;
or
(c) 1.3 to 1.0, if as of the incurrence date, we are party to
Permitted PPAs covering, in the aggregate, at least 50% of the
capacity of the Facility for the consecutive period of eight
full quarters, taken as a whole, following the incurrence date;
or
(d) 1.2 to 1.0, if as of the incurrence date, we are party to
Permitted PPAs covering, in the aggregate, at least 75% of the
capacity of the Facility for the consecutive period of eight
full quarters, taken as a whole, following the incurrence date;
or
(e) 1.1 to 1.0, if as of the incurrence date, we are party to
Permitted PPAs covering, in the aggregate, 100% of the capacity
of the Facility for the consecutive period of eight full
quarters, taken as a whole, following the incurrence date; and
. Indebtedness incurred for modifications and improvements (other than
required modifications) to the Facility that cost less than $25,000,000
in the aggregate, which we refer to as optional modifications, as long
as each of the following conditions is satisfied:
(1) no default or event of default has occurred and is continuing, or
will result from the incurrence of the Indebtedness;
(2) the Debt Service Coverage Ratio for the two quarter period
preceding the incurrence date and the Projected Debt Service
Coverage Ratio for the four quarter period succeeding the
incurrence date (after taking into account the incurrence of the
Indebtedness) are each greater than or equal to:
(a) 1.7 to 1.0; or
(b) 1.6 to 1.0, if as of the incurrence date, we are party to
Permitted PPAs covering, in the aggregate, at least 25% of the
capacity of the Facility for the consecutive period of eight
full quarters, taken as a whole, following the incurrence date;
or
(c) 1.45 to 1.0, if as of the incurrence date, we are party to
Permitted PPAs covering, in the aggregate, at least 50% of the
capacity of the Facility for the consecutive period of eight
full quarters, taken as a whole, following the incurrence date;
or
(d) 1.3 to 1.0, if as of the incurrence date, we are party to
Permitted PPAs covering, in the aggregate, at least 75% of the
capacity of the Facility for the consecutive period of eight
full quarters, taken as a whole, following the incurrence date;
or
(e) 1.2 to 1.0, if as of the incurrence date, we are party to
Permitted PPAs covering, in the aggregate, 100% of the capacity
of the Facility for the consecutive period of eight full
quarters, taken as a whole, following the incurrence date.
As a condition to incurring Indebtedness for required modifications or
optional modifications, we must deliver to the trustee and the collateral agent
an officer's certificate certifying as to the matters described in the
applicable clauses (1) and (2) above (including the relevant Permitted PPAs).
We will determine the satisfaction
102
of the conditions in each clause (2) based on projections prepared by us in
good faith based upon assumptions consistent in all material respects with the
relevant contracts and agreements, the transaction documents, historical
operations and our good faith projections of future revenues and projections of
our operating and maintenance expenses in light of existing or reasonably
expected regulatory and market environments in the markets in which the
Facility is or will be operated and upon the assumption that there will be no
early redemption or prepayment of Indebtedness or that any Indebtedness which
matures within the projected periods will be refinanced on reasonable terms.
Limitation on Liens
We will not, nor will we permit any of our subsidiaries to, create, suffer
to exist or permit any lien upon any of our properties, other than the
following liens, which we refer to as 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 aggregate amount, at any time
outstanding, not exceeding $5,000,000 plus monies used from amounts
otherwise available to our members as a distribution permitted in
accordance with the terms described below 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 by us;
. any exceptions to title existing on the date of the offering of the
existing bonds and set forth on the title policies issued in connection
with the offering of the existing bonds;
. 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, releases
of attachments, stays of execution or injunctions, performances 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 by us (excluding any attachment prior to judgment,
judgment lien or attachment in aid of execution on a judgment);
. 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 removed or
bonded within 60 days after filing (but in any event before
enforcement), or which are the subject of a good faith contest by us;
. liens on assets acquired with the proceeds of permitted purchase money
or capital lease obligations;
. 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; and
. liens arising under Shared Facilities Agreements.
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Distributions
We will not make a distribution (including by transfer of assets or
assumption or incurrence of any debt or liability) to our members unless the
distribution is made on a scheduled bond payment date and each of the following
conditions are satisfied on the date of the distribution, which we refer to as
the distribution date:
. all required transfers and payments described under the caption "--
Deposit and Disbursement Agreement--Deposit and Disbursement of Funds"
have been completed and all accounts established under the deposit and
disbursement agreement are funded to their required levels;
. no default or event of default has occurred and is continuing or will
result from the distribution;
. the Debt Service Coverage Ratio for the four quarter period preceding
the distribution date and the Projected Debt Service Coverage Ratio for
each of the two four quarter periods succeeding the distribution date
(after taking into account the making of the proposed distribution) are
each greater than or equal to:
(1) 1.7 to 1.0; or
(2) 1.6 to 1.0, if as of the distribution date, we are party to
Permitted PPAs covering, in the aggregate, at least 25% of the
capacity of the Facility for the consecutive period of eight full
quarters, taken as a whole, following the distribution date; or
(3) 1.45 to 1.0, if as of the distribution date, we are party to
Permitted PPAs covering, in the aggregate, at least 50% of the
capacity of the Facility for the consecutive period of eight full
quarters, taken as a whole, following the distribution date; or
(4) 1.3 to 1.0, if as of the distribution date, we are party to
Permitted PPAs covering, in the aggregate, at least 75% of the
capacity of the Facility for the consecutive period of eight full
quarters, taken as a whole, following the distribution date; or
(5) 1.2 to 1.0, if as of the distribution date, we are party to
Permitted PPAs covering, in the aggregate, 100% of the capacity of
the Facility for the consecutive period of eight full quarters,
taken as a whole, following the distribution date; and
. We deliver to the trustee and the collateral agent an officer's
certificate certifying as to the matters described in each of the
conditions set forth above (including the relevant Permitted PPAs). We
will determine the satisfaction of the conditions set forth in the
immediately preceding bullet point based on projections prepared by us
in good faith based upon assumptions consistent in all material respects
with the relevant contracts and agreements, the transaction documents,
historical operations and our good faith projections of future revenues
and projections of our operating and maintenance expenses in light of
existing or reasonably expected regulatory and market environments in
the markets in which the Facility is or will be operated and upon the
assumption that there will be no early redemption or prepayment of
Indebtedness or that any Indebtedness which matures within the projected
periods will be refinanced on reasonable terms.
For any calculations under the financing documents with respect to periods
following a bond payment date or a distribution date, the beginning point of
the calculation will be the first day of the month in which the bond payment
date or distribution date occurs.
Amendments to Material Project Documents
We will not:
. terminate, amend, waive or modify any of the material project documents
(other than the power sales agreements) to which we are a party,
. exercise any rights we may have to consent to any assignment of any of
the material project documents (other than the power sales agreements)
by the other parties thereto, or
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. exercise any option under any of the material project documents (other
than the power sales agreements) to which we are a party
unless such termination, amendment, waiver, modification, assignment or
exercise:
. would not reasonably be expected to result in a Material Adverse Effect,
as certified in certain instances by the independent engineer; or
. is reasonably necessary in order to maintain a power sales agreement in
full force and effect, as certified by the independent engineer; 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 the Facility to maintain its certification as an "eligible
facility" or for us to maintain our certification as an "exempt
wholesale generator"; or
. is the result of:
(1) a change in tariffs or similar publicly promulgated rates approved
by any governmental authority which are incorporated by reference
into a project document, or
(2) implementation of provisions requiring adjustments to price or
volume under, and in accordance with, the terms of a material
project document, if we exercise good faith and commercially
reasonable efforts to negotiate price changes under such provisions
for adjustments to price which do not result in a Material Adverse
Effect.
Amendments to Power Sales Agreements
We will not:
. terminate, amend, waive any material obligations under, or modify any of
the power sales agreements,
. exercise any rights we may have to consent to any assignment of any of
the power sales agreements by the other party thereto, or
. exercise certain options listed on a schedule to the indenture under any
of the power sales agreements,
unless such termination, amendment, waiver, modification, assignment or
exercise would not reasonably be expected to result in a Material Adverse
Effect, as certified by us in an officer's certificate delivered to the trustee
and the collateral agent and concurred with in writing by the independent
engineer.
Prohibition on Fundamental Changes and Disposition of Assets
We will not:
. enter into any transaction of merger or consolidation (except that our
subsidiaries may merge into us), change our form of organization or our
business, or liquidate or dissolve (or suffer any liquidation or
dissolution) unless contemporaneously reconstituted with no adverse
effect on the Secured Parties;
. purchase or otherwise acquire all or substantially all of the assets of
any other person except as contemplated by the transaction documents;
. except as contemplated by the transaction documents, sell, lease (as
lessor) or transfer (as transferor) any property or assets material to
the operation of the Facility except in the ordinary course of our
business to the extent that:
(1) such property is worn out or is no longer useful or necessary for
the operation of the Facility, or
(2) such property is replaced with property of equivalent use and value,
or
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(3) such 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 under the project documents;
provided, however, we have the right under the indenture to share our property
and the use thereof in accordance with, and to the extent reasonably necessary
to effect, the Shared Facilities Agreements.
Replacement Power
We will not elect to use replacement power to satisfy the requirements under
our power sales agreements unless:
. we are constrained from generating and delivering power;
. we certify to the trustee and the collateral agent that our use of
replacement power would not reasonably be expected to result in a
Material Adverse Effect; and
. we enter into an agreement, which we refer to as an acceptable
replacement power arrangement, satisfying the following conditions:
(1) the agreement has a delivery period not exceeding 45 days; or
(2) the execution and performance of the agreement would not reasonably
be expected to result in a Material Adverse Effect (as confirmed by
the independent engineer); or
(3) the agreement has a delivery period not exceeding 90 days and the
agreement's counterparty (or the credit support provider for such
counterparty) is rated at least "BBB-" by S&P or at least "Baa3" by
Moody's, provided that this credit rating standard will not apply if
such counterparty has dedicated existing generating assets and
capacity for the provision of the replacement power and such
generating assets have a proven track record for satisfying the
obligation to provide all of the replacement power.
Additional Documents
We will not enter into any material agreements, contracts or other
arrangements or commitments other than the following:
. the transaction documents and agreements or other arrangements
contemplated by the transaction documents;
. agreements, contracts or other arrangements entered into by us with
respect to the disposition of assets that we are entitled to sell,
transfer, assign, lease or sublease under the indenture;
. agreements, contracts or other arrangements entered into by us in the
ordinary course of business and that are included in our annual
operating budget;
. agreements, contracts or other arrangements entered into in substitution
for existing agreements, contracts or other arrangements on
substantially similar terms and conditions;
. the Shared Facilities Agreements, Permitted PPAs, and replacement power
arrangements;
. agreements for sale of excess fuel or firm transportation (to the extent
not required for the operation of the Facility or the performance of our
obligations under the power sales agreements), the performance of which
could not reasonably be expected to result in a Material Adverse Effect;
and
. contracts for emergency repairs or to avoid or minimize unplanned
outages.
Transactions with Affiliates.
We will not enter into any transaction or agreement with any affiliate other
than agreements identified in the indenture, Shared Facilities Agreements, and
transactions and agreements in the ordinary course of business
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on fair and reasonable terms no less favorable to us than we would obtain in an
arm's-length transaction with a person that is not our affiliate. Before
entering into any transaction with an affiliate, we will deliver to the trustee
and the collateral agent an officer's certificate stating that the requirements
of this paragraph are met.
New Generation Facilities.
Our affiliates are considering the development of new generation facilities
on land they control adjacent to portions of the Facility site. If the new
generation facilities are developed, the owners of the new generation
facilities may need to enter into certain agreements with us with respect to
certain shared facilities and the use of such facilities for the benefit of the
new generation facilities. Such shared facilities may include roads, easements,
fuel and utility lines and pipes, transmission lines and interconnects, water
disposal and treatment systems, control systems, and other property or rights
that we own or lease, and some of the shared facilities may be facilities that
we use in the operation of the Facility. We will not enter in any Shared
Facility Agreement unless the execution, delivery and performance of such
Shared Facility Agreement:
. will not result in a downgrade of the then current rating on the bonds
by either of S&P and Moody's,
. could not reasonably be expected to result in a Material Adverse Effect
(as certified by us) and
. will not have a material adverse effect on the operation or technical
integrity of the Facility, including, without limitation, as to
availability and anticipated financial performance (all as certified by
the independent engineer).
Additional Covenants
We will also be required to:
. maintain our existence and title to properties;
. obtain, maintain and comply with all necessary governmental approvals;
. comply with applicable laws and the terms of each project document;
. maintain insurance for the Facility;
. keep the bonds equivalent in right of payment and ability to share in
the collateral with our other senior debt;
. deliver financial statements, notices of default, notices of power sales
agreement buy-outs and other documents to the trustee, the collateral
agent and the rating agencies;
. operate and maintain the Facility in compliance with prudent utility
practices, applicable laws, governmental approvals and the project
documents;
. deliver annual operating budgets to the trustee, the collateral agent
and the independent engineer;
. prepare a major maintenance plan;
. submit an annual report covering the status of the insurance for the
Facility;
. provide the independent engineer, the trustee and the collateral agent
reasonable inspection rights and the right to witness the performance
tests;
. maintain our status as an "exempt wholesale generator" and the
Facility's status as an "eligible facility";
. pay our taxes;
. diligently pursue all rights we may have to compensation in respect of
certain events of loss or governmental taking; and
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. cause any project document we enter into after the date of this offering
to become subject to the lien of the collateral agent.
In addition, we will be restricted from engaging in the following
activities:
. conducting any business other than the construction, ownership,
operation, maintenance, administration and financing of the Facility;
. making investments other than Permitted Investments;
. establishing subsidiaries or allowing our existing subsidiaries to
engage in activities other than those that they are engaged in on the
date of the offering; and
. establishing employee benefit plans which result in the imposition of
material liabilities on us.
If at any time after completion of the exchange offer, we are no longer
required to, and do not, file periodic reports and other information under the
Exchange Act, we are obligated to provide equivalent information to the
bondholders, unless we receive the consent of holders of a majority in
principal amount of the bonds relieving us of this obligation.
The affirmative and negative covenants described above are subject to 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 fail 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 five or more days; or
. any representation or warranty made by us in any financing document, or
in any certificate furnished to the Secured Parties or the independent
consultants in accordance with the terms of the financing documents,
proves to have been false or misleading in any respect as of the time
made, and the fact, event or circumstance that gave rise to the
misrepresentation has resulted in or is reasonably expected to result in
a Material Adverse Effect and such misrepresentation or such Material
Adverse Effect continues uncured for 30 or more days from the date we
obtain knowledge thereof; provided that if we commence efforts to cure
(or to cause to be cured) the misrepresentation by curing (or causing to
be cured) the factual situation resulting in the misrepresentation or
such Material Adverse Effect within this 30-day period, we may continue
to effect (or cause) such cure (and such misrepresentation will not be
deemed an event of default) for an additional 90 days so long as we
certify to the trustee and the collateral agent that such
misrepresentation or such Material Adverse Effect is reasonably capable
of being cured within such period and that we are diligently pursuing
(or causing) such cure; or
. we fail to perform or observe our covenant in the indenture to maintain
adequate insurance for the Facility; provided, however, that we will
have five business days to correct or cause to be corrected this failure
before an event of default occurs; or
. we 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, amendments to power sales agreements, the
incurrence of Indebtedness, liens, distributions, the nature of our
business, fundamental changes, sales of assets, investments or
additional documents, and this failure continues uncured for 30 or more
days after we have knowledge of such failure; or
. we fail to perform or observe in any material respect any of the
covenants contained in any other provision of the indenture (other than
those referred to above) or any other financing document and such
failure continues uncured for 30 or more days after we have knowledge of
such failure; provided that if we commence efforts to cure such default
within such 30-day period, we may continue to effect such
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cure of the default (and such default will not be deemed an event of
default) for an additional 180 days so long as we provide an officer's
certificate to the trustee and the collateral agent stating that such
default is reasonably capable of being cured within such period and we are
diligently pursuing the cure; provided further, in the case of a default
arising from our failure to comply with permits or laws, or to maintain
permits, and within such 180 day period we enter into a consent decree or
other arrangement under which the applicable governmental authorities
agree to stay or delay enforcement against such non-compliance, then such
cure period shall be further extended for the period of such stay or
delay; or
. certain events of bankruptcy or insolvency occur;
. 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 therein
(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
. with respect to any material transaction document:
(1) a term of such transaction document ceases to be a valid and binding
obligation of the parties thereto or is declared unenforceable by a
governmental authority, or
(2) such transaction document is terminated (before its normal
expiration), or
(3) a party to a project document denies its liability thereunder or
defaults on its obligations thereunder (and any grace or cure period
with respect to such failure has expired); and
in each such case, the event described above could reasonably be expected
to result in a Material Adverse Effect; provided that none of the events
described in clauses (1), (2) or (3) will be an event of default if
within 180 days from the occurrence of any such event, we have cured or
caused the relevant party to cure the circumstances described in the
appropriate clause and caused the relevant party to resume performance in
accordance with the relevant project document, or entered into a
replacement project document in substitution of the relevant project
document which is reasonably satisfactory to the independent engineer; or
. we fail to make any payment in respect of any Indebtedness, including
permitted indebtedness, having an outstanding principal amount of more
than $15,000,000 (other than any amount owing with respect to any bond)
when due (subject to 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 $15,000,000 is rendered against us, and the same
remains unpaid or unstayed for a period of 90 or more consecutive days
after such payment is due and payable; or
. an Event of Abandonment occurs.
In the case of an event of default arising from certain events of
bankruptcy or insolvency, 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.
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
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(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 may, at any time, terminate all of our obligations under the indenture,
the bonds and the other financing documents, and may terminate the liens of the
security documents on the collateral (a "Legal Defeasance"). In addition, we
may terminate, at any time, our obligations under any of the covenants under
the indenture, the bonds and the other financing documents, and may terminate
the liens of the security documents on the collateral, other than our covenants
to maintain our 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:
. we have irrevocably deposited or caused to be deposited in trust with
the trustee cash, non-callable United States government obligations or a
combination thereof in such 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;
. we have delivered to the trustee an opinion of counsel to the effect
that as of the date of such opinion, (1) the trust funds will not be
subject to the rights of holders of Indebtedness other than the bonds;
(2) subject to certain assumptions and exceptions, the trust funds will
not be subject to the effect of any applicable bankruptcy, insolvency,
reorganization or similar law affecting creditors' rights generally; and
(3) the holders of the bonds shall have a perfected security interest
under applicable law in the obligations so deposited;
. no default or event of default has occurred and is continuing on the
date of, or will result from, such deposit (other than from the
incurrence of Indebtedness the proceeds of which will be used to
defease);
. such Legal Defeasance or Covenant Defeasance does not result in a breach
or violation of, or constitute a default under, any other material
agreement or instrument to which we are a party or by which we are
bound;
. in the case of a Legal Defeasance, we have delivered to the trustee an
opinion of counsel confirming that (a) 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 such Legal Defeasance and will be subject to federal
income tax on the same amounts, in the same manner and at the same times
as would have been the case if such Legal Defeasance had not occurred;
. in the case of a Covenant Defeasance, we have delivered to the trustee
an opinion of counsel reasonably acceptable to the trustee confirming
that the holders of the bonds will not recognize income, gain or loss
for federal income tax purposes as a result of such Covenant Defeasance
and will be subject to federal income tax on the same amounts, in the
same manner and at the same times as would have been the case if such
Covenant Defeasance had not occurred; and
. 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.
Deposit and Disbursement Agreement
General
We have entered into the Deposit and Disbursement Agreement with the
collateral agent, the administrative agent and the intercreditor agent. We may
cause the holders of any Indebtedness (along with any
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agent acting on their behalf) for optional modifications and/or required
modifications to become a party to the deposit and disbursement agreement. The
deposit and disbursement agreement sets forth, among other things, the terms
upon which our operating revenues and other amounts received by or on behalf of
us are disbursed to pay operation and maintenance costs, debt service and other
amounts due from us.
Deposit and Disbursement of Funds
We will deposit all of our operating revenues into the revenue account and
the administrative agent will disburse these revenues on the last day of each
calendar month (except as indicated below) in the following order of priority:
. First, to the O&M account in an amount sufficient to pay all O&M Costs
(including, without duplication, the repayment of any draws in respect
of such costs under a permitted working capital facility) due and
payable on the disbursement date or reasonably expected to be due and
payable within the next month;
. Second, on the final day of any quarter beginning in the year 2006 until
such time that we have made the final payment with respect to certain
sales tax obligations, to the sales tax reserve account, in an amount
equal to the Sales Tax Reserve Requirement;
. Third, to the debt service payment account in an amount equal to 1/6 of
all principal, interest and other amounts which will be due and payable
on the outstanding bonds and any other Senior Secured Obligations (other
than principal on debt service reserve letter of credit loans, but
including, without limitation, principal on debt service reserve letter
of credit bonds) on the next succeeding scheduled bond payment date
together with the appropriate portion of any Senior Secured Obligations
which are due and payable more frequently than on a semi-annual basis;
. Fourth, to the debt service reserve letter of credit loan principal
account, in an amount (together with the amounts then on deposit
therein) equal to the appropriate portion of principal of debt service
reserve letter of credit loans calculated based on the amortization
schedule for such loans;
. Fifth, to the debt service reserve account in an amount which, together
with all amounts on deposit therein or credited thereto, is equal to the
then current debt service reserve requirement. See "--Debt Service
Reserve Account";
. Sixth, to the major maintenance reserve account in an amount that is
equal to 1/6 of the difference between (i) the scheduled major
maintenance reserve required balance (as may be adjusted annually in
consultation with the independent engineer) as of the next bond payment
date and (ii) amounts already on deposit in or credited to the major
maintenance reserve account as of the immediately preceding bond payment
date;
. Seventh, beginning in December 2012 and ending in December 2023, to the
PSA contingency reserve account in an amount that equals the then
current PSA Contingency Reserve Requirement; 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.
If the distribution conditions set forth in the indenture are satisfied on
any scheduled bond payment date, funds in the distribution suspense account may
be transferred to the distribution account for distribution to us.
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 major
maintenance expenditures funded through the major maintenance reserve account.
The administrative agent will disburse amounts from the O&M account upon
delivery by us of an officer's
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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 which are due and payable on the date of
disbursement.
Sales Tax Reserve Account
Beginning on March 31, 2006 and on the last day of each quarter thereafter
until such time that the final payment with respect to certain sales tax
obligations is due and payable, we will be required to transfer the Sales Tax
Reserve Requirement to the sales tax reserve account. We refer to the date on
which final payment is due under the sales tax sharing agreements as the final
sales tax payment date. We will not be entitled to withdraw any amounts from
the sales tax reserve account until the final sales tax payment date, at which
time amounts on deposit therein will be withdrawn to pay all amounts due under
the sales tax sharing agreements. Any amounts remaining on deposit in the sales
tax reserve account after the final payment has been made or after we have
received an opinion of counsel that no further payments will be due in respect
thereof due to a change in law or otherwise will be transferred in accordance
with the operating flow of funds described above under the caption "--Deposit
and Disbursement of Funds."
Debt Service Payment Account
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 due or becoming due in respect of the bonds and the other Senior
Secured Obligations (other than principal on debt service reserve letter of
credit loans, but including, without limitation, principal on debt service
reserve letter of credit bonds) on any date when such principal, premium,
interest or other amounts are due.
Debt Service Reserve Letter of Credit Loan Principal Account
Amounts on deposit in the debt service reserve letter of credit loan
principal account will be used to pay the principal due or becoming due with
respect to any debt service reserve letter of credit loans on the date when
such principal is due.
Debt Service Reserve Account
On any monthly funding date occurring: (1) after January 1, 2013 on which:
. we are party to Permitted PPAs covering, in the aggregate, 75% or more
of the Facility's capacity for the consecutive period of four full
quarters following such date;
and either:
. we have provided a guaranty from an entity that is rated at least "BBB"
by S&P and "Baa2" by Moody's that will guarantee the difference between
the amount of the 12-month debt service reserve requirement and the
amount of the 6-month debt service reserve requirement; or
. each of S&P and Moody's confirms that the failure to provide such a
guaranty will not result in a downgrade of the then current rating of
the bonds;
or (2) on or before December 31, 2012,
we will be required to maintain an amount on deposit in or credited to the debt
service reserve account from time to time equal to the principal and interest
payments due, in the aggregate, in respect of the Senior Secured Obligations on
the next succeeding scheduled bond payment date. We refer to this amount as the
6-month debt service reserve requirement.
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On any other monthly funding date, we will be required to maintain an amount
on deposit in or credited to the debt service reserve account equal to the
principal and interest payments due, in the aggregate, in respect of the Senior
Secured Obligations on the next two succeeding scheduled bond payment dates.
Amounts on deposit in or credited to the debt service reserve account will
be used to pay the principal of and interest on the Senior Secured Obligations
and any other amounts payable to the Secured Parties under the financing
documents at any time when amounts on deposit in or credited to the debt
service payment account are insufficient to make such payments.
Major Maintenance Reserve Account
The major maintenance reserve required balance for each 6-month period
during the term of the bonds will be set forth on a schedule to the deposit and
disbursement agreement, which schedule is subject to annual adjustment in
consultation with the independent engineer. The major maintenance reserve
required balance was $3,800,000 as of January 5, 2002. At any time that the
major maintenance reserve required balance is adjusted, we are required to
deliver a certificate countersigned by the independent engineer to the trustee
and the collateral agent certifying that the adjusted amount is reasonably
expected to be sufficient to fund scheduled major maintenance of the Facility
on a timely basis. Amounts on deposit in or credited to the major maintenance
reserve account will be used to pay the costs of major maintenance activities
associated with the Facility.
PSA Contingency Reserve Account
Beginning in December 2012 and ending in December 2023, we will be required
to maintain an amount on deposit in or credited to the PSA contingency reserve
account in an amount equal to the then current PSA Contingency Reserve
Requirement. If, on any monthly funding date immediately preceding a bond
payment date, amounts on deposit in the debt service payment account and the
debt service reserve account, together with any amounts transferred into such
accounts from the revenue account, are insufficient to pay amounts due on the
Senior Secured Obligations on the bond payment date, funds will be transferred
from the PSA contingency reserve account to make up the shortfall.
Subject to the requirements set forth below, if on any monthly funding date
immediately preceding any bond payment date, the monies on deposit in or
credited to the PSA contingency reserve account exceed the then current PSA
Contingency Reserve Requirement, an amount equal to this excess, which we refer
to as the PSA reserve excess, will be transferred to the distribution suspense
account. Before a transfer to the distribution suspense account may be made,
however, transfers will be made from the PSA contingency reserve account,
first, to the debt service reserve account and, second, to the major
maintenance reserve account to the extent either account is less than fully
funded after transfers to it from the revenue account on such date. In
addition, on any such date, which we refer to as a PSA funding reduction date,
that the PSA Contingency Reserve Amount is reduced from the Maximum PSA
Contingency Amount to $0 because we have satisfied the test set forth in clause
(i)(b) of the definition of PSA Contingency Reserve Amount (which is set forth
in Annex A), then we will be required to maintain the following amounts (at the
relevant times) on deposit in the PSA contingency reserve account
(notwithstanding the reduction in the PSA Contingency Reserve Amount):
. from the PSA funding reduction date until the first anniversary of the
PSA funding reduction date, 50% of the amount on deposit in or credited
to the PSA contingency reserve account immediately before the reduction
in the PSA Contingency Reserve Amount from the Maximum PSA Contingency
Amount to $0;
. from the first anniversary of the PSA funding reduction date until the
second anniversary of the PSA funding reduction date, 25% of the amount
on deposit in or credited to the PSA contingency reserve account
immediately before the reduction in the PSA Contingency Reserve Amount
from the Maximum PSA Contingency Amount to $0;
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. from the second anniversary of the PSA funding reduction date until the
third anniversary of the PSA funding reduction date, 12.5% of the amount
on deposit in or credited to the PSA contingency reserve account
immediately before the reduction in the PSA Contingency Reserve Amount
from the Maximum PSA Contingency amount to $0; and
. from the third anniversary of the PSA funding reduction date until the
fourth anniversary of the PSA funding reduction date, 6.25% of the
amount on deposit in or credited to the PSA contingency reserve account
immediately before the reduction in the PSA Contingency Reserve Amount
from the Maximum PSA Contingency Amount to $0;
unless, on any such funding date, we have satisfied the tests set forth in
clauses (i)(a), (ii), (iii) or (iv) of the definition of PSA Contingency
Reserve Amount (set forth in Annex A), in which case, the applicable remaining
amount of the PSA reserve excess will be transferred to the distribution
suspense account.
Reserve Account Letters of Credit and Guaranties
Instead of depositing some or all cash to maintain the sales tax reserve
requirement, the debt service reserve requirement, the PSA Contingency Reserve
Requirement and/or the major maintenance reserve requirement, we may:
. provide or cause to be provided one or more irrevocable direct pay
letters of credit issued by a bank or other financial institution rated
at least "A" by S&P and at least "A2" by Moody's and naming the
collateral agent as beneficiary; provided that, with respect to the
sales tax reserve, major maintenance reserve and PSA contingency reserve
letters of credit, we will not be permitted to be named as the account
party; or
. provide one or more several guaranties issued by entities that are each
rated at least "BBB" by S&P and "Baa2" by Moody's.
If we replace existing cash reserves with a letter of credit or guaranty, we
may withdraw the funds in the applicable account.
In order for us to be the account party on a DSR letter of credit, at the
time the debt service reserve letter of credit is issued, each of S&P and
Moody's must confirm that there will be no downgrade in the then current
ratings on the bonds as a result of indebtedness incurred in respect of the
debt service reserve letter of credit or the underlying letter of credit
agreement.
We initially plan to provide several guaranties issued by Dominion
Resources, Inc. and Peoples Energy Corporation instead of depositing cash to
maintain the debt service reserve requirement. Dominion Resources, Inc. is
rated BBB+ by S&P and Baa1 by Moody's. Peoples Energy Corporation is rated A+
by S&P and A2 by Moody's. For additional information concerning Dominion
Resources, Inc. and Peoples Energy Corporation, see "Where You Can Find
Information."
Distribution Suspense Account
The distribution suspense account will be funded with amounts remaining in
the revenue account after all other required disbursements have been made as
described above under "--Deposit and Disbursement of Funds." On any scheduled
bond payment date on which each of the conditions set forth under the caption
"Indenture--Certain Covenants--Distributions" are satisfied, the amounts on
deposit in the distribution suspense account will be transferred to the
distribution account for distribution to or as directed by us.
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
114
timely furnished such a written direction or confirmed a standing instruction
to the administrative agent, the administrative agent will invest such amounts
only in certain Permitted Investments with a maturity of one year or less. Any
written direction from us 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 such amounts and have maturity dates or
are subject to redemption at the option of the holder thereof on or before
maturity as needed for the purposes of such accounts. No Permitted Investments
will mature more than one year after the date acquired. Any income or gain
realized from such investments will be deposited into the Revenue Account.
Debt Service Reserve Letter of Credit Agreement
Each drawing under any debt service reserve letter of credit in which we are
the account party will be converted into a loan that will mature not less than
five years after the drawing giving rise to the loan, which we refer to as a
debt service reserve letter of credit loan. Any such loan that is outstanding
five years after the Closing Date may be converted into a substitute loan
(which we call a debt service reserve letter of credit bond) that will
amortize, will mature on the maturity date of the bonds, will bear interest at
a rate to be negotiated between the issuer of the debt service reserve letter
of credit and us, and will rank equally in right of payment with the bonds.
Both the debt service reserve letter of credit loans and the debt service
reserve letter of credit bonds will share equally and ratably in the collateral
with the bonds.
Collateral Agency Agreement
We have entered into a collateral agency agreement with the trustee, the
collateral agent and the administrative agent. We may cause the holders of any
Indebtedness (along with any agent acting on their behalf) to become parties to
the collateral agency agreement for optional modifications and required
modifications. Under the collateral agency agreement, the Secured Parties (or
their representatives party thereto) have appointed the collateral agent to
hold and administer the collateral and to enter into and exercise remedies
under the security documents on behalf of the Secured Parties.
The collateral agent will apply the proceeds of any collection, sale or
other realization of all or any part of the 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 liabilities 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 Secured Parties current on interest on overdue
interest to the same proportionate extent as the other 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 Secured Parties current on interest on overdue
principal due to the same proportionate extent as the other 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;
. fifth, to the payment of the remaining Senior Secured Obligations
outstanding; and
. finally, to us, or our successors or assigns, or as a court of competent
jurisdiction may direct, of any surplus then remaining.
115
Intercreditor Agreement
Each of the Secured Parties (or a representative for them) will enter into
the intercreditor agreement upon the incurrence of the Indebtedness held by
such Secured Party. Under the intercreditor agreement:
. 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 a event of default 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;
. the affirmative vote of persons holding greater than 50% of the Senior
Secured Obligations will be required to amend documents and grant
consents and approvals (other than with respect to certain fundamental
decisions); and
. the affirmative vote of persons holding 100% of the Senior Secured
Obligations will be required to amend documents and grant consents and
approvals with respect to certain fundamental decisions, including
without limitation amendments, consents and approvals resulting in the
release of collateral.
116
FEDERAL INCOME TAX CONSIDERATIONS
This discussion of certain United States federal income tax considerations
applies to you if you are the beneficial owner of bonds and if you acquire the
bonds (or existing bonds which are exchanged for new bonds) for cash and hold
the bonds as a "capital asset," generally, for investment, under Section 1221
of the Internal Revenue Code of 1986, as amended (the "Code"). This discussion
does not, however, address any federal estate, gift or alternative minimum
taxes or state, local or foreign tax laws. In addition, it does not address all
of the rules which may affect the United States tax treatment of your
investment in the bonds. For example, special rules not discussed here may
apply to you if you are:
. a partnership;
. a broker-dealer, a dealer in securities or currencies, or a financial
institution;
. an S corporation;
. an insurance company;
. a regulated investment company;
. a tax-exempt organization;
. subject to the alternative minimum tax provisions of the Code;
. holding the bonds in a tax-deferred or tax-advantaged account, as part
of a hedge or conversion transaction for tax purposes, a straddle or
other risk reduction or constructive sale transaction;
. a shareholder in, or partner or beneficiary of, an entity that is
holding the bonds;
. not using the U.S. dollar as your functional currency; or
. a nonresident alien or foreign corporation subject to United States
federal income tax on a net-basis with respect to income or gain derived
from a bond because such income or gain is effectively connected with
the conduct of a United States trade or business.
This discussion only describes certain federal income tax consequences that
may apply to you based on current United States federal tax law, including the
Code, Treasury regulations and administrative and judicial interpretations
thereof, any of which may change, possibly retroactively, and which may be
subject to differing interpretations.
This summary may not cover your particular circumstances because it does not
consider foreign, state or local tax laws, may not address certain federal tax
considerations relevant to your particular circumstances or status, and does
not describe future changes in federal tax laws. Please consult your own tax
advisor with respect to the tax consequences of purchasing, owing and disposing
of the bonds in light of your own particular circumstances rather than relying
on this general description.
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 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)(3) of the
Code;
. a corporation (or other entity treated as a corporation for United
States federal income tax purposes) that is created or organized in the
United States or under the laws of the United States or of any political
subdivision of the United States;
117
. 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.
Exchange of Existing Bonds. The exchange of existing bonds for new bonds in
the exchange offer should not be a taxable disposition of the existing bonds,
and there should be no federal income tax consequences to holders upon the
exchange. Any holder should have the same tax basis and holding period in the
new bonds that the holder had in existing bonds immediately before the
exchange.
Taxation of Stated Interest. Generally, you must pay federal income tax on
the interest on the 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 Bonds. You must recognize taxable
gain or loss on the sale, exchange (other than the exchange of existing bonds
for new bonds in the exchange offer), redemption, retirement or other taxable
disposition of a bond. The amount of your gain or loss equals the difference
between the amount you receive for the bond (in cash or other property, valued
at fair market value), less the amount attributable to accrued interest on the
bond, minus your adjusted tax basis in the bond. Your initial tax basis in a
bond equals the price you paid for the bond.
Your gain or loss will generally be a long-term capital gain or loss if you
have held the 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.
Mandatory Redemption Payments. For purposes of determining whether a bond
is a contingent payment debt instrument, remote or incidental contingencies
are ignored. Although it is possible that the Internal Revenue Service could
assert that mandatory redemption payments above par value of the bonds are
"contingent payments," we believe that the likelihood of any such mandatory
redemption is remote and, accordingly, do not intend to treat the bonds as
contingent payment debt instruments. You should, therefore, include any such
payment as ordinary income if it is accrued or paid, in accordance with your
own method of accounting. If, however, such payments are considered
"contingent payments" for United States federal income tax purposes, the bonds
would be treated as contingent payment debt instruments and certain adverse
United States federal income tax consequences could result.
Backup Withholding and Information Reporting. You may be subject to a
backup withholding tax and to information reporting when you receive interest
payments on the bonds or proceeds upon the sale or other taxable disposition
of a bond. Certain holders (including, among others, corporations and certain
tax-exempt organizations) are generally not subject to backup withholding. In
addition, the 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 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 IRS.
118
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 a 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.
Portfolio Interest Exemption. Generally, you will not have to pay United
States federal income tax on interest paid on the 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 BEN (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 bond on your behalf, certifies to us or our agent under
penalties of perjury that it has received IRS Form W-8 BEN (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;
. you are a bank receiving interest described in section 881(c)(3)(A) of
the Code; or
. you do not meet the certification requirements under Code section 871(h)
or 881(c) and related Treasury regulations.
Withholding Tax if the Interest is not within the Portfolio Interest
Exemption. 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 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 IRS Form W-8 BEN.
Sale or Other Disposition of the 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 a 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 an individual who is a former citizen or resident of the United
States, your loss of citizenship or residency occurred within the last
ten years (and, if you are a former resident, on or after February 6,
1995), and it had as one of its principal purposes the avoidance of
United States tax, in which case you may be taxed on the net gain
derived from the sale under the graduated United States federal income
tax rates that are applicable to United States citizens and resident
aliens, and you may be subject to withholding under certain
circumstances.
You generally will not be subject to withholding tax on payments of principal
of the bonds.
119
Backup Withholding and Information Reporting. We report annually to the
Internal Revenue Service and to you the amount of interest paid to, and the tax
withheld, if any, with respect to you. In addition, if a bond is held by a Non-
United States Holder through a United States, or United States related, broker
or financial institution, backup withholding may apply if the Non-United States
Holder fails to provide evidence of Non-United States Holder status. Non-United
States Holders should consult their tax advisors regarding the application of
information reporting and backup withholding in their particular situations and
the availability of, and procedure for obtaining, an exemption, if available.
120
PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC set forth in no-action
letters issued to third parties, we believe that the new bonds may be offered
for resale, resold and otherwise transferred by you without compliance with the
registration and prospectus delivery requirements of the Securities Act
provided that:
. you acquire any new bond in the ordinary course of your business;
. you are not participating, do not intend to participate and have no
arrangement or understanding with any person to participate, in the
distribution of the new bonds;
. you are not a broker-dealer who purchased existing bonds directly from us
for resale under Rule 144A or any other available exemption under the
Securities Act; and
. you are not an "affiliate" (as defined in Rule 405 under the Securities
Act) of our company.
If our belief is inaccurate and you transfer any new bond without delivering
a prospectus meeting the requirements of the Securities Act or without an
exemption from registration of your bonds from these requirements, you may
incur liability under the Securities Act. We do not assume any liability or
indemnify you against any liability under the Securities Act.
Each broker-dealer that is issued new bonds for its own account in exchange
for existing bonds must acknowledge that it will deliver a prospectus meeting
the requirements of the Securities Act in connection with any resale of the new
bonds. A broker-dealer that acquired existing bonds for its own account as a
result of market making or other trading activities may use this prospectus for
an offer to resell, resale or other retransfer of the new bonds.
We will not receive any proceeds from any sale of new bonds by broker-
dealers. New bonds received by broker-dealers for their own account in this
exchange offer may be sold from time to time in one or more transactions in the
over the counter market, in negotiated transactions, through the writing of
options on the new bonds or a combination of such methods of resale, at market
prices prevailing at the time of resale, at prices related to such prevailing
market prices or negotiated prices. Any such resale may be made directly to
purchasers or to or through brokers or dealers who may receive compensation in
the form of commissions or concessions from any such broker-dealer or the
purchasers of any such new bonds. Any broker dealer that resells new bonds that
were received by it for its own account in this exchange offer and any broker
or dealer that participates in a distribution of such new bonds may be deemed
to be an "underwriter" within the meaning of the Securities Act, and any profit
on any such resale of new bonds and any commission or concessions received by
any such persons may be deemed to be underwriting compensation under the
Securities Act. The Letter of Transmittal states that, by acknowledging that it
will deliver and by delivering a prospectus, a broker dealer will not be deemed
to admit that it is an "underwriter" within the meaning of the Securities Act.
For a period of 90 days after the expiration date we will promptly send
additional copies of this prospectus and any amendment or supplement to this
prospectus to any broker dealer that requests such documents in the Letter of
Transmittal. We have agreed to pay all expenses incident to this exchange offer
(including the expenses of one counsel for the holders of the bonds) other than
commissions or concessions of any brokers or dealers and will indemnify the
holders of the bonds (including any broker dealers) against certain
liabilities, including liabilities under the Securities Act.
121
LEGAL MATTERS
Certain legal matters with respect to the bonds offered hereby will be
passed upon by McGuireWoods LLP, our counsel.
EXPERTS
The financial statements included in this prospectus have been audited by
Deloitte & Touche LLP, independent auditors, as stated in their report
appearing herein (which report expresses an unqualified opinion and includes an
explanatory paragraph referring to a change in the method of accounting for
derivatives and hedging transactions), and have been so included in reliance
upon the report of such firm given upon their authority as experts in
accounting and auditing.
The financial statements and the related financial statement schedules
incorporated in this prospectus by reference from Dominion Resources' Annual
Report on Form 10-K for the year ended December 31, 2000 have been audited by
Deloitte & Touche LLP, independent auditors, as stated in their reports, which
are incorporated herein by reference (which express an unqualified opinion and
include an explanatory paragraph relating to changes in accounting principle
for the method of accounting used to develop the market-related value of
pension plan assets, and for the method of accounting for oil and gas
exploration and production activities to the full cost method), and have been
so incorporated in reliance upon the reports of such firm given upon their
authority as experts in accounting and auditing.
The financial statements of Peoples Energy Corporation incorporated in this
prospectus by reference from Peoples Energy Corporation's Annual Report on Form
10-K as of and for the year ended September 30, 2001 have been audited by
Arthur Andersen LLP, independent auditors, as stated in their report, which is
incorporated herein by reference.
INDEPENDENT ENGINEER
Stone & Webster prepared the independent engineer's report included as Annex
B to this prospectus. We include that report in this prospectus in reliance
upon Stone & Webster's conclusions and their experience in the review of the
design, development, construction and operation of electric generation
facilities. You should read the Stone & Webster report in its entirety for
information with respect to the Facility and the related subjects discussed
therein.
INDEPENDENT POWER MARKET AND FUEL CONSULTANT
Pace Global Energy Services, LLC prepared the independent power market and
fuel consultant's reports included as Annex C-1 and Annex C-2 to this
prospectus. We include these reports in this prospectus in reliance upon Pace's
conclusions and their experience in analyzing power markets and fuel supply and
transportation arrangements for independent power projects. You should read the
Pace reports in their entirety for information with respect to the MAIN power
market and the availability of fuel supply and transportation arrangements to
serve our Facility.
122
WHERE YOU CAN FIND MORE INFORMATION
We are not currently subject to the periodic reporting and other information
requirements of the Exchange Act. Upon completion of the exchange offer, we
will become subject to those requirements. We have filed with the SEC a
registration statement under the Securities Act registering the new bonds. This
prospectus does not include all the information contained in the registration
statement. For additional information about us, agreements to which we are a
party and the new bonds, you may refer to the registration statement.
Statements contained in this prospectus as to the contents of any contract or
other document are necessarily not complete; in each instance, if the contract
or other document is filed as an exhibit to the registration statement,
reference is made to the copy so filed, and each statement in this prospectus
is qualified by that reference. A copy of the registration statement, including
exhibits and schedules, is available through the SEC's public reference rooms
or may be accessed through its web site described below.
Dominion Resources, Inc. and Peoples Energy Corporation file annual,
quarterly and special reports and other information with the SEC. Their SEC
filings are available to the public over the Internet at the SEC's web site at
http://www.sec.gov. You may also read and copy any document they file at the
SEC's public reference rooms in Washington, D.C., New York, and Chicago. Please
call the SEC at 1-800-SEC-0330 for further information on the public reference
rooms. You may also read and copy these documents at the offices of the New
York Stock Exchange, 20 Broad Street, New York, New York 10005.
We incorporate by reference the documents listed below and any future
filings made with the SEC by us or by Dominion Resources, Inc. and Peoples
Energy Corporation under Sections 13(a), 13(c), 14, or 15(d) of the Exchange
Act until such time as the offering of securities covered by this prospectus
has been completed:
Dominion Resources, Inc.
. Annual Report on Form 10-K for the year ended December 31, 2000.
. Quarterly Reports on Form 10-Q for the quarters ended March 31, 2001,
June 30, 2001 and September 30, 2001.
. Current Reports on Form 8-K dated January 12, 2001, January 24, 2001,
May 25, 2001, September 10, 2001, November 14, 2001 (as supplemented by
a Current Report on Form 8-K dated January 11, 2002) and January 29,
2002.
Peoples Energy Corporation
. Annual Report on Form 10-K, as amended, for the year ended September 30,
2001.
. Current Reports on Form 8-K dated October 30, 2001 and November 15,
2001.
You may request a copy of these filings, at no cost, by writing or calling
Dominion Resources, Inc. or Peoples Energy Corporation, respectively, at the
following addresses:
Corporate Secretary Peoples Energy Corporation
Dominion Resources, Inc. Attention: Shareholder Services
120 Tredegar Street 130 East Randolph Drive
Richmond, Virginia 23219 Chicago, Illinois 60601
Telephone (804) 819-2000 Telephone (800) 228-6888
123
ELWOOD ENERGY LLC
Financial Statements as of
September 30, 2001 and 2000
and for the years ended
September 30, 2001, 2000 and 1999 and
Independent Auditors' Report
INDEPENDENT AUDITORS' REPORT
To the Management Committee of
Elwood Energy LLC
Elwood, Illinois
We have audited the accompanying consolidated balance sheets of Elwood
Energy LLC and subsidiaries (the "Company") as of September 30, 2001 and 2000,
and the related consolidated statements of operations, members' capital, and
cash flows for each of the three years in the period ended September 30, 2001.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company as of September
30, 2001 and 2000, and the results of its operations and its cash flows for
each of the three years in the period ended September 30, 2001, in conformity
with accounting principles generally accepted in the United States of America.
As discussed in Note 4 to the consolidated financial statements, in 2001 the
Company changed its method of accounting for derivatives and hedging
transactions.
DELOITTE & TOUCHE LLP
Richmond, VA
November 30, 2001
F-1
ELWOOD ENERGY LLC
(A Limited Liability Company)
CONSOLIDATED BALANCE SHEETS
September 30,
--------------------
2001 2000
--------- ---------
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents............................... $ 74 $ 8,553
Accounts receivable..................................... 33,841 9,039
Receivables from affiliated companies................... -- 106
Notes receivable from affiliate......................... 32,406 17,704
Prepaid assets.......................................... -- 60
Inventory--spare parts & other.......................... 244 244
Inventory--fuel......................................... -- 313
Other................................................... -- 1,269
--------- ---------
Total current assets.................................. 66,565 37,288
Property, plant & equipment:
Land.................................................... 3,791 3,765
Plant and equipment..................................... 537,475 187,701
Construction in progress................................ 178 133,477
Accumulated depreciation................................ (27,155) (11,318)
--------- ---------
Net property, plant & equipment....................... 514,289 313,625
Other assets.............................................. 544 --
--------- ---------
Total assets.............................................. $ 581,398 $ 350,913
========= =========
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Accounts payable........................................ $ 2,609 $ 4,374
Payables to affiliatated companies...................... 17,425 2,720
Notes payable to affliliates--current................... 275,843 --
Accrued expenses........................................ 21,886 1,637
Commodity contract liability............................ 18,900 --
Deferred sales tax liability--current................... 770 --
--------- ---------
Total current liabilities............................. 337,433 8,731
Deferred sales tax liability--long term................... 14,437 --
Notes payable to affiliates--long-term.................... -- 130,126
Members' capital:
Members' capital........................................ 248,428 212,056
Accumulated other comprehensive income.................. (18,900) --
--------- ---------
Total members' capital................................ 229,528 212,056
--------- ---------
Total liabilities and members' capital.................... $581,398 $350,913
========= =========
The accompanying notes are an integral part of the financial statements.
F-2
ELWOOD ENERGY LLC
(A Limited Liability Company)
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended
September 30,
-------------------------
2001 2000 1999
-------- ------- -------
(In thousands)
Operating revenues:
Electric sales...................................... $ 88,270 $56,849 $25,593
Gain on settlement of derivative.................... 8,197 -- --
-------- ------- -------
Total operating revenues............................ 96,467 56,849 25,593
Operating expenses:
Fuel................................................ 23,779 16,045 4,439
Operations.......................................... 3,750 2,470 1,248
Depreciation........................................ 15,837 8,233 3,085
General and administrative.......................... 882 371 504
Other taxes......................................... 201 288 61
-------- ------- -------
Total operating expenses............................ 44,449 27,407 9,337
-------- ------- -------
Operating income ................................... 52,018 29,442 16,256
-------- ------- -------
Other income:
Interest income..................................... 1,132 913 51
Interest expense.................................... (3,937) -- --
Other income/(expenses)............................. 1 1 721
-------- ------- -------
Total other income.................................. (2,804) 914 772
-------- ------- -------
Income before cumulative effect of a change in
accounting principle............................... $ 49,214 $30,356 $17,028
-------- ------- -------
Cumulative effect of a change in accounting
principle.......................................... 158 -- --
-------- ------- -------
Net income.......................................... $ 49,372 $30,356 $17,028
-------- ------- -------
Other comprehensive income:
Unrealized loss on interest rate swap............... (18,900) -- --
-------- ------- -------
Comprehensive income................................ $ 30,472 $30,356 $17,028
-------- ------- -------
The accompanying notes are an integral part of the financial statements.
F-3
ELWOOD ENERGY LLC
(A Limited Liability Company)
CONSOLIDATED STATEMENTS OF MEMBERS' CAPITAL
Dominion Peoples
Elwood, Elwood
Total Inc. LLC
-------- -------- --------
(In thousands)
Balance--October 1, 1998.......................... $ 28,347 $ 13,059 $ 15,288
Capital contributions............................. 146,325 74,277 72,048
Net income........................................ 17,028 8,514 8,514
-------- -------- --------
Balance--September 30, 1999....................... $191,700 $ 95,850 $ 95,850
-------- -------- --------
Capital contributions............................. -- -- --
Dividends......................................... (10,000) (5,000) (5,000)
Net income........................................ 30,356 15,178 15,178
-------- -------- --------
Balance--September 30, 2000....................... $212,056 $106,028 $106,028
-------- -------- --------
Capital contributions............................. 20,000 8,000 12,000
Dividends......................................... (33,000) (16,500) (16,500)
Comprehensive Income:
Net income........................................ 49,372 24,723 24,649
Unrealized loss on interest rate swap............. (18,900) (9,450) (9,450)
-------- -------- --------
Balance--September 30, 2001....................... $229,528 $112,801 $116,727
-------- -------- --------
The accompanying notes are an integral part of the financial statements.
F-4
ELWOOD ENERGY LLC
(A Limited Liability Company)
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended September
30,
----------------------------------
2001 2000 1999
---------- ---------- ----------
(In thousands)
Cash flows from operating activities:
Net income................................ $ 49,372 $ 30,356 $ 17,028
Adjustments to reconcile net income to
cash:
Depreciation............................ 15,837 8,233 3,085
Changes in current assets and
liabilities:
Accounts receivable..................... (24,802) 14,753 (23,898)
Receivables from affiliated companies... 106 -- --
Prepaid assets.......................... 60 60 (120)
Inventory--spare parts & other.......... -- (72) (172)
Inventory--fuel......................... 313 615 (928)
Other current assets.................... 1,269 (1,269) --
Other assets............................ (544) -- --
Accounts payable........................ (1,765) 2,240 3,290
Payables to affilitated companies....... 14,705 2,720 --
Construction payable.................... -- (25,008) 25,008
Accrued expenses........................ 20,249 (474) 893
Deferred sales tax liability............ 15,207 -- --
---------- ---------- ----------
Net cash flows from operating activities.. $ 90,007 $ 32,154 $ 24,186
---------- ---------- ----------
Cash flows (used in) from financing
activities:
Capital contributions................... 20,000 -- 146,325
Dividends paid.......................... (33,000) (10,000) --
Cash borrowed on notes payable.......... 145,717 130,126 --
---------- ---------- ----------
Net cash flows (used in) from financing
activities............................... $ 132,717 $ 120,126 $ 146,325
---------- ---------- ----------
Cash flows used in investing activities:
Capital expenditures.................... (216,500) (133,745) (173,032)
Proceeds from sale of fixed assets...... -- -- 7,923
Cash (loaned)/repaid on notes
receivable............................. (14,702) (17,704) 2,300
---------- ---------- ----------
Net cash flows used in investing activi-
ties..................................... $ (231,203) $ (151,449) $ (162,809)
---------- ---------- ----------
Net (decrease) increase in cash........... (8,479) 831 7,702
Cash and cash equivalents at beginning of
year..................................... $ 8,553 7,722 20
---------- ---------- ----------
Cash and cash equivalents at end of year.. $ 74 $ 8,553 $ 7,722
---------- ---------- ----------
The accompanying notes are an integral part of the financial statements.
F-5
ELWOOD ENERGY LLC
(A Limited Liability Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Operations
Elwood Energy LLC (the "Company"), a Delaware limited liability company, was
organized on May 13, 1998. Its Members are Dominion Elwood, Inc., a wholly
owned subsidiary of Dominion Energy Inc. ("DEI"), and Peoples Elwood LLC, an
indirect, wholly-owned subsidiary of Peoples Energy Resource Corp. ("PERC").
Pursuant to an Operating Agreement dated July 23, 1998, Dominion Elwood and
Peoples Elwood became sole members of the Company. Each Member owns a 50%
interest in the profits, losses and distributions made by the Company. In
August 2001, the Company merged with Elwood Energy II, LLC and Elwood Energy
III, LLC, with the Company as the surviving entity. Until August 2001, the
Company owned only Units 1-4; however, as a result of the merger, Units 5-9
were added. See Note 6 to the Consolidated Financial Statements.
During the year ended September 30, 2001, Peoples Elwood LLC contributed $4
million more than Dominion Elwood, Inc. for the purchase of the Unit 9 plant
assets. Therefore, at September 30, 2001, there were unequal capital
contributions between the two Members. It was agreed that preferential
treatment would be given to the $4 million excess contribution, such that upon
any dissolution, Peoples Elwood LLC would receive the entire remaining book
value (if any) of the plant assets or the first $4 million from any proceeds
upon a sale of Unit 9. In November of 2001, Dominion Elwood, Inc. increased its
capital contributions by $4 million (related to the settlement of GE turbine
purchases) thereby equaling the Members' contributions. Thereafter, capital
distributions, income and dividends will be distributed 50% to each member.
The permitted purposes of the Company are: (i) to own and develop 1,409 MW
of simple cycle electric power generating peaking facilities and thereafter up
to 2,500 MW of additional combined cycle and simple cycle electric power
generating facilities located near Elwood, Illinois; (ii) to purchase and sell
fuel, electricity and capacity, and to operate and manage the facility and
(iii) to engage in any other activities permitted by law.
The Company is managed by a Management Committee which has the full,
exclusive and complete authority to manage, direct and control the business and
affairs of the Company. The Management Committee consists of two managers, one
appointed by each Member. Unanimous approval of the managers is required for
the Management Committee to act and each manager has the number of votes equal
to its Member's percentage interest. If the Members reach a material deadlock,
and the senior executives of DEI and PERC are not able to resolve the dispute,
then either party can offer to sell its interest in the Company to the other
Member at a stated price in accordance with the provisions of the Operating
Agreement.
The Company was granted exempt wholesale generator ("EWG") status by the
Federal Energy Regulatory Commission ("FERC") pursuant to the Public Utility
Holding Company Act of 1935 ("PUHCA") on March 5, 1999. The Company is
therefore not considered to be an electric utility for purposes of PUHCA and
accordingly ownership of an interest in an EWG does not subject the owners to
regulation as a utility holding company.
The Federal Power Act ("FPA") gives FERC exclusive rate-making jurisdiction
over virtually all wholesale sales of electricity and the transmission of
electricity in interstate commerce. Pursuant to the FPA, all public utilities
subject to the FERC's jurisdiction are required to file rate schedules with the
FERC prior to commencement of wholesale sales of electricity. Because it will
be making wholesale sales of electricity to Exelon Generation Compay, LLC
("Exelon"), Engage America LLC ("Engage"), Aquila Energy Marketing Corporation
("Aquila") and ultimately to others, the Company is a public utility for
purposes of the FPA.
On February 3, 1999, the Company filed a proposed market-based rate schedule
with the FERC. On April 5, 1999, FERC issued an order accepting the Company's
proposed rate schedule, thereby authorizing the
F-6
ELWOOD ENERGY LLC
(A Limited Liability Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Company to make wholesale sales of electricity at negotiated rates to any party
other than Virginia Power, the electric utility affiliate of DEI. The Company
was allowed to begin making sales under the rate schedule as of April 5, 1999,
the effective date of FERC's order.
The Company is primarily a peaking facility, providing more energy when
demand is highest, generally in the summer months. The Company has contracted
to sell 100% of the generation capacity and electric energy output to Exelon,
Engage and Aquila under power sales agreements with each of them.
The Company's primary fuel is natural gas. Its fuel requirements are served
through three types of contracted services (i) Gas Transportation and Balancing
Services Agreement with NICOR; (ii) physical fuel supply with various market
participants and (iii) the Fuel Management Services Agreement with Cinergy
Marketing & Trading, LLC. As of September 30, 2001 there are no purchase
commitments outstanding for commodity purchases of natural gas.
2. Summary of Significant Accounting Policies
Cash
Cash consists of amounts on deposit net of outstanding checks and deposits
in transit. Cash equivalents include broker margin accounts.
Inventory
Spare parts and fuel inventory are valued at the lower of cost or market,
with cost based on the average valuation method.
Property, Plant & Equipment
Property, plant and equipment is recorded at cost. The costs of major
additions and improvements are capitalized. Replacements, maintenance and
repairs which do not improve or extend the life of the respective assets are
expensed in the period incurred.
Depreciation on the facility is computed using the straight-line method.
Estimated service lives of principal items of property and equipment range from
5 to 30 years.
Whenever events or changes in circumstances indicate that the carrying
amount of long-lived assets may not be recoverable, an evaluation for
impairment is performed. Such evaluations may consider various analyses,
including undiscounted future cash flows attributable to the assets.
Capitalized Interest
Interest is capitalized in connection with the construction of major units.
The capitalized interest is recorded as part of the asset and is depreciated
over the assets' estimated useful life. Interest costs of $8,987,000 and
$2,559,000 were capitalized for the years ended September 30, 2001 and 2000,
respectively.
Income Taxes
Income or loss of the Company for income tax purposes is includable in the
tax returns of the Members. Accordingly, no provision for income taxes has been
made in the accompanying financial statements.
Revenue Recognition
Generation revenue is recognized when electricity is delivered. The Company
records capacity revenues based on estimated operating hours of the plant, in
accordance with Emerging Issues Task Force (EITF) Issue No. 91-6, Revenue
Recognition of Long-Term Power Sales Contracts.
F-7
ELWOOD ENERGY LLC
(A Limited Liability Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from
those estimates.
Derivatives
Under Statement of Financial Accounting Standards (SFAS) No. 133, Accounting
for Derivative Instruments and Hedging Activities, derivatives are recognized
on the Consolidated Balance Sheets at fair value, unless a scope exception is
available under the standard. Commodity contracts representing unrealized gain
positions are reported as commodity contract assets; commodity contracts
representing unrealized losses are reported as commodity contract liabilities.
In addition, purchased options and options sold are reported as commodity
contract assets and commodity contract liabilities, respectively, at estimated
market value until exercise or expiration. Cash flows from derivative
instruments are presented in net cash flow from operating activities.
On the date swaps or option contracts are entered into, the Company either
designates the derivative as held for trading (trading instruments); as a hedge
of a forecasted transaction or future cash flows (cash flow hedges); as a hedge
of a recognized asset, liability, or firm commitment (fair value hedge); as a
normal purchase or sale contract; or leaves the derivative undesignated for
contracts not afforded special hedge accounting.
For all derivatives designated as hedges, the Company formally documents the
relationship between the hedging instrument and the hedged item, as well as the
risk management objective and strategy for the use of the hedging instrument.
The Company assesses, both at the inception of the hedge and on an ongoing
basis, whether the hedge relationship between the derivative and the hedged
item is highly effective in offsetting changes in cash flows. Any change in
fair value of the derivative resulting from ineffectiveness, as defined by SFAS
No. 133, is recognized currently in earnings. Further, for derivatives that
have ceased to be a highly effective hedge, the Company discontinues hedge
accounting prospectively.
For cash flow hedge transactions in which the Company is hedging the
variability of cash flows related to a variable-priced asset, liability,
commitment, or forecasted transaction, changes in the fair value of the
derivative are reported in accumulated other comprehensive income (AOCI). The
gains and losses on the derivatives that are reported in AOCI are reclassified
as earnings in the periods in which earnings are impacted by the variability of
the cash flows of the hedged item. The ineffective portion of the change in
fair value of derivatives and the change in fair value of derivatives not
designated as hedges for accounting purposes are recognized in current-period
earnings. For options designated as cash flow hedges, changes in time value are
excluded from the measurement of hedge effectiveness and are, therefore,
recorded in earnings.
Gains and losses on derivatives designated as hedges, when recognized, are
included in the operating revenue and income, expenses and interest and related
charges in the Consolidated Statements of Income. Specific line item
classification is determined based on the nature of the risk underlying
individual hedge strategies.
F-8
ELWOOD ENERGY LLC
(A Limited Liability Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Prior to the adoption of SFAS No. 133, on October 1, 2000, gains and losses
from the Company's natural gas options, collars and swaps were recognized in
the financial statements as an addition or a reduction to the cost of fuel
expense. Gains of $4 million and $0 were recognized as a reduction to fuel
expense for the years ended September 30, 2000 and 1999, respectively.
Recent Accounting Pronouncements
In July 2001, the Financial Accounting Standards Board (FASB) issued
Statements of Financial Accounting Standards (SFAS) Nos. 141, Business
Combinations, and 142, Goodwill and Other Intangible Assets. SFAS No. 141
requires all business combinations initiated after June 30, 2001 to be
accounted for using the purchase method of accounting, thus eliminating the use
of the "pooling" method of accounting. Under SFAS No. 142, goodwill is no
longer subject to amortization; instead it will be subject to new impairment
testing criteria. Other intangible assets will continue to be amortized over
their estimated useful lives, although those with indefinite lives are not to
be amortized but will be tested at least annually for impairment. The new
standards also provide new guidance regarding the identification and
recognition of intangible assets, other than goodwill, acquired as part of a
business combination. The Company will adopt these standards effective
January 1, 2002. At September 30, 2001, the Company had no material goodwill or
other intangible assets, obtained in business combinations, on its books.
In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations, which provides accounting requirements for the recognition and
measurement of liabilities for obligations associated with the retirement of
tangible long-lived assets. Under the standard, these liabilities will be
recognized at fair value as incurred and capitalized as part of the cost of the
related tangible long-lived assets. Accretion of the liabilities due to the
passage of time will be expensed. The Company will adopt this standard
effective January 1, 2003. The Company has not performed a complete assessment
of possible retirement obligations associated with long-lived assets and has
not yet determined the impact of adopting this new standard.
In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets, which provides guidance that will eliminate
inconsistencies in accounting for the impairment or disposal of long-lived
assets under existing accounting pronouncements. The Company will apply the
provisions of this standard prospectively beginning January 1, 2002 and does
not expect the adoption to have a material impact on its results of operations
or financial condition.
Reclassification
Certain amounts in the 2000 and 1999 Consolidated Financial Statements have
been reclassified to conform to the 2001 presentation.
3. Related Parties
During 2001, 2000 and 1999 the Company incurred costs of $1,501,000,
$1,040,000 and $422,000, respectively, under the Operation and Maintenance
Agreement with Dominion Elwood Services Company, Inc. At September 30, 2001 and
2000, $1,362,000 and $406,000, respectively, was included in payables to
affiliated companies related to these costs. Dominion Elwood Services Company
is a wholly owned subsidiary of DEI.
During 2001, 2000 and 1999 the Company incurred costs of $572,000, $235,000
and $237,000, respectively, for general management services from DEI under the
provisions of Article IV of the Operating Agreement between Peoples Elwood and
Dominion Elwood. At September 30, 2001 and 2000, $677,000 and $162,000,
respectively, was included in payables to affiliated companies related to these
costs.
F-9
ELWOOD ENERGY LLC
(A Limited Liability Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
During 2001, 2000 and 1999 the Company incurred costs of $435,000, $203,000
and $384,000, respectively, for reimbursement of legal and other expenses
provided through PERC. At September 30, 2001 and 2000, $26,000 and $10,000,
respectively, was included in payables to affiliated companies related to these
costs.
The Company made advances to DEI during 2001 and 2000. At September 30, 2001
and 2000 advances were $14,702,000 and $17,704,000, respectively. The related
accrued interest receivables at September 30, 2001 and 2000 were $97,000 and
$105,000, respectively.
In connection with the construction of Units 5-9, the Company has borrowed
funds under separate notes payable from both DEI and PERC. The total amounts
payable to DEI at September 30, 2001 and 2000 were $135,950,000 and
$63,284,000, respectively. The total amounts payable to PERC at September 30,
2001 and 2000 were $139,893,000 and $63,284,000, respectively. The related
accrued interest payables to DEI at September 30, 2001 and 2000 were $7,759,000
and $1,281,000, respectively. The related accrued interest payables to PERC at
September 30, 2001 and 2000 were $7,723,000 and $1,277,000, respectively.
Interest on related party advances and notes payable is calculated using
DEI's internal borrowing rate. As of September 30, 2001 and 2000, the average
interest rate was 5.4% and 6.9%, respectively.
The Company entered into an Easement Agreement to construct, maintain and
operate an electric transmission line on property maintained by The Peoples Gas
Light and Coke Company for a one-time fee of $43,000.
4. Derivatives and Hedge Accounting
Adoption of SFAS No. 133
The Company adopted SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, as amended by SFAS No. 138, Accounting for Certain
Derivative Instruments and Certain Hedging Activities, on October 1, 2000. In
accordance with the transition provisions of SFAS 133, the Company recorded a
cumulative effect adjustment of $158,600 as a reduction in earnings. The
cumulative effect adjustment reducing accumulated other comprehensive income
(AOCI) and Member's Capital was $2,450,000. The Company reclassified this
entire AOCI amount to earnings during the year ended September 30, 2001 due to
derivatives designated as cash flow hedges that were sold.
Derivatives and Hedge Accounting Results
The Company did not recognize any decreases to earnings for hedge
ineffectiveness during the year ended September 30, 2001. The Company
recognized $673,000 as fuel expenses related to the time value of natural gas
option contracts purchased.
Approximately $18.9 million of net losses in AOCI at September 30, 2001 is
expected to be reclassified to earnings over the life of the bonds discussed in
Note 7. The actual amounts that will be reclassified to earnings over the life
of the bonds will vary from this amount as a result of changes in market
conditions. The effect of the amounts being reclassified from AOCI to earnings
will generally be offset by the recognition of the hedged transactions (e.g.,
anticipated sales) in earnings, thereby achieving the realization of prices
contemplated by the underlying risk management strategies. As of September 30,
2001, the Company is hedging its exposure to the variability in future cash
flows for forecasted transactions over 25 years.
F-10
ELWOOD ENERGY LLC
(A Limited Liability Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Currently, there are ongoing discussions surrounding the implementation and
interpretation of SFAS No. 133 by the Financial Accounting Standards Board's
(FASB) Derivative Implementation Group. In June 2001, the FASB approved Issue
C15, "Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-
Type Contracts and Forwards Contracts in Electricity." Under the guidance of
Issue C15, buyers and sellers of electricity are not required to mark-to-market
contracts meeting certain criteria. Option-type contracts include capacity
contracts that allow the Company's customers to meet volatile demand by
providing the option to purchase electricity as needed. The FASB concluded if
such contracts meet the criteria outlined in Issue C15, they could qualify as a
normal purchase or sale under SFAS No. 133. This new SFAS No. 133
implementation guidance became effective July 1, 2001. In response to this
guidance, the Company reevaluated certain of its long-term power sale
agreements. Based on this reevaluation, the Company determined that such
agreements qualify for the normal purchases and normal sales exception based on
the criteria set forth in the recently issued guidance. As such, these
agreements continue to be exempt from fair value accounting otherwise required
by SFAS No. 133. On October 10, 2001, the FASB made certain editorial changes
to the qualifying criteria outlined in Issue C15. The revised guidance becomes
effective January 1, 2002. The Company is currently in the process of
evaluating the significance of these editorial changes to determine whether
certain of its long-term power sale agreements will continue to qualify for the
normal purchases and normal sales exception at the effective date of the
revised guidance.
Future interpretations of SFAS No. 133 by the FASB or other standard-setting
bodies could result in fair value accounting being required for certain
contracts that are not currently being subjected to such requirements.
Accordingly, such future interpretations may impact the Company's ultimate
application of the standard. However, if future changes in the application of
SFAS No. 133 should result in additional contracts becoming subject to fair
value accounting under SFAS No. 133, the Company would pursue hedging
strategies to mitigate any potential future volatility in reported earnings.
5. Financial Instruments
Fair Values
The fair value amounts of the Company's financial instruments have been
determined using available market information and valuation methodologies
deemed appropriate in the opinion of management. However, considerable judgment
is required to interpret market data to develop the estimates of fair value.
Accordingly, the estimates presented herein are not necessarily indicative of
the amounts that the Company could realize in a current market exchange. The
use of different market assumptions and/or estimation assumptions may have a
material effect on the estimated fair value amounts.
Cash and Notes Receivable
The carrying amount of these items is a reasonable estimate of their fair
value.
Derivatives and Price Risk Management Activities
The Company uses derivatives to manage the commodity and financial market
risks of its business operations. The Company managed the commodity price risk
associated with the purchase of natural gas by utilizing derivative commodity
instruments including commodity natural gas options, collars and swaps.
Effective with the amendment of the Exelon and Engage power sales agreements in
2001 to effectively change to tolling agreements, fuel price risk has been
eliminated. The Company does continue to manage its interest rate risk exposure
by entering into interest rate swap transactions.
F-11
ELWOOD ENERGY LLC
(A Limited Liability Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company has designated all current derivatives as cash flow hedges. The
Company's hedge strategies represent cash flow hedges of the variable price
risk associated with purchases of natural gas and of variable interest rates on
long-term debt using derivative instruments discussed in the preceding
paragraph.
Interest Rate Swap
In August 2001, the Company entered into an interest rate swap as a hedge
against interest rate fluctations. A loss of $18.9 million was recorded in AOCI
for the year ended September 30, 2001.
Options Contracts
At September 30, 2000, the Company utilized call options contracts covering
2,440,000 mmBTUs of gas maturing in 2001 and a collar covering 1,220,000 mmBTUs
of gas expiring in 2002. The Company's net unrealized gain related to its use
of options contracts was approximately $1.8 million at September 30, 2000.
These options were sold in 2001 and a gain of $8 million was recognized in
earnings.
OTC Swap Agreements
In addition to options contracts, the Company entered into OTC price swap
agreements to manage its exposure to commodity price risk for the anticipated
future purchases of gas. At September 30, 2000, the Company had swap agreements
maturing in 2003 and 2004. Net notional quantities at September 30, 2000
related to those swap agreements in which the Company agreed to pay a fixed
price in exchange for a variable price totaled 3,680,000 mmBTUs. The Company's
unrealized gain related to swap agreements was approximately $0.7 million at
September 30, 2000.
Market and Credit Risk
Price risk management activities expose the Company to market risk. Market
risk represents the potential loss that can be caused by the change in market
value of a particular commitment.
Price risk management activities also expose the Company to credit risk.
Credit risk represents the potential loss that the Company would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with respect to
its counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition. The Company also monitors the financial condition of existing
counterparties on an ongoing basis. Considering the system of internal controls
in place, the Company believes it is unlikely that a material adverse effect on
its financial position, results of operations or cash flows would occur as a
result of counterparty nonperformance.
F-12
ELWOOD ENERGY LLC
(A Limited Liability Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
6. Common Control Merger
On August 3, 2001, Elwood Energy LLC merged with Elwood Energy II, LLC and
Elwood Energy III, LLC, with Elwood Energy LLC as the surviving entity. All of
the entities that participated in the merger were owned 50% by Dominion Elwood,
Inc. and affiliates and 50% by Peoples Elwood, LLC and affiliates. The merger
has been accounted for on the historical cost basis and the financial
statements for all periods presented have been combined. The separate condensed
financial statements of Elwood Energy LLC, Elwood Energy II, LLC and Elwood
Energy III, LLC were as follows for each year ended:
September 30, September 30, September 30,
2001 2000 1999
------------- ------------------------------ ------------------------------
Elwood Elwood Elwood II Elwood III Elwood Elwood II Elwood III
------------- -------- --------- ---------- -------- --------- ----------
Operating revenues...... $ 96,467 $ 56,849 $ -- $ -- $ 25,593 $-- $ --
Operating expenses...... (44,449) (27,262) -- (145) (9,337) -- --
Other income............ (2,804) 914 -- -- 772 -- --
Cumulative effect of
accounting change...... 158 -- -- -- -- 1 --
-------- -------- ------- ------- -------- ---- -----
Net income (loss)....... $ 49,372 $ 30,501 $ -- $ (145) $ 17,028 $ 1 $ --
======== ======== ======= ======= ======== ==== =====
Current assets.......... $ 66,565 $ 35,959 $ 505 $ 824 $ 32,840 $-- $ --
Property, plant &
equipment.............. 514,289 180,861 51,630 81,134 188,113 -- --
Other assets............ 544 -- -- -- -- -- --
-------- -------- ------- ------- -------- ---- -----
Total assets........... $581,398 $216,820 $52,135 $81,958 $220,953 $-- $ --
======== ======== ======= ======= ======== ==== =====
Liabilities............. $351,870 $ 4,619 $52,234 $82,004 $ 29,253 $-- $ --
Members' capital........ 229,528 212,201 -- (145) 191,700 -- --
-------- -------- ------- ------- -------- ---- -----
Total liabilities and
members' capital...... $581,398 $216,820 $52,234 $81,859 $220,953 $-- $ --
======== ======== ======= ======= ======== ==== =====
7. Subsequent Events
On October 23, 2001, the Company issued $402,000,000 of 8.159% Senior
Secured Bonds due 2026. The proceeds of the bonds were used to repay notes due
to affiliates and for working capital.
F-13
ELWOOD ENERGY LLC
(A Limited Liability Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
8. Quarterly Financial Data (unaudited)
The following amounts reflect all adjustments, consisting of only normal
recurring accruals, necessary in the opinion of the Company's management for a
fair statement of the results for the interim periods.
2001 2000
------- ------
(thousands)
Operating Revenues
First Quarter.............................................. 5,821 3,731
Second Quarter............................................. 16,731 13,372
Third Quarter.............................................. 9,371 13,151
Fourth Quarter............................................. 64,544 26,595
------- ------
Year....................................................... 96,467 56,849
======= ======
Operating Income
First Quarter.............................................. 2,729 3,346
Second Quarter............................................. 15,106 9,591
Third Quarter.............................................. 6,924 7,799
Fourth Quarter............................................. 27,259 8,706
------- ------
Year....................................................... 52,018 29,442
======= ======
Income before cumulative effect of a change in accounting
principle
First Quarter.............................................. 1,853 3,301
Second Quarter............................................. 13,219 7,790
Third Quarter.............................................. 5,474 5,888
Fourth Quarter............................................. 28,668 13,377
------- ------
Year....................................................... 49,214 30,356
======= ======
Net income
First Quarter.............................................. 2,084 3,301
Second Quarter............................................. 13,146 7,790
Third Quarter.............................................. 5,474 5,888
Fourth Quarter............................................. 28,668 13,377
------- ------
Year....................................................... 49,372 30,356
======= ======
Other Comprehensive Income
First Quarter.............................................. 4,780 --
Second Quarter............................................. (4,780) --
Third Quarter.............................................. -- --
Fourth Quarter............................................. (18,900) --
------- ------
Year....................................................... (18,900) --
======= ======
F-14
Annex A
ANNEX A--DEFINITIONS
"Buy-Out" means the exercise by a counterparty to a power sales agreement
of a right to pay us to terminate the power sales agreement or to reduce
capacity and energy to be sold under the power sales agreement.
"Cash Available for Debt Service" means, for any period, all operating
revenues (excluding any receipts derived from the sale of any property (other
than energy, capacity, ancillary services, fuel or fuel transportation rights)
pertaining to the Facility) received, or to be received, during such period,
minus (i) all O&M Costs paid, or to be paid, during such period and (ii) all
deposits, if any, made, or to be made, into the sales tax reserve account and
the major maintenance reserve account during such period (other than deposits
into the major maintenance reserve account out of Bond proceeds).
"Casualty Event" means an event that causes all or a portion of the
Facility to be damaged, destroyed or rendered unfit for normal use for any
reason whatsoever, other than an Expropriation Event or a Title Event.
"Change of Control" means DEI (or Dominion Resources or any successor
entity to DEI which is a majority owned subsidiary of Dominion Resources) and
PERC (or Peoples Energy Corporation or any successor entity to PERC which is a
majority owned subsidiary of Peoples Energy Corporation), collectively, shall
cease to own, directly or indirectly, at least 50.1% of the membership
interests in us; provided that such failure to own shall not be deemed a "Change
of Control" if (x) such failure to own resulted from a transfer to a Qualified
Transferee or (y) such events are approved by holders holding at least 66 2/3%
in aggregate principal amount of the outstanding Bonds.
"Closing Date" means the date on which the Bonds are issued and
delivered.
"Commercially Feasible Basis" means that, following a Loss Event:
o the proceeds received in respect of that Loss Event, together with
any other amounts that we are irrevocably committed, or irrevocably
commit, to contribute to restoring all or a portion, as the case may
be, of the Facility, will be sufficient to permit the restoration of
the Facility;
o the sum of (a) the proceeds of the business interruption insurance
which we have received, (b) the moneys available in the O&M account,
(c) any amounts that we are irrevocably committed, or irrevocably
commit, to contribute (without duplication of the amounts referred
to in the previous bullet point) and (d) our anticipated operating
revenues during the estimated period of restoration will be
sufficient to pay all Debt Service and O&M Costs (taking into
account the limitation on the use of such funds set forth in the
Deposit and Disbursement Agreement) during the estimated period of
restoration; and
o we reasonably believe that the Facility 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.
"Contracted Cash Available for Debt Service" means, for any period, the
aggregate of all payments to be received by us under Permitted PPAs for such
period, plus interest income attributable to units subject to such Permitted
PPAs for such period, minus (i) all O&M Costs attributable to units subject to
such Permitted PPAs for such period and (ii) all deposits, if any, into the
sales tax reserve account for such period.
"Contracted Coverage Ratio" means, for any period, the ratio of (i) the
aggregate of all Contracted Cash Available for Debt Service for such period to
(ii) the aggregate of all Debt Service for such period, in each case calculated
on a projected basis and confirmed by the independent engineer.
"Debt Service" means, for any period, without duplication, (i) the
aggregate of all fees payable to the Secured Parties in respect of Indebtedness
permitted under the indenture during such period, plus (ii) the aggregate of all
principal, premium (if any) and interest payable with respect to outstanding
Indebtedness that is
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permitted under the indenture (other than subordinated indebtedness and
intercompany indebtedness existing on the closing date between us and our
subsidiaries) for such period, plus (iii) the aggregate amount of overdue
principal, premium (if any) and interest payments owed with respect to
outstanding Indebtedness that is permitted under the indenture (other than
subordinated indebtedness) from previous periods, all as determined on a cash
basis in accordance with GAAP.
"Debt Service Coverage Ratio" means, for any period, the ratio of (i) the
aggregate of all Cash Available for Debt Service for such period to (ii) the
aggregate of all Debt Service for such period.
"Discounted Present Value" of any Bond subject to redemption shall be
equal to the present value of all principal and interest payments scheduled to
become due in respect of such Bond after the date of such redemption (excluding
accrued interest to the date of redemption) discounted to the date of redemption
on a semiannual basis (assuming a 360-day year consisting of twelve 30-day
months), at a discount rate equal to the sum of (x) the yield to maturity on the
United States treasury securities having an interpolated maturity equal to the
remaining average life of such Bond and trading in the secondary market at the
price closest to par and (y) 50 basis points. However, if there is no United
States treasury security having an interpolated maturity equal to the remaining
average life of such Bond, such discount rate shall be calculated using a yield
to maturity interpolated or extrapolated on a straight-line basis (rounding to
the nearest month, if necessary) from the yields to maturity for two United
States treasury securities having average lives most closely corresponding to
the remaining average life of such Bond and trading in the secondary market at
the price closest to par.
"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 or entity acting under power of eminent
domain unless such transfer or taking is being contested in good faith.
"Loss Event" means a Casualty Event, an Expropriation Event or a Title
Event.
"Indebtedness" of any person at any date means, without duplication, (i)
all obligations of such person for borrowed money, (ii) all obligations of such
person evidenced by bonds, debentures, notes or other similar instruments, (iii)
all obligations of such person to pay the deferred purchase price of property or
services, except trade accounts payable arising in the ordinary course of
business, (iv) all obligations of such person under leases which are or should
be, in accordance with GAAP, recorded as capital leases in respect of which such
person is liable to the extent of the capitalized amount thereof determined in
accordance with GAAP, (v) all obligations of such person under interest rate or
currency protection agreements or other hedging instruments, (vi) all
obligations of such 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), (vii) all deferred obligations of such person to
reimburse any bank or other person in respect of amounts paid or advanced under
a letter of credit or other instrument, (viii) all Indebtedness of others
secured by a lien on any asset of such person, whether or not such Indebtedness
is assumed by such person, and (ix) all Indebtedness of others guaranteed
directly or indirectly by such person or as to which such person has an
obligation substantially the economic equivalent of a guarantee or other
arrangement to assure a creditor against loss.
"Involuntary Buy-Out" means any Buy-Out of a power sales agreement that is
not voluntarily sought by us, but into which we are legally or practically
required to enter by force of law or regulation, or by an 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
such power sales agreement on the part of, or an actual or threatened
termination of such power sales agreement by, the purchaser of electricity under
such power sales agreement.
"Make-Whole Premium" means an amount equal to the Discounted Present Value
calculated on the third business day before the redemption date 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.
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"Material Adverse Effect" means:
o a material adverse change in the status of our business, operations,
property or financial condition; or
o any event or occurrence of whatever nature which materially
adversely affects (a) our ability to perform our obligations under
any financing document or any material project document or (b) the
perfection, validity or priority of the Secured Parties' security
interests in the collateral.
"Maximum PSA Contingency Amount" means, at any time, an amount equal to
the difference between (a) the aggregate principal amount of the Bonds then
Outstanding and (b) the Maximum PSA Yearly Factor.
"Maximum PSA Yearly Factor" means, as applicable, (i) through 2017,
$45,000,000, (ii) in 2018, $40,000,000, (iii) in 2019, $40,000,000, (iv) in
2020, $42,000,000, (v) in 2021, $32,500,000, (vi) in 2022, $17,000,000 and (vii)
in 2023, $15,000,000.
"New Generation Facility" means a new electric generation facility to be
constructed and/or owned by one or more of our affiliates, by affiliates of our
members (but not by us), or by a third party, on all or part of the parcels of
land adjacent to our Facility site.
"O&M Costs" means, for any period, the sum, computed without duplication,
of the following: all cash expenses incurred by us during such period for
maintenance, administration and operation of the Facility, including payments
made by us in respect of fuel or fuel transportation, taxes (other than those
based on our income), insurance and consumables, payments under any leases or
pursuant to the O&M Agreement, the equipment sales agreements, the Common
Facilities Agreement and the Administrative Services Agreements, legal fees and
expenses paid by us in connection with the management, maintenance or operation
of the Facility, fees paid in connection with obtaining, transferring or
amending any governmental approvals, and reasonable general and administrative
expenses. However, O&M Costs shall not include:
o any non-cash charges, including depreciation or obsolescence charges
or reserves therefor, or amortization or other bookkeeping entries
of a similar nature;
o Debt Service and all other interest and principal payable on
Indebtedness permitted under the indenture;
o expenditures for major maintenance of the Facility to the extent
paid with funds on deposit in or credited to the account of the
major maintenance reserve account;
o payments into any of the accounts established under the Deposit and
Disbursement Agreement;
o the cost of restorations of the Facility;
o distributions of any kind to us or our affiliates or payments on, or
amounts due in respect of, subordinated indebtedness;
o capital expenditures (whether or not such expenditures are for major
maintenance of the Facility) other than those included in and
approved as part of our annual operating budget and not funded with
Indebtedness permitted under the indenture; and
o taxes paid with funds on deposit in the sales tax reserve account.
"Permitted Investments" means:
o 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 90 days from the date of issuance;
o time deposits and certificates of deposit having a maturity not
exceeding 90 days of any domestic commercial bank of recognized
standing having capital and surplus in excess of $500,000,000;
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o commercial paper issued by the parent corporation of any domestic
commercial bank of recognized standing having capital and surplus in
excess of $500,000,000 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 90 days from the date of
acquisition;
o fully secured repurchase obligations with a term not exceeding seven
days for underlying securities of the types described in the first
bullet point above entered into with any bank meeting the
qualifications established in the second bullet point above;
o high-grade corporate bonds rated at least "AA" or the equivalent
thereof by S&P or at least "Aa2" or the equivalent thereof by
Moody's; and
o money market funds having a rating in the highest investment
category granted thereby by S&P or Moody's 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 such
funds for services rendered (provided that such 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.
"Permitted PPA" means:
(i) an arms-length, executed, valid and binding agreement that is
then in full force and effect and not in default in any material respect
and which is not terminable without cause between us and either:
(A) a purchaser (including any of our affiliates) whose (or if
the purchaser's obligations are unconditionally guaranteed, whose
guarantor's) long-term senior unsecured debt is rated no less than
"Baa3" by Moody's and "BBB-" by S&P; or
(B) an affiliate of ours, so long as such affiliate has
executed a valid and binding agreement with a third party purchaser
whose (or if the purchaser's obligations are unconditionally
guaranteed, whose guarantor's) long-term senior unsecured debt is
rated no less than "Baa3" by Moody's and "BBB-" by S&P with
substantially the same terms (other than any pricing spread) as such
affiliate's agreement with us;
in each case, for the sale of electric energy or capacity (in the case of
both energy and capacity, on a take or pay, take and pay, or take, if
tendered basis) at prices established at a formula, index or other price
risk management methodology not based on spot market prices (unless such
agreement is structured such that it (or it together with a financial hedge
arrangement of the type described in clause (ii) below) creates an
arrangement that is the functional equivalent of a tolling arrangement or
other contractual arrangement not dependent on spot market prices) by us to
such third party or such affiliate, as applicable; or
(ii) financial hedge agreements relating to energy or capacity
pricing that are:
(A) fully supported by our available energy or capacity; and
(B) with counterparties having long-term senior unsecured debt
that is rated no less than "Baa2" by Moody's and "BBB" by S&P;
However, notwithstanding anything to the contrary contained in this
definition, each of our power sales agreement in existence on the Closing Date
will be deemed a Permitted PPA.
"Projected Debt Service Coverage Ratio" means, for any period, the ratio
of (i) the aggregate of all Cash Available for Debt Service for such period to
(ii) the aggregate of all Debt Service for such period, in each case calculated
by us on a projected basis and confirmed in writing by the independent engineer.
"PSA Contingency Reserve Amount" means:
(i) $0, if, on the funding date immediately preceding the applicable
bond payment date, either (a) the average Contracted Coverage Ratio for
the consecutive period of the lesser of (x) sixteen full fiscal
A-4
quarters following such scheduled bond payment date and (y) the number of
full fiscal quarters from such scheduled bond payment date until the first
scheduled bond payment date in 2024, in either case taken as a whole, is
equal to or greater than 1.40 to 1.0 or (b) the PSA Coverage Ratio for the
six fiscal quarter period immediately preceding such scheduled bond
payment date, taken as a whole, is greater than or equal to the PSA
Historical Ratio and the Projected PSA Coverage Ratio for the consecutive
period of the lesser of (x) sixteen full fiscal quarters following such
scheduled bond payment date and (y) the number of full fiscal quarters
from such scheduled bond payment date until the first scheduled bond
payment date in 2024, in either case taken as a whole, is greater than or
equal to the PSA Projected Ratio; or
(ii) if the requirement set forth in clause (i) above has not been
satisfied, 25% of the Maximum PSA Contingency Amount, if, on the funding
date immediately preceding the applicable bond payment date, the average
Contracted Coverage Ratio for the consecutive period of the lesser of (x)
sixteen full fiscal quarters following such scheduled bond payment date
and (y) the number of full fiscal quarters from such scheduled bond
payment date until the first scheduled bond payment date in 2024, in
either case taken as a whole, is equal to or greater than 1.25 to 1.0; or
(iii) if the requirements set forth in clauses (i) or (ii) above
have not been satisfied, 33 1/3 % of the Maximum PSA Contingency Amount,
if, on the funding date immediately preceding the applicable bond payment
date, the average Contracted Coverage Ratio for the consecutive period of
the lesser of (x) sixteen full fiscal quarters following such scheduled
bond payment date and (y) the number of full fiscal quarters from such
scheduled bond payment date until the first scheduled bond payment date in
2024, in either case taken as a whole, is equal to or greater than 1.1 to
1.0; or
(iv) if the requirements set forth in clauses (i), (ii) or (iii)
above have not been satisfied, the Maximum PSA Contingency Amount.
"PSA Contingency Reserve Requirement" means, for any date of
determination, an amount equal to (i) the PSA Contingency Reserve Amount, as
determined on the scheduled bond payment date immediately preceding such date of
determination (or on such date of determination, if such date is a scheduled
bond payment date), less (ii) monies already on deposit in the PSA contingency
reserve account and/or the aggregate amounts of any applicable letters of credit
or guarantees.
"PSA Coverage Ratio" means, for any period, the ratio of (i) the aggregate
of all Cash Available for Debt Service for such period plus all deposits, if
any, made to the major maintenance reserve account for such period, to (ii) the
aggregate of all Debt Service for such period.
"PSA Historical Ratio" means, for any date of determination, (x) (i) 4.0
minus (ii) 2.6 times the percentage of the Facility's capacity that is covered
by Permitted PPAs for the six-quarter period, taken as a whole, immediately
preceding such date of determination, to (y) 1.0.
"PSA Projected Ratio" shall mean, for any date of determination, (x) (i)
4.0 minus (ii) 2.6 times the percentage of the Facility's capacity that is
covered by Permitted PPAs for the sixteen-quarter (or less, if applicable)
period, taken as a whole, immediately following such date of determination to
(y) 1.0.
"Projected PSA Coverage Ratio" means, for any period, the ratio of (i) the
aggregate of all Cash Available for Debt Service for such period plus all
deposits, if any, made or to be made to the major maintenance reserve account
for such period, to (ii) the aggregate of all Debt Service for such period, in
each case calculated by us on a projected basis and confirmed by the independent
engineer.
"Qualified Transferee" means any person that acquires after the Closing
Date, directly or indirectly, ownership of membership interests in us so long
as:
o the acquiring person has, or is controlled by a person that has, (a)
significant experience in the business of owning and operating
facilities similar to the Facility and (b) a senior unsecured credit
rating of at least "BBB-" from S&P and "Baa3" by Moody's;
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o after giving effect to the acquisition, no default or event of
default has occurred and is continuing under the indenture;
o the acquisition could not reasonably be expected to result in a
Material Adverse Effect;
o to the extent relevant to the acquisition, the collateral agent
receives a pledge of and lien on our membership interests in
accordance with the security documents and we have furnished to the
trustee and the collateral agent such documents, certificates and
opinions of counsel as the trustee and the collateral agent shall
reasonably require; and
o each of S&P and Moody's confirms that the acquisition will not
result in a downgrade of the then current ratings on the Bonds.
"Sales Tax Reserve Requirement" means (i)(x) $350,000 times (y) the number
of quarters the requirement to make deposits into the sales tax reserve account
has been in effect, less (ii) monies already on deposit in the sales tax reserve
account and/or the aggregate amounts of any applicable letters of credit or
guarantees.
"Secured Parties" means the trustee, the holders of the Bonds, the
collateral agent, the administrative agent, the securities intermediary under
the indenture, any bank or agent providing working capital loans to us, any
provider of a DSR letter of credit (including any bank or agent party to an
underlying debt service letter of credit agreement), any holder of Indebtedness
permitted under the indenture in respect of required modifications or optional
modifications (including any agent party to an agreement in respect of such
indebtedness), in each case to the extent such party (or an agent on its behalf)
is, or pursuant to the intercreditor agreement becomes, a party to the
intercreditor agreement.
"Senior Secured Obligations" means, collectively, without duplication: (i)
all of our Indebtedness, financial liabilities and obligations, of whatsoever
nature and howsoever evidenced (including, but not limited to, principal,
interest, fees, reimbursement obligations, penalties, indemnities and legal and
other expenses, whether due after acceleration or otherwise) to the Secured
Parties in their capacity as such under the applicable financing document or any
other agreement, document or instrument evidencing, securing or relating to such
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; (ii) any and all sums advanced by the
collateral agent in order to preserve the collateral or preserve its security
interest in the collateral; and (iii) in the event of any proceeding for the
collection or enforcement of the obligations described in clauses (i) and (ii)
above, after an event of default under the indenture 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.
"Shared Facilities" means roads, easements, fuel and utility lines and
pipes, transmission lines and interconnects, water disposal and treatment
systems, control systems, permits and other property or rights which (or, in
the case of easements and roads, the underlying property of which) are owned or
leased by us and as to which we have granted a license or right of use for the
benefit of a New Generation Facility.
"Shared Facilities Agreement" means an agreement between us and the owner
or lessee of a New Generation Facility relating to the use of any Shared
Facilities.
"Title Event" means the existence of any defect of title or lien or
encumbrance on the real property subject to the mortgage granted by us in favor
of the collateral agent (other than liens permitted under the indenture and in
effect on the Closing Date) that entitles the collateral agent to make a claim
under the title policies.
"Voluntary Buy-Out" means any Buy-Out of a power sales agreement that is
not an Involuntary Buy-Out.
Annex B
Independent Engineer's Report
INDEPENDENT TECHNICAL REVIEW
ELWOOD ENERGY POWER PROJECT
For
ELWOOD ENERGY LLC
And
CREDIT SUISSE FIRST BOSTON
J.O. 12832
Copyright 2001
Stone & Webster Consultants, Inc
Denver, Colorado
October 12, 2001
Revised January 23, 2002
TABLE OF CONTENTS
Section # Page #
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SECTION 1.0 ........................................................................ 1
EXECUTIVE SUMMARY .................................................................. 1
1.1 INTRODUCTION
1.2 SCOPE OF SERVICES ...................................................... 1
1.3 TECHNICAL DESCRIPTION OF ASSETS ........................................ 2
1.4 PROJECT DESIGN AND CONDITION OF ASSETS ................................. 3
1.5 PERFORMANCE ............................................................ 4
1.6 POWER SALES AGREEMENTS ................................................. 4
1.7 FUEL SUPPLY AND MANAGEMENT ............................................. 5
1.8 GAS TRANSPORTATION AND BALANCING ....................................... 6
1.9 OPERATION AND MAINTENANCE .............................................. 6
1.10 ENVIRONMENTAL AND SITE ASSESSMENT ...................................... 6
1.11 REMAINING LIFE ......................................................... 7
1.12 FINANCIAL PROJECTIONS .................................................. 7
1.13 CONCLUSIONS ............................................................ 8
SECTION 2.0 ........................................................................ 10
PROJECT DESIGN .................................................................... 10
2.1 ELECTRIC POWER GENERATION EQUIPMENT .................................... 10
2.2 AUXILIARY PLANT SYSTEMS ................................................ 13
2.3 STATION ELECTRICAL SYSTEMS ............................................. 15
2.4 CIVIL, STRUCTURAL AND ARCHITECTURAL .................................... 17
SECTION 3.0 ........................................................................ 18
CONTRACTS AND AGREEMENTS .......................................................... 18
3.1 ENGINEERING, PROCUREMENT AND CONSTRUCTION (EPC)
AGREEMENTS ............................................................. 18
3.2 ENGINEERING, DESIGN, PROCUREMENT, CONSTRUCTION AND
INSTALLATION SERVICES (EPC) AGREEMENTS ................................. 18
3.3 PROCUREMENT AGREEMENTS - UNITS 5 AND 6 (Amended and Restated) .......... 21
3.4 PROCUREMENT AGREEMENTS - UNITS 7 AND 8 (Amended and Restated) .......... 22
3.5 PROCUREMENT AGREEMENT - UNIT 9 (Amended and Restated) .................. 23
3.6 ENGAGE P0WER SALES AGREEMENT ........................................... 23
3.7 EXELON POWER SALES AGREEMENT ........................................... 25
3.8 AQUILA POWER SALES AGREEMENTS .......................................... 30
3.9 CINERGY FUEL SUPPLY AND MANAGEMENT AGREEMENT
3.10 GAS TRANSPORTATION AND BALANCING AGREEMENT ............................. 35
3.11 INTERCONNECTION AGREEMENT .............................................. 38
3.12 OPERATION AND MAINTENANCE AGREEMENTS ................................... 39
3.13 ADMINISTRATIVE SERVICES AGREEMENTS ..................................... 39
3.14 COMMON FACILITIES AGREEMENT ............................................ 40
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3.15 SPARE PARTS AGREEMENT .................................................. 40
SECTION 4.0 ........................................................................ 41
PERFORMANCE GUARANTEES, COMPLETION TESTING, OPERATION AND
PROJECT SCHEDULE .................................................................. 41
4.1 PERFORMANCE GUARANTEES ................................................. 41
4.2 COMPLETION TESTING ..................................................... 42
4.3 OPERATION .............................................................. 45
4.4 PROJECT SCHEDULE ....................................................... 46
SECTION 5.0 ........................................................................ 47
PROJECT SITE ...................................................................... 47
5.1 GENERAL SITE LOCATION, ACCESS AND CONDITIONS ........................... 47
5.2 SITE ASSESSMENT ........................................................ 47
SECTION 6.0 ........................................................................ 50
PERMITS, APPROVALS AND CERTIFICATIONS .............................................. 50
6.1 FEDERAL PERMITS ........................................................ 51
6.2 STATE PERMITS .......................................................... 51
6.3 LOCAL PERMITS .......................................................... 53
SECTION 7.0 ........................................................................ 54
PROJECT PARTICIPANTS .............................................................. 54
7.1 ELWOOD ENERGY LLC ...................................................... 54
7.2 PEOPLES ENERGY RESOURCES CORP .......................................... 54
7.3 DOMINION ENERGY, INC ................................................... 54
7.4 AQUILA ENERGY MARKETING CORPORATION .................................... 54
7.5 EXELON GENERATION ...................................................... 55
7.6 ENGAGE ENERGY US, LP ................................................... 55
7.7 NORTHERN ILLINOIS GAS COMPANY (NICOR GAS COMPANY) ...................... 56
7.8 CINERGY CORP ........................................................... 56
7.9 DOMINION EL WOOD SERVICES COMPANY, INC ................................. 56
SECTION 8.0 ........................................................................ 57
PROJECT FINANCIAL ASSESSMENT ...................................................... 57
8.1 OVERVIEW ............................................................... 57
8.2 PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS ............................... 57
8.3 OPERATING ASSUMPTIONS .................................................. 58
8.4 REVENUES ............................................................... 60
8.5 OPERATING EXPENSES ..................................................... 63
8.6 FINANCING ASSUMPTIONS .................................................. 66
8.7 PROJECTIONS ............................................................ 66
8.8 SENSITIVITY ANALYSES ................................................... 66
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LIST OF ATTACHMENTS
1. Documents Received
2. Vicinity Map
3. Site Plans
4. Financial Projections
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"LEGAL NOTICE"
This document was prepared by Stone & Webster Consultants, Inc. (Stone &
Webster) solely for the benefit of Credit Suisse First Boston (CSFB).
Neither Stone & Webster, nor its parent corporation or its or their
affiliates, nor CSFB, nor any person acting in their behalf (a) makes any
warranty, expressed or implied, with respect to the use of any information
or methods disclosed in this document; or (b) assumes any liability with
respect to the use of any information or methods disclosed in this
document.
Any recipient of this document, by acceptance or use of this document,
releases Stone & Webster, its parent corporation and its and their
affiliates, and CSFB from any liability for direct, indirect,
consequential or special loss or damage whether arising in contract,
warranty, express or implied, tort or otherwise, and irrespective of
fault, negligence, and strict liability.
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SECTION 1.0
EXECUTIVE SUMMARY
1.1 INTRODUCTION
Stone & Webster Consultants, Inc. (Stone & Webster) has performed an independent
technical review (the Report) and assessment of the Elwood Energy Project (the
Project). The Project is a 1,409 MW natural gas fired, simple cycle, electric
generating station, located near the Village of Elwood, Illinois, approximately
50 miles southwest of Chicago. This report provides a review and assessment of
the Project's design and engineering, contracts and agreements, test results,
operation, permits and environmental considerations, organization, and economic
projections.
The Project has been designed for peaking operation. The station configuration
utilizes nine combustion turbines driving nine electric generators all
manufactured by the General Electric Company (GE). Initially, the Project was
developed in 1998 with Unit 1 entering commercial service on July 19, 1999. The
next phase of development started in 2000 with the five newer GE combustion
turbine generators entering commercial service in 2001. All of the power
generation equipment and the equipment selected for the auxiliary facilities
employ designs and technologies commonly used in simple cycle electric
generating stations. Natural gas is used to fuel the combustion turbines. Water
for the Project is provided from deep wells on the adjoining property owned by
Peoples Gas Light and Coke Company.
The Project has been developed and is owned by Elwood Energy, LLC (the Owner).
Elwood Energy, LLC is itself owned by subsidiaries of Peoples Energy Resources
Corp. (50% ownership) and Dominion Energy, Inc. (50% ownership).
The Owner entered into five EPC Agreements with the General Electric Company for
the development of the nine electric generating units. All of the units have
entered commercial service and all of the obligations under the EPC Agreements
have been met with the exception of some minor punchlist items, which are
currently being completed with final acceptance expected around September 2001.
Power sales agreements for the full capacity of the plant have been executed and
are in full force and effect for periods between 12 and 16 years. All of these
agreements have energy pricing indexed to the market price of natural gas,
thereby providing the economic equivalent of a tolling arrangement and
mitigating the fuel price risk.
1.2 SCOPE OF SERVICES
Stone & Webster was retained to prepare this Report to support the debt capital
markets financing for Elwood Energy LLC. As part of this review, Stone & Webster
performed a condition assessment, asset life evaluation, performance, operation
and maintenance (O&M) review, and a review of the site environmental assessment
done by Woodward-Clyde International-Americas.
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EXECUTIVE SUMMARY
================================================================================
The Report includes Stone & Webster's independent technical assessment of the
Project, based on, among other things, the review of the available technical
data, historic performance and cost data, and visits to each facility. The
Report presents our findings and conclusions regarding the following:
o Contractual Requirements and Interfaces
o Design and engineering
o Geotechnical assessment
o Environmental assessment
o Major equipment selection and design integration
o Construction schedule
o Operating unit performance
o Performance testing
o Permit status
o Project participants
o Analysis of the Financial Projections
In addition, Stone & Webster reviewed power sales agreements, and received
technical input from Pace Global Energy Services LLC (Pace), who developed the
market forecasts. The market forecasts prepared by Pace cover the period 2001
through 2026. The data used from the market forecasts includes unit specific
data on energy generation, energy revenues, fuel expenses, fuel consumption,
capacity and energy revenues. Pace also opined on the extension of the Aquila
PSA. The data provided by Pace was adjusted to include inflation.
As part of the Review, Stone & Webster developed a financial model, which
combined the market forecasts prepared by Pace with the contracted revenue and
fuel supply forecasts, O&M expenses, and capital expenditure forecasts. The pro
forma Financial Projections prepared using the financial model show cash flows
available to support repayment of interest and principle of the debt from 2001
through 2026 and debt service coverage ratios (DSCRs) for a base case and
several sensitivity cases from 2001 through 2026.
Stone & Webster conducted this analysis and prepared the Report utilizing
reasonable care and skill in applying methods consistent with normal industry
practice. In the preparation of this report and in formulating the expressed
opinions, Stone & Webster has made certain assumptions with respect to
conditions, which may exist, or events, which may occur in the future. The
specific information reviewed by Stone & Webster is listed in Attachment 1.
Assessment of legal issues is outside of Stone & Webster's scope of work as
Independent Technical Consultant.
1.3 TECHNICAL DESCRIPTION OF ASSETS
The Project is being developed on a portion of a 195-acre site located in the
Village of Elwood, in Will County, Illinois, which is located approximately 50
miles southwest of Chicago. The site terrain is generally flat and is located in
a rural area. A vicinity map is provided in Attachment 2 and two development
drawings are included in Attachment 3.
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The key technical aspects of the Project are summarized in the following table.
The information shown in the table includes the in-service date of the units,
the summer rating of the unit, and the turbine model.
----------------------------------------------------------------
Commercial Rated
Operation Turbine Capacity
Unit Date Model (kW)
----------------------------------------------------------------
1 July 19, 1999 GE7231 155,260
2 July 18, 1999 GE7231 155,260
3 July 23, 1999 GE7231 155,260
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4 July 19, 1999 GE7231 155,260
5 May 10, 2001 GE7241 155,842
6 May 31, 2001 GE7241 155,842
7 June 29, 2001 GE7241 155,842
8 July 3, 2001 GE7241 155,842
9 May 6, 2001 GE7241 155,842
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1.4 PROJECT DESIGN AND CONDITION OF ASSETS
Stone & Webster performed a site inspection at the Project, and reviewed
relevant inspection and design reports to assess the condition of the equipment.
Stone & Webster has reviewed the design criteria for the major mechanical and
electrical systems and the civil/structural design requirements of the Project.
The design configuration of the Project is typical of modern natural gas fired,
simple cycle power generating stations. Appropriate equipment redundancy has
been included in the design to achieve a high level of operating reliability. If
the Project is operated in accordance with accepted electric utility practices,
it should be able to safely and reliably perform as represented in the Financial
Projections.
Units 1 through 4 were constructed under two separate EPC Agreements, and Units
5 through 9 were constructed under three separate EPC Agreements. Units 1
through 4 entered into commercial operation in 1999 and all terms of the EPC
Agreements have been satisfied. Units 5 through 9 entered into commercial
operation in 2001 and are complete except for minor "punchlist" items and some
outstanding change orders in the amount of approximately $3 million, which are
currently being negotiated. GE has submitted a claim for additional payment in
connection with the construction of Units 5-9, asserting differing site
conditions that required unanticipated cut and fill work, severe weather that
constituted force majeure for purposes of determining whether required
performance should be delayed, and damage to a gas turbine during ocean shipment
that required procuring a replacement generator and rescheduling work
activities. GE's total claim is approximately $17 million above the amount
budgeted for payment under the EPC Contracts. Dominion Energy, Inc. and Peoples
Energy Resources Corp. have agreed to advance the Project any amount that is
paid to GE in excess of the EPC budget, in the form of subordinated debt. The
EPC Agreements included reasonable and customary terms
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and conditions including provisions for, among other things, bonuses, liquidated
damages, warranties, and performance testing.
1.5 PERFORMANCE
Performance guarantees and the procedures for conducting the performance tests
and criteria are provided in each EPC Agreement. All nine units have
successfully passed the Operational Capability Tests. Units 1, 2, and 5 through
9 have met or exceeded capacity and heat rate performance guarantees. Units 3
and 4 were accepted as being within the contractual test tolerances.
Acoustic Associates, Ltd. prepared reports to present the results of the near
field sound level tests on Units 1 through 4, 5, and 9. The reports indicate
that the sound level measurements met the near field noise guarantee as required
in the EPC Agreement. Data for far field testing was taken and evaluated for
compliance with Illinois State Regulations. A preliminary analysis from Acoustic
Associates, Ltd. showed compliance.
There are no schedule issues with Units 1 through 4 since they have been
operating for approximately two years. Units 5 through 9 have also been
completed in advance of their scheduled completion dates
Stone & Webster has reviewed the historical availability, forced outage, and
heat rate data for each of the units. This data was found to be consistent with
industry norms. Stone & Webster has reviewed the Projected availability, forced
outage, and heat rate data used by Pace and conclude that they are reasonable.
The projected maintenance and capital expenditures budgets allow for adequate
repairs and equipment replacement to maintain the Projected level of
reliability.
1.6 POWER SALES AGREEMENTS
The Owner has entered into long-term power sale agreements covering the sale of
all capacity and electric energy output of the facility. An agreement with
Exelon Generation Company, LLC covering Units 3, 4 and 9 through December 31,
2012 and Units 1 and 2 from January 1, 2005 through December 31, 2012; two
agreements with Aquila Energy Marketing Corporation covering Units 5 and 6 and
7-8 for terms expiring on August 31, 2016 and August 31, 2017 (and further
subject to a five year extension by Aquila), respectively; and an agreement
with Engage Energy US, L.P. covering Units 1 and 2 through December 31, 2004.
The terms of the Engage contract are rendered moot by a monthly adjustment under
the Exelon contract. Under separate contract, Exelon re-purchased from Engage
the rights to dispatch Units 1 and 2 through December 31, 2004. Exelon and the
Owner subsequently agreed to adjust the pricing of dispatches under the Engage
contract to equal that contained in the Exelon agreement.
The power sales agreements require Exelon and Aquila to pay 1) a monthly fixed
fee "capacity charge" based on the tested capacity of the units, as adjusted for
the performance reliability of the facility (see below); and 2) an energy
payment composed of a fuel charge based on the published index price of gas and
the facility's heat rate, plus certain variable O&M expenses.
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This structure is the economic equivalent of a tolling arrangement whereby fuel
and variable costs are collected via the energy charge when dispatched.
Capacity payments under the Exelon and Aquila agreements contain incentives to
promote operation of the units in the most reliable manner. Increases to
capacity payments as bonuses and decreases in the capacity payments as penalties
are defined in Section 3.7 of this Report. Reductions to capacity payments are
limited to instances where Owner fails to meet the dispatch of Exelon and
Aquila, after options for use of replacement power, and cannot be more than the
capacity. The Owner should be able to earn equivalent availability and monthly
reliability bonuses for performance and satisfy the operational standards set
forth in this Agreement.
Pace has determined that based on upon the payment structure of the Aquila
PSA's, the Project's forecast dispatch profile, forecast market-clearing prices,
and the market-based revenues that Aquila is forecast to earn by marketing the
output and capacity of Units 5 through 8, there is a sufficient economic
incentive that would cause Aquila to exercise its option to extend the term of
the Aquila PSA's for an additional five year period.
Upon expiration of the Exelon PSA and Aquila PSA Extension, the Owner will enter
into new term agreements. If new term agreements are not signed, the Owners will
sell the capacity and energy from the Project on a "merchant" basis.
1.7 FUEL SUPPLY AND MANAGEMENT
The Owner has entered into a supply agreement with Cinergy Marketing and Trading
LLC to procure, schedule and deliver to Northern Illinois Gas Company (Nicor)
and or Peoples Gas, on a firm (non-interruptible basis) to meet the Project's
fuel requirements on firm power sales. A separate agreement between the Owner
and Nicor (described below and in Section 4.2.5) provides gas transportation and
balancing for the gas arranged by Cinergy under this Agreement. Cinergy, as
agent of Elwood under the Elwood-Nicor contract, may procure interstate gas
supplies from NBPL, APL and Natural Gas Pipeline Company of America (NGPL) to
support the Project's needs.
The quantity of fuel to be supplied and delivered pursuant to these Agreements
should be sufficient to support the operation of the units at the anticipated
dispatch levels. Fuel costs paid by the Owner to Cinergy are indexed to the
published price of daily gas supplies. Similarly, the fuel component of the
energy charge revenues in the Aquila and Exelon power sales agreements are
indexed to the price of daily gas supplies, mitigating price risk and creating
the economic equivalent of a tolling arrangement. With respect to the forecast
variance charges and storage inventory overrun charges to be paid by the Owner
under these Agreements, the amount to be paid is largely dependent upon the
Owner's ability to anticipate Unit dispatch. The amounts to be paid, if any, are
also dependent upon Cinergy's ability to manage fuel supply and transportation
on behalf of the Owner.
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1.8 GAS TRANSPORTATION AND BALANCING
The Owner has entered into a long-term transportation and storage balancing
service with Northern Illinois Gas Company (Nicor) for firm (non-interruptible)
hourly delivery of fuel supplies in quantities sufficient to meet the firm
dispatch obligations of Exelon and Aquila. Peoples Gas is the owner and operator
of the gas pipeline delivering to the facility but Nicor holds the utility
franchise to gas utility services in this region. Nicor was consequently
selected as the contract provider of gas transportation and balancing services
but owns only meters and meter runs at the facility. Nicor contracts with
Peoples for service to support transportation and balancing services to the
facility on substantially the same terms and conditions as the Owner's contract
with Nicor. The Owner may purchase Nicor's meter facilities and bypass Nicor
via lump-sum buyout provisions if more competitive services are available
directly from the interstate pipelines.
The Peoples pipeline is interconnected with high pressure interstate gas
supplies received from Northern Border Pipeline Company (NBPL) approximately
2.8 miles from the facility and from the Alliance Pipeline Company (APL) at an
interconnect located just a few hundred feet of the facility. Nicor and Peoples
have entered into contracts with NBPL to provide hourly balancing services to
support the facility. The Peoples pipeline is also connected to their Mahomet
Pipeline, which receives and delivers gas to Peoples' underground cavern storage
facilities at Manlove Field, in the event of a pipeline curtailment.
1.9 OPERATION AND MAINTENANCE
Stone & Webster reviewed staffing, O&M, and major maintenance expense
information provided by the Owners. The O&M Agreements for the units provide
for payment of an annual fee and further provide for reimbursement of certain
costs as more specifically defined in the Agreement. The terms and conditions of
these Agreements were similar to other cost plus O&M arrangements we have
reviewed for other projects. The O&M Agreements do not include incentives for
operation of the units at certain levels. However, given the relationship of the
parties involved in ownership of the Project and the parties to the O&M
Agreements and the performance incentives provided through the Power Sales
Agreements, it is reasonable to believe that the operator has appropriate
incentives to meet or exceed the operational standards set forth in the Power
Sales Agreements.
1.10 ENVIRONMENTAL AND SITE ASSESSMENT
The Project site is located in Will County, Illinois. The site is accessible by
county roads and interstates. Rail transportation is available and during
construction, arrangements were made for unloading equipment on the siding in
Millsdale, Illinois, near the Elwood Site. The same arrangements should be
available for heavy equipment transportation during the commercial operations
period if necessary.
The EPC Agreements for Units 1 through 9 require the Contractor to be
responsible to determine subsurface conditions at the site. The EPC Agreements
also specify civil codes and standards, which Stone & Webster considers
appropriate. Given the structure of the EPC Agreement
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requirements, Stone & Webster believes that the foundations for Units 1 through
9 and other structures are acceptable. The objectives of the report were to
establish an environmental baseline for soil and ground water and to determine
the potential for adverse health impacts for workers.
Stone & Webster reviewed the Phase I Environmental Site Assessments prepared by
Woodward-Clyde International-Americas. The Report, among other things, concludes
that the concentrations of certain constituents do not exceed Tier 1 remediation
objectives and thus do not pose a health and safety concern for future
operations activities.
An application for the CAAPP operating permit will be submitted to the Illinois
EPA within 180 days following initial startup of Units 5 through 9 in order to
allow for equipment shakedown and emissions testing. The submittal of a complete
permit application will satisfy the CAAPP permit requirements and will ensure
that Units 5 through 9 operate in compliance with those requirements.
The low NO(x) emissions for the units should result in relatively low emission
allowance costs. Based on the allowance price forecast, NO(x) allowance costs
are projected to cost the Project $4.9 million over the term of the Projections.
The legal and regulatory requirements have been identified for the Project.
Certain Illinois EPA permits are pending, but they are considered routine and
no problems are anticipated in obtaining them. The Project is not under any
enforcement issues regarding permitting or compliance with Federal, State or
local regulatory agencies.
1.11 REMAINING LIFE
The remaining life of the Assets was evaluated for 25 years. The performance,
O&M budget, and capital expense estimates have been prepared to 2026. The
remaining life estimates are based on the Owners continuing to operate under the
Projected estimated budget for the period 2001 through 2026.
With proper O&M and adequate funding of the required capital and overhaul
expenses, all the units should be capable of operating for the evaluated Asset
life.
1.12 FINANCIAL PROJECTIONS
Stone & Webster has prepared Financial Projections for the Project from October
2001 through June 2026. The cash available for debt service is compared to the
Owner's annual debt service obligation to determine the DSCR for each year for
the term of the Financial Projections. The Financial Projections include a base
case and two downside alternatives taken from the Pace forecasts. In addition,
Stone & Webster performed sensitivity analyses using the pro forma financial
model by increasing the O&M expenditures, decreasing the inflation rate,
assuming that the Aquila contract is not extended, and excluding the volatility
revenue.
Stone & Webster combined the forecasts developed by Pace, the O&M expense
forecasts and contract energy sale projections provided by the Owners, and the
debt service schedule provided
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by CSFB to develop the Financial Projections. The Financial Projections are
based on market energy and capacity price forecasts, and facility specific
energy generation forecasts developed by Pace. The fuel expenses are based on
natural gas fuel projections by Pace. The forecasts prepared by Pace extend
through December 2026.
Stone & Webster has reviewed the assumptions and the data necessary to support
the Projections of cash flow available for the debt service payments, Stone &
Webster has verified that the underlying model assumptions are consistent with
the Pace projected generation and pricing. Stone & Webster did not review the
financing assumptions, including the debt service payment, which was provided by
CSFB. These Financial Projections represent Stone & Webster's best judgment of
the Projected performance of the Project.
1.13 CONCLUSIONS
Set forth below are the principal opinions, which have been reached regarding
the review of the Project. For a complete understanding of the assumptions upon
which these opinions are based, the Report should be read in its entirety. On
the basis of our review and the assumptions set forth in the Report, Stone &
Webster provides the following opinions:
1. The Project was found to be well maintained and in good condition. The
Project has been designed, constructed, operated, and maintained according
to good utility industry practice. The Project should function beyond the
period of the debt term, provided equipment is operated and maintained in
accordance with good utility industry practice. The Owner has proven
experience operating and maintaining power plants.
2. The Project participants have extensive corporate experience in the
development, design, procurement, construction, testing, and operation of
power plants and in procuring and transporting natural gas.
3. Stone & Webster reviewed the technical assumptions that were used as
inputs to Pace's dispatch simulation model. The key input data, in Pace's
model such as claimed capacity, scheduled and forced outage rates, and
heat rate are reasonable and are consistent with comparable units.
4. The anticipated performance of the Project, given the condition and
capability of the units, is accurately reflected in the Financial
Projections.
5. The Project is technically capable of performing at the capacity factors
projected by Pace.
6. The O&M expenses forecasted by the Project are consistent with the
staffing and operating plan and recent historical expenses for the
Project. The O&M expenses appear reasonable and adequate to meet the
Project's operation, maintenance and performance objectives.
7. The Project staffing is reasonable for a peaking facility.
8. The overhaul schedules developed by the Project are prudent and
consistent with current and forecasted operations. The overhaul expenses
forecasted in the Financial Model are consistent with the overhaul
schedules and should be adequate to support the continued operation of the
Project through 2026.
9. The on-going repair/replacement expenses forecast for the Project forecast
are reasonable and consistent with the design of the assets and the
projected capacity factors.
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10. The Project is in compliance with current permit requirements. Phase I
Environmental Site Assessments (ESAs), prepared by others, were provided
for the Project and reviewed.
11. The technical assumptions assumed in the Financial Projections are
reasonable and are consistent with the agreements. The financial model
fairly presents, in our judgment, projected revenues and projected
expenses under the Base Case Assumptions. Therefore, the Financial
Projections are a reasonable forecast of the financial results under the
Base Case Assumptions.
12. The Projected revenues are more than adequate to pay the annual operating
and maintenance expenses (including provisions for major maintenance),
other operating expenses, and debt service based on our studies and
analyses and the assumptions set forth in this Report. Contributions to
major maintenance reserves and debt service reserves are excluded from
cash flow available for debt service. The debt service requirements for
each year are the payments to be made on July 5 of that year and January 5
the following year. The Base Case resulting minimum DSCR is 1.5lx and
occurs in 2005 and 2006. The Base Case resulting average DSCR is 3.60x.
The following table summarizes the Base Case and sensitivities:
================================================================================
Base Case and Sensitivity Summary
================================================================================
Minimum DSCR Average DSCR
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Base Case 1.51x 3.60x
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Increased O&M Cost 1.49x 3.56x
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Decreased Inflation Rate 1.5lx 3.36x
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High Gas Price Case 1.50x 3.58x
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Overbuild Case 1.5lx 3.55x
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No Aquila Contract Extension 1.5lx 3.83x
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No Volatility Revenue 1.5lx 2.97x
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SECTION 2.0
PROJECT DESIGN
Stone & Webster has reviewed the design criteria for the major mechanical and
electrical systems and the civil/structural design requirements of the Project.
The following discussion of Project design features is based on details provided
in the technical specifications established in the EPC Contracts except where
otherwise noted.
The design configuration of the Project is typical of modern natural gas fired,
simple cycle power generating stations. Appropriate equipment redundancy has
been included in the design to achieve a high level of operating reliability.
If the Project is operated in accordance with accepted electric utility
practices, it should be able to safely and reliably perform as presented in the
Financial Projections.
2.1 ELECTRIC POWER GENERATION EQUIPMENT
The Project features power generation equipment manufactured by the General
Electric Company (GE). All of the combustion turbines are the 7FA type,
however Units 1 through 4 use the model PG7231 turbine and Units 5 through 9 use
the model PG7241 turbine. The primary difference between these two models is
that the newer PG7241 is designed to operate at a higher combustor temperature,
which improves the overall turbine performance. All of the combustion turbines
are designed to operate on natural gas as the sole fuel.
The 7FA turbines utilize dry low nitrogen oxide (NO(x)) combustion technology
with inlet air cooling. The NO(x) emission level is controlled by algorithms
implemented by the GE SPEEDTRONIC turbine control system provided with each
turbine. The control system regulates the distribution of the gas fuel to each
of the natural gas nozzles and to the total premix combustor arrangement.
Inlet Air System
Each combustion turbine is equipped with an inlet air system to condition the
inlet combustion air to ensure the quality and cleanliness. The inlet air system
includes high efficiency, self-cleaning, media filters, evaporative coolers,
silencing features, a plenum and ductwork and a support structure with walkways,
ladders, and platforms. The evaporative coolers are used during warm weather
operation to cool the inlet air, which improves the combustion turbine
performance.
Fuel System
The natural gas fuel system includes fuel nozzles in each combustion chamber, a
fuel gas "Y" strainer, stainless steel fuel piping, flexible fuel nozzle
pigtails, fuel gas stop/speed ratio and control valves, and instrumentation to
monitor fuel pressure, gas control valve discharge pressure, and gas stop/ratio
valve discharge pressure. The fuel system pressure is designed to
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be maintained between 380 and 450 psig, depending upon turbine load conditions,
and is sized for the full load gas flow required by the combustion turbine.
Exhaust System
The hot exhaust gases are discharged axially from the combustion turbine. The
exhaust system for each combustion turbine includes a diffuser, expansion joint,
ducting, silencer and stack.
Lubrication and Hydraulic System
The lubrication and hydraulic control oil system for each turbine generator
package is incorporated into a common system located in the auxiliary
compartment. The lubrication and hydraulic oil systems consist of one 100
percent capacity AC motor-driven main lube oil pump, one 100 percent capacity
AC motor-driven auxiliary lube oil pump, one 100 percent capacity AC main
hydraulic oil pump, one 100 percent capacity AC motor-driven auxiliary
hydraulic oil pump, one DC motor-driven emergency lube oil pump, one bearing
lift oil pump, and one AC/DC emergency seal oil pump. Dual oil coolers, dual
lube oil filters and dual hydraulic oil filters are also provided.
Turning Gear and Starting System
Each combustion turbine is provided with an AC motor driven turning gear for
rotor cooldown and indexing.
A single 12 pulse water-cooled static starting system is shared by the two CTGs
within each two CTG group (1 and 2, 3 and 4, 5 and 6, 7 and 8). Unit 9 is
furnished with a dedicated LCI starting system with provisions for interface to
a tenth CTG. The LCI static starting system provides variable frequency power
directly to the generator terminals, using the generator as a motor to
accelerate the turbine to a self-sustaining condition. Since the Facility does
not have "black start capability, backfeed of power from the grid is required
to operate the static starting system and start the CTGs.
Compressor Water Wash System
A compressor water wash system is shared by the two CTGs within each two CTG
group (1 and 2, 3 and 4, 5 and 6, 7 and 8). Unit 9 is furnished with a dedicated
water wash system with provisions for interface to a tenth CTG. The system is
used to remove fouling deposits, which can accummilate on the compressor blade
surfaces. Deposits such as dirt, oil mist, industrial or other atmospheric
contaminants from the surrounding site environment, will reduce air flow, lower
the compressor efficiency and lower the compressor pressure ratio, which will
reduce thermal efficiency and output of the combustion turbine. Compressor
cleaning removes these deposits to restore performance and slow the progress of
internal corrosion, thereby increasing blade wheel life.
The water wash system includes provisions for both on-line and off-line
cleaning. The on-line cleaning system utilizes water injection sprays to clean
the blades while the compressor is
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running. The off-line cleaning system injects a cleaning solution into the air
compressor, while it is being turned at cranking speed. The advantage of on-line
cleaning is that washing can be accomplished without having to shut down the
combustion turbine. On-line washing, however, is not as effective as off-line
washing, therefore, the on-line washing is utilized to supplement off-line
washing.
Combustion Turbine Control System
Each combustion turbine is controlled by a GE Mark V SPEEDTRONIC
microprocessor-based control system. This control system is, structured around
triple redundant controllers, processors and sensors, and has been proven to be
extremely reliable. Mark V features include fuel flow control, automatic and
manual synchronizing, droop control, load limiting, vibration monitoring,
overspeed protection, power factor/VAR control, and speed control (governor),
and voltage control.
Fire Protection System
The design for the combustion turbine and accessory compartments includes fire
detection and C02 fire suppression systems. A system of hazardous atmosphere
detectors is used to automatically initiate the release of C02. The fire
protection system is capable of establishing a non-combustible atmosphere in
less than one minute in accordance with the National Fire Protection Association
Standards.
Generator
Each combustion turbine drives a General Electric 7FH2 hydrogen cooled electric
generator rated at 195.3 MVA, 166 MW, 18 kV, 0.85 power factor (lagging), 60 Hz
and 3,600 rpm. The generator windings are manufactured using class F insulation
with a class B temperature rise. The generator supporting equipment includes a
digital static excitation system, surge protection, electrical protection
module, a power system stabilizer and a grounding transformer with secondary
resistor and motor-operated disconnect switch.
Electrical protection for the generator and generator step-up transformer is
provided by a combination of integrated and discrete relays located on the
generator control panel. Temperature monitoring is provided for stator windings,
hydrogen cooling gas path, bearings, and lube oil system.
Generator bearing lube oil and bearing lift oil systems are supplied from the
combustion turbine lubrication system.
A recirculating hydrogen gas cooling system is provided for each generator. The
cold gas is circulated into and around the stator core using generator fans.
After the gas has passed through the generator, it is cooled by five
gas-to-water heat exchangers and is then returned to the rotor fans and
recirculated. With a single cooler out of service, the generator design
capacity is reduced to about 80 percent of its rating, based on a class F
temperature rise.
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A hydrogen control system maintains the hydrogen purity in the generator casing
at approximately 98 percent. Carbon dioxide is used to purge the generator
casing of air before admitting hydrogen and to purge hydrogen before admitting
air. The generator is equipped with a seal oil system, to minimize leakage of
hydrogen gas past the generator bearing seals.
Enclosures
The packaged electric and electronic control compartment (PEECC) is a completely
enclosed, self contained electronic and electrical control compartment designed
for outdoor installation. Heating, air conditioning, compartment lighting, power
outlets, temperature alarms, and smoke detectors are included for protection of
personnel and equipment in the compartment. Turbine and generator control panels
located inside the PEECC allow local monitoring and control of the CTGs. The
PEECC also houses the combustion turbine motor control centers and 125Vdc
system including battery and charger.
Enclosures are also supplied for the combustion turbine, the turbine accessory
compartment, and the generator compartment. The enclosures provide weather
protection, thermal insulation, acoustical attenuation and fire containment. The
enclosures allow access to equipment for routine inspections and maintenance.
These enclosures are ventilated, heated, lighted and fire protected.
Motor Control Centers, Batteries and Chargers
Each combustion turbine generator is supplied with two motor control centers
for distribution of 480 Vac power to auxiliary equipment.
A 125 Vdc system consisting of a lead acid battery and redundant battery
chargers provides each turbine generator a source of stored energy for operation
of control systems, electrical protection systems, and lubrication pumps during
emergency conditions when AC power is not available.
Stone & Webster is of the opinion that the GE combustion turbines, electrical
generators and auxiliary equipment provided are capable of supporting the safe
and reliable operation of this Project if installed, operated and maintained
according to the manufacturer's recommendations.
2.2 AUXILIARY PLANT SYSTEMS
The auxiliary plant systems operate to support plant operation and the primary
power production equipment. The following is a summary of these necessary
systems.
Facility Fuel Gas System
Natural gas arrives at the Facility fuel gas pressure regulating stations
through a 24" diameter supply pipeline at a pressure varying from 500 psig to
700 psig. There are plans to increase the supply pressure in the future to 1,050
psig. At present, the supply pipeline receives natural gas
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from the Alliance pipeline and the Northern Border pipeline. There are three
pressure regulating stations at the site supplying Units 1 through 4, Units 5
through 8 and Unit 9, respectively.
In addition to the pressure regulators, the fuel gas system includes fuel gas
scrubbers, fuel gas heaters, fuel meters and all associated piping, valves and
controls.
Service Water/Potable Water System
The service water supply for the Station originates from wells on the adjacent
property owned by Peoples Energy Corporation. These wells were initially
established to meet the requirements of the synthetic gas plant originally
operating adjacent to the Unit 1 through 4 site. Presently, the service water
facility consists of two 700 gpm well pumps, one 932,700 gallon storage tank,
three 740 gpm service water pumps and two 165 gpm service water pumps. The two
smaller pumps were recently added to reduce the operating frequency of the
larger pumps when demand for water is reduced.
A separate potable water supply system receives water from the wells. The
potable water supply system consists of a supply tank, a chlorinator and two
potable water supply pumps.
Demineralized Water System
The station service water system provides water to the demineralized water
system, which provides water for washing the CTG air compressor blades. A
trailer-mounted demineralizer is brought to the site and used to provide the
demineralized water.
Station Fire Protection System
The Station fire water system uses water stored (750,000-800,000 gallons) in
the lower part of the service water storage tank. This water is provided to the
fire water pumps, where it is pumped through the Station fire water system. The
pumps include a 2,500 gpm electric motor-driven fire pump, a 2,500 gpm
diesel-driven fire pump and a 50 gpm jockey fire pump. The water system is
pressurized to 125 psig. The fire water pumps supply water to a fire water loop
distribution system protecting Units 1 through 4 and to a second fire water loop
system protecting Units 5 through 9.
Each fire water distribution system is arranged in a loop configuration with
hydrants and hose cabinets. The main step-up transformers are provided with
water from the distribution headers and each is protected with a deluge
sprinkler system.
Compressed Air System
The Station compressed air system is comprised of a utility air system for
general station compressed air requirements and an instrument air system, which
produces clean and dried compressed air for use by plant instrumentation and
controls. The compressed air system includes redundant air compressors,
receivers and air dryers.
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Hydrogen and Carbon Dioxide Gas Systems
The hydrogen system consists of both standard pressurized hydrogen storage
bottles and a Station bulk hydrogen storage system. The hydrogen storage system
is used to maintain the hydrogen pressure of all nine electrical generators.
The carbon dioxide system is available for use in purging the electrical
generators of hydrogen before they are opened for inspection or maintenance.
Each electrical generator is equipped with a manifold and standard pressurized
carbon dioxide storage bottle.
2.3 STATION ELECTRICAL SYSTEMS
Station Switchyard and Utility Interconnection
The ComEd Elwood Energy Center 345 kV switchyard is arranged in a double ring
bus configuration. One ring bus is identified as the red bus, and the other as
the blue bus. The Electrical Interconnection between the Project and the ComEd
grid will be made at the interface between the Project section of the switchyard
and the ComEd section of the switchyard.
Five of the nine units for the Elwood Project are connected to a common
collector bus in the Project section of the switchyard via overhead
transmission lines. Three 345 kV breakers, provide protection and isolation for
the units and overhead lines prior to connection to the collector bus. One
breaker is provided for each of the two pairs of CTG units, and the third
breaker is provided for Unit 9. The Projects collector bus is in turn connected
via a single line to the ComEd blue ring bus in the ComEd section of the
switchyard (Point of Interconnection).
The other four units are each connected to a second collector bus located in the
Project section of the switchyard via overhead transmission lines. The second
collector bus is in turn connected via a single line (Point of Interconnection)
to the ComEd red ring bus. Metering is provided at the 345 kV level on the
ComEd side of the interconnection between the collector bus and the red ring
bus and revenue metering is provided on each individual unit. The 18 kV
generator breakers provide protection and isolation for the units and overhead
lines. The collector bus is designed to accommodate the future addition of a
tiebreaker, additional generators, and a second connection to ComEd's blue ring
bus.
Generation System
The electrical generation system consists of the generator, the generator step
up transformer, excitation system, and interconnecting isolated phase bus duct.
(The technical description of the generator is provided above as part of the
combustion turbine generator description.)
Each generator energizes a 18-362 kV, 115/154/192 MVA, OA/FA/FA, 65(degree)C.
three-phase, 60 HZ, grounded wye-delta, step-up transformer with a +/-2-2.5
percent no load tap changer. Each transformer is sized to deliver the maximum
MVA output of each combustion turbine generator.
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A 24 kV, 8,000 amp SF6 generator circuit breaker is provided for each electrical
generator. The 24 kV generator breakers includes gang operated disconnect
switches, current transformers, potential transformers, lightning arrestors and
surge capacitors.
Each electrical generator is connected to the associated step-up transformer
through an isolated phase bus duct, which is sized to accommodate the generator
output under all loading conditions.
The referenced generator breaker and isolated phase bus duct sizing criteria,
accessories, standards, and fabrication requirements are in accordance with good
utility practice.
Auxiliary Electrical Distribution System
The station auxiliary loads are supplied from a unit auxiliary transformer (UAT)
connected to the 18 kV generator isolated phase bus duct between the generator
breaker and the generator step-up transformer. Each auxiliary transformer is
rated 12 MVA, 18 kV-4.16 kV, delta-wye grounded with +/-2-2.5% high voltage
taps. Each transformer is sized to serve the load requirements of the two units
within each two unit group (1 and 2, 3 and 4, 5 and 6, 7 and 8, and 9 and
future).
Medium and Low Voltage Electrical Distribution Systems
Each of the two UATs within each group of two CTGs energizes one end of a double
ended 4.16 kV switchgear bus. The double ended switchgear bus is furnished with
a tie breaker, allowing either CTG to provide auxiliary power to both CTGs in
the group. The LCI static starting system, generator excitation system, and
480 V secondary unit substations are fed from the 4.16 kV switchgear. The
secondary unit substations are also designed in a double ended with tie breaker
configuration. Each 4.16 kV switchgear bus energizes one end of the substation.
The secondary unit substations in turn provide power to the MCCs and other low
voltage loads.
Emergency Power, DC, and UPS Systems
A connection is provided to each 4.16 kV switchgear from a 34.5/4 kV power feed
which is independent of the TSS-900 switching station. Should power be lost from
the normal 345 KV feed through the GSUs, the system will automatically be
aligned to the emergency power system to allow a normal shutdown of the unit.
Each combustion turbine generator is designed with a DC System capable of
providing stored energy to safely shut the unit down while providing emergency
lighting, and power for critical control and protection systems.
The overall Facility is furnished with a 3 kVA, 120 Vac UPS system capable of
providing regulated uninterruptible power to critical AC loads. The UPS system
includes the inverter, battery, redundant chargers, static transfer switch, and
bypass.
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Miscellaneous Electrical Systems and Equipment
Requirements for station grounding systems, electrical protection, lightning
protection, lighting, freeze protection, and communications systems are
specified and included in the design.
A lighting system with fixtures, poles, convenience receptacles, welding
receptacles and switches is included in the design.
A grounding system consisting of a network of bare copper conductor and ground
rods, in accordance with NEC requirements, is provided to ensure equipment and
personnel safety.
Lightning protection for buildings and structures in accordance with NFPA
requirements is included in the Facility design. Lightning arrestors are
required by the design for the generator step-up transformers.
Freeze protection is provided for enclosures, piping, instrumentation, and other
devices subject to freezing.
The communications system for normal and emergency operations are required by
OSHA. The Elwood communication system design includes hand held radios, desktop
telephones in offices and other occupied areas, and CCTV/security for gate
access.
Instrumentation and Controls
In addition to local control of the CTGs from the PEECC, the CTGs communicate
with supervisory interface servers located in the existing Facility central
control room via an Ethernet connection.
Dual redundant GE PLCs are provided to perform control and monitoring of BOP
systems and equipment including the fuel pressure reduction station, fuel
heaters, air compressor, and CEMS.
The CEMS system is be provided with NO(x) and O2 analyzers. The system includes
a PLC for control, data acquisition, data storage, automatic calibration, and
report generation.
2.4 CIVIL, STRUCTURAL AND ARCHITECTURAL
The EPC Contractor provided all materials, labor, equipment, and services
necessary to develop the site and construct the power facilities. This included
all foundations, buildings, structures, geotechnical investigations, surveys,
clearing and grubbing, excavation, filling and backfilling, paving, surfacing,
utilities, culverts, finished grading, landscaping and fencing.
The Contractor designed and constructed the Project in conformance with prudent
utility industry practice and with all applicable national, state and local
engineering, environmental, construction, safety, and electrical generation
codes and standards.
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SECTION 3.0
CONTRACTS AND AGREEMENTS
3.1 ENGINEERING, PROCUREMENT AND CONSTRUCTION (EPC) AGREEMENTS
Units 1 through 4
Two separate EPC Agreements were prepared to develop the site and construct the
first four units. The first EPC Agreement was executed on July 23, 1998 between
the General Electric Company (Contractor) and Elwood Energy LLC (Owner). Under
the terms of this Agreement, the Contractor developed the site and installed
Units 1 and 2 for a lump sum price of $91,281,000. The second EPC Agreement was
executed on September 25, 1998 between the General Electric Company (Contractor)
and Elwood Energy LLC (Owner). This Agreement and a subsequent Amendment, dated
April 26, 1999, covered the installation of Units 3 and 4 for a lump sum price
of $87,966,635. The four units all achieved commercial operation in 1999. All
terms of the EPC Agreements have been satisfied and there are presently no
disputed conditions.
3.2 ENGINEERING, DESIGN, PROCUREMENT, CONSTRUCTION AND INSTALLATION SERVICES
(EPC) AGREEMENTS
Units 5 through 9
Three separate EPC Agreements were prepared to develop Units 5 through 9. For
these units, an equipment purchase contract was executed first for the power
producing equipment, an EPC Agreement was then prepared for the installation of
the equipment purchased and for installation of balance-of-plant equipment, and
then the initial equipment purchase contract was amended to include the balance
of plant equipment.
Units 5 and 6
For Units 5 and 6, an EPC Agreement was executed on July 31, 2000 between the
General Electric Company and Elwood Energy II, LLC for the installation,
start-up and testing of the two units. The Agreement established a fixed
Contract Price of $23,473,950 for performance of the work. The Contract Price
was to be paid in accordance with a Milestone Schedule (Exhibit B of the EPC
Agreement) established on the basis of scheduled dates and specific activities
over a 25 month period. No retainage was specified. All of the scheduled dates
and durations of the EPC Agreement were based on the Provisional Acceptance
Date. The Required Provisional Acceptance Dates for Unit 5 and Unit 6 of June 1,
2001 and June 15, 2001, respectively, have been achieved.
The Agreement includes provisions for Contractor schedule bonuses and liquidated
damage payments from the Contractor for exceeding or missing the Provisional
Acceptance Dates and the Guaranteed Performance Conditions. For each Unit,
schedule bonuses will be paid for
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achieving Provisional Acceptance earlier than scheduled in accordance with
Exhibit N of the EPC Agreement. The bonus period is from May 1 through June 15
and can result in a maximum cumulative bonus of $880,000 for both units. There
are provisions, however, for reducing the bonus if the Demand Reliability Rate
is determined to be less than 92%.
The performance related liquidated damage provisions require the Contractor to
pay the Owner $500/kW if the net Unit output falls below 155,842 kW for each
Unit, provided, however, that a deficiency in output of no more than 1,500 kW on
a particular Unit max be offset to the degree that the output of the other Unit
exceeds the guaranteed output without the imposition of liquidated damages. In
addition, the Contractor is required to pay the Owner $12,133 per Btu/kWh if the
net heat rate exceeds 9,696 Btu/kWh for each Unit, provided, however, that a
deficiency in the net Unit heat rate of a particular Unit of no more than 100
Btu/kWh (net) max be offset to the degree thermal performance of the other Unit
exceeds the guaranteed heat rate without the imposition of liquidated damages.
The total liability of the Contractor for failure to meet the Unit output and
heat rate guarantees is limited to $14,547,840. The liability cap for all
liquidated damages under the Agreement is limited to $24,246,400.
Exhibit K of the EPC Agreement specifies all of the tests required to achieve
Provisional Acceptance. These tests include the testing required to determine if
the guarantee conditions for electrical output, heat rate and emissions have
been achieved and in addition require testing of the fire protection system. It
also requires that the combustion turbine generator successfully pass five
types of operational capability tests. Exhibit D of the EPC Agreement
establishes the specific procedures for conducting the electrical output and
heat rate tests for each Unit.
A warranty period has been established for each Unit based on the earliest of
150 starts after Provisional Acceptance or 1,250 fired hours after Provisional
Acceptance or 24 months after Provisional Acceptance.
Unit 5 successfully achieved Provisional Acceptance on May 9, 2001 and was
declared Commercial to Aquila on May 10, 2001. Unit 6 successfully achieved
Provisional Acceptance on May 31, 2001 and was declared Commercial to Aquila on
the same day.
Units 7 and 8
For Units 7 and 8, an EPC Agreement was executed on July 31, 2000 between the
General Electric Company (Contractor) and Elwood Energy III, LLC (Owner) for
the installation, start-up and testing of the two units. The Agreement
established a fixed Contract Price of $29,983,750 for performance of the work.
The Contract Price was to be paid in accordance with a Milestone Schedule
(Exhibit B of the EPC Agreement) established on the basis of scheduled dates and
specific activities over a 22 month period. No retainage was specified: however
the last payment is contingent upon Final Acceptance. All of the scheduled dates
and durations of the EPC Agreement were based on the Required Provisional
Acceptance Date. The Required Provisional Acceptance Dates of July 1, 2001 for
Unit 7, and August 1, 2001 for Unit 8 have been met.
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The Agreement includes provisions for Contractor schedule bonuses and liquidated
damage payments from the Contractor for exceeding or missing the Provisional
Acceptance Dates and the Guaranteed Performance Conditions. For each Unit,
schedule bonuses will be paid for achieving Provisional Acceptance earlier than
scheduled in accordance with Exhibit N of the EPC Agreement. The bonus period is
from June 1 through July 15 and can result in a maximum cumulative bonus of
$6,580,000 for both units. There are provisions, however, for reducing the bonus
if the Demand Reliability Rate is determined to be less than 92%.
The performance related liquidated damage provisions require the Contractor to
pay the Owner $500/kW if the net Unit output falls below 155,842 kW for each
Unit, provided, however, that a deficiency in output of no more than 1,500 kW on
a particular Unit may be offset to the degree that the output of the other Unit
exceeds the guaranteed output without the imposition of liquidated damages. In
addition, the Contractor is required to pay the Owner $12,133 per Btu/kWh if the
net heat rate exceeds 9,696 Btu/kWh for each Unit, provided, however, that a
deficiency in the net Unit heat rate of a particular Unit of no more than 100
Btu/kWh (net) may be offset to the degree thermal performance of the other Unit
exceeds the guaranteed heat rate without the imposition of liquidated damages.
The total liability of the Contractor for failure to meet the Unit output and
heat rate guarantees is limited to $16,610,378. The liability cap for all
liquidated damages under the Agreement is limited to $27,683,963.
Exhibit K of the EPC Agreement specifies all of the tests required to achieve
Provisional Acceptance. These tests include the testing required to determine if
the guarantee conditions for electrical output, heat rate and emissions have
been achieved and in addition require testing of the fire protection system. It
also requires that the combustion turbine generator successfully pass five types
of operational capability tests. Exhibit D of the EPC Agreement establishes the
specific procedures for conducting the electrical output and heat rate tests for
each Unit.
A warranty period has been established for each Unit based on the earliest of 1
50 starts after Provisional Acceptance or 1,250 fired hours after Provisional
Acceptance or 24 months after Provisional Acceptance.
Unit 7 achieved Provisional Acceptance on June 16, 2001 and was declared
Commercial to Aquila on June 29, 2001. Unit 8 achieved Provisional Acceptance on
June 16, 2001 and was declared Commercial on July 3, 2001.
Unit 9
The EPC Agreement for Unit 9 was executed on September 20, 2000 between the
General Electric Company (Contractor) and Elwood Energy III, LLC (Owner) for the
installation, start-up and testing of this Unit. The Agreement established a
fixed Contract Price of $13,562,600 for performance of the work. The Contract
Price was to be paid in accordance with a Milestone Schedule (Exhibit B of the
EPC Agreement) established on the basis of scheduled dates and specific
activities over a 14 month period. No retainage was specified; however the last
payment is contingent upon Final Acceptance. For this Unit, the Required
Provisional Acceptance Date is May 31, 2001.
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The Agreement includes provisions for Contractor schedule bonuses and liquidated
damage payments from the Contractor for exceeding or missing the Provisional
Acceptance Date and the Guaranteed Performance Conditions. For this Unit, a
schedule bonus will be paid for achieving Provisional Acceptance earlier than
scheduled in accordance with the table included in Section 12.6 of the
Agreement. The bonus period is from May 1 through May 30 and can result in a
maximum bonus amount of $200,000.
The performance related liquidated damage provisions require the Contractor to
pay the Owner $500/kW if the net Unit output falls below 155,842 kW for each
Unit. In addition, the Contractor is required pay the Owner $12,133 per Btu/kWh
if the net heat rate exceeds 9,696 Btu/kWh for each Unit. The total liability of
the Contractor for failure to meet the Unit output and heat rate guarantees is
limited to $7,567,427. The liability cap for all liquidated damages under the
Agreement is limited to $12,612,379.
Exhibit K of the EPC Agreement specifies all of the tests required to achieve
Provisional Acceptance. These tests include the testing required to determine if
the guarantee conditions for electrical output, heat rate and emissions have
been achieved and in addition, require testing of the fire protection system. It
also requires that the combustion turbine generator successfully pass five types
of operational capability tests. Exhibit D of the EPC Agreement establishes the
specific procedures for conducting the electrical output and heat rate tests for
the Unit.
A warranty period has been established for Unit 9 based on the earliest of 150
starts after Provisional Acceptance or 1,250 fired hours after Provisional
Acceptance or 24 months after Provisional Acceptance.
Unit 9 successfully achieved Provisional Acceptance and Commercial Operation on
May 7, 2001.
3.3 PROCUREMENT AGREEMENTS- UNITS 5 AND 6 (Amended and Restated)
Separate Unit 5 and Unit 6 combustion turbine and balance of plant equipment
procurement agreements were executed for this project. This equipment has been
delivered to the Elwood energy site and the two units have entered commercial
service. Pertinent details of the procurement are summarized below.
Unit 5
This Amended and Restated Unit 5 Combustion Turbine Power Plant and Balance Of
Plant Equipment Procurement Agreement was executed on October 6, 2000 between
Elwood II Holdings, LLC (Owner) and the General Electric Company (Supplier).
This Agreement supersedes a previous Turbine Agreement dated February 10, 2000
between Elwood Energy II, LLC, and the Supplier. The Turbine Agreement was
assigned to the Owner on October 6, 2000.
For a Contract Price of $36,755,900 the Supplier has agreed to sell and deliver
to the Owner one General Electric (GE) PG724 I FA Combustion Turbine Generator
Power Plant (defined as Unit 5) and additional equipment (Balance of Plant). A
Unit Payment Schedule and a Balance of
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Plant Equipment Payment Schedule are included as Exhibits 2 and 3 of the
Procurement Agreement, respectively to specify the payment conditions. Shipment
was scheduled to occur on or before December 31, 2000.
The Agreement delineates the same guarantee conditions, acceptance testing
procedures and requirements, liquidated damage conditions for performance and
warranty conditions as were defined in the EPC Agreement for Unit 5.
The combustion turbine power plant and balance of plant equipment for Unit 5 has
been installed and this Unit has entered commercial service.
Unit 6
This Amended and Restated Unit 6 Combustion Turbine Power Plant and Balance Of
Plant Equipment Procurement Agreement was executed on October 6, 2000 between
Elwood II Holdings, LLC (Owner) and the General Electric Company (Supplier).
This Agreement supersedes a previous Turbine Agreement dated February 10, 2000
between Elwood Energy II, LLC and the Supplier. The Turbine Agreement was
assigned to the Owner on October 6, 2000.
For a Contract Price of $36,755,900, the Supplier has agreed to sell and deliver
to the Owner one General Electric (GE) PG7241FA Combustion Turbine Generator
Power Plant (defined as Unit 6) and additional equipment (Balance of Plant). A
Unit Payment Schedule and a Balance of Plant Equipment Payment Schedule are
included as Exhibits 2 and 3 of the Procurement Agreement, respectively, to
specify the payment conditions. Shipment was scheduled to occur on or before
January 31, 2001.
The Agreement delineates the same guarantee conditions, acceptance testing
procedures and requirements, liquidated damage conditions for performance and
warranty conditions as were defined in the EPC Agreement for Unit 6. The
combustion turbine power plant and balance of plant equipment for Unit 6 has
been installed and this Unit has entered commercial service
3.4 PROCUREMENT AGREEMENT - UNITS 7 AND 8 (Amended and Restated)
Units 7 and 8
This Amended and Restated Unit 7 and 8 Combustion Turbine Power Plant and
Balance Of Plant Equipment Procurement Agreement was executed on October 6, 2000
between Elwood III Holdings, LLC (Owner) and the General Electric Company
(Supplier). This Agreement supersedes a previous Turbine Agreement dated
February 10, 2000 between Elwood Energy III, LLC, and the Supplier. The Turbine
Agreement was assigned to the Owner on October 6, 2000.
For a Contract Price of $80,752,100, the Supplier has agreed to sell and deliver
to the Owner one General Electric (GE) PG7241FA Combustion Turbine Generator
Power Plant (defined as Unit 7), one General Electric (GE) PG7241FA Combustion
Turbine Generator Power Plant (defined
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as Unit 8) and additional equipment (Balance of Plant). A Unit Payment Schedule
and a Balance of Plant Equipment Payment Schedule are included as Exhibits 2 and
3 of the Procurement Agreement, respectively to specify the payment conditions.
Shipment was scheduled to occur on or before December 31, 2000.
The Agreement delineates the same guarantee conditions, acceptance testing
procedures and requirements, liquidated damage conditions for performance and
warranty conditions as were defined in the EPC Agreement for Units 7 and 8.
The combustion turbine power plants and balance of plant equipment for Units 7
and 8 have been delivered to the Elwood Energy Project site and these units have
entered commercial service.
3.5 PROCUREMENT AGREEMENT - UNIT 9 (Amended and Restated)
Unit 9
This Amended and Restated Unit 9 Combustion Turbine Power Plant and Balance Of
Plant Equipment Procurement Agreement was executed on September 20, 2000 between
Elwood III Holdings, LLC (Owner) and the General Electric Company (Supplier).
This Agreement supersedes a previous Turbine Agreement dated December 31, 1999
between Enron North America Corp. and the Supplier. The Turbine Agreement was
assigned to the Owner on September 20, 2000.
For a Contract Price of $36,886,914, the Supplier has agreed to sell and deliver
to the Owner one General Electric (GE) PG7241FA Combustion Turbine Generator
Power Plant (defined as Unit 9) and additional equipment (Balance of Plant). A
Unit Payment Schedule and a Balance of Plant Equipment Payment Schedule are
included as Exhibits 2 and 3 of the Procurement Agreement, respectively to
specify the payment conditions. Shipment was scheduled to occur on or before
November 27, 2000.
The Agreement delineates the same guarantee conditions, acceptance testing
procedures and requirements, liquidated damage conditions for performance and
warranty conditions as were defined in the EPC Agreement for Unit 9.
The combustion turbine power plant and balance of plant equipment for Unit 9 has
been delivered to the Elwood Energy Project site and this Unit has entered
commercial service.
3.6 ENGAGE POWER SALES AGREEMENT
The Owner and Engage Energy US, LP (Engage) are parties to a Power Sales
Agreement (Agreement) dated as of April 5, 1999 and amended November 10, 1999.
The Agreement specifies requirements and contract payments associated with the
sale and purchase of capacity and energy from Elwood Units 1 and 2 (Committed
Units). The term of the Agreement is from April 5, 1999 through December 31,
2004. The Owner receives from Engage a fixed monthly
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capacity payment for the exclusive rights to the generating capacity and
electric energy from the Committed Units(1).
The capacity charge is $9.00 per kW each month for the first contract year and
$5.00 per kW month for the remainder of the term. In addition, the Owner
receives a variable energy charge payment ranging from $35.00/MWh at 60%
dispatch level to $30.00/MWh at lOO% dispatch level(2). A start up charge of
$2,500 per event is assessed by the Owner.
For any contract year in which Engage's annual gross revenues from the sales of
electric energy, capacity and ancillary services from the Committed Units exceed
Engage's total costs the Owner receives 16.25% of the excess. Also, if the
Owner, at its discretion decides to operate the Committed Units in excess of
their Net Dependable Capacity, the excess capacity and energy max be sold to a
third party, but, it must first be offered to Engage at the Owner's incremental
variable production cost. Profits from Engage's resale of the capacity and
energy are shared 85% to Engage and 15% to the Owner.
The Target Forced Outage Adjustment Factor (FOAF) is five percent for the
on-peak hours of the summer period. Though there is no target FOAF during any
other time period, the Owner is required to use commercially reasonable efforts
to achieve a high level of availability for the Committed Units during the
Non-Summer months. A Capacity Adjustment Factor provides a bonus payment to the
Owner of one percent (or fraction thereof) of the annual capacity payments for
each one percent the Committed Units are below the target FOAF. A corresponding
penalty is assessed for a FOAF above the target FOAF.
Periods of curtailment, reduction, or interruptions caused by Commonwealth
Edison or its successors and assigns do not count as forced outages or deratings
for FOAF calculations if the Committed Units are otherwise available during
these periods. If the Committed Units experience an unplanned outage lasting
three consecutive days or longer, the Owner has the right to offer substitute
capacity and energy to Engage from another generating source for the lesser of
$30/MWh or the actual cost of the capacity and energy. Substitute energy is
considered as available for the Committed Units for purposes of the FOAF
calculation.
Engage may dispatch the delivery of electric energy from each Committed Unit at
a rate from 60% to 100% of Net Dependable Capacity. Maximum running time is
1,500 hours per year for each Committed Unit or 3,000 hours per year cumulative
for both Committed Units. Each hour that a Committed Unit is operating counts
towards the 1,500-hours/year limitation, regardless of load.
Normal ramp up time from start up to base load of 60% of Net Dependable
Capacity is 20 minutes and from base load to lOO% of Net Dependable Capacity is
10 minutes. The Committed
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1 Engage subsequent resold the output of these units to Commonwealth
Edison, the predecessor of Exelon Generation Company, LLC ("Exelon"). Exelon
now controls dispatch of the Engage units and agreed with Elwood in March, 2001
to have the pricing terms of the Exelon PSA apply to the dispatch by Exelon of
the Engage units. This is accomplished by means of a monthly adjustment, which
effectively supersedes the Engage PSA terms.
2 Fixed price dispatch costs are effectively eliminated under the Exelon
Agreement.
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Units have a feature that allows loading to take place at twice this normal
rate, but reduces equipment life. If Engage requests this fast load ramp option,
an additional $500 per start up is charged by the Owner.
Not less than 48 hours before the beginning of each week, Engage is to notify
the Owner of its estimated hour-by-hour requirements for electric energy, start
ups and ancillary services for that week and provisionally, during the following
week. Also, Engage is to provide the Owner with a provisional estimate of hourly
requirements for the following day. The Owner is to notify Engage by noon each
day of the estimated capacity of each Committed Unit that will be available each
hour of the day commencing 36 hours later and provisionally for the day
immediately thereafter. None of these estimates by Engage or the Owner is
binding.
During the Summer On-Peak Period, the Owner is required to start a Committed
Unit within one-hour of notification by Engage. During all other periods, a
three-hour notice is required. A four-hour minimum run-time per start and
two-hour minimum off time between start-ups is required. At all times other than
Summer On-Peak Periods, the Owner has the right to refuse start up of the
Committed Units if it determines that operation is not commercially reasonable.
The Owner must then propose a rate at which it is willing to operate the
Committed Units, which Engage can then accept or reject.
Engage is not allowed to dispatch a Committed Unit during any planned outage,
maintenance outage, forced outage, Force Majeure event, or during periods when
the Committed Units are restricted due to the interconnected utility.
Upon the occurrence and during the continuance of an Event of Default by the
Owner or Engage, the non-defaulting party may at its discretion terminate the
Agreement upon thirty days written notice. Engage may terminate the Agreement
for a Committed Unit upon a thirty day written notice to the Owner if a forced
outage or Force Majeure event lasts more than 120 days provided the Owner does
not demonstrate that it has taken significant steps to remediate the cause of
the event and that it will end within 240 days of its commencement.
Going forward, the units should be able to meet or exceed the operational
standards including the target forced outage rate. It is reasonable to
anticipate that the Owner may be paid bonuses for achieving forced outage rates
less than five percent. Also, the true-up provision eliminates fuel price risk.
3.7 EXELON POWER SALES AGREEMENT
The Owner and Exelon Generation Company, LLC (Exelon) as assignee of
Commonwealth Edison Company entered into a Second Amended and Restated Power
Sales Agreement (Exelon PSA) dated as of March 1, 2001. The Agreement specifies
requirements and contract payments associated with the sale and purchase of
capacity and energy from Elwood Units 1 through 4, and 9 (Committed Units). The
term of the Agreement is from March 1, 2001 through December 31, 2012 for Units
3, 4 and 9 and from the expiration date of the Engage PSA (December 31, 2004)
through December 31, 2012 for Units 1 and 2.
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Units 1 and 2 are effectively in Exelon's control due to Engage's resale of
energy and capacity of Units 1 and 2 to Exelon. Prior to the Engage PSA
expiration date, Units 1 and 2 are committed in the sense that they are subject
to a monthly true-up for capacity and energy pricing. After expiration of the
Engage PSA, Units 1 and 2 are directly subject to the Exelon PSA. From March 1,
2001 until the expiration of the Engage Agreement, a pricing true-up is in
effect which provides Exelon with the same financial and operational
arrangements for Units 1 and 2 that exist for Units 3, 4 and 9 under this
Agreement. The true-up compares pricing and operational parameters between the
Engage and Exelon agreements and provides for a credit or debit to the monthly
payment calculation. The true-up does not apply to, nor does it affect, the
Reliability Bonus or the 2001 Special Bonus applicable to this Agreement.
Capacity payments are paid monthly as fixed reservation fees and average $4.35
per kW of net dependable capacity as follows:
o Jan - May $2.71875
o Jun $6.525
o Jul - Aug $9.7875
o Sep $4.35
o Oct - Dec $2.71875
Exelon is required to pay an energy charge consisting of two components, a
Variable O&M Charge, and a Fuel Charge. The Variable O&M Charge is $1.50/MWh and
is adjusted for inflation by the GDP-IPD as published by the U.S. Department of
Commerce. The Fuel Charge is composed of the sum of the gas price and an adder
of $0.32/MMBtu. Gas prices are indexed to the published price in Gas Daily,
Daily Price Survey, Midpoint for Chicago-LDCs, large end users, flow days. The
heat rate used for energy payments is 10,900 Btu/kWh at 100% load and 12,900
Btu/kWh at 60% load. Heat rate is prorated to the proportionate level between
these load points.
A charge of $3,250 (adjusted for inflation by the GDP-IPD) per event is charged
for each successful start up and for start-ups cancelled with less than one-hour
notice during Summer On-Peak Hours. Cancellations with at least one hour notice
during Summer On-Peak Hours are not assessed a charge. During Summer Non-Peak
Hours and Non-Summer On-Peak Hours, if cancellation is made more than four hours
prior to start-up, no Cancellation Charge is assessed but a Fuel Adjustment
Charge must be paid by Exelon. Notification from 2 to 4 hours prior to start-up
results in a $1,000 Cancellation Charge and Fuel Adjustment Charge.
Cancellations with less than two hours notice are subject to a $4,000
Cancellation Charge and Fuel Adjustment Charge.
Fuel Adjustment Charges are applied to changes in energy requirements. If
Exelon increases the amount of energy required pursuant to the day-ahead
schedule for Summer On-Peak Hours, the Intra-Day Gas Cost (higher of the day
of burn or next day after burn) applies to the incremental energy. The Next Day
Gas Cost applies to the original energy request amount. If Exelon decreases the
amount of energy pursuant to the day-ahead schedule, all energy is based on
the Next Day Gas Cost.
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Increases by Exelon to Non-Summer On-Peak Hours and Summer Non Peak Hours are
adjusted using the Next Day Gas Cost applied to the original amount of energy
delivered according to the day ahead schedule and a Fuel Adjustment Charge
applied to the incremental energy. The Fuel Adjustment Charge consists of the
Balancing Gas Cost (the two days later than the day of burn price) plus a
volumetric balancing cost applied as follows:
Amount of Increase Volumetric Balancing Cost
- ------------------ -------------------------
o 28 unit hours or less $.125 per MMBtu/MWh
o 28 to 43 unit hours $.625 per MMBtu/MWh
o Over 43 unit hours Owner's volumetric cost of balancing charges
per MMBtu
Decreases to Non-Summer On-Peak Hours and Summer Non-Peak Hours by Exelon are
subject to the Next Day Gas Cost for all energy delivered. In addition, a Fuel
Change Fee consisting of the net of the Next Day Gas Cost and the Balancing Gas
Cost (which could be positive or negative) plus a volumetric balancing cost are
included. The volumetric balancing costs are assessed as follows:
Amount of Decrease Volumetric Balancing Cost
- ------------------ --------------------------
o 28 unit hours or less $.125 per MMBtu/MWh
o 28 to 43 unit hours $.625 per MMBtu/MWh
o Over 43 unit hours Owner's volumetric cost of balancing charges
per MMBtu
A bonus and penalty plan has been structured to promote operation of the
Committed Units in the most optimal manner. Summer Months (Jun-Sep) bonuses are
awarded to the Company monthly for Equivalent Availability (EA) across all five
Committed Units for Summer Super Peak Hours (1100 to 1900 hours. Mon-Fri) and
Summer Partial Peak Hours (0600 to 1100 hours and 1900 to 2200 hours, Mon-Fri)
using a target 97% EA. Summer Month penalties are assessed to the Company
monthly for Summer Super Peak Hours. Summer Partial Peak Hours, and Summer
Non-Peak Hours (2200 to 0600 hours, Mon-Fri) also using a 97% EA.
Equivalent Availability is calculated using the formula:
{1 - ((FOH + EFDH)/PH)}, where FOH equals Forced Outage Hours, EFDH equals
Equivalent Forced Derated Hours, and PH means Period Hours. A Forced Outage or
Forced Derating event is only included in the calculation of the EA if Owner
fails to meet Exelon's Dispatch and fails to deliver Substitute Energy.
Substitute Energy is credited as unit availability and does not affect the FOH
or EFDH. The EA Summer Months Bonus is calculated on a percentage basis per MW
of Net Dependable Capacity.
Summer Month Bonus
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Month Super-Peak Partial-Peak Off-Peak
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June $71.43 $23.81 $0
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July $107.14 $35.71 $0
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August $107.14 $35.71 $0
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September $47.62 $15.87 $0
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Penalties associated with being below the EA target for the Summer Months are
divided into two groups. The first deals with EA's below 97% and above or equal
to 70% while the second covers EA percentages below 70% and above or equal to
44%. Below 44% EA, no further penalties apply. At no time can the EA penalty for
a Summer Month exceed that month's capacity payment.
Summer Month Penalty (EA < 97%, => 70%)
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Month Super-Peak Partial-Peak Off-Peak
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June $74.95 $24.98 $14.27
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July $113.75 $37.91 $21.67
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August $113.75 $37.91 $21.67
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September $47.44 $15.81 $9.03
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Summer Month Penalty (EA < 70%, => 44%)
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Month Super-Peak Partial-Peak Off-Peak
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June $80.79 $26.93 $15.39
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July $121.19 $40.39 $23.08
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August $121.19 $40.39 $23.08
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September $53.86 $17.95 $10.25
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Non-Summer Months performance is also subject to a bonus/penalty program with a
target EA of 93%. A bonus of $47.62 per MW for each percent or fraction thereof
above 93% EA for the Non-Summer period is awarded to the Owner. Penalties
associated with being below the target EA of 93% are divided into three groups.
o > 93% =>86% $95.24
o < 86% =>80% $2,811.11
o < 80% =>44% $117.13
Below 44% EA, no further penalties apply. In addition, at no time can the
aggregate penalties associated with the Non-Summer Months EA penalty exceed the
Capacity Payments for such Non-Summer Months.
In addition to the Equivalent Availability bonuses, during the Summer Months a
Reliability Bonus is also available to the Owner. The threshold reliability
level to receive a bonus is 8O% and the Monthly Reliability Bonus amounts for
each unit for each percent above this target vary by month.
o June $1,250 per 1%
o July $5,000 per l%
o August $5,000 per 1%
o September $1,250 per 1%
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Reliability is calculated for each of the five Committed Units for each Summer
Month. Average reliability for the five units is then determined for each month
and this becomes the Bonus Reliability achieved. This Bonus Reliability is
compared to the 80% threshold. The reliability bonus period consists of the
period from hour ending 0700 to hour ending 2200 on the four highest priced
On-Peak Days of each month (as defined by Power Markets Week or other mutually
agreed upon daily index into ComEd) for a total of 64 hours each in June, July,
August and September. The Bonus Reliability calculation in percent is therefore
expressed:
{1-((FOH + EFDH)/64)}, where FOH = Forced Outage Hours and EFDH= Equivalent
Forced Derated Hours.
The total reliability bonus amount received monthly by the Owner is determined
as follows:
(Monthly Reliability Bonus in $ per %) x (Bonus Reliability - 80%) x 100x5 Units
It is reasonable to believe that the Owner should be able to earn equivalent
availability and monthly reliability bonuses. The Units should be able to
satisfy the operational standards set forth in this Agreement.
Exelon may dispatch the delivery of electric energy from the Committed Units at
a rate from 60% to 100% of Net Dependable Capacity. Exelon specifies the number
of committed Units to be operated and the operating level for each Committed
Unit, but the Owner has the sole discretion to decide which units are operated
to meet the dispatch requirements or whether to use substitute electric energy
from Elwood. Substitute energy from a source outside Elwood is subject to mutual
agreement between the Owner and Exelon. Exelon may request the Owner to operate
a Committed Unit at a level above its Net Dependable Capacity, however, the
Owner is not under obligation to generate or sell the excess capacity.
Maximum running time is 1,500 hours per year for each Committed Unit or 7,500
hours for all five Committed Units. Each hour that a Committed Unit is
operating, regardless of output, counts towards the 1,500-hours/year Limitation.
Also, there is a Limit of 60 units-hours/day (number of units operating x number
of hours operating) during the Non-Summer Months and 80 units-hours/day during
the Summer Months. If Exelon requires units-hours greater than the stated
Limits, the Owner is to provide a reasonable operating cost to extend the
Schedule.
Normal ramp up time from startup to base load of 60% of Net Dependable Capacity
is 20 minutes. The ramp up or ramp down rate is approximately 8.3% of net
dependable Capacity per minute. Power requirements for start up of all five
units are 750 kWh per unit, with a maximum demand of 7.5 MW per unit for a
three-minute duration (15 MW demand when starting two units simultaneously).
Not later than 0830 each day, Exelon is to provide the Owner with an estimate of
its requirements on an hour by hour basis for electric energy and start ups for
the following day. To the degree that actual usage does not reflect these
estimates, penalties will be assessed as previously discussed. The Owner is to
inform Exelon by noon each day of the estimated capacity including deratings
that will be available for the following three days. These estimates are not
binding and the Owner can alter its estimates.
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During Summer On-Peak Hours, the Owner is required to start up to three
committed units simultaneously within one hour after being notified by Exelon.
For a dispatch request of four units simultaneously, a minimum of one hour and
15 minutes is required and for five units, a minimum of one hour and 25 minutes
is required. During all other periods, a four-hour notification is required. A
four-hour minimum run time per start and two hour minimum off time between start
ups is required.
Exelon is not allowed to dispatch a Committed Unit during any planned outage,
maintenance outage, Force Majeure event, or during periods when the Committed
Units are restricted due to the interconnected utility. Exelon has exclusive
rights to receive and purchase all electricity generated by each Committed Unit.
Except for testing purposes and response to emergency conditions at the
interconnected utility, the Owner is only allowed to operate a Committed Unit in
response to a dispatch request from Exelon.
All emission allowances allocated to the Owner by any state or federal
governmental agencies including NO(x), SO(2), mercury, carbon, or other
greenhouse gases are to be used to support generation under this Agreement. Any
additional allowances for NO(x) or SO(2) compliance necessary to meet Exelon's
dispatch requirements are to be provided by Exelon. If any new air emissions
programs are implemented, the Owner and Exelon are to develop and implement a
mutually acceptable compliance plan. Exelon is to pay for all costs to comply
with the plan up to an annual cost of $562,000.
Upon the occurrence and during the continuance of an Event of Default by the
Owner or Exelon, the non-defaulting party may at its discretion terminate the
Agreement upon thirty days written notice. Exelon may terminate the Agreement
for a Committed Unit upon a thirty days written notice to the Company if a
forced outage, planned outage or maintenance outage not excused by Force Majeure
lasts more than 120 days, provided the Owner does not demonstrate that it has
taken significant steps to remediate the cause of the event and that it will end
within 365 days of its commencement. If the Owner provides substitute energy and
capacity, the 120 day and 365 day periods are to be extended on a day to day
basis.
3.8 AQUILA POWER SALES AGREEMENTS
The Owner and Aquila Energy Marketing Corporation entered into two Amended and
Restated Power Sales Agreements (Agreements) dated as of June 30, 2000. The
Agreements specify requirements and tariff payments associated with the sale and
purchase of capacity and energy from Elwood Units 5 and 6 (Elwood II) and Units
7 and 8. The term of the Agreement for Units 5 and 6 is from June 30, 2001
through August 31, 2016. The term of the Agreement for Units 7 and 8 is from
June 30, 2001 through August 31, 2017. Both Agreements contain the same terms
and conditions and are extendable for an additional five year or mutually
agreeable time period. Aquila pays a fixed monthly reservation fee in the form
of a capacity payment for the exclusive rights to the capacity and energy from
all of the units. Monthly capacity payments to the Owner are $7.90 per kW for
Units 5 and 6 and $7.39 per kW for Units 7 and 8 for 2001 and $5.11 per kW for
the remainder of the Agreement. The capacity rate for an Agreement extension is
$4.90 per kW. Capacity charges are based on the Net Dependable Capacity but may
be adjusted for performance as an Availability Adjustment, which is based on
Equivalent Availability (EA). The Availability Adjustment reduces capacity
payments if any of the units do not achieve the
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Guaranteed Summer Super Peak Availability (97%). Guaranteed Summer Partial Peak
Availability (97%), or Guaranteed Non-Summer On Peak Availability (97%).
Forced Outage or Forced Derating event is only included in the calculation of
the EA if Owner fails to meet Aquila's dispatch and fails to deliver Replacement
Energy or pay for Aquila to acquire Substitute Energy.
The Availability Adjustment for the Summer Months (June - August) consists of
the sum of the Availability Adjustment for Super Peak Hours and the greater of
zero and the Availability Adjustment for Partial Peak Hours:
o Super Peak Hours Availability Adjustment Factor =
Annual Capacity Payments x Monthly Adjustment Factor x .75 x (.97 - EA).
o Partial Peak Hours Availability Adjustment Factor =
Annual Capacity Payments x Monthly Adjustment Factor x .25 x (.97 - EA).
The Monthly Adjustment Factor applied in the above calculations is l8% for June
and 32% for July and August. If the EA during Super Peak in any month is less
than or equal to 80%, then the EA during Partial Peak Hours is used as the EA
for Super Peak Hours.
The Availability Adjustment for the Non-Summer Period is equal to the
Availability Adjustment for Non-Summer On Peak Hours.
o Non-Summer On Peak Availability Adjustment Factor =
Annual Capacity Payments x .l8 x (.97 - EA).
The annual Availability Adjustment is not to exceed $24,000,000 in the first
Agreement year, $l2,000,000 in the last Agreement year, and $l8,000,000 per year
in all other Agreement years.
A Capacity Bonus is available to the Owner during the Summer Months if the
Average Summer Super Peak Availability exceeds the Guaranteed Summer Super Peak
Availability (97%) and the Average Summer Partial Peak Availability exceeds the
Guaranteed Partial Peak Availability. Also, Summer Super Peak Availability
during each Summer Month must be greater than 80%. The Capacity Bonus is divided
by l2 and paid over a l2-month term beginning with September of each Agreement
year. After the first Agreement year, maximum Capacity Bonus is $l25,000 per
Unit.
Capacity Bonus = {$l25,000 x .75 x (.97-EA)/.03} + {$l25,000 x .25 x
(.97-EA)/.03}
Going forward, it is reasonable to believe that the Owner will be able to earn
an availability bonus. The units should be able to satisfy the operational
standards set forth in this Agreement.
Aquila pays a monthly $/MWh Energy Charge consisting of the sum of the Variable
O&M cost and the product of the Fuel Charge and Heat Rate.
o Energy Charge = Variable O&M + ( Fuel Charge x Heat Rate/l000)
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Variable O&M is $l.00/MWh and is adjusted annually using the GDP-Implicit Price
Deflator. The Fuel Charge is based on the index published in Gas Daily -
Midpoint, Chicago-lDC's, large End Users plus an adder. If Aquila does not alter
its Day Ahead Schedule, the Fuel Charge is equal to the index plus $.l0/MMBtu.
If Aquila makes a change to the Day Ahead Schedule for Summer On Peak Hours or
for September On Peak Hours, a charge of $.l5/MMBtu is added to the fuel index.
If a change is made to the Day Ahead Schedule for Non-Summer and Summer Off Peak
Hours, a surcharge is applied to cover the costs of gas purchase adjustments.
The energy charge is tied to a fuel index, which prevents fuel price risk.
The heat rate is determined monthly based upon the measured volume of fuel and
energy for Aquila Units 5 through 8. The Owner has guaranteed Aquila that this
heat rate will not exceed l0,787 mmBtu/Mw at base load and with allowance for GE
degradation ("Guaranteed Heat Rate") and is verified by periodic testing. If the
results of periodic heat rate testing indicate the Units 5 through 8 fail to
meet the Guaranteed Heat Rate as a composite average, an adjustment is provided
to Aquila by the ratio of the Guaranteed Heat Rate/ tested Net Heat Rate in
calculating the monthly Energy Charge. The Company is allowed to accrue heat
rate credits when the tested heat rate surpasses a Threshold Heat Rate (l0,759
Btu/KWh) for use to offset occurrences when the heat rate exceeds the Guaranteed
Heat Rate (l0,787 Btu/KWh).
A start up charge of $2,500 per event adjusted annually by GPD-IPD is paid to
the Owner.
Aquila may dispatch the delivery of electric energy at a rate from 60% to l00%
of Net Dependable Capacity (but no less than 90 MW. The Owner has sole
discretion to decide which units are operated to meet dispatch requirements or
whether to use substitute electric energy. Incremental energy may be made
available through Limited over-firing of the units up to five MW per unit over
Net Dependable Capacity. Aquila may dispatch the incremental energy up to 250
hours per year when the Owner is not using it to offset a forced derating. The
Owner is not required to comply with dispatch orders during maintenance outages,
compressor washes, or Force Majeure events.
Maximum permitted running time per unit is 2,500 hours per year, except for the
first contract year, which allows 90% of maximum running time and the final
contract year, which permits 92% of maximum running time. To the extent that the
permitted running time is less than 2,500 hours per year, the Owner is to
deliver replacement power to meet Agreement requirements. Minimum time required
to start up one unit is 22 minutes. Under simultaneous dispatch, two or three
units are to be started within 37 minutes, and four units within 52 minutes. The
ramp rate for each unit from synchronization to minimum load is l2.5 MW/minute
with a minimum time period of seven minutes. Ramp rate from minimum load to
maximum load is l3 MW/minute with a minimum time requirement of 4.6 minutes.
Ramp down rate from all load levels is ll.5 MW /minute.
Not later than 0900 each day, Aquila is to provide the Owner its dispatch
Schedule for each hour of the following day. During Summer On Peak Hours, Aquila
may alter its Day Ahead Dispatch Schedule, but must notify the Company a minimum
of one hour and 25 minutes prior to requested dispatch time for up to two units.
If more than two units are to be dispatched, a minimum notification period of
one hour and 35 minutes is required. During September, the
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Day Ahead Schedule may be changed until five hours prior to Scheduled dispatch.
During Non-Summer Periods and Summer Off Peak Hours, changes to the Day Ahead
Schedule by Aquila are subject to a surcharge by the Owner.
The Owner is to inform Aquila by noon each day of the estimated capacity
including deratings that will be available for the following three days. The
Owner estimates are not binding and may be changed.
A four hour minimum run time per start and two hour minimum off-time between
start ups is required, however, Aquila is allowed to dispatch each unit for a
minimum run time of two hours up to ten times each year.
Using the difference between the sum of each unit's revenue meter and the
interconnected utility revenue meter, the facility parasitic load is determined.
This non-billable generation is then prorated among the operating units.
Upon the occurrence and during the continuance of an Event of Default by the
Owner or Aquila, the non-defaulting party may at its discretion terminate the
Agreement upon thirty days written notice or in the case of bankruptcy, five
days notice. If Aquila defaults, the Owner has the right to sell capacity and
energy to third parties. If the units have chronically poor availability of less
than 80% for three summers or 70% for two summers, Aquila may terminate the
Agreement.
3.9 CINERGY FUEl SUPPlY AND MANAGEMENT AGREEMENT
The Owner and Cinergy Marketing and Trading LLC entered into a Fuel Supply and
Management Agreement (Agreement) dated as of May l, 200l. The Agreement
specifies requirements for Cinergy as Fuel Manager to procure, Schedule and
deliver to Northern Illinois Gas Company (Nicor) and or Peoples Gas, volumes of
natural gas sufficient to meet the Owner's requirements. The term of the
Agreement is from May l, 200l to April 30, 2002. A separate agreement between
the Owner and Nicor (described in Section 4.2.5) provides gas transportation and
balancing for the gas supplied by Cinergy under this Agreement. Cinergy is
responsible for management and administration of the Nicor Transportation and
Balancing Agreement (Nicor Agreement). Any changes to the Nicor Agreement by the
Owner must be approved by Cinergy.
Cinergy is to be the sole supplier of gas to the Owner during the term of this
Agreement. Gas must be supplied from the following sources:
l. Northern Border Pipeline Company (NBPl), Alliance Pipeline Company (APl),
or Natural Gas Pipeline Company of America (NGPl) interstate pipelines.
2. Inventory in storage under the Nicor Agreement.
3. Purchase from Nicor as Requested Authorized Use or Unauthorized Use
Volumes under the Nicor Agreement.
The Maximum Daily Quantity (MDQ) of gas that Cinergy is obligated to sell and
deliver to the Owner during the Summer Months is 362,400 MMBtu/d; of which
24l,600 MMBtu/d is firm and l20,800 MMBtu/d is non-firm. Firm MDQ during
Non-Summer Months is the lesser of
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2l3,300 MMBtu/d or 88,875 MMBtu/d plus Cinergy's nominated volumes plus any
Requested Authorized Use Volumes. The non-firm MDQ during the Non-Summer Months
is Cinergy's obligation to provide quantities up to 426,600 MMBtu/d. At the
request of the Owner, Cinergy is obligated to make reasonable efforts to supply
gas in excess of the firm MDQ, but not to exceed the MDQ. The Nicor Agreement
provides firm transportation of 24l,600 MMBtu/d during the Summer Months and
284,400 MMBtu/d during the Non-Summer Months. These quantities provide
sufficient gas for l6 hours/d of operation for all nine units.
The Maximum Hourly Quantity of gas that Cinergy is to supply to the Owner during
the Summer Months is l5,l00 MMBtu/hour and during Non-Summer Months is l7,775
MMBtu/hour. These quantities meet maximum demand requirements for all units. Gas
is metered and measured by Nicor Gas at its meters located at the Delivery
Point.
The Owner is to make available to Cinergy, a gas balance storage amount of
725,000 MMBtu. This storage provides a source of fuel to allow operation of the
facility if gas is not available from other sources and to accommodate daily
fluctuations between forecasted and actual burn. The total storage inventory
allows all nine units at the facility to operate for approximately 50 hours.
Storage inventory used by Cinergy is to be replenished and returned to the Owner
upon expiration of this Agreement.
The Nicor Agreement allows the Owner (and Cinergy as its agent) to inject or
withdraw from storage up to l8l,200 MMBtu/d during the Summer Months and up to
88,875 MMBtu/d during the Non-Summer Months on a firm (non-interruptible) basis.
These quantities allow all units to operate for l2 hours during the Summer
Months and hours during the Non-Summer Months. Gas for injection or withdrawal
from storage that exceed the firm amounts are interruptible and subject to
additional fees as discussed in the Nicor Agreement description.
Cinergy receives $65,000 per month for each of the Summer Months and $l0,000 per
month for each Non-Summer Month as compensation under the Agreement. Also, for
any Non-Special Day, Cinergy receives the Gas Daily Average Price plus
$.04/MMBtu for gas supplied. For Special Days, the Company pays Cinergy at a
negotiated price for all gas ordered. A Special Day is defined as a day on
which:
l. Nicor declares a Critical Day under the Nicor Agreement.
2. Nicor forecasts an effective degree day greater than or equal to 60
effective degree days.
3. Storage withdrawal or transportation service has been curtailed by Nicor
4. Nicor has declared a force majeure.
In addition, the Owner is required to pay Cinergy $0.05/MMBtu/d for the Forecast
Variance (difference between the forecast burn and actual consumption) up to
24l,600 MMBtu/d for each day during the Summer Months and up to a 67,400 MMBtu/d
variance during the Non-Summer Months.
Although the Owner is responsible for paying all charges to Nicor under the
Nicor Agreement, certain charges under that agreement are reimbursable to the
Owner by Cinergy.
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l. Forecast variance Charges attributable to the portion of the variance up
to 24l,600 MMBtu/d in the Summer Months and 67,400 MMBtu/d in the
Non-Summer Months.
2. Delivery Variance Charges except to the extent attributable to volumes in
excess of the firm MDQ.
3. Storage Inventory Overrun Charges or Excess Storage Charges assessed for
daily storage quantity above 95l,500 MMBtu.
4. Charges for Requested Authorized Use and Unauthorized Use.
These charges are collectively referred to as the Fuel manager's T and B Charges
and may be applied by the Owner as a credit to Cinergy's invoices.
Cinergy may offer to sell power to the Owner from time to time so that the
Company can forgo running the facility and receiving gas. The Owner has no
obligation to accept these offers and acceptance is subject to the consent of
the Owner's customers.
The Owner has the right to suspend or terminate this Agreement if Cinergy's
performance results in written notice from Nicor Gas that service will be
terminated under the Nicor Agreement and Cinergy does not correct the conditions
that led to the cancellation notice.
The quantity of fuel to be supplied and delivered pursuant to this Agreement
should be sufficient to support the operation of the units at the anticipated
dispatch levels. With respect to the forecast variance charges and storage
inventory overrun charges to be paid by the Owner under this Agreement, the
amount to be paid is largely dependent upon the Owner's ability to anticipate
Unit dispatch. The amounts to be paid, if any, are also dependent upon Cinergy's
ability to manage fuel supply and transportation on behalf of the Owner.
3.l0 GAS TRANSPORTATION AND BAlANCING AGREEMENT
The Company and Northern Illinois Gas Company (Nicor) entered into a Gas
Transportation and Balancing Agreement (Agreement) dated as of May l, 200l. The
Agreement specifies requirements and fees for delivery and storage of interstate
gas supplies by Nicor. The term of the Agreement is divided into two phases.
Phase I, which applies to Units l through 4 is from May l, 200l through
September 30, 2004. Phase II, which applies to Units 5 through 9 is from May l,
200l through March 3l, 2006. Three options for extension of the Agreement are
available. Phase I Primary Term Extension provides for an l8 month extension for
Units l through 4 ending March 3l, 2006. Phase II Term Extension extends the
term for Units 5 through 9 for five years from April l, 2006 through March 3l,
20ll. Phase I and Phase II Term Extension extends the term for all nine units
from April l, 2006 through March 3l, 20ll. Extensions of the Agreement provide
for an increase in initial demand charges of 30 percent.
While Nicor is responsible for transportation and balancing gas requirements for
the facility, actual transportation is through Peoples Gas light and Coke
Company's (PGl) 24" main pipeline. The PGl pipeline interconnects with Northern
Border Pipeline Company (NBPl) and Alliance Pipeline Company (APl) lines. The
PGl pipeline is also connected to PGl's Mahomet Pipeline, which receives and
delivers gas to PGl's underground cavern storage facilities at Manlove Field in
downstate Illinois. Nicor has contracted with Peoples for service to support
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CONTRACTS AND AGREEMENTS
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transportation and balancing services to Elwood on substantially the same terms
and conditions of the Elwood-Nicor contract.
Although this Agreement is between the Owner and Nicor, under the Fuel Supply
and Management Agreement between the Owner and Cinergy, Cinergy is responsible
for day-to-day management of this Agreement. This Agreement uses units expressed
as therms while the Cinergy Fuel Management Agreement uses units expressed as
MMBtu. Since the two agreements are so closely related, they are easier to
understand by using the same units for both. For ease of comparison, the units
used in the description of this Agreement have been converted from therms to
MMBtu using the conversion factor of one MMBtu equal to ten therms.
The Owner has the right to firm transportation service within the
Minimum-Maximum Daily Nomination (MMDN) available, not to exceed the Maximum
Daily Contract Quantity (MDCQ). Nicor determines MMDN by providing to Cinergy
the daily maximum and minimum amount of gas Cinergy may nominate in response to
Cinergy's requested Day Ahead requirements. MDCQ is the maximum daily amount of
gas that Nicor is required to transport to the Owner. MDCQ during the summer
months is 24l,600 MMBtu/d and in Non-Summer months is 284,400 Btu/d. Maximum
Hourly Quantity (MHQ) is Limited to l5,l00 MMBtu/hour in Summer Months and
l7,775 MMBtu/hour in the Non-Summer Months.
Nicor provides gas storage up to a Maximum Balancing Service Account Balance
(MBAB) of 725,000 MMBtu. Balances exceeding this Limit are subject to charges as
described below. During the Summer Months, the Maximum Firm Balancing Quantity
Summer (MFBQS) is Limited to l8l,200 MMBtu/d and quantities in excess of this
amount are interruptible. During the Non-Summer Months, a Maximum Firm Balancing
Quantity Non-Summer (MFBQnS) of 88,750 MMBtu is allowed and gas exceeding this
amount is interruptible. During Non-Summer Months when forecasted Effective
Degree Days are 60 or above and days declared as Critical Days (operational
problems) by Nicor or PGl, withdrawal from storage may be further curtailed and
deliveries may be Limited to daily or hourly firm city-gate volumes.
There are a number of charges applicable to the transportation and balancing
services provided under the Agreement. A Reservation Charge of $0.45/MMBtu for
(24l,600 MMBtu/d) of MDCQ is paid to Nicor for each Summer Month. Nicor also
receives payment of a Volumetric Charge at the rate of $0.037/MMBtu for gas
delivered during the Summer Months and $0.092/MMBtu for Non-Summer Month
delivery. A Balancing and Storage Service Reservation Charge is assessed for
each Summer Month at the rate of $3.35/MMBtu of MFBQS (l8l,200 MMBtu/d).
A Delivery Variance Charge is assessed to the Owner at the rate of $0.50/MMBtu
each day that the Delivery Variance is greater than or equal to 5,000 MMBtu/d on
non-Critical days and non-Operational Flow Order days. Delivery variance is the
quantity of gas delivered to Nicor that is greater than the maximum or less than
the minimum quantity defined by Nicor for MMDN. This charge is waived if the
first six Delivery Variances are less than 60,000 MMBtu in a Contract Year. If
the 60,000 MMBtu threshold is exceeded, all prior and subsequent Delivery
Variances are assessed. On Critical Days and Operational Flow Order Days, the
Delivery Variance applies to all quantities of gas different from the MMDN.
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The Forecast Variance is the difference between Cinergy's projected Day Ahead
burn forecast as reported to Nicor and the amount of gas actually delivered. A
Forecast Variance Charge is applied to any Forecast Variance, which exceeds the
greater of 20,000 MMBtu/d or a quantity equal to plus or minus 20 percent of
Cinergy's daily Forecast Burn. Charges are assessed daily according to the
following:
Summer Months
20,000 MMBtu < variance <= l20,800 MMBtu $0.05/MMBtu
l20,800 MMBtu < variance <= l8l,200 MMBtu $0.l0/MMBtu
l8l,200 MMBtu < variance <= 24l,600 MMBtu $0.48/MMBtu
24l,600 MMBtu < variance (non-firm) negotiable
Non-Summer Months
20,000 MMBtu < variance <= 47,400 MMBtu $0.05/MMBtu
47,400 MMBtu < variance <= 88,875 MMBtu $0.55/MMBtu
88,875 MMBtu < variance <= ll8,000 MMBtu (non-firm) $0.55/MMBtu
ll8,000 MMBtu < variance (non-firm) negotiable
A Storage Inventory Overrun Charge is paid to Nicor at the rate of $0.50/MMBtu
for each occurrence where the highest daily quantity in storage is in excess of
725,000 MMBtu but less than 95l,500 MMBtu. An Excess Storage Charge is applied
monthly at the rate of $l.00/MMBtu for each occurrence where the highest daily
quantity in storage exceeds 95l,500 MMBtu. The Excess Storage Charge is also
assessed daily when balancing and storage service on any Summer Month day is
greater than 24l,600 MMBtu/d and less than 302,000 MMBtu/d and on any Non-Summer
Month Day when balancing and storage service exceeds ll8,000 MMBtu/d but is less
than l47,500 MMBtu/d.
The Owner pays Upstream Transportation Charges, which are in effect passed on to
PGl through the Transportation and Balancing Service Agreement between Nicor and
PGl. The Upstream Transportation Charges consist of two components. A
Reservation Charge is payable to Nicor for each Summer Month at the rate of
$0.737/MMBtu of MDCQ (24l,600 MMBtu/d). Also, a Volumetric Charge is included
for each month at the rate of $0.044/MMBtu on all gas delivered by Nicor.
The Owner and Nicor may agree to negotiate authorized overrun levels of daily
balancing and storage service for injection or withdrawal of gas and/or Forecast
Variance Charges; or for purchase of Nicor owned gas. An agreement prior to use
for these services constitutes Requested Authorized Use. Requested Authorized
Use of Nicor's gas supplies when approved is charged at the higher of Nicor's
gas cost or market price plus $0.20/MMBtu. Use of Nicor's gas supplies without
requested authorization and approval is considered Unauthorized Use and is
charged at the Requested Authorized Use Charge plus $60.00/MMBtu.
The minimum monthly bill for each Summer Month is the sum of the Reservation
Charge, the Balancing, and Storage Reservation Charge, and the Reservation
Charge component of the Upstream Transportation Charge and totals $4.35 million.
Phase I and II contract extensions result in a pro-rata increase in monthly and
annual minimum payments.
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Nicor is obligated to rebate 25 percent of annual charges billed to the Owner,
which exceed $5.75 million and 50 percent of annual charges, which exceed $6.75
million. Applicable charges exclude Storage Inventory Overrun, Excess Storage,
Delivery Variance, Requested Authorized Use, Unauthorized Use, Buy-Out-Amounts,
incremental GPA/OPA charges and taxes.
The Owner may terminate the Agreement beginning September 30, 2002 and at the
end of each successive Summer Month period upon giving one year prior written
notice to Nicor and paying the following lump sum amounts:
Anniversary Buy-Out-Amount
- ----------- --------------
September 30, 2002 $4,112,000
September 30, 2003 $2,789,000
September 30, 2004 $1,420,000
The Agreement is transferable by either the Owner or Nicor without consent of
the other party.
The quantity of fuel to be supplied and delivered pursuant to this Agreement
should be sufficient to support the operation of the units at the anticipated
dispatch levels. With respect to the forecast variance charges and storage
inventory overrun charges to be paid by the Owner under this Agreement, the
amount to be paid is largely dependent upon the Owner's ability to anticipate
Unit dispatch. The amounts to be paid, if any, are also dependent upon Cinergy's
ability to manage fuel supply and transportation on behalf of the Owner.
3.11 INTERCONNECTION AGREEMENT
Three separate Interconnection Agreements (Agreements) were entered into between
the Company and Commonwealth Edison company (ComEd) for the interconnection of
the Elwood Facility to ComEd's 345 kv transmission system. Separate Agreements
were used to reflect the different completion dates of the generating units. The
first Agreement was dated as of April 23, 1999 and provides interconnection for
Units 1 through 4. The other two Agreements were dated as of January 4, 2001 and
provide interconnection for Units 5 and 6, and Units 7 -9 respectively. Terms of
the Agreements continue until cancellation. As provided for in the Agreements,
after construction of the switchyard facilities by the Company, ownership of the
equipment and property including easements have been conveyed to ComEd by the
Company in accordance with FERC regulations.
The interconnection point is at the TSS-900 switchyard located on the northeast
corner of Patterson and Noel Road. In order to increase reliability, the 345 kv
interconnection is divided into two systems at the switchyard. Units 1 through 4
are connected to a bus designated as the "Red" system and Units 5 through 9 are
connected to a bus labeled the "Blue" system. Each system operates on separate
345 kv lines. To further enhance reliability, the systems are can be cross
connected to allow any of the units to connect to either system.
The Interconnection Agreements appear to have been properly executed and the
switchyard is currently operating successfully. Proper operation and maintenance
of the facilities should ensure reliable power delivery.
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3.12 OPERATION AND MAINTENANCE AGREEMENTS
The Project is operated by Dominion Elwood Services Company, Inc. (Operator)
under the terms of three Operation and Maintenance Agreements. The Agreements
are reasonable for three to five-year periods, if such is mutually agreeable.
The Operator provides all of the services , goods, and materials necessary to
operate and maintain the Project in a clean, safe, efficient and environmentally
acceptable manner in compliance with all applicable agreements, licenses,
permits and regulations and in accordance with Prudent Utility Practice. The
costs of all major maintenance of the combustion turbines and electrical
generators are the responsibility of the Owner.
The scope of services includes development of the following programs, standards
and procedures: Administrative Program, Communications Program, Facility
Management Standards, Operating Procedures, Maintenance Program, Materials
Management Program, Diagnostic Testing Program. Problem Assessment Program and
Safety Program. The Operator is also responsible for preparing an Annual
Facility Operating Plan, Annual Budget, and a Five Year Budget.
As compensation to the Operator, the Owner pays an annual operating fee of
$650,000 and in addition, reimburses the Operator for all Reimbursable Costs.
Reimbursable Costs are defined in Appendix B to the Agreements, but are
essentially all of the costs of operating and maintaining the Project, such as
labor, parts, materials, insurance, etc. For the second year of the Agreement
and all subsequent years, the annual operating fee is adjusted using the Gross
Domestic Product Implicit Price Deflator Index published each quarter by the
U.S. Department of Commerce.
The terms and conditions of these Agreements are similar to other cost plus O&M
arrangements we have reviewed for other projects. This O&M Agreements do not
include incentives for operation of the units at certain levels. However, given
the relationship of the parties involved in the O&M Agreements and the Power
Sales Agreements, it is reasonable to believe that the operator has appropriate
incentives to meet or exceed the operational standards set forth in the Power
Sales Agreements.
3.13 ADMINISTRATIVE SERVICES AGREEMENTS
An Administrative Services Agreement was executed on December 27, 2000 between
Dominion Elwood Services Company, Inc. (Dominion), and Elwood II Holdings, LLC
(Holdings II). A second Administrative Services Agreement was also executed on
December 27, 2000 between Dominion Elwood Services Company, Inc. and Elwood III
Holdings, LLC (Holdings III). These two agreements establish Dominion as the
Administrative Agent to manage, operate, direct, and exercise control over the
administrative affairs of the Elwood operating assets.
An annual fee of $1,000 is payable to Dominion as compensation under each
Agreement for its services. Any direct expenses incurred by Dominion will be
reimbursed within 30 days after receipt of invoices. The term of the Agreements
commence on the execution date and continue until terminated by written notice
from either party to the other.
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3.14 COMMON FACILITIES AGREEMENT
The Common Facilities Agreement was established on April 16, 1999 between
Peoples Gas light and Coke Company (Peoples) and Elwood Energy LLC (Elwood). An
Amendment No. 1 was executed on March 30, 2000 between Peoples Energy Resources
Corporation (PERC) and Elwood Energy LLC. Together these two documents provide
the conditions for Elwood to utilize existing facilities owned by Peoples to
provide services for Units 1 through 4. A future amendment will be required to
establish these same services for Units 5 through 9.
The following are the Facilities to be utilized and the services to be provided
under the terms of this Agreement.
o Service Water o Janitorial Services
o Fire Protection Water o Security Services
o Storm Water Discharge o Snow Plowing Services
o Blowdown Water Discharge o Landscaping
o Office space, restrooms, showers, locker rooms, o EPCRA Reporting
warehousing and machine shop access o Easements
o Air Monitoring and Reporting o Generation and
Disposal of Waste
The term of the Agreement extends until December 31, 2028. A Payment SCHEDULE is
included in the Appendices to compensate Peoples and PERC for these services and
facilities. There are provisions established for adjusting the fees in
accordance with the GDPIPD index.
The conditions set forth in the Agreement and amendments are reasonable and the
Company should be able to benefit from the use of the existing facilities for a
fair fee.
3.l5 SPARE PARTS AGREEMENT
At present, there is no spare parts agreement or long term service agreement for
the Elwood Energy Project. However, Dominion will have a fleet of 47 of the GE
7F units by 2005. This should provide leverage for reducing O&M expenses,
provide for economies in managing parts inventory, and facilitate the
acquisition of parts in a timely manner. It is the intention of DELSCO that
these benefits will be available to the partnership.
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SECTION 4.0
PERFORMANCE GUARANTEES, COMPLETION TESTING,
OPERATION AND PROJECT SCHEDULE
4.1 PERFORMANCE GUARANTEES
The Performance Guarantees are established in the Exhibit C included with each
EPC Agreement. The procedures for conducting the performance tests and the
acceptance criteria are included in the Thermal Performance Test Procedure
document included as Exhibit D to the EPC Agreement. Guarantees have been
established for net power output, net heat rate, nitrogen oxides (NO(x))
emissions, carbon monoxide (CO) emissions and noise guarantees. The following
Table 5-1 is a summary of the Performance Guarantees as they pertain to the
individual combustion gas turbines.
Table 4-1
Performance Guarantees
- --------------------------------------------------------------------------------
Units 1 - 4 Units 5 - 9
- --------------------------------------------------------------------------------
Net Output With Evaporative Cooler kW 155,260 155,842
- --------------------------------------------------------------------------------
Net Heat Rate (HHV) With Evaporative Btu/kWh 10,734 10,753
Cooler [1]
- --------------------------------------------------------------------------------
NO(x) at 15% O(2) ppmvd 15 9
Units 1 through 4 Load Range From 60%-100%
Units 5 through 9 Load Range From 50%-100%
- --------------------------------------------------------------------------------
CO (load Range From 50%-100%) ppmvd NA 9
- --------------------------------------------------------------------------------
Near Field Sound Pressure Level dBA <= 85 <= 85
When measured 1 meter in the horizontal plane and at an
elevation of 1.5 meters from machine baseline with the
equipment operating at base load
- --------------------------------------------------------------------------------
Far Field Sound Pressure Level dBA <= 66 <= 67
The Sound Pressure Level for Units 1 through 4, when
measured no closer than 4000 feet from the site boundary
with equipment operating at base load.
The Sound Pressure Level for Units 5 through 9, when
measured at a distance of 400 feet from the nearest
equipment and operating at base load. There is no far
field guarantee for Unit 9.
- --------------------------------------------------------------------------------
1. The guaranteed heat rates are on an LHV basis and were multiplied by 1.109
to arrive at the HHV heat rates presented herein.
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The Performance Guarantees summarized in Table 4-1 above are established at the
Design Basis Conditions which are defined as:
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Elevation 610 ft.
- --------------------------------------------------------------------------------
Ambient Temperature 85(degree)F
- --------------------------------------------------------------------------------
Ambient Relative Humidity 60%
- --------------------------------------------------------------------------------
Inlet System Pressure Drop With
Evaporative Cooler 4.0 in. H(2)O
- --------------------------------------------------------------------------------
Exhaust System Pressure 5.5 in. H(2)O
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Natural Gas Fuel Heating Value (LHV) @ 80(degree)F
(20540 Btu/lb for Units 1 through 4) 20539 Btu/lb
- --------------------------------------------------------------------------------
Combustion System Type Dry low NO(x)
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4.2 COMPLETION TESTING
In order to obtain Provisional Acceptance, the EPC Agreements require the
Contractor to successfully complete the Operational Capability Tests as
described in Exhibit K of the EPC Agreements. The Operational Capability Tests
include all of the tests required to substantiate the performance guarantees,
except the noise level guarantees, and they include some additional tests to
prove operational readiness capability. Units 1 through 4 passed all of the
Operational Capability Tests. Commercial operation was declared for all four of
these units in l999. Units 5- 9 have achieved Provisional Acceptance and have
been declared Commercial Operating Units. The following discussions examine the
results of the completion testing conducted to date.
CTG Performance Testing
Performance testing has been completed on all of the units and Stone & Webster
has reviewed the test reports. The results of the tests are summarized in Table
4-2.
Table 4-2
Performance Test Results
- --------------------------------------------------------------------------------
Capacity, kW Capacity Margin Heat Rate, Btu/kWh Heat Rate
HHV [1] Margin
- --------------------------------------------------------------------------------
Unit 1 154,676 -0.38% 10,732 +0.02%
- --------------------------------------------------------------------------------
Unit 2 155,510 +0.16% 10,636 +0.91%
- --------------------------------------------------------------------------------
Unit 3 152,539 -1.75% 10,788 -0.51%
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Unit 4 152,200 -1.97% 10,747 -0.13%
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Unit 5 159,454 +2.32% 10,539 +2.03%
- --------------------------------------------------------------------------------
Unit 6 158,034 +1.41% 10,591 +1.53%
- --------------------------------------------------------------------------------
Unit 7 158,396 +1.64% 10,555 +1.84%
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Unit 8 157,624 +1.14% 10,612 +1.31%
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Unit 9 159,901 +2.60% 10,369 +3.70%
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l. The performance test heat rates were reported on an lHV basis and
were multiplied by l.l09 to arrive at the HHV heat rates presented
herein.
The testing results indicated that all of the units met their performance
guarantees. On the average, the units met the guarantees for output and heat
rate by margins of 0.6 and l.2 percent, respectively. The EPC Agreements allowed
uncertainty test tolerances of 2.09 and l.94 percent for output and heat rate,
respectively. Since all of the negative margins were within the test tolerances,
all units met their contractual guarantees.
Units 5 through 9 demonstrated higher capacity and lower heat rates because they
are a newer model of the GE 7FA gas turbine than the Units I through 4.
Emissions guarantee testing has been completed on all of the units, except for
Units 6, 7 and 8. Due to the duplicity of equipment, a petition was submitted to
the EPA and approved, requesting permission to use Unit 5's emission test as a
surrogate for Unit 6 and Unit 9's test results as a surrogate for Units 7 and 8.
Stone & Webster reviewed the results of the emissions testing for Units l
through 4 conducted in l999 by Cubix Corporation. Stone & Webster also reviewed
the results of the emission testing for Units 5 and 9 conducted in 200l by Cubix
Corporation. The results for each Unit are summarized in the following Tables
5-3 through 5 through 8. The guarantee values and the EPA Limits have also been
provided. All units achieved their respective emissions guarantees. Note that
Units l through 4 were not required to meet a carbon monoxide emission
guarantee; only Units 5 through 9 were required to meet this guarantee.
Table 4-3
Unit l Emissions
- --------------------------------------------------------------------------------
Parameter 90 ll5 l35 l50 MW Guarantee EPA
Load Load Load Base Limit Limit
MW MW MW Load
- --------------------------------------------------------------------------------
NO(x) (ppmvd @ l5% O(2)) 7.52 6.32 7.95 l0.68 l5 l5
NO(x) (lb/MMBtu) 0.027 0.023 0.0294 0.039 0.06l
NO(x) (lb/hr) 32.33 3l.49 4.34 63.68 l08.0
NO(x) (tons/yr.) 24.25 23.62 33.25 47.76 72.7
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Table 4-4
Unit 2 Emissions
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Parameter 90 ll5 l35 l50 MW Guarantee EPA
Load Load Load Base Limit Limit
MW MW MW Load
- --------------------------------------------------------------------------------
NO(x) (ppmvd @ l5% O(2)) 5.27 5.02 6.62 8.94 l5 l5
NO(x) (lb/MMBtu) 0.0l9 0.0l8 0.024 0.033 0.06l
NO(x) (lb/hr) 22.59 24.29 36.06 5l.52 l08.0
NO(x) (tons/yr.) l6.94 l8.22 27.05 38.64 72.7
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Table 4-5
Unit 3 Emissions
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Parameter 90 ll5 l35 l50 MW Guarantee EPA
Load Load Load Base Limit Limit
MW MW MW Load
- --------------------------------------------------------------------------------
NO(x) (ppmvd @ l5% O(2)) 9.26 6.4l 7.64 l2.l6 l5 l5
NO(x) (lb/MMBtu) 0.034 0.023 0.03 0.044 0.06l
NO(x) (lb/hr) 39.82 3l.l3 4l.77 70.60 l08.0
NO(x) (tons/yr.) 29.86 23.34 3l.33 52.95 72.7
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Table 4-6
Unit 4 Emissions
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Parameter 90 ll5 l35 l50 MW Guarantee EPA
Load Load Load Base Limit Limit
MW MW MW Load
- --------------------------------------------------------------------------------
NO(x) (ppmvd @ l5% O(2)) 6.73 5.29 6.26 8.87 l5 l5
NO(x) (lb/MMBtu) 0.025 0.0l9 0.023 0.032 0.06l
NO(x) (lb/hr) 29.l4 25.24 33.75 5l.33 l08.0
NO(x) (tons/yr.) 2l.86 l8.93 25.3l 38.50 72.7
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Table 4-7
Unit 5 Emissions
-----------------------------------------------------------------
Parameter 90 MW 150 MW Guarantee EPA
Load Base Limit Limit
Load
-----------------------------------------------------------------
NO(x) (ppmvd @ 15% O(2)) 6.29 6.99 9 0
NO(x) (lb/MMBtu) 0.023 0.026 0.061
NO(x) (lb/hr) 25.11 39.89 108.0
-----------------------------------------------------------------
CO (ppm) 0 0.1 9 --
-----------------------------------------------------------------
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Table 4-8
Unit 9 Emissions
-----------------------------------------------------------------
Parameter 90 MW 150 MW Guarantee EPA
Load Base Limit Limit
Load
-----------------------------------------------------------------
NO(x) (ppmvd @ 15% O(2)) 4.91 7.54 9 0
NO(x) (lb/MMBtu) 0.018 0.027 0.061
NO(x) (lb/hr) 19.79 43.00 108.0
-----------------------------------------------------------------
CO (ppm) 0.3 0.1 9 --
-----------------------------------------------------------------
Noise Testing
Units 1 through 4
Acoustic Associates, Ltd. Prepared a report on November 29, 1999 to present the
results of a near field sound level test on Units 1 through 4. The test
procedure was based on the "GE Gas Turbine Noise Assessment Protocol". Average
sound level across 57 locations for each unit was 75-76 dBA. which is in
compliance with the 85-dBA guarantee.
Units 5 through 9
Units 5 and 9 were tested by Acoustics Associates, Ltd. On June 12, 2001 and
results reported on July 2, 2001. The average sound levels across 57 locations
for each unit were 80 dBA and 77 dBA, meeting the guarantee point of 85 dBA.
These units are representative of Units 6, 7 and 8, which will be tested for
near field compliance in the near future. Far field sound measurements were
collected by Acoustics Associates for Units 5 and 9 and the preliminary results
indicate compliance with the State of Illinois Noise Regulations. Units 5 and 9
represent the two different types of noise abatement used on the units. Test
results of these two units can be considered representative of the other units.
4.3 OPERATION
Stone & Webster reviewed the Year 1999 (July through December) and 2000
operating data for Units 1 through 4. The following Tables 5-12 and 5-13
summarize the operating data. The Project reports the forced outage adjustment
factor (FOAF) separately for the summer and non-summer periods. The Year 1999
operating data indicates that the FOAF are higher relative to the Year 2000.
Operation of the units in 1999 was limited; therefore, any outage would consume
a relatively significant number of hours resulting in a higher FOAF. Also, it is
common that in the initial commercial operations period that there are an
increased number of outages. This is common in combustion turbine power plants.
The Year 1999 operating data reflects these
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points. As the number of operating hours increased on the units, the forced
outages and the duration of the forced outages decreased, which are the trends
that we would expect.
Table 4-9
Units 1 Through 4
Year 1999 Operating Data
-----------------------------------------------------------------
Starts Fired Hours MW Hrs FOAF (%)
(Summer Period)
-----------------------------------------------------------------
Unit 1 57 438 50,254 2.42
-----------------------------------------------------------------
Unit 2 52 433 51,514 8.64
-----------------------------------------------------------------
Unit 3 57 411 54,362 5.23
-----------------------------------------------------------------
Unit 4 62 485 59,416 8.60
-----------------------------------------------------------------
Table 4-10
Units I Through 4
Year 2000 Operating Data
-----------------------------------------------------------------
Starts Fired Hours MW Hrs FOAF
(Summer Period)
-----------------------------------------------------------------
Unit 1 81 575 83,760 1.01
-----------------------------------------------------------------
Unit 2 77 595 89,299 0.03
-----------------------------------------------------------------
Unit 3 115 794 119,986 0.00
-----------------------------------------------------------------
Unit 4 107 840 124,357 0.12
-----------------------------------------------------------------
4.4 PROJECT SCHEDULE
There are no schedule issues with Units 1 through 4, since they have been
complete for approximately two years. Units 5 through 9 have also all been
completed in advance of the scheduled completion dates. As a result, there are
no Schedule issues to examine.
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SECTION 5.0
PROJECT SITE
5.1 GENERAL SITE LOCATION, ACCESS AND CONDITIONS
The Project site is located near the Village of Elwood in Will County, Illinois,
approximately 50 miles southwest of Chicago. The 195 acre site was initially
developed in 1998 when the first four combustion turbines were constructed. The
initial development consisted of Units 1 through 4, which entered commercial
service in 1999 and the next phase of development for Units 5 through 9 will be
completed in the summer of 2001. Elevation of the site is approximately 610 feet
above mean sea level.
Interstate Highway No. 55 passes close to the site and good county roads link
the interstate highway to the site. The nearest airport is in Joliet, a few
miles to the north. Rail transportation is available for the site and
arrangements have been made for unloading of equipment on a siding near the
Elwood Site in Millsdale, Illinois. Natural gas may be procured from three
separate suppliers and can be transported to the site by three existing
pipelines.
5.2 SITE ASSESSMENT
Geotechnical and Foundation Conditions
The EPC Agreements for Units 1 through 9 require the Contractor to be
responsible to determine subsurface conditions at the site using a program of
field investigations, laboratory testing, and engineering analysis which defines
critical geotechnical characteristics of the site. The Contractor was
responsible for defining the parameters used in the design and proportioning of
the foundation systems and providing appropriate foundations for the proposed
power facilities.
The EPC Agreements for Units 1 through 9 also specify the same civil codes and
standards, which are considered appropriate. All structures are to be designed
and constructed in accordance with BOCA 1996, Building Officials and Code
Administrators International, which specifies foundation design requirements for
static and dynamic load conditions. Foundations are also required to be designed
to satisfy any load or performance requirements designated by equipment
suppliers.
The foundations for Units 1 through 9, other structures, and support facilities
are considered to be designed and constructed per the requirements of the EPC
Agreements and are, therefore, acceptable.
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Environmental Site Assessment
The Woodward-Clyde International-Americas (Woodward-Clyde) office in Chicago
prepared an Environmental Investigation Report, dated August 3, 1998, for the
Peoples Gas light and Coke Company. The power plant area is located in an
industrial area and adjacent to a spray irrigation area that is used to dispose
of treated storm water. The site also was used in the past for agriculture and
may also include pesticides/herbicides from farming activities. On this basis,
soil and groundwater sampling and laboratory testing was conducted to determine
whether site contamination exists which might affect site development.
The objectives of the Woodward-Clyde Report were to establish an environmental
baseline for soil and ground water; and also to determine the potential for
adverse health impacts for workers.
The Conclusions presented in this report indicate that:
l. Arsenic was present, and exceeded the Tier 1 remediation objective for
ingestion but did not exceed the Tier 1 remediation objective for direct
worker contact. The detected levels are within typical background ranges
for metropolitan areas in Illinois and, therefore, are not a concern.
2. Benzene was detected in a subsurface soil sample slightly above the lowest
Tier 1 remediation objective for migration to groundwater pathway, but was
below the Tier 1 remediation objective for direct worker contact. The
benzene is not expected to be of concern since it was detected at a
relatively low concentration level and was not detected in a nearby
groundwater monitoring well.
3. Dieldrin was detected in a subsurface soil sample slightly above the
lowest Tier 1 remediation objective for the migration to groundwater, but
is below the Tier 1 remediation objective for direct worker contact.
Dieldrin is not expected to be of concern since it was detected at a
relatively low concentration and at a shallow depth.
4. No environmental concerns related to possible releases from the adjacent
spray irrigation or groundwater in the vicinity of the spray irrigation
field were identified.
5. No environmental concerns related to possible releases from the adjacent
Praxair-Linde property were identified.
The report concludes that even though arsenic, benzene, and Dieldrin were
detected in site soils, the concentrations of these constituents do not exceed
Tier I remediation objectives for direct contact for construction workers and
thus do not posed a health and safety concern for future construction
activities.
Ambient Noise
The EPC Agreements establish the noise guarantee requirements, which must be met
by the Contractor. The requirements consist of a near field noise guarantee and
a far field noise guarantee. The near field noise guarantee is typical of
guarantee requirements used in the utility industry for operating equipment and
requires that the sound pressure level not exceed 85 dBA, when measured 1 meter
in the horizontal plane and at an elevation of 1.5 meters from machine baseline
with the equipment operating at base load. Units 1 through 4, 5 and 9 have been
tested
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for near field noise and are in compliance with the guarantee requirements.
Units 6 through 8 are expected to be tested in the near future and due to their
similarity to Unit 5, should meet the guarantees.
The far field noise guarantee is specified differently for the first four units
than for the last five units. Units 1 through 4 have a limit of 66 dBA, when
measured no closer than 4000 feet from the site boundary. Units 5 through 8 have
a limit of 67 dBA, when measured at a distance of 400 feet from the nearest
equipment and operating at base load. Unit 9 does not have a far field
guarantee, although the unit was tested by the owner after installation. The
State of Illinois has established Noise Regulations, which impose daytime, and
nighttime sound level limits on properties adjoining noise generating
facilities.(3)
Units 5 and 9 have been tested for far field noise and preliminary results
indicate compliance with the Illinois Noise Regulations. These units are
representative of the other units at the Facility and their compliance can be
considered as acceptable for all units.
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3 Illinois State Environmental Regulations-Title 35, Subtitle H: Noise
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SECTION 6.0
PERMITS, APPROVALS, AND CERTIFICATIONS
The legal and regulatory requirements have been identified for the Project.
Since the combustion gas turbines and the auxiliary equipment have been
constructed and all of the machines have entered commercial service, the
permits, approvals and certifications have been obtained. The following Table
7-1 is a summary of the permits, approvals and certifications that have been
obtained.
Table 6-1
Status of Permits, Approvals, and Certifications
============================================================================================================
Date of
Issuing Agency Type of Approval Permit Status Approval
============================================================================================================
Federal
============================================================================================================
Federal Energy Certification of Exempt Wholesale Generator Complete for
Regulatory Status -- With Market Based Rates. Needed to Units 1-4 3/5/99
Commission (FERC) make sales of electricity at wholesale from Units 5 and 6 2/1/01
the facility. Units 7 2/5/01
through 9
============================================================================================================
State of Illinois
============================================================================================================
Illinois PSD -- Air Permit to Construct Complete
Environmental required for a major new source of emissions Units 1-4 12/21/98
Protection Agency Units 5 and 6 10/17/00
(IEPA) Units 7 10/17/00
through 9
Air Quality -- Title V Operating Complete
Permit (PSD) for pollutant emitting Unit 1-4 12/27/99
facility (Units 5
through 9 after
operation)
Acid Rain Permit Phase II Complete 01/01/2000
Units 1-14
NPDES Permit for industrial facilities Complete
for discharge NPDES for Units 1-9 Units 1-4 11/19/98
under Peoples Gas Units 5 05/17/01
through 9
============================================================================================================
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6.1 FEDERAL PERMITS
Federal Energy Regulators Commission (FERC)
The Energy Policy Act of 1992 provides for creation and certification of Exempt
Wholesale Generators (EWGs), which are entities authorized for and engaged
exclusively in the generation and sale of electric energy at wholesale. EWGs are
exempt from provisions of the Public Utility Holding Company Act (PUHCA) of 1935
and may apply to FERC for an order requiring access to transmission lines. The
Certification of Exempt Wholesale Generator Status was approved for Units 1
through 4 on March 5, 1999, Units 5 and 6 on February 1, 2001, and Units 7
through 9 on February 5, 2001. The Approval of Rates for wholesale sales of
electricity under the Federal Power Act was also approved for Units 1 through 4
on February 31, 1999.
Federal Aviation Administration (FAA)
The FAA requires notification of construction of any structure in excess of 200
feet above ground level. No transmission lines, stacks or cranes are anticipated
being higher than 199 feet. Notification of construction to the FAA is not
required.
6.2 STATE PERMITS
Illinois Environmental Protection Agency (IEPA)
Pursuant to the Clean Air Act of 1970 and its amendments, IEPA has adopted the
Federal standards for criteria pollutants and the promulgated standards for
additional pollutants. The US Environmental Protection Agency (EPA) has
delegated the responsibility for administering the Acid Rain and Prevention of
Secondary Determination (PSD) programs to the IEPA.
The nine simple cycle units must meet requirements of the EPA's Acid Rain
Program since they are larger than 25 MW. The Elwood peaking generation facility
must also undergo PSD permitting in accordance with 4OCFR52.21. The Clean Air
Permit Program (CAAPP) for Units 1 through 4 received a completeness
determination from the IEPA on December 27, 1999, which allows Units 1 through 4
to operate in compliance with CAAPP (Title V) permit requirements. An
application for the CAAPP operating permit is to be submitted to Illinois EPA
within 180 days following initial startup of Units 5 through 9 in order to allow
for equipment shakedown and emissions testing. The submittal of a complete
permit application will satisfy the CAAPP permit requirements.
The Construction Permit PSD for the Units 5 and 6 and 7 through 9 were each
approved on January 27, 2000. The IEPA has determined that the Elwood Energy
Project will comply with applicable state and federal emission standards and
will utilize Best Available Control Technology (BACT) for emissions of NO(x),
CO, SO(2), VOM, and PM. The Elwood Energy Project must demonstrate compliance
with specified emissions limits as listed in Table 6-2.
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Table 6-2
Annual Project Emissions (tons/yr.)
--------------------------------------------------------
Pollutant Limit (Total)
--------------------------------------------------------
NO(x)
Units 1-4 292.64
Units 5 and 6 217.9
Units 7 through 9 326.9
CO
Units 1-4 146.74
Units 5 and 6 60.1
Units 7 through 9 90.2
PM/PM(10)
Units 1-4 54.36
Units 5 and 6 57.7
Units 7 through 9 86.6
VOM
Units 1-4 4.03
Units 5 and 6 7.57
Units 7 through 9 11.35
SO(2)
Units 1-4 3.32
Units 5 and 6 3.58
Units 7 through 9 5.4
--------------------------------------------------------
1. Includes fuel gas heaters.
2. The annual limits are based on Units 1 through 4 operating no more than
1,500 hours per calendar year and Units 5 through 9 operating no more than
3,200 hours per calendar year.
3. Combustion turbines (CT) will be dry low NO(x) combustors and fuel gas
heaters will be low NO(x) burners.
The CT units include the latest BACT. During the proposed simple cycle
operation, the units will comply and emissions are anticipated to meet all IEPA
and EPA emission requirements.
On November 19, 1998, the IEPA issued a NO NPDES Permit Modification Required
for Units 1 through 4, using existing site Permit No. IL0046779, under the name
of Peoples Gas pursuant to sections 2.3 and 2.4 of the Common Facilities
Agreement with the Owner. On May 17, 2001, The IEPA issued a Final Permit No. IL
0074811, under the Owner's name which covers Units 5 through 9. It is
anticipated that all of the requirements for the NPDES permits can be satisfied
for operation of the Elwood Energy Project.
The EPC Contractor is responsible for obtaining the NPDES stormwater
construction permit from the IEPA, for the Owner, for construction of Units 5
through 9.
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Other IEPA permits required for operation of Units 5 through 9 presently under
construction will be applied for at the appropriate time. These permits are
considered routine and no problems are anticipated in obtaining the remainder of
the permits required to operate these units.
6.3 LOCAL PERMITS
No local permits, critical to start up or operation, are required for Units 1
through 9.
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SECTION 7.0
PROJECT PARTICIPANTS
7.1 ELWOOD ENERGY LLC
Elwood Energy LLC is a Delaware limited liability company formed in 1998 to
develop, construct, own and operate the Elwood Energy electric generating
facility. Elwood Energy LLC is owned indirectly by Peoples Energy Resources
Corp. and Dominion Energy, Inc.
7.2 PEOPLES ENERGY RESOURCES CORP
Peoples Energy Resources Corp. (PERC) is an Illinois corporation formed on
January 26, 1996 as a wholly-owned subsidiary of Peoples Energy Corporation to
engage in various unregulated business enterprises, including midstream fuel
services and electric power generation. The midstream fuel services operation is
structured to complement Peoples Energy Corporation's natural gas business.
The electric power generation business segment is operated by PERC Power, LLC,
which is a Delaware Limited Liability Company formed on June 29, 1999, as a
wholly owned subsidiary of PERC. Since its inception, PERC Power LLC has engaged
in the development, construction, operation, and ownership of electric
generation facilities for electricity sales to electric utilities and power
marketers.
7.3 DOMINION ENERGY, INC.
Dominion Energy, Inc. is a wholly owned subsidiary of Dominion Resources, Inc.
(Dominion). Dominion is a fully integrated gas and electric energy holding
company headquartered in Richmond, Virginia. As of December 31, 2000, DRI had
approximately $29.3 billion in assets. Dominion Energy has $4.4 billion in
assets and operates generation facilities in West Virginia, Connecticut and
Illinois.
7.4 AQUILA ENERGY MARKETING CORPORATION
Aquila Energy Marketing Corporation is a subsidiary of Aquila, Inc. (Aquila).
Based in Kansas City, Aquila, partially owned by Utilicorp United, is one of the
top wholesalers of electricity and natural gas in North America, owns and
controls a diverse portfolio of merchant assets including power plants, gas
storage, pipeline, and processing facilities, and other merchant infrastructure
facilities. For the 12 months ended March 31, 2001, total revenues from Aquila's
businesses were $33.2 billion. In 2000, Aquila was ranked as one of the nation's
largest wholesalers of natural gas and power. Aquila's asset portfolio includes
electric generation, natural gas storage, natural gas transportation, gathering
pipelines and processing assets, coal terminals and handling facilities, and
long-haul fiber. During 1999, Aquila marketed approximately 10.4 Bcf/d of
natural gas, 236.5 thousand MWh's of power and 16.9 million tons of coal and
related products
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worldwide. Aquila has approximately 4,500 MW of electric power generation
capacity owned, controlled or under development.
Aquila is 80 percent owned by UtiliCorp United, a multinational energy company
based in Kansas City with more than 4 million customers. Utilicorp operates in
the United States, Canada, New Zealand and Australia. At March 31, 2001,
UtiliCorp had 12-month revenues of $36.3 billion and total assets of $13.3
billion.
7.5 EXELON GENERATION
Exelon Generation is the largest competitive electric generation company in the
United States, as measured by owned and controlled megawatts.
Exelon Generation owns generation assets in the Mid-Atlantic and Midwest regions
with net capacity of 19,159 MW, including 13,949 MW of nuclear capacity. Exelon
Generation also controls another 16,013 MW of capacity in the Midwest, Southeast
and South Central regions through long-term power purchase agreements. Exelon
Generation also has a 49.9% interest in Sithe Energies which owns and operates
generation facilities and currently has 9,879 MW of capacity in operation, under
construction or in advanced development. Exelon Generation also owns a 50%
interest in AmerGen Energy Company, LLC, which owns three nuclear stations with
a total generation capacity of 2,378 MW.
The Exelon Power Team division is a major wholesale marketer of energy, that
uses Exelon's generation portfolio, transmission rights and expertise to provide
generation to wholesale customers under long and short-term contracts.
ComEd Energy Delivery is a unit of Chicago-based Exelon Corporation, one of the
nation's largest electric utilities. ComEd Energy Delivery provides service to
more than 3.4 million customers across Northern Illinois, or 70 percent of the
state's population.
7.6 ENGAGE ENERGY US, LP
Engage Energy was originally formed in 1997 as a joint venture of the Coastal
Corporation of Houston, Texas and Westcoast Energy Inc. of Vancouver, Canada.
Engage Energy offered a range of energy services, including natural gas
marketing and trading, electricity trading and sales, energy management
services, structured storage and transportation related services. The joint
venture was terminated on September 25, 2000.
Following the termination, Westcoast Energy Inc. retained the right to use the
Engage Energy US name and certain natural gas and electric power endeavors.
Westcoast Energy Inc. has substituted Engage Energy America LLC as the contract
party in the Power Sales Agreement with Elwood Energy LLC.
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7.7 NORTHERN ILLINOIS GAS COMPANY (NICOR GAS COMPANY)
Nicor Gas Company, a regulated natural gas distribution utility and a subsidiary
of NICOR, Inc. (Nicor), provides service to a territory that encompasses most of
the northern third of Illinois, excluding the city of Chicago. Nicor's revenues
for the year ended December 31, 2000 were $2.3 billion. In addition to providing
natural gas service to more than 5.7 million people living and working in 641
communities, Nicor Gas Company transports and stores natural gas for nearly
129,000 commercial, industrial and residential customers who purchase their own
gas supplies. In 2000, residential customers accounted for 43 percent of natural
gas deliveries, while commercial and industrial customers accounted for 25
percent and 32 percent, respectively. The company has approximately 2,200
employees and a 29,000-mile distribution system, which is connected to seven
interstate pipelines, each originating in a major gas producing area in North
America.
7.8 CINERGY CORP.
Based in Cincinnati, Ohio, Cinergy Corp. is one of the nation's leading
diversified energy companies. Cinergy's net revenues were $8.4 billion for the
year ended December 31, 2000 and had assets of $12 billion. Cinergy has a
focused strategy intent on growing its energy merchant business. Cinergy owns,
operates or has under development over 21,000 megawatts of generation. Cinergy
has the eighth-largest electricity trading organization in the U.S. as well as
physical and financial gas trading capabilities of 35 billion cubic feet per
day. Cinergy has approximately 52,000 miles of electric and gas transmission
lines in the U.S. and abroad. Cinergy owns regulated operations in Ohio, Indiana
and Kentucky that server 1.5 million electric customers and about 500,000 gas
customers.
7.9 DOMINION ELWOOD SERVICES COMPANY, INC
Dominion Elwood Services Company, Inc. is the wholly owned subsidiary of
Dominion Energy Inc., which was formed to provide operation and maintenance
services to Elwood Energy LLC. Operation and maintenance expertise is acquired
through the Dominion Energy organization.
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SECTION 8.0
PROJECT FINANCIAL ASSESSMENT
8.1 OVERVIEW
The Financial Projections (Projections) consist of pro forma cash flows for
Elwood Energy LLC (Project) from October 2001 through June 2026. Stone & Webster
has reviewed the assumptions, data, and the calculations necessary to support
the cash flow projections of the cash flow available for debt service. Stone &
Webster has verified that the underlying model assumptions are consistent with
the expected performance and the commercial terms of the Project Agreements.
Stone & Webster has compared the Projections to the Project Agreements, data
provided to Stone & Webster, and power industry public information. Stone &
Webster has not reviewed the tax and insurance assumptions, which were provided
by the Owner and financing assumptions, which were provided by CSFB.
Lastly, Stone & Webster performed several sensitivities to determine the impact
of certain variables on the DSCRs. The Projections for the sensitivity cases are
included in Attachment 4 of this Report. The Projections are calculated in
nominal dollars based on an assumed inflation rate of 3.0% per annum.
8.2 PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
In preparing this Report and the conclusions contained herein, Stone & Webster
has made certain assumptions with respect to the conditions, which may exist, or
events, which may occur in the future. While Stone & Webster believes these
assumptions to be reasonable for the purpose of this Report, they are dependent
on future events, and actual conditions may differ from those assumed. In
addition, Stone & Webster has used and relied on information provided to us by
sources that we believe to be reliable. Stone & Webster believes that the use of
this information and assumptions is reasonable for the purposes of this Report.
However, some assumptions may vary significantly due to unanticipated events and
circumstances. To the extent that actual future conditions may differ from those
assumed in this Report, or provided to us by others, the actual results will
vary from those forecast. This Report summarizes our work up to the date of the
Report and changes in conditions occurring or that became known after such date
could affect the Projections.
The principal considerations and assumptions related to the Projections are
listed below:
1. The electricity market forecasts for energy and capacity prices, Project
dispatch, fuel prices, etc., were prepared by Pace using a market
simulation model. Stone & Webster reviewed the technical inputs to the
Pace model and found them to be reasonable. Stone & Webster did not
independently verify the methodology used by Pace nor verify the accuracy
of the forecasts.
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2. Stone & Webster has made no determination as to the validity and
enforceability of any contract, agreement, rule, or regulation as
applicable to the Project and its operations. For the purposes of this
Report, Stone & Webster has assumed that all contracts, agreements, rules,
or regulations will be valid and fully enforceable in accordance with the
terms and that all parties will comply with the provisions of their
respective agreements.
3. Stone & Webster has reviewed the O&M expenses for the Project. We have
assumed that the Project will operate and be maintained in accordance with
the manufacturers' recommendations, O&M agreements, O&M and capital
budgets, standard industry practice, and in a safe and environmentally
responsible manner.
4. It is assumed that the fuel will be available in sufficient quantities and
at the prices forecasted by Pace for the period covered in the
Projections.
5. Fuel transportation, management, and balancing services will be provided
by Northern Illinois Gas Company (NICOR) and Cinergy under their
respective agreements and similar successor agreements. Stone & Webster
assumes that the fuel management will not result in any significant costs
for variances, etc. under those agreements.
6. Stone & Webster has assumed that all licenses, permits, and approvals
required to operate the Project which have not been obtained will be
obtained in a timely basis and any changes that may be required to any
permits will not materially affect the design, operation, cost, or
maintenance of the Project.
7. Stone & Webster has assumed that the Project will be able to purchase
emission allowances, to the extent any are required, on an as needed basis
to comply with the emission limits. We have assumed that emission offsets
will be available for purchase at the prices forecasted in the
Projections. Stone & Webster has not evaluated the feasibility or cost of
Elwood implementing alternate strategies for complying with its emission
limits.
8. Stone & Webster has not evaluated the non-operating expenses projected by
the Project including property and sales taxes, insurance, and general and
administrative expenses.
8.3 OPERATING ASSUMPTIONS
Stone & Webster evaluated the operating assumptions associated with the Project.
The Projections are based on a 1,409 MW net peaking capacity operating at an
average capacity factor of approximately eleven percent over the 26 year
horizon. In 2001, Elwood is assumed to have a summer heat rate of approximately
10,600 Btu/kWh. The average heat rate for the entire forecast period is 11,170
Btu/kWh HHV, which reflects degradation and partial load operation. This is
conservative compared to Pace, which, consistent with its forecast methodology,
assumes Elwood and all competing peaking units will operate at 10,600 Btu/kWh
during the summer with no degradation. Stone & Webster believes that the
operating assumptions underlying the Projections are reasonable and achievable.
Power Plant Availability
Power Plant availability is a function of many variables, including design and
construction quality, operation and maintenance practices and fuel quality. The
Projections and the
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underlying Pace market study are based on a forced outage rate of 2.5 percent
and two weeks for maintenance, which allows ample time for maintenance and an
allowance for forced outages. The Pace analysis assumed the same availability
for the competing peaking units in its model.
Capacity Factor
The Project capacity factor is based on Pace's economic dispatch of the Project
within the context of its MAIN market study. Stone & Webster did not
independently verify the methodology that Pace used to develop the capacity
factor nor verify the accuracy of the forecast. Pace projected for the
Projections that the Project will have an average capacity factor of
approximately eleven percent.
Capacity
The Projections are based on the net Project capacity operating at site
conditions, with monthly adjustments for ambient conditions and degradation. The
capacity forecasts in the Projections are based on each unit's performance test
results, excluding the test tolerances. Those test results were adjusted to
representative ambient conditions for each month, which approximate the
conditions when the unit would probably operate during that month. Gas turbine
evaporative inlet air coolers were assumed to operate above 55(degree)F, which
increases a unit's capacity.
Degradation was applied to each unit's capacity based on its operating hours, in
accordance with General Electric's degradation curves for these gas turbines.
Those curves reach a maximum degradation of 5.3 percent at the end of a
maintenance cycle. Because the maintenance cycle is dictated by the number of
starts for these units, the degradation is not expected to reach such high
levels of degradation. The average degradation rate for this scenario is 3.6
percent.
The Aquila PSA capacity payment includes a correction for degradation that is to
be based on GE's degradation curve. Therefore, that payment would be constant if
the CTs degrade in accordance with GE's curve.
These levels of degradation are based on good operation and maintenance
practices, including compressor washes. Stone & Webster considers the assumed
degradation to be within the range of expected degradation for such power
generation facilities based on the planned maintenance SCHEDULE.
Heat Rate
Unit heat rates were determined based on the performance test results, with
monthly adjustments for ambient conditions and degradation.
Degradation was calculated based on cumulative operating hours, logarithmically
approaching a maximum value of 2.5 percent after 48,000 operating hours. The
average degradation rate for this scenario is 1.8 percent.
The Aquila PSAs specify a guaranteed heat rate of 10,787 Btu/kWh against which
the actual, full-load heat rate is evaluated for purposes of determining
penalties against the Project. The
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Project will earn credits for heat rates below the threshold heat rate of 10,759
Btu/kWh. The evaluation includes an allowance for degradation according to GE's
degradation curve.
The Exelon PSA specifies guaranteed heat rates of 10,900 and 12,900 Btu/kWh at
100 and 60 percent loads, respectively. Heat rates at intermediate loads are to
be interpolated.
The forecast heat rates in the Projections are significantly better than the
guaranteed heat rates in the PSAs, so adjustments for deficient heat rates are
not expected.
8.4 REVENUES
The Projections assume that the Project will operate under four PSAs initially
and as a merchant facility thereafter. Those PSAs are described in Section 4 of
this report. The PSA with Engage is transacted through the Exelon PSA, so it is
included here as part of the Exelon PSA. The Aquila PSAs are assumed to be
extended for five years. The three primary PSAs are summarized below:
----------------------------------------------------------------------------
Aquila Aquila II Exelon
----------------------------------------------------------------------------
Units 5 & 6 7 & 8 1, 2, 3, 4, & 9
----------------------------------------------------------------------------
Termination Date [1] 8/22 8/23 12/12
----------------------------------------------------------------------------
Dispatch Range, % 60 to 100 60 to 100 60 to 100
----------------------------------------------------------------------------
Capacity Payment, $/kW-yr. 61 [3] 61 [3] 52
----------------------------------------------------------------------------
Startup Payment, $/start [2] $2,500 $2,500 $3,250
----------------------------------------------------------------------------
Basis for Availability Bonus/Penalty 97% 97% 97%
----------------------------------------------------------------------------
Guaranteed Heat Rate, HHV Btu/kWh [4] 10,787 10,787 10,900
----------------------------------------------------------------------------
Operating Limit, hr/yr. 2,500 2,500 1,500
----------------------------------------------------------------------------
Variable O&M Payment, $/MWh [2] 1.00 1.00 1.50
----------------------------------------------------------------------------
Fuel Adder, $/mmBtu 0.10 0.10 0.32
----------------------------------------------------------------------------
1. It is assumed that the five year extension of the Aquila PSAs is
exercised.
2. Escalating at GDP/IPD
3. For the extension terms the capacity payment is $59.
4. Heat rate at full load
The revenues forecasted in the Projections are based on Pace's forecast of sales
under each PSA until they expire, followed by sales to the market. Due to the
economics in 2016 and 2017, Pace assumes that the Aquila PSAs will be extended
per the agreement terms. The PSA revenues include evaluation of PSA heat rate
guarantees and associated costs.
The PSA revenues for the first full calendar year (Year 2002) are $132.8 million
and are summarized below, in 2002 $000:
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-----------------------------------------------------------
Aquila Exelon (includes Engage)
-----------------------------------------------------------
Capacity $39,063 $42,319
-----------------------------------------------------------
Energy $43,837 $7,661
-----------------------------------------------------------
Startup $875 $380
-----------------------------------------------------------
Other $0 ($1,381)
-----------------------------------------------------------
Total $83,775 $48,979
-----------------------------------------------------------
Aquila Revenues
The Aquila units are forecast to be dispatched approximately 18 percent of the
time over the term of the PSAs, resulting in average revenues of $82 million per
year in nominal dollars.
During the startup performance tests, the average HHV heat rate for the Aquila
units was 10,571 Btu/kWh, which is two percent better than the PSA guaranteed
heat rate of 10,787 Btu/kWh. The PSA allows an adjustment to the heat rate to
account for degradation, based on GE's degradation curve. Therefore, we do not
expect there to be any heat rate costs to the Project under the Aquila PSA.
Startup revenues of $2,500 per start (escalating) are to be paid by Aquila and
are included in the Projections. Based on the Pace forecast of starts, the
Project will receive an average startup revenue from Aquila of approximately
$1.2 million per year in nominal dollars.
Pace has determined that based upon the payment structure of the Aquila PSA's,
the Project's forecast dispatch profile, forecast market-clearing prices, and
the market-based revenues that Aquila is forecast to earn by marketing the
output and capacity of Units 5 through 8, there is sufficient economic incentive
to cause Aquila to exercise its option to extend the term of the Aquila PSAs for
an additional five year period.
Exelon Revenues
The Exelon units are forecast to be dispatched five percent of the time over the
PSA term, resulting in average revenues of $44 million per year in nominal
dollars. The operating heat rate is forecast to be better than the PSA heat
rate, so there are no costs to the Project associated with heat rate in the
Projections.
Merchant Sales
After the termination of each PSA, the affected units are projected to sell into
the market through 2026. Pace has forecast the underlying dispatch levels and
merchant market prices for those
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sales, which are reflected in the Projections. The merchant revenues for the
units initially under the Aquila PSAs are projected to average $123 million per
year in nominal dollars after the PSA extension expires and $138 million per
year for the units initially under the Exelon PSA. Pace has projected the
additional merchant revenue based on the market price fluctuations around the
average market price called volatility revenue. This revenue is included in the
base case. The nominal volatility revenue ranges from $20.9 million for the
first merchant year (2013) to $63.4 million in 2025.
The forecast dispatch levels and starts are illustrated in Figures 8-1 and 8-2.
The dispatch level determines the revenues and the startups determine the major
maintenance schedule.
Figure 8-1
Pace Forecast of Unit Dispatch Levels
[GRAPH DISPLAYING FORECASTED DISPATCH
LEVELS THROUGH 2025 FOR UNITS 1-4 + 9
AND UNITS 5-8]
Figure 8-2
Pace Forecast of Unit Startups
[GRAPH DISPLAYING FORECASTED NUMBER OF
STARTUPS ANNUALLY FOR UNITS 1-4 + 9 AND UNITS 5-8
THROUGH 2025]
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8.5 OPERATING EXPENSES
The Projections include expenses for fuel, major maintenance, routine O&M, and
overhead. The O&M will be provided under the O&M Agreement with Dominion Elwood
Services Company, as described in Section 3 of this report. The fuel and major
maintenance costs are discussed later in this section, while the other expenses
are summarized in Table 8-3.
Maintenance schedule and Budget
The Projections include a major maintenance schedule that is consistent with
General Electric's recommendations for combustor inspections, hot gas path
inspections, and major overhauls. Stone & Webster believes that the Project's
planned maintenance schedule and budget are reasonable and adequate.
The recommended maintenance schedule for each unit is dictated by the number and
types of starts and trips that the unit experiences. Each maintenance cycle
includes combustor inspections every 400 starts, hot-gas-path inspections every
900 starts, and a major inspection every 2,400 starts.
The startup forecast shows that during the horizon of the Projections, there
will be 40 combustor inspections, 17 hot-gas-path inspections, and no major
overhauls. The Sponsors have determined the budget based on GE's estimated costs
for those inspections. The average cost for one maintenance cycle is expected to
be approximately $30 million. The budget includes a reasonable discount below
GE's parts price list in anticipation of Dominion negotiating a parts supply
agreement for its fleet of GE units.
The major maintenance reserve fund for Units 1 through 4 and 9 begins with an
initial funding of $2 million. The maintenance reserve fund is increased
according to the following schedule:
Table 8-1
Units 1 through 4 and 9 Maintenance Reserve Fund
---------------------------------------------------------------
Initial Reserve Fund $2 million
---------------------------------------------------------------
October 2001 to December 2012 $166,000 monthly
---------------------------------------------------------------
January 2013 to December 2016 $833,000 monthly
---------------------------------------------------------------
January 2017 to December 2020 $500,000 monthly
---------------------------------------------------------------
January 2021 to December 2025 $1,166,000 monthly
---------------------------------------------------------------
January 2026 to December 2026 $333,000 monthly
---------------------------------------------------------------
The major maintenance reserve fund for Units 5 through 8 does not begin with an
initial funding. The maintenance reserve fund will be funded according to the
following schedule:
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PROJECT FINANCIAL ASSESSMENT
================================================================================
Table 8-2
Units 5 through 8 Maintenance Reserve Fund
-----------------------------------------------------------------
October 2001 to December 2012 $433,000 monthly
-----------------------------------------------------------------
January 2013 to December 2023 $666,000 monthly
-----------------------------------------------------------------
January 2024 to December 2026 $166,000 monthly
-----------------------------------------------------------------
Operations and Maintenance Budget
The Projections include detailed expenses for the operation and maintenance of
the Project, which Stone & Webster has reviewed and found to be reasonable. For
2002 the fixed and variable non-fuel O&M expenses total $7.4 million and are
detailed in Table 8-3. The forecast O&M expenses are escalated at 3.0 percent
per year.
Table 8-3
Estimated Routine Maintenance & Overhead Expenses
($ in 000)
----------------------------------------------------
Labor $1,505
----------------------------------------------------
Fixed O&M 1,487
----------------------------------------------------
Standby & Startup 1,152
----------------------------------------------------
Property Taxes 540
----------------------------------------------------
Insurance 377
----------------------------------------------------
Fixed DELSCO Fee 706
----------------------------------------------------
Environmental 174
----------------------------------------------------
Management Salary & Exp. 360
----------------------------------------------------
General & Administrative 312
----------------------------------------------------
Elwood Holdings Sales Tax Payment 766
----------------------------------------------------
Total $7,379
----------------------------------------------------
Stone & Webster reviewed the O&M assumptions utilized in the Projections. The
information reviewed included assumptions and forecasts for unit performance,
staffing functions and levels, and annual O&M budget summary. Stone & Webster
considers these Project assumptions to be reasonable and comparable to other
large power facilities.
The Project's planned functional positions and staffing levels were reviewed and
are considered satisfactory to operate and maintain the Project safely in
accordance with the operational and regulatory requirements. The staffing levels
compare favorably with and are typical of those found in similarly configured
plants that Stone & Webster has reviewed.
Emission Compliance Costs
Beginning in 2004, facilities in Illinois will be subject to the states
implementation plan of the EPA's "NO(x) SIP Call" requirements, which requires
power plants to qualify for and/or purchase allowances to emit NO(x).
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PROJECT FINANCIAL ASSESSMENT
================================================================================
The state of Illinois has issued some of the regulations in this regard,
specifically those relating to the one-hour standard. Stone & Webster reviewed
information from the state and made reasonable assumptions to determine the
impact on the Project. This interpretation is summarized below:
Years Requirements
- ----- ------------
Prior to 2004 No requirements
2004 - 2006 Purchase allowances for the NO(x) emitted that exceeds
requested eligible allocations.
2007 - 2008 Purchase allowances for the NO(x) emitted above 80% of the
quantity that would be emitted at the permitted rate, subject
to a floor of 0.055 lb/mmBtu.
2009 - 2010 Purchase allowances for the NO(x) emitted above 50% of the
quantity that would be emitted at the permitted rate, subject
to a floor of 0.055 lb/mmBtu.
2011 on Assumed to be the same as the 2009 to 2010 period. Purchase
allowances for the NO(x) emitted above the maximum quantity
emitted in the prior four to six year period
The NO(x) permit limits for Units 1, 2, 3, and 4 are 15 ppm, while the other
units are permitted at 9 ppm. Stone & Webster has assumed that each will operate
at those levels. The units are monitored by continuous emission monitoring
systems (CEMS). This translates into emission rates of 0.040 and 0.025 lb/mmBtu
for the two groups of units. These values are very good compared to most MAIN
units and result in relatively low emissions costs. The plant is forecast to
sell allowances in two of the years.
The Projections assume that the Project will need approximately 796 tons of
NO(x) allowances over the term of the Projections at the assumed current market
value of $3,400 per ton, escalating at three percent per year. NO(x) allowance
costs are projected to cost the Project $4.9 million in nominal dollars over the
term of the Projections.
The units are expected to emit minimal amounts of SO(x), therefore SO(x)
emissions costs were not included in the Projections.
Fuel Expense
During the PSAs, the fuel is essentially a pass-through, aside from any heat
rate penalties, which are not expected. After each PSA terminates the Project
will be responsible for providing the fuel for those units to operate as
merchant units. The Projections assume that the fuel will be purchased at the
price stipulated in the Pace report.
Other fuel-related expenses are to be paid under the agreements with Cinergy and
NICOR, as described in Section 3 of this report. It was assumed in the
Projections that those agreements are
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[LOGO] Stone & Webster Consultants Page 65 Revised 01/23/02
PROJECT FINANCIAL ASSESSMENT
================================================================================
succeeded by similar agreements. Therefore the terms and pricing in those
agreements are assumed to be in effect through 2026.
8.6 FINANCING ASSUMPTIONS
CSFB provided the financing assumptions for the $402 million senior secured
notes. The notes have a final maturity of 25 years with an average life of 12
years. The interest rate is 8.159%. The combined annual debt service (principal
plus interest) ranges from a low of $1,797,000 in 2026 to a high of $46,509,000
in 2005. The debt service requirements for each year are the payments to be made
on July 5 of that year and January 5 the following year.
8.7 PROJECTIONS
The Projections are shown in Attachment 4 of this Report. On the basis of our
review of the Project, the Project Agreements and the assumptions set forth in
this Report, the projected revenues are more than adequate to pay the annual O&M
expenses (including provisions for major maintenance), other operating expenses,
and debt service. Contributions to major maintenance reserves and debt service
reserves are excluded from cash flow available for debt service. The Base Case
resulting minimum DSCR is 1.51x and occurs in 2001. The Base Case resulting
average DSCR is 3.60x.
8.8 SENSITIVITY ANALYSES
Due to uncertainties necessarily inherent in relying on assumptions and
forecasts, it should be anticipated that actual operating results may differ,
perhaps materially, from those assumed and described herein. In order to
demonstrate the impact of certain circumstances on the Projections, certain
sensitivity analyses have been developed by Stone & Webster. It should be noted
that other examples could have been considered, and those presented are not
intended to reflect the full extent of possible impacts on the Project.
Stone & Webster performed sensitivity analyses using the pro forma Projections
by varying Project specific key input parameters including lower inflation rates
and O&M costs.
Project Sensitivities
Operation and Maintenance Cost Sensitivity -- The O&M costs were increased by
ten percent relative to the Base Case. The resulting minimum and average DSCRs
for the period 2001 to 2026 is 1.49x and 3.56x, respectively.
Lower Inflation Rates - The inflation rates in the Base Case are decreased by
0.5% each year. The resulting minimum and average DSCRs for the period 2001 to
2026 is 1.51x and 3.36x, respectively.
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Pace Sensitivities
In addition, sensitivity of the Project results was assessed for the two
sensitivity cases, a High Gas Price Case and an Overbuild Case. The High Gas
Price and the Overbuild Case scenarios were taken from the Pace forecasts. Stone
& Webster applied the results from the two Pace sensitivities to the
Projections.
High Gas Price - Pace increased natural gas prices by 15% above the Base Case
levels in 2001 and increased up to 69% over the Base Case levels in 2026. The
resulting minimum and average DSCR for the period 2001 to 2026 is 1.50x and
3.58x, respectively.
Overbuild -- Pace's overbuild scenario assumes that an extra 2,739 MW (summer
capacity) of gas-fired combined cycle capacity is in operation in 2005. The
impact of this overbuild is concentrated during the period 2005-2012 and the
market gradually returns to an equilibrium point by 2013. The resulting minimum
and average DSCR for the period 2001 to 2026 is 1.51x and 3.55x, respectively.
No Aquila Extension -- Pace assumed that there is not sufficient economic
incentive to cause Aquila to exercise its option to extend the term of the
Aquila PSAs for an additional five-year period. Pace determined the Project's
forecast dispatch profile, forecast market-clearing prices, and the market-based
revenues that Aquila is forecast to earn by marketing the output and capacity of
Units 5 through 8. The resulting minimum and average DSCR for the period 2001 to
2026 is 1.51x and 3.83x, respectively
No Volatility Revenue -- This sensitivity does not include the volatility
revenue during the merchant period projected by Pace. The resulting minimum and
average DSCR for the period 2001 to 2026 is 1.51x and 2.97x, respectively
Summary
The following Table 8-4 summarizes the Base Case and Sensitivities:
Table 8-4
Base Case and Sensitivity Summary
- --------------------------------------------------------------------------------
Min DSCR Avg DSCR
- --------------------------------------------------------------------------------
Base Case 1.51x 3.60x
- --------------------------------------------------------------------------------
Increased O&M Cost 1.49x 3.56x
- --------------------------------------------------------------------------------
Decreased Inflation Rate 1.51x 3.36x
- --------------------------------------------------------------------------------
High Gas Price Case 1.50x 3.58x
- --------------------------------------------------------------------------------
Overbuild Case 1.51x 3.55x
- --------------------------------------------------------------------------------
No Aquila Contract Extension 1.51x 3.83x
- --------------------------------------------------------------------------------
No Volatility Revenue 1.51x 2.97x
- --------------------------------------------------------------------------------
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[LOGO] Stone & Webster Consultants Page 67
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ATTACHMENT 1
DOCUMENTS RECEIVED
J.O. 12784
DOCUMENTS RECEIVED
ELWOOD ENERGY
Most of the Documentation is from People's Energy, if not it is noted
- --------------------------------------------------------------------------------
DATE RECEIVED
RECEIVED FROM DOCUMENT
- --------------------------------------------------------------------------------
05/16/01 People's Information Memorandum May 2001
Energy
- --------------------------------------------------------------------------------
05/24/01 Power Sales Agreement (PSA) 3/24/99
- --------------------
05/24/01 Waiver to PSA 08/12/99
- --------------------
05/24/01 Amendment #1 to PSA 11/10/99
- --------------------
06/02/01 Second Amended and Restated Power Sales Agreement 3/1/01
- --------------------------------------------------------------------------------
05/24/01 Power Sales Agreement (PSA) (Elwood II) 6/30/00
- --------------------
05/24/01 Waiver to PSA 03/20/01
- --------------------------------------------------------------------------------
05/24/01 Power Sales Agreement to PSA (Elwood III) 06/30/00
- --------------------
05/24/01 Amendment to PSA Waiver 12/07/00
- --------------------
05/24/01 Waiver to PSA 03/20/01
- --------------------------------------------------------------------------------
05/24/01 Test Power purchase Agreement (Elwood II) 04/1/01
- --------------------------------------------------------------------------------
05/24/01 Test Power purchase Agreement (Elwood III) 04/1/01
- --------------------------------------------------------------------------------
05/24/01 Interconnection Agreement 600 MW 04/23/99
- --------------------------------------------------------------------------------
05/24/01 Interconnection Agreement -- 300MW 01/4/01
- --------------------------------------------------------------------------------
05/24/01 Interconnection Agreement -- 450 MW 01/4/01
- --------------------------------------------------------------------------------
05/24/01 Procedure Agreement -- Unit 5 Combustion Turbine & BOP
Equipment (Amended and Restated) 10/6/00
- --------------------------------------------------------------------------------
05/24/01 Procurement Agreement -- Unit 6 Combustion Turbine & BOP
Equipment (Amended and Restated) 10/6/00
- --------------------------------------------------------------------------------
05/24/01 Procurement Agreement -- Unit 7&8 Combustion Turbine & BOP
Equipment (Amended and Restated) 10/6/00
- --------------------------------------------------------------------------------
06/01/01 Procurement Agreement -- Unit 9 Combustion Turbine & BOP
Equipment (Amendment and Restated) 09/20/00
- --------------------------------------------------------------------------------
05/24/01 EPC Agreement -- Units 1 &2 07/23/98
- --------------------------------------------------------------------------------
05/24/01 EPC Agreement Units 3&4 09/25/98
- --------------------
05/24/01 Amendment to EPC Agreement 04/26/99
- --------------------------------------------------------------------------------
05/24/01 EPC Agreement Units 5&6 (Elwood II) 07/31/00
- --------------------------------------------------------------------------------
05/24/01 EPC Agreement Unit 7&8 (Elwood III) 07/31/01
- --------------------------------------------------------------------------------
06/06/01 EPC Agreement-- Unit 9 (Elwood III) 9/20/00
- --------------------------------------------------------------------------------
05/24/01 Gas Transportation and Balancing Agreement 05/1/99
- --------------------------------------------------------------------------------
05/24/01 Transportation & Balancing Service Agreement (T&BSA) 12/5/00
- --------------------
05/24/01 Amendment #1 to T&BSA 09/30/99
- --------------------------------------------------------------------------------
06/01/01 Transportation & Balancing Service Agreement (T&BSA) 5/1/01
- --------------------------------------------------------------------------------
05/24/01 Fuel Supply and Management Agreement 06/1/99
- --------------------------------------------------------------------------------
06/01/01 Fuel Supply & Management Agreement 5/1/01
- --------------------------------------------------------------------------------
05/24/01 Operation and Maintenance (O&M) Agreement 06/18/99
- --------------------------------------------------------------------------------
05/30/01 Operation & Maintenance (O&M) Agreement Units 5&6 05/23/01
- --------------------------------------------------------------------------------
05/30/01 Operation & Maintenance (O&M) Agreement Units 7-9 05/23/01
- --------------------------------------------------------------------------------
06/21/01 Common Faci1ities Agreement #1 06/10/2000
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
05/24/01 Clean Air Act Permit Program (CAAPP) Permit and Title I
Permit
- --------------------------------------------------------------------------------
1
- --------------------------------------------------------------------------------
DATE RECEIVED
RECEIVED FROM DOCUMENT
- --------------------------------------------------------------------------------
11/29/99
- --------------------------------------------------------------------------------
06/14/01 CAAPP Application Completeness Determination & Source Fee
Determination
- --------------------------------------------------------------------------------
06/22/01 CAAPP Application Completeness Determination & Source Fee
Determination-Revised
- --------------------------------------------------------------------------------
05/24/01 Environmental Investigation Report 08/03/98
- --------------------------------------------------------------------------------
05/24/01 Soil Boring Logs and Core Analysis 1998
- --------------------------------------------------------------------------------
06/12/01 Self-Certification Filing for Fuel Use Act. (1/25/99)
- --------------------------------------------------------------------------------
06/12/01 FERC Exempt Generator Filing Response (03/05/99)
- --------------------------------------------------------------------------------
06/12/01 FERC Rate schedule (03/31/99)
- --------------------------------------------------------------------------------
06/19/01 FERC Exempt Generator Determinations (Feb. 01) Units 5-9
- --------------------------------------------------------------------------------
07/25/01 McGuire IEPA acid Rain-Phase II Permit-Elwood Facility
Woods
- --------------------------------------------------------------------------------
07/25/01 McGuire IEPA acid Rain-Phase II Permit-Elwood II Facility
Woods
- --------------------------------------------------------------------------------
07/25/01 McGuire IEPA acid Rain-Phase II Permit-Elwood III Facility
Woods
- --------------------------------------------------------------------------------
06/14/01 NPDES Permit Modification Determination 1l/19/98
- --------------------------------------------------------------------------------
05/24/01 Construction Permit -- PSD-Revised 10/17/00
- --------------------------------------------------------------------------------
05/24/01 Construction Permit -- PSD Approval -- NSP Source
(Elwood II) 10/17/00
- --------------------------------------------------------------------------------
05/24/01 Construction Permit -- PSD Approval -- NSP Source
(Elwood III) 10/17/00
- --------------------------------------------------------------------------------
05/24/01 Administrative Services Agreement (Elwood II) 12/27/00
- --------------------------------------------------------------------------------
05/24/01 Administrative Services Agreement (Elwood III) 12/27/00
- --------------------------------------------------------------------------------
05/25/01 Pro Forma
- --------------------------------------------------------------------------------
05/25/01 Noise Assessment -- Unit 1-4 11/29/99
- --------------------------------------------------------------------------------
05/29/01 Performance Test Data -- Units 1-4
- --------------------------------------------------------------------------------
06/21/01 Performance Test Report -- Units 1-4 11/07/99
- --------------------------------------------------------------------------------
05/29/01 Performance Test Data -- Units 5, 6, & 9
- --------------------------------------------------------------------------------
06/02/0l Thermal Performance Test Report -- Unit 5 5/11/01
- --------------------------------------------------------------------------------
06/12/01 Unit #9 Performance Test Report (04/28/0l)
- --------------------------------------------------------------------------------
06/12/01 Units 5, 6, & 9 Performance Test Summary
- --------------------------------------------------------------------------------
06/14/01 Thermal Performance Test Report Unit 6 6/12/01
- --------------------------------------------------------------------------------
06/20/01 Preliminary Performance Test Results -- Units 7 & 8
- --------------------------------------------------------------------------------
06/29/01 Thermal performance Test Report-Unit 7 06/25/01
- --------------------------------------------------------------------------------
06/29/01 Thermal performance Test Report-Unit 8 06/25/01
- --------------------------------------------------------------------------------
06/04/01 Operating Reports 1999-2000 (Units 1-4)
- --------------------------------------------------------------------------------
05/30/01 Electrical One Line Diagram Units 1&2
- --------------------------------------------------------------------------------
05/30/01 Electrical One Line Diagram Units 3&4
- --------------------------------------------------------------------------------
05/30/01 Electrical One Line Diagram Units 5&6
- --------------------------------------------------------------------------------
05/30/01 Electrical One Line Diagram Units 7&8
- --------------------------------------------------------------------------------
05/30/01 Electrical One Line Diagram Unit 9
- --------------------------------------------------------------------------------
06/06/01 Certificate of Commercial Operation -- Unit 1 (7/19/99)
- --------------------------------------------------------------------------------
06/06/01 Certificate of Commercial Operation -- Unit 2 (7/18/99)
- --------------------------------------------------------------------------------
06/06/01 Certificate of Commercial Operation -- Unit 4 (7/19/99)
- --------------------------------------------------------------------------------
06/12/01 Elwood Fuel Supply Diagram
- --------------------------------------------------------------------------------
2
- --------------------------------------------------------------------------------
DATE RECEIVED
RECEIVED FROM DOCUMENT
- --------------------------------------------------------------------------------
06/12/01 Elwood Gas Line Location Dwg SG-D-826
- --------------------------------------------------------------------------------
06/12/01 Bank Due Diligence Meetings Agenda & Exhibits 06/12/01
- --------------------------------------------------------------------------------
06/12/01 McGuire Woods Memo Dated 06/8/01 Regarding
Combining Elwood Entities
- --------------------------------------------------------------------------------
06/12/01 GE Electrical/Controls Description (Units 7&8)
- --------------------------------------------------------------------------------
06/12/01 GE Compressed Gas Systems Description & P&IDS
- --------------------------------------------------------------------------------
06/12/01 Electrical One-Line Diagrams
- --------------------------------------------------------------------------------
06/12/01 Facility Water System Description and P&ID
- --------------------------------------------------------------------------------
06/12/01 Units 5-9 Milestone Payment schedule
- --------------------------------------------------------------------------------
06/14/01 Site Drawing Units 1-4
- --------------------------------------------------------------------------------
06/14/01 Site Drawing Units 5-9
- --------------------------------------------------------------------------------
06/12/01 Spare Parts Inventory
- --------------------------------------------------------------------------------
06/22/01 Emissions Test Report -- Units 1-4
- --------------------------------------------------------------------------------
07/11/01 Alternative Fuel Use Self-Certification-Elwood II
- --------------------------------------------------------------------------------
07/11/01 Alternative Fuel Use Self-Certification-Elwood III
- --------------------------------------------------------------------------------
07/03/01 Acoustic Assocs-Noise Assessment Report
(Preliminary 07/02/01)
- --------------------------------------------------------------------------------
06/27/01 Emissions Test Report-Units 5 & 9 (Preliminary June 2001)
- --------------------------------------------------------------------------------
07/05/01 Request for Approval of Alternate Emissions Testing
Procedures-Elwood II 06/27/01
- --------------------------------------------------------------------------------
07/06/01 People's Acoustic Associates-Determination of Property Line Sound
Energy Levels-Units 5, 6, 7, 8,& 9 Running
- --------------------------------------------------------------------------------
07/23/01 Pace Pace-Power Market Assessment 07/20/01
- --------------------------------------------------------------------------------
3
ATTACHMENT 2
VICINITY MAP
- --------------------------------------------------------------------------------
[LOGO] Stone & Webster Consultants 12784/COO315
ROUTE MAP
to ELWOOD, IL
[MAP OF ROUTES TO THE ELWOOD FACILITY]
ATTACHMENT 3
SITE PLANS
- --------------------------------------------------------------------------------
[LOGO] Stone & Webster Consultants 12784/COO315
UNITS 1
[SITE PLAN DRAWING (FOUR UNITS)]
UNITS 5 - 9
[SITE PLAN DRAWING (OTHER FIVE UNITS)]
ATTACHMENT 4
Elwood
Annual Cash Flow Statement
Base Case
Project Year 1 2 3 4 5 6
Year 2001 2002 2003 2004 2005 2006
Percent of Year 33% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- --
Contract Revenues 32,635 132,754 121,836 116,730 129,175 131,295
Volatility Revenues -- -- -- -- -- --
Total Operating Revenues 32,635 132,754 121,836 116,730 129,175 131,295
Operating Expenses ($,000)
Fuel Costs 11,788 55,573 46,285 41,246 52,369 55,039
Fixed O&M Expenses
Units 1-4 & 9 771 3,368 3,465 3,557 3,651 3,997
Units 5-8 875 4,010 4,133 4,231 4,332 5,207
Variable O&M 3 17 15 15 22 22
Emission Costs -- -- -- 373 344 359
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 20 260 548 836 1,108 1,212
Interest Income on Cash Balances 440 804 780 803 818 846
Cash Flow Available
For Debt Service ($,000) 19,659 70,850 69,266 68,947 70,385 68,728
Debt Service ($,000)(1)
Debt 5,600 14,210 14,180 15,530 17,910 18,330
Interest 6,742 32,239 31,096 29,916 28,599 27,117
Total Debt Service 12,342 46,449 45,276 45,446 46,509 45,447
Debt Service Coverage Ratio 1.59x 1.53x 1.53x 1.52x 1.51x 1.51x
-----------------------------------------------------------
Average Debt Service Coverage Ratio 3.60x
Minimun Debt Service Coverage Ratio 1.51x
-----------------------------------------------------------
Cash F1ow After Debt Service ($,000) 7,317 24,401 23,990 23,500 23,876 23,281
Major Maintenance ($,000)
Units 1-4 & 9 500 2,000 2,000 2,000 2,000 2,000
Units 5-8 1,300 5,200 5,200 5,200 5,200 5,200
Cash Flow After Debt Service and Major Maintenance ($,000) 5,517 17,201 16,790 16,300 16,676 16,081
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
1
Elwood
Annual Cash Flow Statement
Base Case
Project Year 7 8 9 10 11 12 13
Year 2007 2008 2009 2010 2011 2012 2013
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- -- 108,582
Contract Revenues 128,030 132,586 136,205 131,894 119,840 130,562 83,238
Volatility Revenues -- -- -- -- -- -- 20,990
Total Operating Revenues 128,030 132,586 136,205 131,894 119,840 130,562 212,810
Operating Expenses ($,000)
Fuel Costs 52,139 56,779 59,741 55,839 45,179 53,549 83,180
Fixed O&M Expenses
Units 1-4 & 9 3,890 4,324 4,430 4,538 4,323 4,204 4,326
Units 5-8 5,699 5,809 5,922 6,039 5,146 4,547 4,674
Variable O&M 23 26 26 24 20 24 36
Emission Costs (48) (50) 155 170 157 149 153
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,319 1,595 1,785 1,214 1,045 1,102 990
Interest Income on Cash Balances 826 874 896 834 787 846 412
Cash Flow Available
For Debt Service ($,000) 68,471 68,168 68,612 67,332 66,847 70,036 121,843
Debt Service ($,000)(1)
Debt 19,390 20,750 22,310 23,230 25,230 29,644 8,211
Interest 25,609 23,997 22,274 20,438 18,511 16,373 14,319
Total Debt Service 44,999 44,747 44,584 43,668 43,741 46,017 22,530
Debt Service Coverage Ratio 1.52x 1.52x 1.54x 1.54x 1.53x 1.52x 5.41x
Cash Flow After Debt Service ($,000) 23,473 23,421 24,028 23,664 23,106 24,019 99,313
Major Maintenance ($,000)
Units 1-4 & 9 2,000 2,000 2,000 2,000 2,000 2,000 10,000
Units 5-8 5,200 5,200 5,200 5,200 5,200 5,200 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 16,273 16,221 16,828 16,464 15,906 16,819 81,313
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
2
Elwood
Annual Cash Flow Statement
Base Case
Project Year 14 15 16 17 18 19 20
Year 2014 2015 2016 2017 2018 2019 2020
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 113,358 122,341 116,920 130,178 132,960 138,696 139,409
Contract Revenues 82,541 83,790 78,607 87,522 86,869 97,233 84,806
Volatility Revenues 22,294 26,003 23,914 27,015 29,478 28,975 29,036
Total Operating Revenues 218,192 232,133 219,442 244,714 249,307 264,904 253,251
Operating Expenses ($,000)
Fuel Costs 88,036 96,637 85,712 103,201 107,631 120,980 105,785
Fixed O&M Expenses
Units 1-4 & 9 4,455 4,581 4,711 4,817 4,984 5,126 5,272
Units 5-8 4,806 4,941 5,080 5,223 5,382 5,535 5,692
Variable O&M 37 42 36 44 44 50 43
Emission Costs 214 217 215 243 230 247 252
Capita1 Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,267 1,479 1,575 1,762 2,142 1,261 301
Interest Income on Cash Balances 423 412 399 389 399 399 399
Cash Flow Available
For Debt Service ($,000) 122,336 127,606 125,662 133,337 133,578 134,625 136,907
Debt Service ($,000)(1)
Debt 7,500 8,341 5,765 13,170 14,765 15,628 20,677
Interest 13,662 13,049 12,370 11,891 10,814 9,615 8,304
Total Debt Service 21,162 21,390 18,135 25,061 25,579 25,243 28,981
Debt Service Coverage Ratio 5.78x 5.97x 6.93x 5.32x 5.22x 5.33x 4.72x
Cash Flow After Debt Service ($,000) 101,174 106,216 107,527 108,276 107,999 109,382 107,926
Major Maintenance ($,000)
Units 1-4 & 9 10,000 10,000 10,000 6,000 6,000 6,000 6,000
Units 5-8 8,000 8,000 8,000 8,000 8,000 8,000 8,000
Cash F1ow After Debt Service and Major Maintenance ($,000) 83,174 88,216 89,527 94,276 93,999 95,382 93,926
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
3
Elwood
Annual Cash Flow Statement
Base Case
Project Year 21 22 23 24 25 26
Year 2021 2022 2023 2024 2025 2026
Percent of Year 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 150,402 219,489 272,674 292,626 296,962 91,698
Contract Revenues 76,695 29,522 -- -- -- --
Vo1atility Revenues 33,225 46,371 58,312 63,179 63,396 28,038
Total Operating Revenues 260,322 295,382 330,986 355,806 360,357 119,736
Operating Expenses ($,000)
Fuel Costs 111,120 110,884 109,719 111,566 118,504 59,955
Fixed O&M Expenses
Units 1-4 & 9 5,431 5,593 5,761 5,934 6,112 3,054
Units 5-8 5,862 6,038 6,219 6,406 6,598 3,352
Variable O&M 45 44 43 44 46 23
Emission Costs 304 276 270 249 230 62
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 1,744 1,935 2,748 2,874 2,161 605
Interest Income on Cash Balances 399 399 399 399 399 233
Cash Flow Available
For Debt Service ($,000) 139,703 174,879 212,120 234,879 231,426 54,128
Debt Service ($,000)(1)
Debt 26,290 21,673 10,158 12,797 8,985 1,726
Interest 6,639 4,449 2,720 1,887 826 70
Total Debt Service 32,929 26,122 12,878 14,684 9,811 1,797
Debt Service Coverage Ratio 4.24x 6.69x 16.47x 16.00x 23.59x 30.12x
Cash Flow After Debt Service ($,000) 106,774 148,757 199,242 220,195 221,616 52,331
Major Maintenance ($,000)
Units 1-4 & 9 14,000 14,000 14,000 14,000 14,000 2,000
Units 5-8 8,000 8,000 8,000 2,000 2,000 1,000
Cash Flow After Debt Service and Major Maintenance ($,000) 84,774 126,757 177,242 204,195 205,616 49,331
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
4
Elwood
Annual Cash Flow Statement
Increased O&M Sensitivity
Project Year 1 2 3 4 5 6
Year 2001 2002 2003 2004 2005 2006
Percent of Year 33% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- --
Contract Revenues 32,635 132,754 121,836 116,730 129,175 131,295
Vo1ati1ity Revenues -- -- -- -- -- --
Tota1 Operating Revenues 32,635 132,754 121,836 116,730 129,175 131,295
Operating Expenses ($,000)
Fuel Costs 11,788 55,573 46,285 41,246 52,369 55,039
Fixed O&M Expenses
Units 1-4 & 9 848 3,705 3,812 3,912 4,016 4,397
Units 5-8 962 4,412 4,547 4,654 4,765 5,727
Variab1e O&M 3 19 17 17 24 25
Emission Costs -- -- -- 373 344 359
Capita1 Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 20 260 548 836 1,108 1,212
Interest Income on Cash Balances 440 804 780 803 818 846
Cash F1ow Available
For Debt Service ($,000) 19,494 70,110 68,504 68,166 69,584 67,805
Debt Service ($,000)(1)
Debt 5,600 14,210 14,180 15,530 17,910 18,330
Interest 6,742 32,239 31,096 29,916 28,599 27,117
Total Debt Service 12,342 46,449 45,276 45,446 46,509 45,447
Debt Service Coverage Ratio 1.58x 1.51x 1.51x 1.50x 1.50x 1.49x
----------------------------------------------
Average Debt Service Coverage Ratio 3.56x
Minimun Debt Service Coverage Ratio 1.49x
----------------------------------------------
Cash Flow After Debt Service ($,000) 7,152 23,662 23,228 22,720 23,076 22,358
Major Maintenance ($,000)
Units 1-4 & 9 550 2,200 2,200 2,200 2,200 2,200
Units 5-8 1,430 5,720 5,720 5,720 5,720 5,720
Cash Flow After Debt Service and Major Maintenance ($,000) 5,172 15,742 15,308 14,800 15,156 14,438
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
5
Elwood
Annual Cash Flow Statement
Increased O&M Sensitivity
Project Year 7 8 9 10 11 12 13
Year 2007 2008 2009 2010 2011 2012 2013
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- -- 108,582
Contract Revenues 128,030 132,586 136,205 131,894 119,840 130,562 83,238
Vo1atility Revenues -- -- -- -- -- -- 20,990
Total Operating Revenues 128,030 132,586 136,205 131,894 119,840 130,562 212,810
Operating Expenses ($,000)
Fuel Costs 52,139 56,779 59,741 55,839 45,179 53,549 83,180
Fixed O&M Expenses
Units 1-4 & 9 4,279 4,756 4,873 4,992 4,755 4,625 4,758
Units 5-8 6,269 6,390 6,514 6,642 5,661 5,002 5,142
Variable O&M 26 28 28 26 22 27 39
Emission Costs (48) (50) 155 170 157 149 153
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,319 1,595 1,785 1,214 1,045 1,102 990
Interest Income on Cash Balances 826 874 896 834 787 846 412
Cash Flow Available
For Debt Service ($,000) 67,510 67,152 67,574 66,272 65,898 69,159 120,939
Debt Service ($,000)(1)
Debt 19,390 20,750 22,310 23,230 25,230 29,644 8,211
Interest 25,609 23,997 22,274 20,438 18,511 16,373 14,319
Tota1 Debt Service 44,999 44,747 44,584 43,668 43,741 46,017 22,530
Debt Service Coverage Ratio 1.50x 1.50x 1.52x 1.52x 1.51x 1.50x 5.37x
Cash Flow After Debt Service ($,000) 22,511 22,406 22,990 22,604 22,157 23,141 98,409
Major Maintenance ($,000)
Units 1-4 & 9 2,200 2,200 2,200 2,200 2,200 2,200 11,000
Units 5-8 5,720 5,720 5,720 5,720 5,720 5,720 8,800
Cash Flow After Debt Service and Major Maintenance ($,000) 14,591 14,486 15,070 14,684 14,237 15,221 78,609
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
6
Elwood
Annual Cash Flow Statement
Increased O&M Sensitivity
Project Year 14 15 16 17 18 19 20
Year 2014 2015 2016 2017 2018 2019 2020
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 113,358 122,341 116,920 130,178 132,960 138,696 139,409
Contract Revenues 82,541 83,790 78,607 87,522 86,869 97,233 84,806
Volatility Revenues 22,294 26,003 23,914 27,015 29,478 28,975 29,036
Total Operating Revenues 218,192 232,133 219,442 244,714 249,307 264,904 253,251
Operating Expenses ($,000)
Fuel Costs 88,036 96,637 85,712 103,201 107,631 120,980 105,785
Fixed O&M Expenses
Units 1-4 & 9 4,900 5,039 5,182 5,299 5,482 5,638 5,800
Units 5-8 5,286 5,435 5,588 5,746 5,920 6,088 6,261
Variable O&M 41 46 40 48 48 55 47
Emission Costs 214 217 215 243 230 247 252
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,267 1,479 1,575 1,762 2,142 1,261 301
Interest Income on Cash Balances 423 412 399 389 399 399 399
Cash Flow Available
For Debt Service ($,000) 121,406 126,650 124,679 132,328 132,537 133,554 135,806
Debt Service ($,000)(1)
Debt 7,500 8,341 5,765 13,170 14,765 15,628 20,677
Interest 13,662 13,049 12,370 11,891 10,814 9,615 8,304
Total Debt Service 21,162 21,390 18,135 25,061 25,579 25,243 28,981
Debt Service Coverage Ratio 5.74x 5.92x 6.88x 5.28x 5.18x 5.29x 4.69x
Cash Flow After Debt Service ($,000) 100,244 105,259 106,544 107,267 106,958 108,311 106,825
Major Maintenance ($,000)
Units 1-4 & 9 11,000 11,000 11,000 6,600 6,600 6,600 6,600
Units 5-8 8,800 8,800 8,800 8,800 8,800 8,800 8,800
Cash Flow After Debt Service and Major Maintenance ($,000) 80,444 85,459 86,744 91,867 91,558 92,911 91,425
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
7
Elwood
Annual Cash Flow Statement
Increased O&M Sensitivity
Project Year 21 22 23 24 25 26
Year 2021 2022 2023 2024 2025 2026
Percent of Year 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 150,402 219,489 272,674 292,626 296,962 91,698
Contract Revenues 76,695 29,522 -- -- -- --
Volatility Revenues 33,225 46,371 58,312 63,179 63,396 28,038
Total Operating Revenues 260,322 295,382 330,986 355,806 360,357 119,736
Operating Expenses ($,000)
Fuel Costs 111,120 110,884 109,719 111,566 118,504 59,955
Fixed O&M Expenses
Units 1-4 & 9 5,974 6,153 6,337 6,528 6,723 3,360
Units 5-8 6,449 6,642 6,841 7,047 7,258 3,688
Variable O&M 49 48 47 48 51 26
Emission Costs 304 276 270 249 230 62
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 1,744 1,935 2,748 2,874 2,161 605
Interest Income on Cash Balances 399 399 399 399 399 233
Cash Flow Available
For Debt Service ($,000) 138,570 173,711 210,918 233,640 230,151 53,485
Debt Service ($,000)(1)
Debt 26,290 21,673 10,158 12,797 8,985 1,726
Interest 6,639 4,449 2,720 1,887 826 70
Total Debt Service 32,929 26,122 12,878 14,684 9,811 1,797
Debt Service Coverage Ratio 4.21x 6.65x 16.38x 15.91x 23.46x 29.77x
Cash Flow After Debt Service ($,000) 105,641 147,589 198,040 218,957 220,340 51,688
Major Maintenance ($,000)
Units 1-4 & 9 15,400 15,400 15,400 15,400 15,400 2,200
Units 5-8 8,800 8,800 8,800 2,200 2,200 1,100
Cash Flow After Debt Service and Major Maintenance ($,000) 81,441 123,389 173,840 201,357 202,740 48,388
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
8
Elwood
Annual Cash Flow Statement
Lower Inflation Sensitivity
Project Year 1 2 3 4 5 6
Year 2001 2002 2003 2004 2005 2006
Percent of Year 33% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- --
Contract Revenues 32,480 131,782 120,850 115,673 127,577 129,391
Volatility Revenues -- -- -- -- -- --
Total Operating Revenues 32,480 131,782 120,850 115,673 127,577 129,391
Operating Expenses ($,000)
Fuel Costs 11,634 54,615 45,322 40,223 50,831 53,215
Fixed O&M Expenses
Units 1-4 & 9 771 3,368 3,452 3,527 3,605 3,934
Units 5-8 875 4,010 4,119 4,200 4,283 5,139
Variable O&M 3 17 15 15 21 22
Emission Costs -- -- -- 373 344 359
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 20 260 548 836 1,108 1,216
Interest Income on Cash Balances 438 802 777 799 814 840
Cash Flow Available
For Debt Service ($,000) 19,656 70,834 69,268 68,970 70,415 68,777
Debt Service ($,000)(1)
Debt 5,600 14,210 14,180 15,530 17,910 18,330
Interest 6,742 32,239 31,096 29,916 28,599 27,117
Total Debt Service 12,342 46,449 45,276 45,446 46,509 45,447
Debt Service Coverage Ratio 1.59x 1.52x 1.53x 1.52x 1.51x 1.51x
-----------------------------------------------
Average Debt Service Coverage Ratio 3.36x
Minimun Debt Service Coverage Ratio 1.51x
-----------------------------------------------
Cash Flow After Debt Service ($,000) 7,314 24,385 23,992 23,524 23,906 23,330
Major Maintenance ($,000)
Units 1-4 & 9 500 2,000 2,000 2,000 2,000 2,000
Units 5-8 1,300 5,200 5,200 5,200 5,200 5,200
Cash Flow After Debt Service and Major Maintenance ($,000) 5,514 17,185 16,792 16,324 16,706 16,130
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
9
Elwood
Annual Cash Flow Statement
Lower Inflation Sensitivity
Project Year 7 8 9 10 11 12 13
Year 2007 2008 2009 2010 2011 2012 2013
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- -- 100,939
Contract Revenues 126,008 130,137 133,339 128,985 117,370 127,239 80,305
Volatility Revenues -- -- -- -- -- -- 19,513
Total Operating Revenues 126,008 130,137 133,339 128,985 117,370 127,239 200,756
Operating Expenses ($,000)
Fuel Costs 50,209 54,436 57,020 53,077 42,800 50,342 77,850
Fixed O&M Expenses
Units 1-4 & 9 3,816 4,224 4,309 4,397 4,159 4,017 4,114
Units 5-8 5,612 5,702 5,793 5,887 4,971 4,347 4,448
Variable O&M 23 25 25 23 19 23 34
Emission Costs (48) (50) 155 170 157 149 153
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,330 1,608 1,804 1,269 1,119 1,177 1,060
Interest Income on Cash Balances 820 865 886 826 781 837 405
Cash Flow Available
For Debt Service ($,000) 68,547 68,275 68,726 67,526 67,164 70,375 115,622
Debt Service ($,000)(1)
Debt 19,390 20,750 22,310 23,230 25,230 29,644 8,211
Interest 25,609 23,997 22,274 20,438 18,511 16,373 14,319
Total Debt Service 44,999 44,747 44,584 43,668 43,741 46,017 22,530
Debt Service Coverage Ratio 1.52x 1.53x 1.54x 1.55x 1.54x 1.53x 5.13x
Cash Flow After Debt Service ($,000) 23,548 23,528 24,142 23,858 23,423 24,358 93,092
Major Maintenance ($,000)
Units 1-4 & 9 2,000 2,000 2,000 2,000 2,000 2,000 10,000
Units 5-8 5,200 5,200 5,200 5,200 5,200 5,200 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 16,348 16,328 16,942 16,658 16,223 17,158 75,092
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
10
Elwood
Annual Cash Flow Statement
Lower Inflation Sensitivity
Project Year 14 15 16 17 18 19 20
Year 2014 2015 2016 2017 2018 2019 2020
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 104,867 112,627 107,115 118,682 120,629 125,223 125,256
Contract Revenues 79,304 80,254 75,276 83,190 82,389 91,553 80,085
Volatility Revenues 20,624 23,938 21,909 24,629 26,745 26,160 26,088
Total Operating Revenues 204,795 216,820 204,299 226,500 229,763 242,936 231,429
Operating Expenses ($,000)
Fuel Costs 82,007 89,568 79,114 94,693 98,540 110,166 95,934
Fixed O&M Expenses
Units 1-4 & 9 4,215 4,315 4,417 4,495 4,628 4,738 4,850
Units 5-8 4,551 4,658 4,767 4,878 5,001 5,119 5,239
Variable O&M 35 39 33 40 41 46 39
Emission Costs 214 217 215 243 230 247 252
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,347 1,575 1,695 1,886 2,282 1,365 396
Interest Income on Cash Balances 415 404 392 382 392 392 392
Cash Flow Available
For Debt Service ($,000) 115,533 120,002 117,840 124,418 123,997 124,376 125,901
Debt Service ($,000)(1)
Debt 7,500 8,341 5,765 13,170 14,765 15,628 20,677
Interest 13,662 13,049 12,370 11,891 10,814 9,615 8,304
Total Debt Service 21,162 21,390 18,135 25,061 25,579 25,243 28,981
Debt Service Coverage Ratio 5.46x 5.61x 6.50x 4.96x 4.85x 4.93x 4.34x
Cash Flow After Debt Service ($,000) 94,371 98,612 99,706 99,357 98,418 99,132 96,921
Major Maintenance ($,000)
Units 1-4 & 9 10,000 10,000 10,000 6,000 6,000 6,000 6,000
Units 5-8 8,000 8,000 8,000 8,000 8,000 8,000 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 76,371 80,612 81,706 85,357 84,418 85,132 82,921
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
11
Elwood
Annual Cash Flow Statement
Lower Inflation Sensitivity
Project Year 21 22 23 24 25 26
Year 2021 2022 2023 2024 2025 2026
Percent of Year 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 134,477 195,295 241,440 257,850 260,399 80,018
Contract Revenues 71,972 27,663 -- -- -- --
Volatility Revenues 29,707 41,260 51,633 55,671 55,590 24,466
Total Operating Revenues 236,156 264,218 293,073 313,520 315,990 104,484
Operating Expenses ($,000)
Fuel Costs 100,289 99,649 98,175 99,353 105,032 52,791
Fixed O&M Expenses
Units 1-4 & 9 4,972 5,096 5,223 5,354 5,488 2,729
Units 5-8 5,370 5,505 5,642 5,783 5,928 2,997
Variable O&M 40 40 39 39 41 21
Emission Costs 304 276 270 249 230 62
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 2,205 2,463 3,283 3,477 2,909 1,057
Interest Income on Cash Balances 392 392 392 392 392 228
Cash Flow Available
For Debt Service ($,000) 127,777 156,507 187,398 206,610 202,572 47,168
Debt Service ($,000)(1)
Debt 26,290 21,673 10,158 12,797 8,985 1,726
Interest 6,639 4,449 2,720 1,887 826 70
Total Debt Service 32,929 26,122 12,878 14,684 9,811 1,797
Debt Service Coverage Ratio 3.88x 5.99x 14.55x 14.07x 20.65x 26.25x
Cash Flow After Debt Service ($,000) 94,848 130,385 174,519 191,927 192,761 45,372
Major Maintenance ($,000)
Units 1-4 & 9 14,000 14,000 14,000 14,000 14,000 2,000
Units 5-8 8,000 8,000 8,000 2,000 2,000 1,000
Cash Flow After Debt Service and Major Maintenance ($,000) 72,848 108,385 152,519 175,927 176,761 42,372
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
12
Elwood
Annual Cash Flow Statement
High Gas Sensitivity
Project Year 1 2 3 4 5 6
Year 2001 2002 2003 2004 2005 2006
Percent of Year 33% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- --
Contract Revenues 33,578 147,433 136,068 127,538 140,279 144,114
Volatility Revenues -- -- -- -- -- --
Total Operating Revenues 33,578 147,433 136,068 127,538 140,279 144,114
Operating Expenses ($,000)
Fuel Costs 12,770 70,221 60,413 52,169 63,895 68,346
Fixed O&M Expenses
Units 1-4 & 9 771 3,368 3,465 3,557 3,651 3,997
Units 5-8 875 4,010 4,133 4,231 4,332 5,207
Variable O&M 3 17 14 14 18 19
Emission Costs -- -- -- 356 307 317
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 20 260 548 836 1,108 1,223
Interest Income on Cash Balances 456 838 823 839 837 868
Cash Flow Available
For Debt Service ($,000) 19,635 70,916 69,412 68,887 70,022 68,319
Debt Service ($,000)(1)
Debt 5,600 14,210 14,180 15,530 17,910 18,330
Interest 6,742 32,239 31,096 29,916 28,599 27,117
Total Debt Service 12,342 46,449 45,276 45,446 46,509 45,447
Debt Service Coverage Ratio 1.59x 1.53x 1.53x 1.52x 1.51x 1.50x
-----------------------------------------------
Average Debt Service Coverage Ratio 3.58x
Minimun Debt Service Coverage Ratio 1.50x
-----------------------------------------------
Cash Flow After Debt Service ($,000) 7,293 24,467 24,136 23,440 23,513 22,872
Major Maintenance ($,000)
Units 1-4 & 9 500 2,000 2,000 2,000 2,000 2,000
Units 5-8 1,300 5,200 5,200 5,200 5,200 5,200
Cash Flow After Debt Service and Major Maintenance ($,000) 5,493 17,267 16,936 16,240 16,313 15,672
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
13
Elwood
Annual Cash Flow Statement
High Gas Sensitivity
Project Year 7 8 9 10 11 12 13
Year 2007 2008 2009 2010 2011 2012 2013
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- -- 120,848
Contract Revenues 139,881 145,730 155,151 148,876 135,093 149,109 97,300
Volatility Revenues -- -- -- -- -- -- 20,990
Total Operating Revenues 139,881 145,730 155,151 148,876 135,093 149,109 239,138
Operating Expenses ($,000)
Fuel Costs 64,371 70,341 78,908 73,061 60,489 72,204 110,753
Fixed O&M Expenses
Units 1-4 & 9 3,890 4,324 4,430 4,538 4,323 4,204 4,326
Units 5-8 5,699 5,809 5,922 6,039 5,146 4,547 4,674
Variable O&M 20 21 22 21 18 22 31
Emission Costs (42) (43) 117 133 138 125 136
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,447 1,664 1,938 2,194 2,233 1,471 929
Interest Income on Cash Balances 848 934 978 860 844 906 434
Cash Flow Available
For Debt Service ($,000) 68,239 67,876 68,668 68,139 68,056 70,385 120,580
Debt Service ($,000)(1)
Debt 19,390 20,750 22,310 23,230 25,230 29,644 8,211
Interest 25,609 23,997 22,274 20,438 18,511 16,373 14,319
Total Debt Service 44,999 44,747 44,584 43,668 43,741 46,017 22,530
Debt Service Coverage Ratio 1.52x 1.52x 1.54x 1.56x 1.56x 1.53x 5.35x
Cash Flow After Debt Service ($,000) 23,241 23,129 24,084 24,471 24,316 24,368 98,050
Major Maintenance ($,000)
Units 1-4 & 9 2,000 2,000 2,000 2,000 2,000 2,000 10,000
Units 5-8 5,200 5,200 5,200 5,200 5,200 5,200 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 16,041 15,929 16,884 17,271 17,116 17,168 80,050
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
14
Elwood
Annual Cash Flow Statement
High Gas Sensitivity
Project Year 14 15 16 17 18 19 20
Year 2014 2015 2016 2017 2018 2019 2020
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 129,770 141,112 134,302 152,240 154,624 166,715 165,930
Contract Revenues 102,943 102,753 96,354 113,374 111,714 127,822 112,874
Volatility Revenues 22,294 26,003 23,914 27,015 29,478 28,975 29,036
Total Operating Revenues 255,007 269,867 254,570 292,628 295,817 323,512 307,839
Operating Expenses ($,000)
Fuel Costs 125,144 135,161 121,123 151,994 155,070 181,230 161,110
Fixed O&M Expenses
Units 1-4 & 9 4,455 4,581 4,711 4,817 4,984 5,126 5,272
Units 5-8 4,806 4,941 5,080 5,223 5,382 5,535 5,692
Variable O&M 35 38 33 41 41 48 42
Emission Costs 192 176 197 219 198 222 228
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,372 1,757 1,807 1,755 2,078 1,274 360
Interest Income on Cash Balances 477 470 465 425 465 465 465
Cash Flow Available
For Debt Service ($,000) 122,224 127,198 125,698 132,513 132,684 133,090 136,320
Debt Service ($,000)(1)
Debt 7,500 8,341 5,765 13,170 14,765 15,628 20,677
Interest 13,662 13,049 12,370 11,891 10,814 9,615 8,304
Total Debt Service 21,162 21,390 18,135 25,061 25,579 25,243 28,981
Debt Service Coverage Ratio 5.78x 5.95x 6.93x 5.29x 5.19x 5.27x 4.70x
Cash Flow After Debt Service ($,000) 101,062 105,807 107,563 107,452 107,105 107,847 107,340
Major Maintenance ($,000)
Units 1-4 & 9 10,000 10,000 10,000 6,000 6,000 6,000 6,000
Units 5-8 8,000 8,000 8,000 8,000 8,000 8,000 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 83,062 87,807 89,563 93,452 93,105 93,847 93,340
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
15
Elwood
Annual Cash Flow Statement
High Gas Sensitivity
Project Year 21 22 23 24 25 26
Year 2021 2022 2023 2024 2025 2026
Percent of Year 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 180,454 266,192 326,219 352,063 359,098 123,342
Contract Revenues 102,735 38,481 -- -- -- --
Volatility Revenues 33,225 46,371 58,312 63,179 63,396 28,038
Total Operating Revenues 316,414 351,044 384,531 415,242 422,493 151,380
Operating Expenses ($,000)
Fuel Costs 170,028 169,025 164,569 176,188 183,354 92,538
Fixed O&M Expenses
Units 1-4 & 9 5,431 5,593 5,761 5,934 6,112 3,054
Units 5-8 5,862 6,038 6,219 6,406 6,598 3,352
Variable O&M 44 43 41 44 45 22
Emission Costs 272 254 272 239 210 59
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 3,638 4,315 3,355 3,369 3,152 730
Interest Income on Cash Balances 465 465 465 465 465 285
Cash Flow Available
For Debt Service ($,000) 138,881 174,869 211,488 230,265 229,790 53,370
Debt Service ($,000)(1)
Debt 26,290 21,673 10,158 12,797 8,985 1,726
Interest 6,639 4,449 2,720 1,887 826 70
Total Debt Service 32,929 26,122 12,878 14,684 9,811 1,797
Debt Service Coverage Ratio 4.22x 6.69x 16.42x 15.68x 23.42x 29.70x
Cash Flow After Debt Service ($,000) 105,952 148,747 198,610 215,582 219,980 51,573
Major Maintenance ($,000)
Units 1-4 & 9 14,000 14,000 14,000 14,000 14,000 2,000
Units 5-8 8,000 8,000 8,000 2,000 2,000 1,000
Cash Flow After Debt Service and Major Maintenance ($,000) 83,952 126,747 176,610 199,582 203,980 48,573
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
16
Elwood
Annual Cash Flow Statement
Overbuild Sensitivity
Project Year 1 2 3 4 5 6
Year 2001 2002 2003 2004 2005 2006
Percent of Year 33% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- --
Contract Revenues 32,635 132,754 121,836 116,730 128,442 130,784
Volatility Revenues -- -- -- -- -- --
Total Operating Revenues 32,635 132,754 121,836 116,730 128,442 130,784
Operating Expenses ($,000)
Fuel Costs 11,788 55,573 46,285 41,246 51,706 54,486
Fixed O&M Expenses
Units 1-4 & 9 771 3,368 3,465 3,557 3,651 3,997
Units 5-8 875 4,010 4,133 4,231 4,332 5,207
Variable O&M 3 17 15 15 10 14
Emission Costs -- -- -- 373 344 359
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 20 260 548 836 1,108 1,223
Interest Income on Cash Balances 440 804 780 803 814 842
Cash Flow Available
For Debt Service ($,000) 19,659 70,850 69,266 68,947 70,322 68,786
Debt Service ($,000)(1)
Debt 5,600 14,210 14,180 15,530 17,910 18,330
Interest 6,742 32,239 31,096 29,916 28,599 27,117
Total Debt Service 12,342 46,449 45,276 45,446 46,509 45,447
Debt Service Coverage Ratio 1.59x 1.53x 1.53x 1.52x 1.51x 1.51x
-----------------------------------------------
Average Debt Service Coverage Ratio 3.55x
Minimun Debt Service Coverage Ratio 1.51x
-----------------------------------------------
Cash Flow After Debt Service ($,000) 7,317 24,401 23,990 23,500 23,813 23,339
Major Maintenance ($,000)
Units 1-4 & 9 500 2,000 2,000 2,000 2,000 2,000
Units 5-8 1,300 5,200 5,200 5,200 5,200 5,200
Cash Flow After Debt Service and Major Maintenance ($,000) 5,517 17,201 16,790 16,300 16,613 16,139
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
17
Elwood
Annual Cash Flow Statement
Overbuild Sensitivity
Project Year 7 8 9 10 11 12 13
Year 2007 2008 2009 2010 2011 2012 2013
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- -- 108,696
Contract Revenues 127,625 132,259 135,737 131,964 119,877 130,585 83,255
Volatility Revenues -- -- -- -- -- -- 20,990
Total Operating Revenues 127,625 132,259 135,737 131,964 119,877 130,585 212,941
Operating Expenses ($,000)
Fuel Costs 51,704 56,323 59,271 55,690 45,124 53,680 83,068
Fixed O&M Expenses
Units 1-4 & 9 3,890 4,324 4,430 4,538 4,323 4,204 4,326
Units 5-8 5,699 5,809 5,922 6,039 5,146 4,547 4,674
Variable O&M 16 17 19 23 18 21 36
Emission Costs (29) (33) 124 127 140 155 145
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,459 1,796 2,009 2,280 2,346 1,458 921
Interest Income on Cash Balances 824 873 892 843 799 847 411
Cash Flow Available
For Debt Service ($,000) 68,627 68,489 68,872 68,671 68,272 70,283 122,024
Debt Service ($,000)(1)
Debt 19,390 20,750 22,310 23,230 25,230 29,644 8,211
Interest 25,609 23,997 22,274 20,438 18,511 16,373 14,319
Total Debt Service 44,999 44,747 44,584 43,668 43,741 46,017 22,530
Debt Service Coverage Ratio 1.53x 1.53x 1.54x 1.57x 1.56x 1.53x 5.42x
Cash Flow After Debt Service ($,000) 23,628 23,742 24,287 25,003 24,531 24,265 99,494
Major Maintenance ($,000)
Units 1-4 & 9 2,000 2,000 2,000 2,000 2,000 2,000 10,000
Units 5-8 5,200 5,200 5,200 5,200 5,200 5,200 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 16,428 16,542 17,087 17,803 17,331 17,065 81,494
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
18
Elwood
Annual Cash Flow Statement
Overbuild Sensitivity
Project Year 14 15 16 17 18 19 20
Year 2014 2015 2016 2017 2018 2019 2020
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 113,484 122,499 117,136 130,429 133,221 138,984 139,706
Contract Revenues 82,596 83,842 77,564 80,325 72,652 77,715 73,543
Volatility Revenues 22,294 26,003 23,914 27,015 29,478 28,975 29,036
Total Operating Revenues 218,373 232,344 218,615 237,769 235,352 245,675 242,285
Operating Expenses ($,000)
Fuel Costs 88,056 96,714 84,760 98,477 107,781 121,162 105,959
Fixed O&M Expenses
Units 1-4 & 9 4,455 4,581 4,711 4,817 4,984 5,126 5,272
Units 5-8 4,806 4,941 5,080 5,223 5,382 5,535 5,692
Variable O&M 37 42 36 44 44 50 43
Emission Costs 183 217 215 243 230 248 252
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,365 1,801 1,963 1,786 2,062 1,261 343
Interest Income on Cash Balances 424 414 399 386 399 399 399
Cash Flow Available
For Debt Service ($,000) 122,626 128,064 126,175 131,137 119,392 115,214 125,808
Debt Service ($,000)(1)
Debt 7,500 8,341 5,765 13,170 14,765 15,628 20,677
Interest 13,662 13,049 12,370 11,891 10,814 9,615 8,304
Total Debt Service 21,162 21,390 18,135 25,061 25,579 25,243 28,981
Debt Service Coverage Ratio 5.79x 5.99x 6.96x 5.23x 4.67x 4.56x 4.34x
Cash Flow After Debt Service ($,000) 101,464 106,674 108,040 106,076 93,814 89,971 96,827
Major Maintenance ($,000)
Units 1-4 & 9 10,000 10,000 10,000 6,000 6,000 6,000 6,000
Units 5-8 8,000 8,000 8,000 8,000 8,000 8,000 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 83,464 88,674 90,040 92,076 79,814 75,971 82,827
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
19
Elwood
Annual Cash Flow Statement
Overbuild Sensitivity
Project Year 21 22 23 24 25 26
Year 2021 2022 2023 2024 2025 2026
Percent of Year 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 150,750 220,042 273,420 293,416 297,787 91,960
Contract Revenues 72,194 32,916 -- -- -- --
Volatility Revenues 33,225 46,371 58,312 63,179 63,396 28,038
Total Operating Revenues 256,170 299,329 331,732 356,595 361,182 119,998
Operating Expenses ($,000)
Fuel Costs 111,324 111,095 109,941 111,698 118,756 60,094
Fixed O&M Expenses
Units 1-4 & 9 5,431 5,593 5,761 5,934 6,112 3,054
Units 5-8 5,862 6,038 6,219 6,406 6,598 3,352
Variable O&M 45 44 43 44 46 24
Emission Costs 305 277 271 250 230 62
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 3,762 4,256 3,255 3,292 3,230 1,206
Interest Income on Cash Balances 399 399 399 399 399 234
Cash Flow Available
For Debt Service ($,000) 137,364 180,937 213,150 235,954 233,068 54,852
Debt Service ($,000)(1)
Debt 26,290 21,673 10,158 12,797 8,985 1,726
Interest 6,639 4,449 2,720 1,887 826 70
Total Debt Service 32,929 26,122 12,878 14,684 9,811 1,797
Debt Service Coverage Ratio 4.17x 6.93x 16.55x 16.07x 23.76x 30.53x
Cash Flow After Debt Service ($,000) 104,436 154,814 200,272 221,271 223,258 53,056
Major Maintenance ($,000)
Units 1-4 & 9 14,000 14,000 14,000 14,000 14,000 2,000
Units 5-8 8,000 8,000 8,000 2,000 2,000 1,000
Cash Flow After Debt Service and Major Maintenance ($,000) 82,436 132,814 178,272 205,271 207,258 50,056
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
20
Elwood
Annual Cash Flow Statement
No Aquila Contract Extension Sensitivity
Project Year 1 2 3 4 5 6
Year 2001 2002 2003 2004 2005 2006
Percent of Year 33% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- --
Contract Revenues 32,635 132,754 121,836 116,730 129,175 131,295
Volatility Revenues -- -- -- -- -- --
Total Operating Revenues 32,635 132,754 121,836 116,730 129,175 131,295
Operating Expenses ($,000)
Fuel Costs 11,788 55,573 46,285 41,246 52,369 55,039
Fixed O&M Expenses
Units 1-4 & 9 771 3,368 3,465 3,557 3,651 3,997
Units 5-8 875 4,010 4,133 4,231 4,332 5,207
Variable O&M 3 17 15 15 22 22
Emission Costs -- -- -- 373 344 359
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 20 260 548 836 1,108 1,212
Interest Income on Cash Balances 440 804 780 803 818 846
Cash Flow Available
For Debt Service ($,000) 19,659 70,850 69,266 68,947 70,385 68,728
Debt Service ($,000)(1)
Debt 5,600 14,210 14,180 15,530 17,910 18,330
Interest 6,742 32,239 31,096 29,916 28,599 27,117
Total Debt Service 12,342 46,449 45,276 45,446 46,509 45,447
Debt Service Coverage Ratio 1.59x 1.53x 1.53x 1.52x 1.51x 1.51x
-----------------------------------------------
Average Debt Service Coverage Ratio 3.83x
Minimun Debt Service Coverage Ratio 1.51x
-----------------------------------------------
Cash Flow After Debt Service ($,000) 7,317 24,401 23,990 23,500 23,876 23,281
Major Maintenance ($,000)
Units 1-4 & 9 500 2,000 2,000 2,000 2,000 2,000
Units 5-8 1,300 5,200 5,200 5,200 5,200 5,200
Cash Flow After Debt Service and Major Maintenance ($,000) 5,517 17,201 16,790 16,300 16,676 16,081
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
21
Elwood
Annual Cash Flow Statement
No Aquila Contract Extension Sensitivity
Project Year 7 8 9 10 11 12 13
Year 2007 2008 2009 2010 2011 2012 2013
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- -- 108,582
Contract Revenues 128,030 132,586 136,205 131,894 119,840 130,562 83,238
Volatility Revenues -- -- -- -- -- -- 20,990
Total Operating Revenues 128,030 132,586 136,205 131,894 119,840 130,562 212,810
Operating Expenses ($,000)
Fuel Costs 52,139 56,779 59,741 55,839 45,179 53,549 83,180
Fixed O&M Expenses
Units 1-4 & 9 3,890 4,324 4,430 4,538 4,323 4,204 4,326
Units 5-8 5,699 5,809 5,922 6,039 5,146 4,547 4,674
Variable O&M 23 26 26 24 20 24 36
Emission Costs (48) (50) 155 170 157 149 153
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,319 1,595 1,785 1,214 1,045 1,102 990
Interest Income on Cash Balances 826 874 896 834 787 846 412
Cash Flow Available
For Debt Service ($,000) 68,471 68,168 68,612 67,332 66,847 70,036 121,843
Debt Service ($,000)(1)
Debt 19,390 20,750 22,310 23,230 25,230 29,644 8,211
Interest 25,609 23,997 22,274 20,438 18,511 16,373 14,319
Total Debt Service 44,999 44,747 44,584 43,668 43,741 46,017 22,530
Debt Service Coverage Ratio 1.52x 1.52x 1.54x 1.54x 1.53x 1.52x 5.41x
Cash Flow After Debt Service ($,000) 23,473 23,421 24,028 23,664 23,106 24,019 99,313
Major Maintenance ($,000)
Units 1-4 & 9 2,000 2,000 2,000 2,000 2,000 2,000 10,000
Units 5-8 5,200 5,200 5,200 5,200 5,200 5,200 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 16,273 16,221 16,828 16,464 15,906 16,819 81,313
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
22
Elwood
Annual Cash Flow Statement
No Aquila Contract Extension Sensitivity
Project Year 14 15 16 17 18 19 20
Year 2014 2015 2016 2017 2018 2019 2020
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 113,358 122,341 127,816 195,091 226,057 237,143 240,221
Contract Revenues 82,541 83,790 69,957 30,157 -- -- --
Volatility Revenues 22,294 26,003 25,562 39,542 42,690 43,937 43,040
Total Operating Revenues 218,192 232,133 223,335 264,790 268,747 281,080 283,261
Operating Expenses ($,000)
Fuel Costs 88,036 96,637 85,446 100,063 99,335 107,877 99,326
Fixed O&M Expenses
Units 1-4 & 9 4,455 4,581 4,711 4,817 4,984 5,126 5,272
Units 5-8 4,806 4,941 5,080 5,223 5,382 5,535 5,692
Variable O&M 37 42 36 41 40 43 40
Emission Costs 214 217 215 243 227 212 182
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,267 1,479 1,575 1,762 2,142 1,261 301
Interest Income on Cash Balances 423 412 399 386 399 399 399
Cash Flow Available
For Debt Service ($,000) 122,336 127,606 129,821 156,550 161,319 163,947 173,448
Debt Service ($,000)(1)
Debt 7,500 8,341 5,765 13,170 14,765 15,628 20,677
Interest 13,662 13,049 12,370 11,891 10,814 9,615 8,304
Total Debt Service 21,162 21,390 18,135 25,061 25,579 25,243 28,981
Debt Service Coverage Ratio 5.78x 5.97x 7.16x 6.25x 6.31x 6.49x 5.98x
Cash Flow After Debt Service ($,000) 101,174 106,216 111,686 131,489 135,741 138,704 144,467
Major Maintenance ($,000)
Units 1-4 & 9 10,000 10,000 10,000 6,000 6,000 6,000 6,000
Units 5-8 8,000 8,000 8,000 8,000 8,000 8,000 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 83,174 88,216 93,686 117,489 121,741 124,704 130,467
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
23
Elwood
Annual Cash Flow Statement
No Aquila Contract Extension Sensitivity
Project Year 21 22 23 24 25 26
Year 2021 2022 2023 2024 2025 2026
Percent of Year 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 234,780 250,997 272,674 292,626 296,962 91,698
Contract Revenues -- -- -- -- -- --
Volatility Revenues 60,220 56,997 58,312 63,179 63,396 28,038
Total Operating Revenues 295,000 307,994 330,986 355,806 360,357 119,736
Operating Expenses ($,000)
Fuel Costs 100,403 105,043 109,723 111,570 118,507 59,956
Fixed O&M Expenses
Units 1-4 & 9 5,431 5,593 5,761 5,934 6,112 3,054
Units 5-8 5,862 6,038 6,219 6,406 6,598 3,352
Variable O&M 40 41 43 44 46 23
Emission Costs 205 199 198 204 230 62
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 1,744 1,935 2,748 2,874 2,161 605
Interest Income on Cash Balances 399 399 399 399 399 233
Cash Flow Available
For Debt Service ($,000) 185,202 193,412 212,188 234,920 231,424 54,127
Debt Service ($,000)(1)
Debt 26,290 21,673 10,158 12,797 8,985 1,726
Interest 6,639 4,449 2,720 1,887 826 70
Total Debt Service 32,929 26,122 12,878 14,684 9,811 1,797
Debt Service Coverage Ratio 5.62x 7.40x 16.48x 16.00x 23.59x 30.12x
Cash Flow After Debt Service ($,000) 152,274 167,290 199,310 220,237 221,613 52,330
Major Maintenance ($,000)
Units 1-4 & 9 14,000 14,000 14,000 14,000 14,000 2,000
Units 5-8 8,000 8,000 8,000 2,000 2,000 1,000
Cash Flow After Debt Service and Major Maintenance ($,000) 130,274 145,290 177,310 204,237 205,613 49,330
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
24
Elwood
Annual Cash Flow Statement
No Volatility Revenue Sensitivity
Project Year 1 2 3 4 5 6
Year 2001 2002 2003 2004 2005 2006
Percent of Year 33% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- --
Contract Revenues 32,635 132,754 121,836 116,730 129,175 131,295
Volatility Revenues -- -- -- -- -- --
Total Operating Revenues 32,635 132,754 121,836 116,730 129,175 131,295
Operating Expenses ($,000)
Fuel Costs 11,788 55,573 46,285 41,246 52,369 55,039
Fixed O&M Expenses
Units 1-4 & 9 771 3,368 3,465 3,557 3,651 3,997
Units 5-8 875 4,010 4,133 4,231 4,332 5,207
Variable O&M 3 17 15 15 22 22
Emission Costs -- -- -- 373 344 359
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 20 260 548 836 1,108 1,212
Interest Income on Cash Balances 440 804 780 803 818 846
Cash Flow Available
For Debt Service ($,000) 19,659 70,850 69,266 68,947 70,385 68,728
Debt Service ($,000)(1)
Debt 5,600 14,210 14,180 15,530 17,910 18,330
Interest 6,742 32,239 31,096 29,916 28,599 27,117
Total Debt Service 12,342 46,449 45,276 45,446 46,509 45,447
Debt Service Coverage Ratio 1.59x 1.53x 1.53x 1.52x 1.51x 1.51x
-----------------------------------------------
Average Debt Service Coverage Ratio 2.97x
Minimun Debt Service Coverage Ratio 1.51x
-----------------------------------------------
Cash Flow After Debt Service ($,000) 7,317 24,401 23,990 23,500 23,876 23,281
Major Maintenance ($,000)
Units 1-4 & 9 500 2,000 2,000 2,000 2,000 2,000
Units 5-8 1,300 5,200 5,200 5,200 5,200 5,200
Cash Flow After Debt Service and Major Maintenance ($,000) 5,517 17,201 16,790 16,300 16,676 16,081
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
25
Elwood
Annual Cash Flow Statement
No Volatility Revenue Sensitivity
Project Year 7 8 9 10 11 12 13
Year 2007 2008 2009 2010 2011 2012 2013
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues -- -- -- -- -- -- 108,582
Contract Revenues 128,030 132,586 136,205 131,894 119,840 130,562 83,238
Volatility Revenues -- -- -- -- -- -- --
Total Operating Revenues 128,030 132,586 136,205 131,894 119,840 130,562 191,820
Operating Expenses ($,000)
Fuel Costs 52,139 56,779 59,741 55,839 45,179 53,549 83,180
Fixed O&M Expenses
Units 1-4 & 9 3,890 4,324 4,430 4,538 4,323 4,204 4,326
Units 5-8 5,699 5,809 5,922 6,039 5,146 4,547 4,674
Variable O&M 23 26 26 24 20 24 36
Emission Costs (48) (50) 155 170 157 149 153
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,319 1,595 1,785 1,214 1,045 1,102 990
Interest Income on Cash Balances 826 874 896 834 787 846 412
Cash Flow Available
For Debt Service ($,000) 68,471 68,168 68,612 67,332 66,847 70,036 100,853
Debt Service ($,000)(1)
Debt 19,390 20,750 22,310 23,230 25,230 29,644 8,211
Interest 25,609 23,997 22,274 20,438 18,511 16,373 14,319
Total Debt Service 44,999 44,747 44,584 43,668 43,741 46,017 22,530
Debt Service Coverage Ratio 1.52x 1.52x 1.54x 1.54x 1.53x 1.52x 4.48x
Cash Flow After Debt Service ($,000) 23,473 23,421 24,028 23,664 23,106 24,019 78,323
Major Maintenance ($,000)
Units 1-4 & 9 2,000 2,000 2,000 2,000 2,000 2,000 10,000
Units 5-8 5,200 5,200 5,200 5,200 5,200 5,200 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 16,273 16,221 16,828 16,464 15,906 16,819 60,323
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
26
Elwood
Annual Cash Flow Statement
No Volatility Revenue Sensitivity
Project Year 14 15 16 17 18 19 20
Year 2014 2015 2016 2017 2018 2019 2020
Percent of Year 100% 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 113,358 122,341 116,920 130,178 132,960 138,696 139,409
Contract Revenues 82,541 83,790 78,607 87,522 86,869 97,233 84,806
Volatility Revenues -- -- -- -- -- -- --
Total Operating Revenues 195,899 206,130 195,528 217,700 219,829 235,929 224,215
Operating Expenses ($,000)
Fuel Costs 88,036 96,637 85,712 103,201 107,631 120,980 105,785
Fixed O&M Expenses
Units 1-4 & 9 4,455 4,581 4,711 4,817 4,984 5,126 5,272
Units 5-8 4,806 4,941 5,080 5,223 5,382 5,535 5,692
Variable O&M 37 42 36 44 44 50 43
Emission Costs 214 217 215 243 230 247 252
Capital Expenditures ($,000) -- -- -- -- -- -- --
Interest Income on Reserve Balances 1,267 1,479 1,575 1,762 2,142 1,261 301
Interest Income on Cash Balances 423 412 399 389 399 399 399
Cash Flow Available
For Debt Service ($,000) 100,042 101,603 101,747 106,322 104,099 105,651 107,871
Debt Service ($,000)(1)
Debt 7,500 8,341 5,765 13,170 14,765 15,628 20,677
Interest 13,662 13,049 12,370 11,891 10,814 9,615 8,304
Total Debt Service 21,162 21,390 18,135 25,061 25,579 25,243 28,981
Debt Service Coverage Ratio 4.73x 4.75x 5.61x 4.24x 4.07x 4.19x 3.72x
Cash Flow After Debt Service ($,000) 78,880 80,213 83,613 81,261 78,521 80,407 78,890
Major Maintenance ($,000)
Units 1-4 & 9 10,000 10,000 10,000 6,000 6,000 6,000 6,000
Units 5-8 8,000 8,000 8,000 8,000 8,000 8,000 8,000
Cash Flow After Debt Service and Major Maintenance ($,000) 60,880 62,213 65,613 67,261 64,521 66,407 64,890
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
27
Elwood
Annual Cash Flow Statement
No Volatility Revenue Sensitivity
Project Year 21 22 23 24 25 26
Year 2021 2022 2023 2024 2025 2026
Percent of Year 100% 100% 100% 100% 100% 100%
Revenues ($,000)
Market Revenues 150,402 219,489 272,674 292,626 296,962 91,698
Contract Revenues 76,695 29,522 -- -- -- --
Volatility Revenues -- -- -- -- -- --
Total Operating Revenues 227,097 249,011 272,674 292,626 296,962 91,698
Operating Expenses ($,000)
Fuel Costs 111,120 110,884 109,719 111,566 118,504 59,955
Fixed O&M Expenses
Units 1-4 & 9 5,431 5,593 5,761 5,934 6,112 3,054
Units 5-8 5,862 6,038 6,219 6,406 6,598 3,352
Variable O&M 45 44 43 44 46 23
Emission Costs 304 276 270 249 230 62
Capital Expenditures ($,000) -- -- -- -- -- --
Interest Income on Reserve Balances 1,744 1,935 2,748 2,874 2,161 605
Interest Income on Cash Balances 399 399 399 399 399 233
Cash Flow Available
For Debt Service ($,000) 106,479 128,508 153,808 171,699 168,031 26,090
Debt Service ($,000)(1)
Debt 26,290 21,673 10,158 12,797 8,985 1,726
Interest 6,639 4,449 2,720 1,887 826 70
Total Debt Service 32,929 26,122 12,878 14,684 9,811 1,797
Debt Service Coverage Ratio 3.23x 4.92x 11.94x 11.69x 17.13x 14.52x
Cash Flow After Debt Service ($,000) 73,550 102,386 140,930 157,016 158,220 24,293
Major Maintenance ($,000)
Units 1-4 & 9 14,000 14,000 14,000 14,000 14,000 2,000
Units 5-8 8,000 8,000 8,000 2,000 2,000 1,000
Cash Flow After Debt Service and Major Maintenance ($,000) 51,550 80,386 118,930 141,016 142,220 21,293
1 The debt service amounts shown above are the sum of the two semiannual
payments relating to the calendar year cash flow. The actual bond payment
will be made on July 5 of that year and January 5 of the following year.
28
Annex C-1
Power Market Report
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Power Market Assessment
MID-AMERICA INTERCONNECTED NETWORK (MAIN)
Prepared for:
Elwood Energy LLC
September 06, 2001
================================================================================
This Report was produced by Pace Global Energy Services, LLC ("Pace") and 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
prior written consent of Pace is forbidden. Except for its stated purpose, this
Report may not be copied or distributed in whole or in part without Pace's prior
written consent.
This Report and the information and statements herein are based in whole or in
part on information obtained from various sources as of September 06, 2001.
While Pace believes such information to be accurate, it makes no assurances,
endorsements or warranties, express or implied, as to the validity, accuracy or
completeness of any such information, any conclusions based thereon, or any
methods disclosed in this Report. Pace assumes no responsibility for the results
of any actions taken on the basis of this Report. By a party using, acting or
relying on this Report, such party consents and agrees that Pace, its employees,
directors, officers, contractors, advisors, members, affiliates, successors and
agents shall have no liability with respect to such use, actions or reliance.
This Report does contain some forward-looking opinions. Certain unanticipated
factors could cause actual results to differ from the opinions contained herein.
Forward-looking opinions are based on historical and/or current information that
relate to future operations, strategies, financial results or other
developments. Some of the unanticipated factors, among others, that could cause
the actual results to differ include regulatory developments, technological
changes, competitive conditions, new products, general economic conditions,
changes in tax laws, adequacy of reserves, credit and other risks associated
with Elwood Energy LLC and/or other third parties, significant changes in
interest rates and fluctuations in foreign currency exchange rates.
Further, certain statements, findings and conclusions in this Report are based
on Pace's interpretations of various contracts. Interpretations of these
contracts by legal counsel or a jurisdictional body could differ.
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================================================================================
TABLE OF CONTENTS
================================================================================
Executive Summary .............................................................1
Transaction Summary .......................................................1
Power Sales Agreements ..................................................2
Extension of Aquila Power Sales Agreements ..............................3
Merchant and Contract Periods ...........................................3
Results and Conclusions ...................................................4
Project Results .........................................................8
Project Volatility Value ................................................9
Assumptions ..............................................................13
Load Growth ............................................................13
Expansion Units and Existing Unit Capacity .............................13
Outline of report ........................................................15
Market Clearing Price Forecast Approach ......................................17
Approach .................................................................17
Equilibrium Pricing of Expansion Capacity ................................19
MAIN Market Pricing Forecast Results .........................................23
CEMAS Simulated Market Pricing Rates .....................................23
MAIN System Market Pricing - Base Case .............................23
Announced and Forecasted System Capacity Additions .................24
Project Results - Base Case ........................................27
Volatility Analysis Approach and Results .....................................31
Summary Results ..........................................................31
Volatility Value Analysis Methodology And Valuation ......................33
Gas Market ...............................................................34
Commodity Price Correlation ..............................................35
Power Market And Valuation Results .......................................35
Insurance ................................................................38
Other Volatility Value Measures ..........................................38
Market Area Definition and Transmission ......................................39
Regulatory Status ........................................................43
Midwest ISO ............................................................47
Midwest RTO ............................................................47
Power Marketing and Trading Activity .....................................47
Electricity Demand In MAIN ...................................................52
Load Forecasting Methodology .............................................52
Energy Demand Forecast Results ...........................................54
Hourly Load Forecasting ..................................................61
MAIN Power Generation Resources ..............................................62
Demand Profile ...........................................................62
Generation Profile .......................................................64
Generating Unit Cost Profile ...........................................65
Generating Unit Fuel Mix ...............................................66
MAIN Nuclear Unit Assessment ...........................................67
Expansion Unit Characterization and Costs ................................68
Elwood Project Characterization and Costs ................................70
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Fuel Pricing .................................................................71
Natural Gas ..............................................................72
Commodity Prices .......................................................72
Regional Basis .........................................................73
Fuel Oil .................................................................75
Commodity Prices .......................................................75
Location Basis .........................................................77
Refined Product Crack Spreads ..........................................78
Delivered Oil Price Forecasts ..........................................79
Coal .....................................................................79
MAIN Coal Consumption Profile ..........................................80
Coal Price Escalation Rates ............................................82
Coal Supply, Demand, and Transportation Trends .........................82
Delivered Coal Price Forecast ..........................................84
Uranium ..................................................................85
Appendix A - Sensitivities ...................................................86
High Gas Case ............................................................86
Overbuild Case ...........................................................92
Aquila PSA Extension Case ................................................97
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EXHIBITS
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EXHIBIT 1: MAIN-NI ANNUAL SYSTEM AVERAGE MARKET PRICE (1998 $/MWH) ...........7
EXHIBIT 2: PROJECT ANNUAL OPERATIONAL SUMMARY - (1998 $) .....................9
EXHIBIT 3: PROJECT ANNUAL VOLATILITY VALUE (1998 $) .........................11
EXHIBIT 4: PROJECT MONTHLY VOLATILITY VALUE - NET OF INSURANCE (1998 $) .....12
EXHIBIT 5: KEY ASSUMPTIONS - BASE CASE ......................................15
EXHIBIT 6: PACE CEMAS METHODOLOGY ...........................................18
EXHIBIT 7: EQUILIBRIUM MARKET PRICES BASED ON EXPANSION UNIT COSTS - 2003 ...20
EXHIBIT 8: MAIN SYSTEM SUPPLY CURVE .........................................21
EXHIBIT 9: MAIN-NI ANNUAL PRICE SUMMARY - BASE CASE (1998 $/MWH) ............24
EXHIBIT 10: BASE CASE ANNOUNCED CAPACITY ADDITIONS (MW) ......................25
EXHIBIT 11: EXPANSION CAPACITY ADDITIONS BY YEAR - BASE CASE .................26
EXHIBIT 12: PROJECT ANNUAL OPERATIONAL SUMMARY (1998 $) ......................28
EXHIBIT 13: EXELON PSA ANNUAL OPERATIONAL SUMMARY (1998 $) ...................29
EXHIBIT 14: AQUILA PSAs ANNUAL OPERATIONAL SUMMARY (1998 $) ..................30
EXHIBIT 15: PROJECT ANNUAL VOLATILITY VALUE (1998 $) .........................32
EXHIBIT 16: PROJECT MONTHLY VOLATILITY VALUE - NET OF INSURANCE (1998 $) .....33
EXHIBIT 17: LONG-TERM MONTHLY HENRY HUB IMPLIED VOLATILITY FORECAST ..........35
EXHIBIT 18: REGIONAL POWER TRADING MARKETS ...................................36
EXHIBIT 19: COM ED 2001 TERM POWER MARKET IMPLIED VOLATILITY FORECAST ........36
EXHIBIT 20: FORECAST OF KEY VOLATILITY DRIVERS ...............................37
EXHIBIT 21: MAIN SUB-REGIONS AND MAJOR UTILITY COMPANIES .....................39
EXHIBIT 22: OTHER FIRST TIER SUB-REGIONS AND MAJOR UTILITY COMPANIES .........40
EXHIBIT 23: MAIN REGIONAL MAP WITH MAJOR IOUs ................................40
EXHIBIT 24: OVERVIEW OF SYSTEM COINCIDENT PEAKS ..............................41
EXHIBIT 25: ASSUMED INTRA-REGIONAL TRANSMISSION CONSTRAINTS ..................42
EXHIBIT 26: INTER-REGIONAL TRANSACTIONS LIMITS ...............................43
EXHIBIT 27: POWER MARKETERS VOLUMES TRADED IN MAIN FROM 1997 TO 1999 .........49
EXHIBIT 28: MAIN NET WHOLESALE PURCHASES/(SALES) - MWH .......................49
EXHIBIT 29: DAILY AVERAGE PEAK PRICING IN MAIN ...............................50
EXHIBIT 30: MAIN PEAK SUMMER POWER PRICING DATA (1997-2001) ..................51
EXHIBIT 31: PACE LOAD FORECASTING METHODOLOGY ................................53
EXHIBIT 32: PACE AGGREGATED ENERGY DEMAND FORECAST (MAIN) ....................55
EXHIBIT 33: PACE MAIN ENERGY DEMAND FORECAST .................................56
EXHIBIT 34: PACE'S SUB-REGIONAL ENERGY AND FORECAST FOR MAIN - GWH ...........57
EXHIBIT 35: ANNUAL ENERGY AND PEAK DEMAND FORECASTS FOR INTERCONNECTED
SUB-REGIONS ......................................................58
EXHIBIT 36: PACE'S SUB-REGIONAL PEAK DEMAND FORECAST FOR MAIN - MW ...........59
EXHIBIT 37: PACE'S ENERGY DEMAND AND PEAK FORECASTS - MAIN &
INTERCONNECTED SUB-REGIONS .......................................60
EXHIBIT 38: MAJOR UTILITIES 1999 DEMAND ......................................62
EXHIBIT 39: MAIN DEMAND AND ENERGY REQUIREMENTS FORECAST .....................63
EXHIBIT 40: MAIN DEMAND AND ENERGY RESERVE MARGIN FORECAST - SUMMER ..........64
EXHIBIT 41: MAIN DEMAND AND ENERGY RESERVE MARGIN FORECAST - WINTER ..........64
EXHIBIT 42: MAIN MARKET GENERATION SUMMER CAPACITY - MW ......................65
EXHIBIT 43: MAIN EMBEDDED COST SUMMARY .......................................66
EXHIBIT 44: MAIN GENERATION MIX BY FUEL TYPE .................................67
EXHIBIT 45: MAIN NUCLEAR UNITS ...............................................68
EXHIBIT 46: EXPANSION UNIT CHARACTERISTICS ...................................69
EXHIBIT 47: REGIONAL COST ADJUSTMENTS ........................................69
EXHIBIT 48: ELWOOD PROJECT SPECIFICATIONS ....................................70
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EXHIBIT 49: MONTHLY FUEL PRICE ADJUSTMENT FACTORS ............................71
EXHIBIT 50: PACE GAS PRICE MAIN SUB-REGIONS ..................................73
EXHIBIT 51: MAIN NATURAL GAS PRICE FORECASTS (1998 $/MMBTU) ..................75
EXHIBIT 52: WTI CRUDE OIL PRICE FORECAST (1998 $/MMBTU) ......................77
EXHIBIT 53: PACE OIL PRICE SUB-REGIONS FOR MAIN ..............................78
EXHIBIT 54: MAIN FUEL OIL LOCATION BASIS (1998 $/MMBTU) ......................78
EXHIBIT 55: CRUDE OIL TO REFINED PRODUCT CRACK SPREADS (1998 $/MMBTU) ........79
EXHIBIT 56: FUEL OIL PRICE FORECAST BY MAIN SUB-REGION (1998 $/MMBTU) ........79
EXHIBIT 57: HISTORICAL DELIVERED COAL PRICES FOR MAIN BY SULFUR CONTENT
(1998 $/MMBTU) ...................................................80
EXHIBIT 58: MAIN COAL CONSUMPTION BY SULFUR GRADE ............................81
EXHIBIT 59: MAIN COAL CONSUMPTION BY SOURCE REGION, 1999 .....................82
EXHIBIT 60: PACE DELIVERED REAL COAL PRICE ESCALATION RATES ..................82
EXHIBIT 61: PROJECTED COAL PRODUCTION GROWTH BY REGION .......................84
EXHIBIT 62: COMPARISON OF BASE CASE AND HIGH GAS CASE HENRY HUB PRICES -
(1998 $/MMBTU) ...................................................87
EXHIBIT 63: MAIN - NI ANNUAL SYSTEM AVERAGE MARKET PRICE - HIGH GAS CASE
(1998 $/MWH) .....................................................88
EXHIBIT 64: DIFFERENCE - BASE CASE & HIGH GAS CASE MARKET PRICES
(1998 $/MWH) .....................................................89
EXHIBIT 65: PROJECT ANNUAL OPERATIONAL SUMMARY - HIGH NATURAL GAS CASE
(1998 $) .........................................................90
EXHIBIT 66: DIFFERENCE - BASE CASE & HIGH NATURAL GAS CASE PROJECT
RESULTS (1998 $) .................................................91
EXHIBIT 67: MAIN-NI ANNUAL PRICE SUMMARY - OVERBUILD CASE (1998 $/MWH) .......93
EXHIBIT 68: DIFFERENCE - BASE CASE & OVERBUILD CASE MARKET PRICES
(1998 $/MWH) .....................................................94
EXHIBIT 69: PROJECT ANNUAL OPERATIONAL SUMMARY - OVERBUILD CASE (1998 $) .....95
EXHIBIT 70: DIFFERENCE - BASE CASE & OVERBUILD CASE PROJECT RESULTS
(1998 $) .........................................................96
EXHIBIT 71: MAIN-NI ANNUAL PRICE SUMMARY - AQUILA PSA EXTENSION CASE
(1998 $/MWH) .....................................................98
EXHIBIT 72: DIFFERENCE - BASE CASE & AQUILA EXTENSION CASE MARKET PRICES
(1998 $/MWH) .....................................................99
EXHIBIT 73: PROJECT ANNUAL OPERATIONAL SUMMARY - AQUILA PSA EXTENSION
CASE (1998 $) ...................................................100
EXHIBIT 74: DIFFERENCE - BASE CASE & AQUILA PSA EXTENSION CASE PROJECT
RESULTS (1998 $) ................................................101
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================================================================================
EXECUTIVE SUMMARY
================================================================================
Pace Global Energy Services, LLC ("Pace") has prepared an independent assessment
of the Mid-America Interconnected Network ("MAIN") and the economic
competitiveness of a 1,409 MW(1) combustion turbine power plant ("Project")
owned by Elwood Energy LLC ("Elwood"). The Project, located in the town of
Elwood, Illinois, 50 miles from Chicago, will operate in the Northern Illinois
("NI") or Commonwealth Edison ("Com Ed") sub-region of MAIN. The market study
provides an assessment of the long-term power market opportunities in support of
the financing of the Project, including a forecast of all-in capacity and energy
prices for the region during the period 2001 to 2026 (the "Study Period").(2)
This report includes Pace's Base Case (the most likely outcome given the
assumptions set and simulation methodology used to develop the forecast)
forecast of market-clearing prices and facility dispatch profile for the
Project, a forecast of volatility values available to the Project, a description
of the key assumptions and methodology underlying the development of the
forecast, and an assessment of the MAIN power market. In addition, Pace prepared
three sensitivity cases against the Base Case results, a High Gas Price Case, an
Overbuild Case and an Aquila PSA Extension Case included as Appendix A to this
report.
Pace has provided a forecast of the volatility values available to the Project
and these values are included in Pace's Base Case revenue forecast. Pace,
however did not evaluate other values potentially derived from the Project
including ancillary service sales and bilateral transactions, as these potential
revenue sources are not fully defined in the market.
To perform the market price forecast analysis Pace utilized its Capacity &
Energy Market Analysis System ("CEMAS") simulation model. 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
a defined set of assumptions.
TRANSACTION SUMMARY
Elwood is an equal partnership between Peoples Energy Resources Corp. and
Dominion Energy, Inc. The 1,409 MW Project consists of nine operating gas-fired
peaking combustion turbine units, which entered commercial operations in stages
between 1999 and 2001.
Elwood has executed four long-term Power Sales Agreements ("PSA") covering the
entire 1,409 MW output of the Project. Each PSA, which is briefly summarized
below, grants the PSA counter-
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1 Summer Capacity. The nominal capacity of the Project is defined as 1,350 MW.
2 This Report and the information and statements herein are based in whole or in
part on information obtained from various sources as of September 06, 2001.
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party the exclusive right to control the generating capacity and electrical
energy, and thus the dispatch of the units covered by the relevant PSA.
During the term of each PSA, Pace has assumed that each unit will be dispatched
in accordance with the PSA covering such unit (see Exhibit 48 for assumptions
concerning each PSA). As each PSA expires, Pace has assumed that the units
formerly covered by the expired PSA will be dispatched on a merchant basis
through the end of the Study Period.
Power Sales Agreements
Elwood has executed the following PSAs:
Engage Power Sales Agreement
The 313 MW capacity of Units 1-2 are contracted to Engage Energy US L.P. until
December 31, 2004, (the "Engage PSA"). Engage has subsequently resold the output
of these units to Commonwealth Edison Corporation ("ComEd"), the predecessor of
Exelon Generation Company, LLC ("Exelon"). Exelon now controls dispatch of the
Engage units and agreed with Elwood in March 2001 to have the pricing terms of
the Exelon PSA apply to the dispatch by Exelon of the Engage units. This is
accomplished by means of a monthly adjustment, which effectively supersedes the
Engage PSA terms.
Exelon Power Sales Agreement
Elwood has entered into a PSA with Exelon Generation Company, LLC ("Exelon") and
ComEd for 783 MW of capacity, covering the output of Units 1-4 and 9 ("Exelon
Units"), (the "Exelon PSA"). The term of the Exelon PSA runs from March 01, 2001
to December 31, 2012. Exelon is the contractual assignee of its electric utility
affiliate ComEd.
Aquila Power Sales Agreement 1
Elwood has entered into a PSA with Aquila Energy Marketing Corporation ("AEMC")
and UtiliCorp United Inc. ("UtiliCorp" and collectively with AMEC, "Aquila") for
313 MW of capacity, covering the output of Units 5-6 ("Aquila 1 Units"), (the
"Aquila PSA 1"). The initial term of the Aquila PSA 1 runs from June 01, 2001 to
August 31, 2016. (3)
Aquila Power Sales Agreement 2
Elwood has entered into a PSA with Aquila for 313 MW of capacity, covering the
output of Units 7-8 ("Aquila 2 Units"), (the "Aquila PSA 2"). The initial term
of the Aquila PSA 2 runs from July 01, 2001 to August 31, 2017.(4)
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3 The initial term of the Aquila PSA 1 ends on August 31, 2016. Pace has assumed
that Aquila will extend this PSA to August 31, 2021.
4 The initial term of the Aquila PSA 1 ends on August 31, 2017. Pace has assumed
that Aquila will extend this PSA to August 31, 2022.
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Extension of Aquila Power Sales Agreements
Aquila has the unilateral right to extend the initial term of both the Aquila
PSA 1 and 2 (together the "Aquila PSAs") covering Units 5-8 ("Aquila Units") for
an additional five-year period provided that Aquila makes it's election to
extend the agreements prior to September 1, 2014 for the Aquila PSA 1 and
September 1, 2015 for the Aquila PSA 2.
Pace has determined that based upon the payment structure of the Aquila PSAs,
the Project's forecast dispatch profile, forecast market-clearing prices, and
the market-based revenues and volatility values that Aquila is forecast to earn
by marketing the output and capacity of the Aquila Units, a compelling economic
incentive is likely to exist which would cause Aquila to exercise its option to
extend the term of the Aquila PSAs for an additional 5-year period. As a
consequence, Pace has included the extension of the Aquila PSAs for a five-year
period beyond the initial term of the Aquila PSAs in the Base Case forecast.
Pace has therefore modeled the termination date of the Aquila PSA 1 as August
31, 2021 and August 31, 2022 for the Aquila PSA 2.
Merchant and Contract Periods
Definition
Pace has divided the Study Period into two distinct periods. The "Contract
Period" refers to the period during which a unit is dispatched in accordance
with the terms of either the Exelon PSA or the Aquila PSAs and covers the period
from the beginning of the Study Period in 2001 to the expiry of the extended
Aquila PSA 2 on August 31, 2022. The "Merchant Period" refers to the period in
which the Project is operated by Elwood as a fully merchant facility and covers
the period from 2022 (after the termination of the Aquila PSA 2) to the end of
the Study Period in 2026.
While we have defined discrete Contract and Merchant Periods, transition periods
exist where Elwood operates certain units on a merchant basis, while other units
remain subject to dispatch under a PSA. Two such transition periods are present
during the Study Period. The first transition period occurs upon the expiry of
the Exelon PSA on December 31, 2012. Units 1-4 and 9 (formerly Exelon Units) are
operated on a merchant basis by Elwood from January 1, 2013, while Units 5-6 and
7-8 (Aquila 1 Units and Aquila 2 Units, respectively) remain subject to dispatch
by Aquila. The second transition period occurs upon the expiry of the extended
Aquila PSA 1 on August 31, 2021. Units 1-4 and 9, and Units 5-6 (formerly Aquila
1 Units) are operated on a merchant basis by Elwood from September 1, 2021 while
Units 7-8 (Aquila 2 Units) remain subject to dispatch by Aquila until the expiry
of the extended Aquila PSA 2 on August 31, 2022.
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Characterization of Project Results during Merchant and Contract Periods
During the Contract Period, the Project's dispatch, operating profile, energy
and capacity revenues and volatility values reflect dispatch of the Project
according to the terms of the Exelon and Aquila PSAs. In the Merchant Period,
the Project's dispatch, operating profile, energy and capacity revenues and
volatility values reflect the operation of the Project as a merchant facility,
with Elwood controlling the Project's dispatch,
The distinction between the Contract Period and the Merchant period is important
in evaluating the Project's energy and capacity revenue and volatility value
forecast presented in Exhibit 12 - Project Annual Operational Summary (1998 $)
and Appendix A - Sensitivities. During the Contract Period, the forecast refers
to the revenues that Exelon and/or Aquila are forecast to receive from marketing
the energy and capacity of the Exelon and Aquila Units, while the revenues that
Elwood receives during the Contract Period are determined by the payment
structure outlined in the Exelon and Aquila PSAs. However, during the Merchant
Period, when Elwood operates the Project as a merchant facility, the forecast
refers to the revenues to be received by Elwood from marketing the energy and
capacity of the Project for its own account.
During the two transition periods that exist over the course of the Study
Period, the forecast represents a mix of forecast energy and capacity revenues
and volatility values to be received by Exelon, Aquila and Elwood, as the
various units of the Project transition from operating under dispatch
instructions from either Exelon and Aquila to operations on a merchant basis by
Elwood.
RESULTS AND CONCLUSIONS
The following represents conclusions and key findings of Pace's MAIN power
market assessment and market clearing price forecast. They are:
1. The MAIN power market is emerging as a highly competitive market for
wholesale power. The market's competitiveness is evidenced by the
region's large volume of wholesale power transactions and the
existence of the "Into-ComEd" electricity-trading hub upon which a
standardized forward contract has been established. Overall, given
the MAIN market's sizable demand growth, Pace's market-clearing
price forecast, and the Project's competitive market position, the
Project is expected to be highly competitive and valuable throughout
the Study Period.
2. Pace anticipates that given the rapid pace of wholesale energy
market development, a commercially operating and deregulated
environment for retail customers' capacity and energy requirements
will be implemented on a near- to mid-term basis for MAIN. Retail
access began in Illinois for industrial consumers in October 1999
with full access scheduled to commence by May 2002 pursuant to the
enactment of the "Electric Service
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Customer Choice and Rate Relief Act of 1997". The development of an
all-in capacity and energy market will allow for sales to the retail
marketplace and should provide additional flexibility and enhanced
marketability for the Project's capacity and energy.
3. The market for power in MAIN is characterized by:
(a) Sustained energy demand growth expected to continue at a
steady annual average pace of 1.47% over the Study
Period in the MAIN power market. This regional demand
increase translates into approximately 1,100 MW of
annual average demand.
(b) Summer peak demand in the MAIN power market is forecast
to increase from 50,066 MW in 2000 to 73,131 MW by 2026.
This regional peak demand increase translates into the
need for the addition of approximately 700 MW of peaking
capacity per year to the MAIN power market through 2026.
(c) A well-developed electrical transmission system capable
of transferring high volumes of electricity throughout
the MAIN power market and covering over 4 states and
approximately 6% of the U.S. power demand.
(d) An installed capacity base (MW) dominated by base-load
coal-fired, nuclear and hydro capacity representing 73%
of installed generation capacity in 2001 and 67% in
2009.
(e) Base-load coal-fired, nuclear and hydro capacity
representing approximately 94% of electrical generation
(MWh) by fuel type in 2001 and 69% in 2025.
(f) Gas-fired combined cycle and combustion turbine capacity
representing the near universal choice for capacity
additions, driving gas-fired generation from a 6.2%
share of generation in 2001 to 31.1% in 2025.
4. The most significant factors affecting the electricity pricing in
the MAIN power market include fuel costs; the efficiency and
replacement rate of existing generating assets and capital costs of
replacing existing generating assets; the cost and efficiency of
incremental capacity additions which are undertaken to meet future
energy requirements and maintain system reliability; and increases
in annual peak demand and energy requirements.
5. Pace's Base Case average market-clearing price forecast for the
Northern Illinois subregion of MAIN ranges between a maximum value
of $37.60/MWh in 2001 and a minimum value of $28.53/MWh in 2009 and
averages $30.42/MWh (measured in 1998 real dollars) over the Study
Period. Pace expects that while a high level of competitive capacity
additions and declining gas prices will lower electricity prices
between 2001 and 2009, prices will remain relatively stable over the
remainder of the Study Period as sufficient capacity is constructed
to meet demand and efficiency improvements offset a modest natural
gas real price increase.
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6. The Project represents a relatively low cost, competitive, and much
needed resource for the growing MAIN market equaling only a small
fraction of the capacity required in the MAIN power market. The
Project is expected to be dispatched at an average annual capacity
factor of 11.93%(5) and realize average gross margins, including
volatility values, of $82.93/kW-year (measured in 1998 real
dollars). Gross margins range from a maximum of $104.30/kW-year in
2001 to a minimum of $76.82/kW-year in 2009 over the Study Period.
7. During the term of the Exelon PSA which covers the dispatch of Units
1-4 and 9, until December 31, 2012, the Exelon Units are expected to
be dispatched at an average annual capacity factor of 3.39% and
realize average gross margins, including volatility values of
$78.63/kW-year (measured in 1998 real dollars). Gross margins range
from a maximum of $97.86/kW-year in 2001 to a minimum of
$71.93/kW-year in 2009.
8. During the term of the Aquila PSAs which cover the dispatch of Units
5-8, until August 31, 2022, the Aquila Units are expected to be
dispatched at an average annual capacity factor of 17.15% and
realize average gross margins, including volatility values of
$87.22/kW-year (measured in 1998 real dollars). Gross margins range
from a maximum of $112.43/kW-year in 2001 to a minimum of
$81.10/kW-year in 2004.
9. Pace conducted a detailed evaluation of the potential volatility
value of the Project. Given Pace's assumptions of market reserve
margins, liquidity, and trading volatility, volatility value (net of
insurance costs) adds on average $20.33/kW-year or $28.6 million per
year to Base Case energy and capacity revenues over the Study
Period. Volatility value ranges from a maximum of $27.26/kW-year or
$38.4 million in 2001 to a minimum of $16.91/kW-year or $23.8
million in 2004. Pace's Base Case revenue forecast contained in this
report includes these volatility values.
10. Pace has determined that based upon the payment structure of the
Aquila PSAs, the Project's forecast dispatch profile, forecast
market-clearing prices, the energy and capacity revenues, and
volatility values that Aquila is forecast to earn by marketing the
output and capacity of the Aquila Units, a compelling economic
incentive is likely to exist which would cause Aquila to exercise
its option to extend the term of the Aquila PSAs for an additional
5-year period.
11. Pace's assumptions provide a conservative forecast of the Project's
dispatch and resulting economics. Therefore, while the dispatch and
revenues of peaking capacity can be highly
- ----------
5 Results include the periods covered by the Exelon and Aquila PSA's in addition
to the merchant period, which commences in 2022 after the expiry of the extended
Aquila PSA 2.
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volatile from year to year, Pace has removed much of the low side
volatility through our modeling assumptions. These considerations
provide a high level of probability that the Pace's Base Case
forecast is likely to be more of a downside case when compared with
actual Project results.
As shown in Exhibit 1, average market-clearing prices are expected to range
between $37.60/MWh and $28.53/MWh over the Study Period. The following causes
this pricing pattern:
o Short-term high natural gas prices in the early years of the Study
Period result in market-clearing prices reaching $37.60/MWh in
2001.
o A high level of competitive capacity additions and declining gas
prices between 2001 and 2009 lowers average annual market-clearing
prices from $37.60/MWh in 2001 to $28.53/MWh in 2009.
o Throughout the remainder of the Study Period, rising demand growth
increases the amount of time during which natural gas is the
marginal price setter, particularly during off-peak periods. This
factor together with the increase in natural gas prices in real
terms results in average market prices gradually increasing over
time.
Exhibit 1: MAIN-NI Annual System Average Market Price (1998 $/MWh)
================================================================================
-----------------------------------------------
Year Off-Peak On-Peak Average
$/MWh $/MWh $/MWh
-----------------------------------------------
2001 26.98 49.28 37.60
-----------------------------------------------
2002 24.33 45.40 34.37
-----------------------------------------------
2003 22.34 40.87 31.16
-----------------------------------------------
2004 20.96 39.44 29.76
-----------------------------------------------
2005 20.94 39.06 29.57
-----------------------------------------------
2006 20.18 39.12 29.20
-----------------------------------------------
2007 20.13 38.15 28.71
-----------------------------------------------
2008 20.71 37.90 28.89
-----------------------------------------------
2009 20.30 37.59 28.53
-----------------------------------------------
2010 21.04 38.16 29.19
-----------------------------------------------
2011 20.71 39.73 29.76
-----------------------------------------------
2012 21.29 38.69 29.58
-----------------------------------------------
2013 21.48 38.51 29.59
-----------------------------------------------
2014 21.67 38.36 29.62
-----------------------------------------------
2015 21.81 38.93 29.96
-----------------------------------------------
2016 21.48 38.66 29.66
-----------------------------------------------
2017 21.97 39.09 30.13
-----------------------------------------------
2018 21.91 39.14 30.11
-----------------------------------------------
2019 22.45 39.10 30.38
-----------------------------------------------
2020 22.28 39.23 30.35
-----------------------------------------------
2021 22.08 38.74 30.01
-----------------------------------------------
2022 22.56 38.84 30.31
-----------------------------------------------
2023 22.60 39.16 30.49
-----------------------------------------------
2024 22.91 40.16 31.13
-----------------------------------------------
2025 23.13 39.80 31.07
-----------------------------------------------
2026 23.67 40.53 31.70
-----------------------------------------------
Avg. 22.00 39.68 30.42
-----------------------------------------------
================================================================================
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Project Results
To provide projections of Project dispatch, operating profile, energy and
capacity revenues and volatility values, Pace explicitly modeled the Project as
a resource in the MAIN region. Specifically, the Project's heat rate efficiency,
delivered fuel costs, and variable operating costs were modeled to simulate the
facility operation and forecast facility dispatch and Project revenues. Pace's
findings are shown in Exhibit 2.
During the Contract Period, the Project's revenue forecast refers to the
revenues that Exelon and/or Aquila are forecast to receive from marketing the
energy and capacity of the Exelon and Aquila Units, while the revenues that
Elwood receives during the Contract Period are determined by the payment
structure outlined in the Exelon and Aquila PSAs. However, during the Merchant
Period, where Elwood operates the Project as a merchant facility, the revenue
forecast refers to the revenues to be received by Elwood from marketing the
energy and capacity of the Project for its own account.
Exhibit 2 provides a summary of the Project's operational results, including
revenues both with and without the volatility values available to the Project.
The gross margins presented in Exhibit 2 reflect both energy and capacity
revenues and volatility values.
The following occurs during the Study Period:
o The average capacity factor for the Project is 11.93% per year.
o Generation for the Project is forecast to average 1,472 GWh per
year.
o Project energy and capacity revenues average $95.12/MWh or $134.3
million per year.
o Project volatility values average $20.33/kW-year or $28.6 million
per year.
o Total Project revenues average $163.0 million per year.
o Gross margins, including volatility values, average $82.93/kW-year.
o Gross margins, including volatility values, range from a maximum of
$104.30/kW-year in 2001 to a minimum of $76.82/kW-year in 2009.
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Exhibit 2: Project Annual Operational Summary - (1998 $)
================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
Energy Energy Volatility Total Gross Gross
Variable and and Value Revenue Margin Margin
Fuel O&M Capacity Capacity Net of with with with
Capacity Generation Capacity Costs Costs Revenue(7) Revenue Insurance(8) Volatility Volatility Volatility
Year MW(6) GWh Factor $1000 $1000 $1000 $/MWh $1000 $1000 $1000 $/kW-yr
- ------------------------------------------------------------------------------------------------------------------------------------
2001 1,409 998 8.08% 54,280 1,051 163,889 164.29 38,395 202,284 146,953 104.30
- ------------------------------------------------------------------------------------------------------------------------------------
2002 1,409 1,128 9.14% 47,074 1,178 149,044 132.11 33,573 182,617 134,365 95.36
- ------------------------------------------------------------------------------------------------------------------------------------
2003 1,409 958 7.76% 34,249 1,002 124,283 129.79 27,016 151,299 116,048 82.36
- ------------------------------------------------------------------------------------------------------------------------------------
2004 1,409 937 7.59% 30,717 994 116,752 124.62 23,821 140,573 108,862 77.26
- ------------------------------------------------------------------------------------------------------------------------------------
2005 1,409 1,299 10.53% 40,005 1,372 126,574 97.44 26,794 153,368 111,991 79.48
- ------------------------------------------------------------------------------------------------------------------------------------
2006 1,409 1,320 10.69% 38,444 1,403 125,353 95.00 28,480 153,833 113,986 80.90
- ------------------------------------------------------------------------------------------------------------------------------------
2007 1,409 1,336 10.83% 37,480 1,401 121,027 90.56 26,324 147,351 108,470 76.98
- ------------------------------------------------------------------------------------------------------------------------------------
2008 1,409 1,415 11.47% 39,111 1,492 124,951 88.28 25,885 150,836 110,233 78.23
- ------------------------------------------------------------------------------------------------------------------------------------
2009 1,409 1,380 11.18% 38,039 1,458 121,222 87.85 26,512 147,734 108,237 76.82
- ------------------------------------------------------------------------------------------------------------------------------------
2010 1,409 1,239 10.04% 34,089 1,317 121,381 97.99 25,830 147,211 111,805 79.35
- ------------------------------------------------------------------------------------------------------------------------------------
2011 1,409 1,026 8.31% 28,433 1,088 123,981 120.86 26,332 150,313 120,792 85.73
- ------------------------------------------------------------------------------------------------------------------------------------
2012 1,409 1,199 9.72% 33,192 1,281 122,973 102.58 26,723 149,696 115,223 81.78
- ------------------------------------------------------------------------------------------------------------------------------------
2013 1,409 1,722 13.96% 46,716 3,646 137,201 79.65 27,040 164,241 113,879 80.82
- ------------------------------------------------------------------------------------------------------------------------------------
2014 1,409 1,736 14.07% 47,452 3,729 137,848 79.41 28,325 166,173 114,992 81.61
- ------------------------------------------------------------------------------------------------------------------------------------
2015 1,409 1,886 15.29% 51,575 4,177 142,151 75.36 30,302 172,453 116,701 82.83
- ------------------------------------------------------------------------------------------------------------------------------------
2016 1,409 1,582 12.82% 43,299 3,498 131,597 83.17 26,911 158,508 111,711 79.28
- ------------------------------------------------------------------------------------------------------------------------------------
2017 1,409 1,866 15.13% 51,564 4,115 143,260 76.76 29,695 172,955 117,276 83.23
- ------------------------------------------------------------------------------------------------------------------------------------
2018 1,409 1,827 14.81% 50,683 4,059 141,442 77.40 30,951 172,393 117,651 83.50
- ------------------------------------------------------------------------------------------------------------------------------------
2019 1,409 2,018 16.36% 56,171 4,307 147,416 73.05 31,661 179,077 118,599 84.17
- ------------------------------------------------------------------------------------------------------------------------------------
2020 1,409 1,688 13.68% 46,981 3,776 138,848 82.26 28,579 167,427 116,670 82.80
- ------------------------------------------------------------------------------------------------------------------------------------
2021 1,409 1,700 13.78% 47,779 3,912 136,959 80.56 30,513 167,472 115,781 82.17
- ------------------------------------------------------------------------------------------------------------------------------------
2022 1,409 1,629 13.20% 45,637 4,795 135,749 83.33 28,039 163,788 113,356 80.45
- ------------------------------------------------------------------------------------------------------------------------------------
2023 1,409 1,549 12.55% 43,112 5,420 134,406 86.79 27,850 162,256 113,724 80.71
- ------------------------------------------------------------------------------------------------------------------------------------
2024 1,409 1,524 12.35% 42,648 5,335 140,078 91.90 29,296 169,374 121,391 86.15
- ------------------------------------------------------------------------------------------------------------------------------------
2025 1,409 1,564 12.67% 44,300 5,472 138,129 88.34 28,540 166,669 116,897 82.96
- ------------------------------------------------------------------------------------------------------------------------------------
2026 1,409 1,740 14.10% 49,451 6,090 145,896 83.85 31,099 176,995 121,454 86.20
- ------------------------------------------------------------------------------------------------------------------------------------
Avg. 1,409 1,472 11.93% 43,172 2,976 134,323 95.12 28,634 162,958 116,809 82.93
- ------------------------------------------------------------------------------------------------------------------------------------
================================================================================
Project Volatility Value
The volatility valuation for the Project is a projection of incremental revenues
that can be achieved by the Project beyond the CEMAS-forecasted spot market
revenues included in the Base Case results. This value measures the potential
value of the variation of the projected spark spread as a result of fluctuations
in underlying power and fuel prices during the hours Pace has forecast that the
Project will be dispatched.
To forecast such volatility revenue, Pace conducted a detailed evaluation of the
potential volatility of the Project. The results of this valuation are presented
annually and monthly in Exhibit 3 and Exhibit 4 respectively.
Exelon and Aquila own the exclusive right to dispatch and receive the output of
the Project during the Contract Period and will therefore have the right to
leverage the volatility value of the
- ----------
6 Summer Capacity.
7 Reflects energy and capacity revenues to Exelon and Aquila during the Contract
Period and to Elwood during the Merchant Period.
8 Reflects net volatility revenues to Exelon and Aquila during the Contract
Period and to Elwood during the Merchant Period.
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Project during this period. During the Merchant Period, the Elwood will be able
to leverage the Project's volatility value or will have it available for sale to
others.
As illustrated in Exhibit 3, Pace concludes that given Pace's assumptions
concerning market reserve margins, liquidity, and trading volatility, volatility
value (net of insurance costs) adds on average approximately $20.33/kW-year or
$28.6 million per year to Base Case revenues over the Study Period. Volatility
value ranges from a maximum of $27.26/kW-year or $38.4 million in 2001 to a
minimum of $16.91/kW-year or $23.8 million in 2004. The high projected
volatility values in 2001 are driven by the high natural gas prices. As natural
gas and thus power prices decrease from 2002 to 2004, so do the levels of
projected spark spread and derived volatility values. After projected natural
gas prices stabilize in the 2008-2009 timeframe, decreasing regional reserve
margins and the resulting increase in implied volatility forecasts become the
major value drivers. Thereafter, the projected Project volatility value is
relatively steady in a range of $18/kW-year to $22/kW-year through the end of
the valuation horizon.
During the term of the Exelon and Aquila PSAs, Exelon is forecast to extract net
volatility values which average $15.85/kW-year or $12.4 million per year, while
Aquila is forecast to earn net volatility values which average $23.92/kW-year or
$14.7 million per year. During the Merchant Period, Elwood is forecast to earn
net volatility values which average $20.73/kW-year or $ 29.2 million per year.
The forecast monthly Project net volatility values outlined in Exhibit 4
illustrate that, five out of the top seven monthly volatility values occur
during the June to October period, with the months of January and March
accounting for the next highest values. Volatility values are forecast to be the
highest in the month of July. This value is four times higher than the next
highest monthly volatility value, which occurs in the month of January.
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Exhibit 3: Project Annual Volatility Value (1998 $)
================================================================================
-------------------------------------------------------------------
Volatility Volatility
Volatility Insurance Value Value
Value Estimate Net of Insurance Net of Insurance
Year $/kW-yr $/kW-yr $/kW-yr $1000
-------------------------------------------------------------------
2001 29.49 2.23 27.26 38,395
-------------------------------------------------------------------
2002 25.79 1.96 23.84 33,573
-------------------------------------------------------------------
2003 20.78 1.60 19.18 27,016
-------------------------------------------------------------------
2004 18.36 1.45 16.91 23,821
-------------------------------------------------------------------
2005 20.50 1.48 19.02 26,794
-------------------------------------------------------------------
2006 21.77 1.55 20.22 28,480
-------------------------------------------------------------------
2007 20.17 1.48 18.69 26,324
-------------------------------------------------------------------
2008 19.85 1.47 18.38 25,885
-------------------------------------------------------------------
2009 20.31 1.49 18.82 26,512
-------------------------------------------------------------------
2010 19.84 1.50 18.34 25,830
-------------------------------------------------------------------
2011 20.29 1.60 18.70 26,332
-------------------------------------------------------------------
2012 20.53 1.55 18.97 26,723
-------------------------------------------------------------------
2013 20.75 1.55 19.20 27,040
-------------------------------------------------------------------
2014 21.70 1.59 20.11 28,325
-------------------------------------------------------------------
2015 23.18 1.66 21.51 30,302
-------------------------------------------------------------------
2016 20.68 1.57 19.11 26,911
-------------------------------------------------------------------
2017 22.74 1.66 21.08 29,695
-------------------------------------------------------------------
2018 23.67 1.69 21.97 30,951
-------------------------------------------------------------------
2019 24.20 1.72 22.48 31,661
-------------------------------------------------------------------
2020 21.95 1.66 20.29 28,579
-------------------------------------------------------------------
2021 23.36 1.69 21.66 30,513
-------------------------------------------------------------------
2022 21.53 1.63 19.91 28,039
-------------------------------------------------------------------
2023 21.39 1.62 19.77 27,850
-------------------------------------------------------------------
2024 22.52 1.72 20.80 29,296
-------------------------------------------------------------------
2025 21.83 1.57 20.26 28,540
-------------------------------------------------------------------
2026 23.85 1.77 22.08 31,099
-------------------------------------------------------------------
Avg. 21.96 1.63 20.33 28,634
-------------------------------------------------------------------
================================================================================
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Exhibit 4: Project Monthly Volatility Value - Net of Insurance (1998 $)
================================================================================
- --------------------------------------------------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total
Year $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000
- --------------------------------------------------------------------------------------------------------------------------
2001 1,685 1,054 3,389 957 1,528 3,241 14,506 4,907 1,689 4,747 691 -- 38,395
- --------------------------------------------------------------------------------------------------------------------------
2002 1,836 1,473 506 785 623 2,105 17,134 1,352 2,603 2,353 1,754 1,049 33,573
- --------------------------------------------------------------------------------------------------------------------------
2003 814 905 1,627 1,908 759 962 11,009 1,316 4,949 2,594 -- 172 27,016
- --------------------------------------------------------------------------------------------------------------------------
2004 555 367 722 86 1,769 2,782 13,295 628 1,438 1,784 46 348 23,821
- --------------------------------------------------------------------------------------------------------------------------
2005 1,283 244 2,148 582 1,402 2,423 11,211 1,980 3,555 904 251 812 26,794
- --------------------------------------------------------------------------------------------------------------------------
2006 1,190 1,611 1,048 779 1,733 1,952 8,841 4,868 1,992 2,427 1,645 394 28,480
- --------------------------------------------------------------------------------------------------------------------------
2007 938 1,004 1,887 260 852 2,085 8,854 3,272 3,166 1,684 441 1,882 26,324
- --------------------------------------------------------------------------------------------------------------------------
2008 873 1,093 1,151 1,018 497 2,515 10,590 2,278 1,189 1,313 851 2,518 25,885
- --------------------------------------------------------------------------------------------------------------------------
2009 1,455 1,490 1,854 594 659 1,626 10,335 1,518 2,713 1,761 763 1,745 26,512
- --------------------------------------------------------------------------------------------------------------------------
2010 831 1,442 1,738 191 349 1,470 11,479 1,197 3,443 1,765 1,139 787 25,830
- --------------------------------------------------------------------------------------------------------------------------
2011 292 1,541 2,555 -- 350 715 12,967 2,731 153 1,458 1,136 2,435 26,332
- --------------------------------------------------------------------------------------------------------------------------
2012 1,090 992 606 2,936 273 1,066 9,751 3,080 2,817 1,374 931 1,808 26,723
- --------------------------------------------------------------------------------------------------------------------------
2013 3,910 1,430 1,598 255 -- 1,743 8,461 1,272 3,085 3,244 253 1,788 27,040
- --------------------------------------------------------------------------------------------------------------------------
2014 4,866 332 1,569 1,519 42 1,907 8,997 1,784 2,676 1,651 1,151 1,832 28,325
- --------------------------------------------------------------------------------------------------------------------------
2015 2,948 3,060 4,313 338 18 1,851 8,894 775 2,478 2,337 1,487 1,805 30,302
- --------------------------------------------------------------------------------------------------------------------------
2016 3,073 2,271 1,790 348 50 1,534 10,399 2,355 1,094 2,454 435 1,109 26,911
- --------------------------------------------------------------------------------------------------------------------------
2017 3,903 2,565 3,311 123 886 1,734 7,348 3,094 1,825 2,610 452 1,844 29,695
- --------------------------------------------------------------------------------------------------------------------------
2018 5,158 2,111 2,869 -- 74 2,210 6,531 1,573 1,882 5,211 1,841 1,491 30,951
- --------------------------------------------------------------------------------------------------------------------------
2019 3,164 1,334 3,262 635 1,465 1,831 6,997 1,518 3,827 3,857 1,057 2,714 31,661
- --------------------------------------------------------------------------------------------------------------------------
2020 3,131 2,688 2,478 222 285 2,286 10,639 1,290 2,614 1,822 710 413 28,579
- --------------------------------------------------------------------------------------------------------------------------
2021 3,506 2,122 3,104 1,872 420 2,159 8,680 1,021 2,109 2,853 1,347 1,320 30,513
- --------------------------------------------------------------------------------------------------------------------------
2022 3,136 1,175 2,603 1,081 91 2,392 9,454 1,766 850 2,607 939 1,946 28,039
- --------------------------------------------------------------------------------------------------------------------------
2023 4,052 3,057 2,126 -- 122 1,906 7,037 2,543 1,845 2,767 582 1,814 27,850
- --------------------------------------------------------------------------------------------------------------------------
2024 3,121 1,024 2,294 28 621 2,029 10,854 1,107 2,550 3,876 142 1,652 29,296
- --------------------------------------------------------------------------------------------------------------------------
2025 4,103 739 2,800 200 249 1,978 9,425 1,018 2,452 1,304 491 3,780 28,540
- --------------------------------------------------------------------------------------------------------------------------
2026 4,605 3,470 1,255 848 316 1,761 7,957 1,319 2,685 3,492 1,010 2,381 31,099
- --------------------------------------------------------------------------------------------------------------------------
Avg. 2,520 1,561 2,100 764 617 1,933 10,063 1,983 2,372 2,471 862 1,594 28,634
- --------------------------------------------------------------------------------------------------------------------------
================================================================================
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Proprietary & Confidential 12
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ASSUMPTIONS
Key assumptions underlying the Base Case 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. The Base Case assumptions were developed by Pace to bracket the
most probable and conservative need for new capacity and market pricing
available to the Project. Exhibit 5 summarizes the major assumption variables
underlying Pace's Base Case forecast.
Qualitatively, Pace's assumptions are conservative in a number of areas as
summarized below:
Load Growth
Market area demand is a key determinant to market pricing and new capacity
development requirements. In determining peak demand and total energy demand
that the Project could serve, Pace endeavored to provide conservative forecasts
of total energy demand, as well as system peak demand assuming the following:
o Incremental demand from short power markets such as ECAR has been
largely excluded from Pace's valuation. Consequently, incremental
market demand attributable to the ECAR market that could add
incremental dispatch or cause higher market prices was not
incorporated in the analysis.
o Demand-side management is included in Pace's peak demand forecast to
levelize system load factor. Pace assumed that demand-side
management programs would effectively reduce peak demand growth in
the future thereby lowering market prices during peak periods.
o The combination of Pace's overall load forecasting methodology, plus
our exclusion of incremental market demand and demand-side
management, provides a conservative demand forecast. In this way,
Pace's market prices, dispatch forecasts and expansion requirements
will have the highest probability to occur under most scenarios over
the next twenty-five years considering variations in weather, load
shape, and economic growth.
Expansion Units and Existing Unit Capacity
Just as demand is a major determinant of market pricing and expansion
requirements, available market supply assumptions and pricing will determine
market pricing fundamentals and addition timing. Again, to create a highly
probable Base Case forecast of Project dispatch, the following was assumed:
o Expansion unit capital costs are at a discount over the Study Period
compared to achievable new build costs today; the analysis assumed
no real price increases over time. Therefore, market prices, which
will be driven by expansion unit costs, have an
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embedded assumption that new units will have a lower cost to build
than units currently being constructed. This assumption is made
despite current trends in plant costs and site availability, which
have been forcing new plant costs higher over time. This assumption
has the impact of lowering market prices by 10%. Pace uses this
conservative assumption to take into account the possibility of
technology or productivity improvements.
o No retirements of existing capacity (other than nuclear units at
license expiration) were simulated despite economics or emissions
costs. While Pace expects some level of existing unit retirements
over the next twenty years, it is highly subjective to determine the
exact units or the timing of these retirements. Additionally, not
all units will achieve better performance or improve as rapidly as
Pace assumed. Again, by assuming no retirements and immediate unit
performance improvement, Pace creates a highly probable Base Case
scenario of the Project's dispatch and revenues over the long-term.
o Existing unit availability and resultant capacity factors are
assumed higher than historical values.
o No quick start capability credit was given to the Project, which
removes its real competitive advantage relative to other units in
the system (i.e., peaking capacity can start very quickly in
response to load changes while other capacity may take 4-6 hours for
start procedures). In most real world situations, peaking capacity
will have a dispatch preference. Therefore, dispatch is purely on
economics and will be lower than what could be expected under actual
operating conditions.
o Pace's methodology assumes a near perfect equilibrium condition for
market pricing and expansion unit additions. Therefore, the maximum
level of new base load and peaking units are installed in the system
at all times throughout the Study Period. This approach creates a
lower level of revenues for the Project, as well as minimizes the
dispatch given the "perfect" amount and mix of capacity in the
market.
o Pace's assumption for new unit heat rates and the Project's heat
rate, as provided by Stone & Webster, place the Project at a slight
competitive disadvantage, assuming a precise dispatch queue based on
these heat rates, and result in a lower level of dispatch relative
to new peaking units. Realistically, new units will only be slightly
more efficient than the Project and market conditions will not be as
precise as a model result of dispatch. Consequently, actual market
based dispatch will most likely exceed projections by 5-7% on
average given Pace's Base Case assumptions.
Taken together, these assumptions provide a conservative forecast of the
Project's dispatch and resulting economics. Therefore, while the dispatch and
revenues of peaking capacity can be highly volatile from year to year, Pace has
removed most of the low side volatility through our modeling assumptions. These
considerations provide a high level of probability that Pace's Base Case
forecast is likely to be more of a downside case when compared with actual
Project results.
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Exhibit 5: Key Assumptions - Base Case
================================================================================
- --------------------------------------------------------------------------------------
Base Case
- --------------------------------------------------------------------------------------
Long Run Equilibrium Reserve Margin 13-15%
- --------------------------------------------------------------------------------------
Load Growth
- --------------------------------------------------------------------------------------
Average Energy Demand 1.47% per year
- --------------------------------------------------------------------------------------
Expansion Unit Costs (MAIN-NI)*
- --------------------------------------------------------------------------------------
CT - Installed Costs $410/kW
- --------------------------------------------------------------------------------------
CC F Class - Installed Costs $606/kW
- --------------------------------------------------------------------------------------
CC G Class - Installed Costs $619/kW
- --------------------------------------------------------------------------------------
CT - Efficiency Winter: 10,400 Btu/kWh (2001-2026)
Summer: 10,600 Btu/kWh (2001-2026)
- --------------------------------------------------------------------------------------
CC F Class - Efficiency 7,050 Btu/kWh (2001)
- --------------------------------------------------------------------------------------
CC G Class - Efficiency 6,850 Btu/kWh (2005)
- --------------------------------------------------------------------------------------
Existing Unit Costs
- --------------------------------------------------------------------------------------
Fixed Capital Costs Current Book Value
- --------------------------------------------------------------------------------------
Fixed & Variable O&M Current Derived Cost / 0% real escalation
- --------------------------------------------------------------------------------------
Base load Capacity No retirement of existing coal units.
Retirement of existing nuclear units
on their license expiration.
- --------------------------------------------------------------------------------------
Annual Fuel Cost Escalation Rates (Real)
- --------------------------------------------------------------------------------------
Natural Gas 0.5% - after 2009
- --------------------------------------------------------------------------------------
Fuel Oil (No. 6 and No. 2) 0.0% - after 2005
- --------------------------------------------------------------------------------------
Coal (varies annually)
Low Sulfur 0.80%
Medium Sulfur -0.21%
High Sulfur -1.43%
PRB Sub-bituminous 0.75%
- --------------------------------------------------------------------------------------
Uranium 0.0%
- --------------------------------------------------------------------------------------
Macroeconomic
- --------------------------------------------------------------------------------------
Standard Interest Rate 8.5%
- --------------------------------------------------------------------------------------
Standard Return on Equity (after-tax) 15%
- --------------------------------------------------------------------------------------
* Due to regional variations in land values, labor costs, property taxes and
other potential cost adders, regional cost adjustments are applied.
================================================================================
Pace believes that the assumptions presented above are conservative estimates of
the future range of variables that yield a highly probable Base Case market
price estimate.
OUTLINE OF REPORT
The remainder of this report is organized into the following seven sections:
o Market Clearing Price Forecast Approach provides a detailed
description of Pace's approach to forecasting electricity prices in
a competitive market.
o MAIN Market Pricing Forecast Results provides detailed market
clearing price results.
o Volatility Analysis Approach and Results provides a forecast of
additional revenues intrinsic to the Project.
o Market Area Definition and Transmission provides support for the
selection of the market area and the transmission transfer
capability.
o Electricity Demand In MAIN provides demand growth expectations for
the market area.
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o MAIN Power Generation Resources reviews existing generation
resources and details expansion unit assumptions.
o Fuel Pricing provides fuel pricing and escalation expectations.
o Appendix A - Sensitivities provides details of the High Gas Case,
Overbuild Case and Aquila PSA Extension Case Sensitivities.
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Proprietary & Confidential 16
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================================================================================
MARKET CLEARING PRICE FORECAST APPROACH
================================================================================
Pace's market clearing price forecast methodology consists of multiple,
interrelated analytical processes. 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 underlying:
o Pace's CEMAS simulation model;
o Pace's basis for determining the market price equilibrium in a
competitive power market; and
o The MAIN power market fundamentals.
APPROACH
Pace conducted a detailed analysis of the MAIN market clearing prices. This
analysis provides in-depth insight into the fundamentals of MAIN and the
emerging competitive market. The analysis was based on Pace's competitive market
vision of a "one-price" market for both capacity and energy. A description of
Pace's approach to this analysis is described below.
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 6, Pace's CEMAS simulation model 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 Bidding 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 determines the peak period
prices that will provide an equilibrium dispatch and pricing
solution and transfers this information to the Market Clearing Price
Module.
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4. Hourly Load Module: The Hourly Load Module aggregates actual utility
hourly loads as reported to the Federal Energy Regulatory Commission
("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 resource-specific
variable costs 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 variable costs and availability.
Peak period prices generated by the Bidding Analysis Module are
integrated into the price forecast to determine market prices under
equilibrium conditions. The Market Clearing Price Module uses a
utility grade dispatch model to model the hourly system constraints
of a regional power pool, optimizing least cost generation choices
to match demand fluctuations.
Exhibit 6: Pace CEMAS Methodology
================================================================================
- --------------------------------------------------------------------------------
Planned Debt & Existing Unit Income Historical
Additions Equity Characteristics Growth Load Escalation
| | | Statistics Files Factors
------------------------ | | |
| ----------------------
V |
------------------ |
Revenue -
Requirement Module |
------------------ |
| |
------------------ | V
Unit Fuel Pricing | -------- ------
Module | Bidding Hourly
------------------ - ----->Analysis Load
Module Module
| -------- ------
| | |
------------------ ------------------------
| | |
Historical Fuel Escalation ---------------
Pricing Factors Market Clearing Maintenance
Price Module [-- Schedules and
--------------- Units Available
for Dispatch
- --------------------------------------------------------------------------------
================================================================================
CEMAS was designed based on 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. Pace has sought with CEMAS to integrate these components into a system
capable of accurately projecting market clearing prices in a competitive market.
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EQUILIBRIUM PRICING OF EXPANSION CAPACITY
While at any time, given the actual supply/demand balance in the market,
generators can adopt various bidding strategies to increase their market
revenues, Exhibit 7 presents Pace's basis for determining the 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 capacity until they drive the market price down to minimum return
levels. Conversely, if market prices are below the cost of expansion units, no
new generators will be built until market prices rise to support their
construction.
Given the foregoing, Exhibit 7 provides a theoretical market pricing formula
consisting of new combined cycle ("CC") and combustion-turbine ("CT") units.
Exhibit 7 provides a comparison of the all-in cost (i.e. fixed and variable
costs) of expansion units operating at various capacity factors for 2003. For
example, at a 20% capacity factor, the all-in cost of CC and CT units would be
$77.55/MWh and $71.05/MWh, respectively. Further, if a unit were needed to
supply power 20% of the time, a CT would be selected due to its lower all-in
costs. However, if a unit were expected to run 50% of the time as base load
capacity, a CC unit would be more economical.
With these assumptions, Exhibit 7 shows that, except at dispatch of 4% or lower,
all generators can bid to their variable cost and still achieve their minimum
revenue requirement. Further, the Exhibit also shows that between 30%-35% load
factor a break-even point exists where CC capacity becomes the more economic
capacity.
Average Market Price, determined by the average of all incremental prices,
provides the theoretical price cap. Specifically, where current pricing levels
rise above our theoretical curve, new capacity installations are signaled until
the market price comes to rest back at the equilibrium point. For example, if
the market price is $43.00/MWh for an average of 70% of the year, a new CC can
be built and dispatched at that level for only $40.18/MWh. Therefore, a
developer would seek to exploit this profit opportunity by entering the market
and building new capacity.
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Exhibit 7: Equilibrium Market Prices Based on Expansion Unit Costs - 2003
================================================================================
- --------------------------------------------------------------------------------
Dispatch Incremental Avg. Market
Factor/System CC All-In $/MWh CT All-In $/MWh Market Price Price $/MWh
Load Factor % $/MWh
- --------------------------------------------------------------------------------
5 234.52 169.82 38.13 169.82
- --------------------------------------------------------------------------------
10 129.87 103.98 38.13 103.98
- --------------------------------------------------------------------------------
15 94.99 82.03 38.13 82.03
- --------------------------------------------------------------------------------
20 77.55 71.05 38.13 71.05
- --------------------------------------------------------------------------------
25 67.09 64.47 38.13 64.47
- --------------------------------------------------------------------------------
30 60.11 60.08 38.13 60.08
- --------------------------------------------------------------------------------
35 55.13 56.94 25.22 55.13
- --------------------------------------------------------------------------------
40 51.39 54.59 25.23 51.39
- --------------------------------------------------------------------------------
45 48.48 52.76 25.23 48.48
- --------------------------------------------------------------------------------
50 46.16 51.30 25.23 46.16
- --------------------------------------------------------------------------------
55 44.25 50.10 25.23 44.25
- --------------------------------------------------------------------------------
60 42.67 49.11 25.23 42.67
- --------------------------------------------------------------------------------
65 41.33 48.26 25.23 41.33
- --------------------------------------------------------------------------------
70 40.18 47.54 25.23 40.18
- --------------------------------------------------------------------------------
75 39.18 46.91 25.23 39.18
- --------------------------------------------------------------------------------
80 38.31 46.36 25.23 38.31
- --------------------------------------------------------------------------------
85 37.54 45.88 25.23 37.54
- --------------------------------------------------------------------------------
90 36.85 45.45 25.23 36.85
- --------------------------------------------------------------------------------
95 36.24 45.06 25.23 36.24
- --------------------------------------------------------------------------------
100 35.69 44.72 25.23 35.69
- --------------------------------------------------------------------------------
Pricing Assumptions
-----------------------------------------------------------
Unit Type CC CT
-----------------------------------------------------------
Heat Rate Btu/kWh(9) 7,050 10,400
-----------------------------------------------------------
Variable O&M $/MWh 1.75 3.50
-----------------------------------------------------------
Fuel Cost for Year $/MMBtu 3.33 3.33
-----------------------------------------------------------
Fixed Cost ($) 24,293,000 9,805,433
-----------------------------------------------------------
Capacity MW 265 170
-----------------------------------------------------------
Variable Cost $/MWh 25.23 38.13
-----------------------------------------------------------
Fixed Cost @100% Load Factor $/MWh 10.46 6.58
-----------------------------------------------------------
================================================================================
Based on the results of this analysis, prices defined by the costs of building
and operating new CT, CC, and coal generators place a theoretical cap on power
prices. Consequently, Pace's analysis model is based on the assumption of
bidding strategies and capacity additions to achieve a market pricing level to
within 5% from this equilibrium point.
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. 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 within 5% of expansion capacity recovery
targets.
Exhibit 8 presents the system supply curve for the MAIN market(10) for 2005 and
2023. These periods where chosen to provide an illustration of the Project
during the Contract and Merchant Periods, respectively. These supply curves have
not been adjusted to account for the availability
- ----------
9 Winter heat rate.
10 Includes interconnected sub-regions of IOWA and OECAR.
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of regional capacity. Realistically, the available generating capacity supply
changes constantly with plants down for planned maintenance on an on-going
basis. Further, supply curves are based on the variable costs of production
only, and do not include fixed costs or any implicit capacity payment. During
higher demand peak periods, prices include an implicit capacity payment that
enables necessary incremental capacity to recover its fixed costs.
Exhibit 8: MAIN System Supply Curve
================================================================================
2005 - Contract Period(11)
[GRAPH DISPLAYING THE FORECASTED SYSTEM
SUPPLY CURVE FOR THE MAIN MARKET
FOR 2005.]
- ----------
11 Includes interconnected sub-regions of IOWA and OECAR.
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2023 - Merchant Period(12)
GRAPH DISPLAYING THE FORECASTED
SYSTEM SUPPLY CURVE FOR THE
MAIN MARKET FOR 2023.
================================================================================
- ----------
12 Includes interconnected sub-regions of IOWA and OECAR.
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================================================================================
MAIN MARKET PRICING FORECAST RESULTS
================================================================================
Pace developed a long-term market price forecast for the MAIN region for the
Study Period. Pace's analysis utilized our proprietary 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. This section presents Pace's market price forecast results
for the MAIN electric system and the Project.
CEMAS SIMULATED MARKET PRICING RATES
Pace's Base Case market price forecast is 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 costs. The
Base Case represents system equilibrium 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 MAIN system and
optimized unit dispatch and bidding to identify the equilibrium market pricing
and price distribution.
MAIN System Market Pricing - Base Case
Exhibit 9 presents the peak, off-peak and average competitive market-clearing
prices in the Northern Illinois sub-region of MAIN for the Study Period. The
price results for the Base Case range from a maximum average price of $37.60/MWh
in 2001 and a minimum average price of $28.53/MWh in 2009. The price forecast
for MAIN-NI over the Study Period can be summarized as follows:
o Short-term high natural gas prices in the early years of the Study
Period result in market clearing prices reaching $37.60/MWh in 2001.
o A high level of competitive capacity additions and declining gas
prices between 2001 and 2009 lowers average annual prices from
$37.60/MWh in 2001 to $28.53/MWh in 2009.
o Throughout the remainder of the Study Period, rising demand growth
increases the amount of time during which natural gas is the
marginal price setter, particularly during off-peak periods. This
factor together with the increase in natural gas prices in real
terms, results in average market prices gradually increasing over
time.
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Exhibit 9: MAIN-NI Annual Price Summary - Base Case (1998 $/MWh)
================================================================================
-------------------------------------
Year Off-Peak On-Peak Average
$/MWh $/MWh(13) $/MWh
-------------------------------------
2001 26.98 49.28 37.60
-------------------------------------
2002 24.33 45.40 34.37
-------------------------------------
2003 22.34 40.87 31.16
-------------------------------------
2004 20.96 39.44 29.76
-------------------------------------
2005 20.94 39.06 29.57
-------------------------------------
2006 20.18 39.12 29.20
-------------------------------------
2007 20.13 38.15 28.71
-------------------------------------
2008 20.71 37.90 28.89
-------------------------------------
2009 20.30 37.59 28.53
-------------------------------------
2010 21.04 38.16 29.19
-------------------------------------
2011 20.71 39.73 29.76
-------------------------------------
2012 21.29 38.69 29.58
-------------------------------------
2013 21.48 38.51 29.59
-------------------------------------
2014 21.67 38.36 29.62
-------------------------------------
2015 21.81 38.93 29.96
-------------------------------------
2016 21.48 38.66 29.66
-------------------------------------
2017 21.97 39.09 30.13
-------------------------------------
2018 21.91 39.14 30.11
-------------------------------------
2019 22.45 39.10 30.38
-------------------------------------
2020 22.28 39.23 30.35
-------------------------------------
2021 22.08 38.74 30.01
-------------------------------------
2022 22.56 38.84 30.31
-------------------------------------
2023 22.60 39.16 30.49
-------------------------------------
2024 22.91 40.16 31.13
-------------------------------------
2025 23.13 39.80 31.07
-------------------------------------
2026 23.67 40.53 31.70
-------------------------------------
Avg. 22.00 39.68 30.42
-------------------------------------
================================================================================
Announced and Forecasted System Capacity Additions
As merchant plant developers become the typical source of new capacity in the
U.S. power market, and utilities divest their generating assets, an integrated
planning process for capacity additions will no longer take place. Currently,
and more so in the future, the marketplace will be relied upon to value and
provide needed capacity.
Consistent with the market approach to capacity additions, Pace conducted its
forecast of market prices under a scenario that considers publicly announced
project development activities in addition to theoretical capacity additions in
response to market conditions. Exhibit 10 lists the announced merchant plant
development projects in the MAIN power market that Pace included in the Base
Case Forecast. Pace believes that as much as 14,097 MW of announced capacity has
strong potential of reaching commercial operation in this short time period.
- ----------
13 Peak Period defined as a 16-hour period for each weekday.
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Exhibit 10: Base Case Announced Capacity Additions (MW)
================================================================================
- -------------------------------------------------------------------------------------------------------
UNIT IN CAPACITY
COMPANY PROJECT NAME LOCATION TYPE SERVICE MW
- -------------------------------------------------------------------------------------------------------
Duke Energy St Francis
- - Assoc Electric Coop Duke St. Francis SMAIN GAS CT 1999 520
- -------------------------------------------------------------------------------------------------------
Elwood Energy LLC Elwood NI GAS CT 1999 600*
- -------------------------------------------------------------------------------------------------------
Wepco Fonddulac Wind WUM Wind Turbine 1999 1
- -------------------------------------------------------------------------------------------------------
Wepco Kewaunee Wind WUM Wind Turbine 1999 9
- -------------------------------------------------------------------------------------------------------
Ameren Corp. Joppa SMAIN GAS CT 2000 232
- -------------------------------------------------------------------------------------------------------
Ameren Corp. Meramec SMAIN GAS CT 2000 48
- -------------------------------------------------------------------------------------------------------
Calpine/ SkyGen DePere Phase I WUM GAS CT 2000 179
- -------------------------------------------------------------------------------------------------------
CILCO (AES) Lincoln SMAIN GAS CT 2000 13
- -------------------------------------------------------------------------------------------------------
Cogen Corp. of America Morris NI GAS CT 2000 60
- -------------------------------------------------------------------------------------------------------
Dynegy Rocky Road NI GAS CT 2000 250
- -------------------------------------------------------------------------------------------------------
Enron Lincoln Energy Center NI GAS CT 2000 668
- -------------------------------------------------------------------------------------------------------
Illinois Power Tilton Energy Center SMAIN GAS CT 2000 176
- -------------------------------------------------------------------------------------------------------
Illinova Power Marketing Havana Restart SMAIN ST 2000 238
- -------------------------------------------------------------------------------------------------------
Indeck Operations, Inc. Rockford NI GAS CT 2000 300
- -------------------------------------------------------------------------------------------------------
Madison Gas and Electric MGE WUM Wind Turbine 2000 11
- -------------------------------------------------------------------------------------------------------
Reliant Shelby SMAIN GAS CT 2000 340
- -------------------------------------------------------------------------------------------------------
Southern Energy Neenah Power Plant WUM GAS CT 2000 300
- -------------------------------------------------------------------------------------------------------
Southwestern Electric
Coop. St. Elmo SMAIN GAS CT 2000 45
- -------------------------------------------------------------------------------------------------------
Soyland Power Alsey SMAIN GAS CT 2000 113
- -------------------------------------------------------------------------------------------------------
Trigen- St. Louis
Entergy Corp. St. Louis Cogen SMAIN GAS CT 2000 15
- -------------------------------------------------------------------------------------------------------
Trigen-Cinergy Solutions Equistar SMAIN GAS CT 2000 6
- -------------------------------------------------------------------------------------------------------
Wepco Germantown Expansion WUM GAS CT 2000 135
- -------------------------------------------------------------------------------------------------------
WI Public Service W. Marionette WUM GAS CT 2000 83
- -------------------------------------------------------------------------------------------------------
Ameren Corp. Pinckneyville SMAIN GAS CT 2001 520
- -------------------------------------------------------------------------------------------------------
Ameren Corp. Gibson SMAIN GAS CT 2001 206
- -------------------------------------------------------------------------------------------------------
Ameren Energy
Generating Co. Grand Tower SMAIN GAS CC 2001 500
- -------------------------------------------------------------------------------------------------------
Calpine/ SkyGen RockGen Energy Center WUM GAS CT 2001 450
- -------------------------------------------------------------------------------------------------------
CILCO (AES) Medina Valley SMAIN GAS CC 2001 45
- -------------------------------------------------------------------------------------------------------
Constellation Power University Park LLC NI GAS CT 2001 300
- -------------------------------------------------------------------------------------------------------
Duke Energy Lee, LLC Lee Generating Station NI GAS CT 2001 640
- -------------------------------------------------------------------------------------------------------
Elwood Energy LLC Elwood NI GAS CT 2001 750*
- -------------------------------------------------------------------------------------------------------
FPL Energy Iowa County Wisconsin Wind Farm WUM Wind Turbine 2001 26
- -------------------------------------------------------------------------------------------------------
LS Power Kendall NI GAS CC 2001 1,100
- -------------------------------------------------------------------------------------------------------
MidAmerican Cordova NI GAS CC 2001 537
- -------------------------------------------------------------------------------------------------------
NRG Energy Audrain SMAIN GAS CT 2001 720
- -------------------------------------------------------------------------------------------------------
Reliant Energy Power
Generation Inc. Reliant Energy Aurora LP NI GAS CT 2001 270
- -------------------------------------------------------------------------------------------------------
University of Missouri University of Missouri-Columbia SMAIN GAS CT 2001 26
- -------------------------------------------------------------------------------------------------------
Ameren Corp. Patoka/ Kinmundy Power Plant SMAIN GAS CT 2002 332
- -------------------------------------------------------------------------------------------------------
Dynegy Rocky Road Expansion NI GAS CT 2002 100
- -------------------------------------------------------------------------------------------------------
Holland Energy LLC Holland Energy SMAIN GAS CC 2002 680
- -------------------------------------------------------------------------------------------------------
Wisvest Calumet Energy Project NI GAS CT 2002 315
- -------------------------------------------------------------------------------------------------------
NRG Energy, Inc. Nelson NI GAS CC 2003 1,188
- -------------------------------------------------------------------------------------------------------
PG&E Corp. BadgerGen WUM GAS CC 2003 1,050
- -------------------------------------------------------------------------------------------------------
TOTAL 14,097
- -------------------------------------------------------------------------------------------------------
================================================================================
After 2003, Pace expects that further merchant projects will be announced and
built as needed to meet demand. Market price expectations and developer growth
strategies will drive these new project additions. Pace's methodology for
determining these competitive market expansions is detailed in the MAIN Power
Generation Resources Section. However, Exhibit 11 summarizes
- ----------
* Nominal Capacity.
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Proprietary & Confidential 25
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the annual additions resulting from both current announced merchant projects and
expansion plants, supported by the expected market prices over time.
As shown in Exhibit 11, Pace expects that over the next twenty-five years the
MAIN market will require and support the construction of approximately 43,000 MW
of new capacity in order to maintain a long run equilibrium reserve margin of
13-15%. Pace did not assume the retirement of existing system capacity except
for nuclear units, which are retired on their license expiration. To the extent
existing units are retired over the Study Period, market prices will increase
and/or additional capacity will be constructed to replace retired capacity.
Exhibit 11: Expansion Capacity Additions by Year- Base Case
================================================================================
CHART SHOWING THE ESTIMATED
CAPACITY ADDITIONS IN THE MAIN
MARKET OVER THE NEXT 25 YEARS.
- -----------------------------------------------------------------------------------------------------------------------------
2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026
- -----------------------------------------------------------------------------------------------------------------------------
ELWOOD 1,409 1,409 1,409 1,409 1,409 1,409 1,409 1,409 1,409 1,409 1,409 1,409 1,409
- -----------------------------------------------------------------------------------------------------------------------------
Announced Coal & Wind 337 337 337 337 337 337 337 337 337 337 337 337 337
- -----------------------------------------------------------------------------------------------------------------------------
Announced CC 3,388 5,492 5,492 5,492 5,492 5,492 5,492 5,492 5,492 5,492 5,492 5,492 5,492
- -----------------------------------------------------------------------------------------------------------------------------
Announced CT 8,300 8,300 8,300 8,300 8,300 8,300 8,300 8,300 8,300 8,300 8,300 8,300 8,300
- -----------------------------------------------------------------------------------------------------------------------------
Expansion CC 0 0 249 1,743 3,984 5,976 7,719 8,466 10,458 12,450 13,944 15,936 17,181
- -----------------------------------------------------------------------------------------------------------------------------
Expansion CT 800 800 1,920 3,200 3,200 3,680 4,960 6,080 7,200 7,680 8,800 9,440 10,080
- -----------------------------------------------------------------------------------------------------------------------------
Total 14,234 16,338 17,707 20,481 22,722 25,194 28,217 30,084 33,196 35,668 38,282 40,914 42,799
- -----------------------------------------------------------------------------------------------------------------------------
* Includes interconnected sub-regions of IOWA and OECAR.
================================================================================
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Project Results - Base Case
To provide Pace's forecast of Project dispatch, operating profile, energy and
capacity revenues, and volatility values, Pace explicitly modeled the Project as
a resource in the MAIN market. Specifically, the Project's heat rate efficiency,
delivered fuel costs, and variable operating costs were modeled to allow the
simulation to dispatch the facility when system marginal costs were equal to or
higher than Project variable costs. The Project specifications, as modeled, are
provided in the MAIN Power Generation Resources Section of this report.
Exhibit 12 illustrates the operational results for the Project(14) while Exhibit
13, and Exhibit 14 outline the results for the Exelon PSA and the combined
results for the Aquila PSAs.
The summary results for the Project cover both the Contract Period and the
Merchant Periods. During the Contract Period, the results reflect the dispatch
of the Exelon and Aquila Units in accordance with the terms of the relevant PSA.
During the Merchant Period, the Project is assumed be dispatched as a fully
merchant facility (see Exhibit 48 for assumptions concerning each PSA and the
modeling assumptions for the Contract Period and the Merchant Period).
During the Contract Period, the Project's revenue forecast refers to the
revenues that Exelon and/or Aquila are forecast to receive from marketing the
energy and capacity of the Exelon and Aquila Units, while the revenues that
Elwood receives during the Contract Period are determined by the payment
structure outlined in the Exelon and Aquila PSAs. However, during the Merchant
Period, when Elwood operates the Project as a merchant facility, the revenue
forecast refers to the revenues to be received by Elwood from marketing the
energy and capacity of the Project on its own account.
The average annual capacity factor for the Project is 11.93% per year with gross
margins, including volatility values that range from a maximum of
$104.30/kW-year in 2001 to a minimum of $76.82/kW-year in 2009. The average
generation for the Project is forecast to be 1,472 GWh per year, with average
total revenues of $173.9 million per year. Energy and capacity revenues average
$95.12/MWh per year or $134.3 million per year and gross margins, including
volatility values average $82.93/KW-year.
Exhibit 13 illustrates the results for the Exelon PSA, which covers the dispatch
of Units 1-4 & 9 and terminates on December 31, 2012. The Exelon Units are
expected to be dispatched at an average capacity factor of 3.39% per year with
gross margins, including volatility values that range from a maximum of
$97.86/kW-year in 2001 to a minimum of $71.93/kW-year in 2009. The average
generation for the Exelon Units is forecast to be 233 GWh per year, with average
total revenues of $69.7 million per year. Energy and capacity revenues average
$256.20/MWh per year or $57.3 million per year and gross margins, including
volatility values average $78.63/kW-year.
- ----------
14 Project and Unit capacities refer to Summer Capacity.
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Exhibit 14 illustrates the results for the Aquila PSAs. The Aquila PSA 1, which
covers the dispatch of Units 5-6, terminates on August 31, 2021, while the
Aquila PSA 2, which covers the dispatch of Units 7-8, terminates one-year later
on August 31, 2022. In 2022, the summary results presented in Exhibit 14 exclude
Units 5-6, which are assumed to be operating on a merchant basis, but includes
Units 7-8 as these units remain under dispatch by Aquila.
Exhibit 14 illustrates an average annual capacity factor of 17.15% per year,
with gross margins, including volatility values, that range from a maximum of
$112.43/kW-year in 2001 to a minimum of $81.10/kW-year in 2004. Generation
averages 921 GWh per year, with average total revenues of $81.9 million per
year. Energy and capacity revenues average $74.07/MWh per year or $67.3 million
per year and gross margins, including volatility values average $87.22/kW-year.
Exhibit 12: Project Annual Operational Summary (1998 $)
================================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
Energy Energy Volatility Total Gross Gross
Variable and and Value Revenue Margin Margin
Fuel O&M Capacity Capacity Net of with with with
Capacity Generation Capacity Costs Costs Revenue(16) Revenue Insurance(17) Volatility Volatility Volatility
Year MW(15) GWh Factor $1000 $1000 $1000 $/MWh $1000 $1000 $1000 $/kW-yr
- ----------------------------------------------------------------------------------------------------------------------------------
2001 1,409 998 8.08% 54,280 1,051 163,889 164.29 38,395 202,284 146,953 104.30
- ----------------------------------------------------------------------------------------------------------------------------------
2002 1,409 1,128 9.14% 47,074 1,178 149,044 132.11 33,573 182,617 134,365 95.36
- ----------------------------------------------------------------------------------------------------------------------------------
2003 1,409 958 7.76% 34,249 1,002 124,283 129.79 27,016 151,299 116,048 82.36
- ----------------------------------------------------------------------------------------------------------------------------------
2004 1,409 937 7.59% 30,717 994 116,752 124.62 23,821 140,573 108,862 77.26
- ----------------------------------------------------------------------------------------------------------------------------------
2005 1,409 1,299 10.53% 40,005 1,372 126,574 97.44 26,794 153,368 111,991 79.48
- ----------------------------------------------------------------------------------------------------------------------------------
2006 1,409 1,320 10.69% 38,444 1,403 125,353 95.00 28,480 153,833 113,986 80.90
- ----------------------------------------------------------------------------------------------------------------------------------
2007 1,409 1,336 10.83% 37,480 1,401 121,027 90.56 26,324 147,351 108,470 76.98
- ----------------------------------------------------------------------------------------------------------------------------------
2008 1,409 1,415 11.47% 39,111 1,492 124,951 88.28 25,885 150,836 110,233 78.23
- ----------------------------------------------------------------------------------------------------------------------------------
2009 1,409 1,380 11.18% 38,039 1,458 121,222 87.85 26,512 147,734 108,237 76.82
- ----------------------------------------------------------------------------------------------------------------------------------
2010 1,409 1,239 10.04% 34,089 1,317 121,381 97.99 25,830 147,211 111,805 79.35
- ----------------------------------------------------------------------------------------------------------------------------------
2011 1,409 1,026 8.31% 28,433 1,088 123,981 120.86 26,332 150,313 120,792 85.73
- ----------------------------------------------------------------------------------------------------------------------------------
2012 1,409 1,199 9.72% 33,192 1,281 122,973 102.58 26,723 149,696 115,223 81.78
- ----------------------------------------------------------------------------------------------------------------------------------
2013 1,409 1,722 13.96% 46,716 3,646 137,201 79.65 27,040 164,241 113,879 80.82
- ----------------------------------------------------------------------------------------------------------------------------------
2014 1,409 1,736 14.07% 47,452 3,729 137,848 79.41 28,325 166,173 114,992 81.61
- ----------------------------------------------------------------------------------------------------------------------------------
2015 1,409 1,886 15.29% 51,575 4,177 142,151 75.36 30,302 172,453 116,701 82.83
- ----------------------------------------------------------------------------------------------------------------------------------
2016 1,409 1,582 12.82% 43,299 3,498 131,597 83.17 26,911 158,508 111,711 79.28
- ----------------------------------------------------------------------------------------------------------------------------------
2017 1,409 1,866 15.13% 51,564 4,115 143,260 76.76 29,695 172,955 117,276 83.23
- ----------------------------------------------------------------------------------------------------------------------------------
2018 1,409 1,827 14.81% 50,683 4,059 141,442 77.40 30,951 172,393 117,651 83.50
- ----------------------------------------------------------------------------------------------------------------------------------
2019 1,409 2,018 16.36% 56,171 4,307 147,416 73.05 31,661 179,077 118,599 84.17
- ----------------------------------------------------------------------------------------------------------------------------------
2020 1,409 1,688 13.68% 46,981 3,776 138,848 82.26 28,579 167,427 116,670 82.80
- ----------------------------------------------------------------------------------------------------------------------------------
2021 1,409 1,700 13.78% 47,779 3,912 136,959 80.56 30,513 167,472 115,781 82.17
- ----------------------------------------------------------------------------------------------------------------------------------
2022 1,409 1,629 13.20% 45,637 4,795 135,749 83.33 28,039 163,788 113,356 80.45
- ----------------------------------------------------------------------------------------------------------------------------------
2023 1,409 1,549 12.55% 43,112 5,420 134,406 86.79 27,850 162,256 113,724 80.71
- ----------------------------------------------------------------------------------------------------------------------------------
2024 1,409 1,524 12.35% 42,648 5,335 140,078 91.90 29,296 169,374 121,391 86.15
- ----------------------------------------------------------------------------------------------------------------------------------
2025 1,409 1,564 12.67% 44,300 5,472 138,129 88.34 28,540 166,669 116,897 82.96
- ----------------------------------------------------------------------------------------------------------------------------------
2026 1,409 1,740 14.10% 49,451 6,090 145,896 83.85 31,099 176,995 121,454 86.20
- ----------------------------------------------------------------------------------------------------------------------------------
Avg. 1,409 1,472 11.93% 43,172 2,976 134,323 95.12 28,634 162,958 116,809 82.93
- ----------------------------------------------------------------------------------------------------------------------------------
================================================================================
- ----------
15 Summer Capacity.
16 Reflects energy and capacity revenues to Exelon and Aquila during the
Contract Period and to Elwood during the Merchant Period.
17 Reflects net volatility revenues to Exelon and Aquila during the Contract
Period and to Elwood during the Merchant Period.
- --------------------------------------------------------------------------------
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Exhibit 13: Exelon PSA Annual Operational Summary (1998 $)
================================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
Energy Energy Volatility Total Gross Gross
Variable and and Value Revenue Margin Margin
Fuel O&M Capacity Capacity Net of with with with
Capacity Generation Capacity Costs Costs Revenue(19) Revenue Insurance(20) Volatility Volatility Volatility
Year MW(18) GWh Factor $1000 $1000 $1000 $/MWh $1000 $1000 $1000 $/kW-yr
- ----------------------------------------------------------------------------------------------------------------------------------
2001 783 189 2.76% 10,568 259 70,919 375.18 16,480 87,399 76,572 97.86
- ----------------------------------------------------------------------------------------------------------------------------------
2002 783 185 2.70% 8,074 253 63,751 344.70 14,564 78,315 69,988 89.44
- ----------------------------------------------------------------------------------------------------------------------------------
2003 783 163 2.38% 6,158 223 55,495 340.25 12,122 67,618 61,236 78.26
- ----------------------------------------------------------------------------------------------------------------------------------
2004 783 195 2.85% 6,822 268 53,975 276.33 11,210 65,185 58,096 74.24
- ----------------------------------------------------------------------------------------------------------------------------------
2005 783 254 3.71% 8,324 348 55,474 218.32 11,809 67,283 58,611 74.90
- ----------------------------------------------------------------------------------------------------------------------------------
2006 783 282 4.11% 8,834 386 56,364 199.89 12,422 68,785 59,565 76.12
- ----------------------------------------------------------------------------------------------------------------------------------
2007 783 233 3.40% 7,003 319 52,545 225.45 11,427 63,972 56,649 72.39
- ----------------------------------------------------------------------------------------------------------------------------------
2008 783 268 3.91% 8,051 368 54,689 203.80 11,238 65,928 57,509 73.49
- ----------------------------------------------------------------------------------------------------------------------------------
2009 783 272 3.97% 8,092 373 53,444 196.48 11,302 64,746 56,282 71.93
- ----------------------------------------------------------------------------------------------------------------------------------
2010 783 264 3.86% 7,857 362 55,359 209.40 11,443 66,801 58,583 74.87
- ----------------------------------------------------------------------------------------------------------------------------------
2011 783 213 3.11% 6,341 292 58,600 275.14 12,507 71,107 64,474 82.39
- ----------------------------------------------------------------------------------------------------------------------------------
2012 783 272 3.96% 8,052 372 56,902 209.44 12,267 69,169 60,745 77.63
- ----------------------------------------------------------------------------------------------------------------------------------
Avg. 783 233 3.39% 7,848 319 57,293 256.20 12,399 69,692 61,526 78.63
- ----------------------------------------------------------------------------------------------------------------------------------
* The results outlined above refer to Units 1-4 and 9. The Exelon PSA terminates
on December 31, 2012.
================================================================================
- ----------
18 Summer Capacity.
19 Reflects energy and capacity revenues to Exelon during the Contract Period
and to Elwood during the Merchant Period.
20 Reflects net volatility revenues to Exelon during the Contract Period and to
Elwood during the Merchant Period.
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Exhibit 14: Aquila PSAs Annual Operational Summary (1998 $)
================================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
Energy Energy Volatility Total Gross Gross
Variable and and Value Revenue Margin Margin
Fuel O&M Capacity Capacity Net of with with with
Capacity Generation Capacity Costs Costs Revenue(22) Revenue Insurance(23) Volatility Volatility Volatility
Year MW(21) GWh Factor $1000 $1000 $1000 $/MWh $1000 $1000 $1000 $/kW-yr
- ----------------------------------------------------------------------------------------------------------------------------------
2001 626 809 14.74% 43,713 792 92,970 114.99 21,915 114,885 70,380 112.43
- ----------------------------------------------------------------------------------------------------------------------------------
2002 626 943 17.20% 39,000 924 85,292 90.42 19,010 104,302 64,377 102.84
- ----------------------------------------------------------------------------------------------------------------------------------
2003 626 794 14.49% 28,091 779 68,787 86.58 14,894 83,681 54,811 87.56
- ----------------------------------------------------------------------------------------------------------------------------------
2004 626 742 13.52% 23,895 727 62,777 84.66 12,610 75,387 50,766 81.10
- ----------------------------------------------------------------------------------------------------------------------------------
2005 626 1,045 19.05% 31,681 1,024 71,099 68.05 14,985 86,085 53,380 85.27
- ----------------------------------------------------------------------------------------------------------------------------------
2006 626 1,038 18.92% 29,610 1,017 68,990 66.49 16,058 85,048 54,421 86.93
- ----------------------------------------------------------------------------------------------------------------------------------
2007 626 1,103 20.12% 30,477 1,081 68,482 62.07 14,897 83,380 51,821 82.78
- ----------------------------------------------------------------------------------------------------------------------------------
2008 626 1,147 20.92% 31,060 1,124 70,262 61.26 14,647 84,909 52,724 84.22
- ----------------------------------------------------------------------------------------------------------------------------------
2009 626 1,108 20.20% 29,947 1,086 67,778 61.18 15,210 82,988 51,956 83.00
- ----------------------------------------------------------------------------------------------------------------------------------
2010 626 974 17.77% 26,233 955 66,023 67.76 14,388 80,410 53,223 85.02
- ----------------------------------------------------------------------------------------------------------------------------------
2011 626 813 14.82% 22,091 797 65,381 80.44 13,825 79,206 56,318 89.97
- ----------------------------------------------------------------------------------------------------------------------------------
2012 626 927 16.91% 25,140 909 66,071 71.27 14,456 80,527 54,479 87.03
- ----------------------------------------------------------------------------------------------------------------------------------
2013 626 945 17.24% 26,040 927 66,093 69.91 13,567 79,660 52,693 84.17
- ----------------------------------------------------------------------------------------------------------------------------------
2014 626 931 16.98% 25,840 913 65,757 70.61 14,432 80,190 53,437 85.36
- ----------------------------------------------------------------------------------------------------------------------------------
2015 626 962 17.55% 26,696 943 66,593 69.21 14,570 81,164 53,524 85.50
- ----------------------------------------------------------------------------------------------------------------------------------
2016 626 809 14.76% 22,451 793 61,386 75.84 12,864 74,251 51,006 81.48
- ----------------------------------------------------------------------------------------------------------------------------------
2017 626 959 17.49% 26,853 940 67,351 70.21 14,289 81,639 53,846 86.02
- ----------------------------------------------------------------------------------------------------------------------------------
2018 626 927 16.91% 26,025 909 66,158 71.35 14,630 80,788 53,854 86.03
- ----------------------------------------------------------------------------------------------------------------------------------
2019 626 1,094 19.94% 30,797 1,072 71,072 64.99 16,086 87,158 55,289 88.32
- ----------------------------------------------------------------------------------------------------------------------------------
2020 626 846 15.43% 23,798 829 64,330 76.05 13,426 77,755 53,128 84.87
- ----------------------------------------------------------------------------------------------------------------------------------
2021 626 895 16.33% 25,454 1,095 64,993 72.59 14,785 79,778 53,230 85.03
- ----------------------------------------------------------------------------------------------------------------------------------
2022 313 439 16.03% 12,441 631 32,364 73.65 6,972 39,336 26,263 83.91
- ----------------------------------------------------------------------------------------------------------------------------------
Avg. 612 921 17.15% 27,606 921 67,273 74.07 14,660 81,933 53,406 87.22
- ----------------------------------------------------------------------------------------------------------------------------------
* The results outlined above refer to Units 5-8. Results in 2022 refer only to
Units 7-8.
================================================================================
- ----------
21 Summer Capacity.
22 Reflects energy and capacity revenues to Aquila during the Contract Period
and to Elwood during the Merchant Period.
23 Reflects net volatility revenues to Aquila during the Contract Period and to
Elwood during the Merchant Period.
- --------------------------------------------------------------------------------
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================================================================================
VOLATILITY ANALYSIS APPROACH AND RESULTS
================================================================================
Pace has performed a valuation of the Project's projected volatility value for
the Study Period. This valuation has been customized to reflect sales of power
into the MAIN power market.
Volatility valuation measures the potential value of variation of the projected
spark spread as a result of fluctuations in the underlying power and fuel
prices. The methodology relies on the deterministic forecast of power prices
relative to fuel costs (the projected spark spread), but assumes commodity price
behaviors around those projected mean values that reflect the market-priced
volatility value of price movement among power and fuel prices at the assets'
forecasted heat rate. Intrinsic value refers to the spark spread projection, and
extrinsic value refers to the incremental value from price fluctuations. A power
plant has embedded this option value by nature of its operation flexibility and
underlying price variations. By structuring and managing the asset's commodity
positions in both the physical and financial markets, the merchant plant can
lock in option value consistent with its desired risk exposure.
The financial markets include options, futures and forwards trading for the
underlying commodities. Since forward contracting involves a firm financial
obligation, an operational commitment of the power asset is required as a hedge
against adverse price movements. For example, if the project sold a spark spread
call option in the forward market, the asset will be required to convert the
fuel to power should the power option be exercised. Therefore, the analysis has
incorporated a proxy for the cost of financially insuring the power plant
against mechanical outages on a portfolio basis.
SUMMARY RESULTS
The Project's annual and monthly volatility values, expressed in 1998 dollars,
consistent with the operating assumptions presented in Pace's CEMAS power market
assessment, are illustrated in Exhibit 15 and Exhibit 16 respectively.
Exelon and Aquila own the exclusive rights to dispatch and receive the output of
the Project during the Contract Period, and will also be able to leverage the
value of the asset in the forward market to extract option or volatility value.
Exelon and Aquila are active power market traders and will likely attempt to
extract this value. During the Merchant Period after the expiration of the
Exelon and Aquila PSAs, Elwood will have the ability to extract this market
value as well.
Given Pace's assumptions concerning reserve margins, liquidity, and trading
volatility, volatility value (net of insurance costs) adds on average
approximately $20.33/kW-year or $28.6 million per year to Base Case energy and
capacity revenues over the Study Period. Volatility value ranges from a maximum
of $27.26/kW-year or $38.4 million in 2001 to a minimum of $16.91/kW-year or
$23.8 million in 2004.
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The high projected volatility values in 2001 are driven by the high natural gas
prices. As natural gas and thus power prices decrease from 2002 to 2004, so do
the levels of projected spark spread and derived volatility values. After
projected natural gas prices stabilize in the 2008-2009 timeframe, decreasing
regional reserve margins and the resulting increase in implied volatility
forecasts become the major value drivers. Thereafter, the projected Project
volatility value is relatively steady in a range of $18/kW-year to $22/kW-year
through the end of the Study Period.
During the term of the Exelon and Aquila PSAs, Exelon is forecast to extract net
volatility values which average $15.85/kW-year or $12.4 million per year, while
Aquila is forecast to earn net volatility values which average $23.92/kW-year or
$14.7 million per year. During the Merchant Period, Elwood is forecast to earn
net volatility values which average $20.73/kW-year or $ 29.2 million per year.
Exhibit 15: Project Annual Volatility Value (1998 $)
================================================================================
-------------------------------------------------------
Volatility Volatility
Value Value
Volatility Insurance Net of Net of
Value Estimate Insurance Insurance
Year $/kW-yr $/kW-yr $/kW-yr $000
-------------------------------------------------------
2001 29.49 2.23 27.26 38,395
-------------------------------------------------------
2002 25.79 1.96 23.84 33,573
-------------------------------------------------------
2003 20.78 1.60 19.18 27,016
-------------------------------------------------------
2004 18.36 1.45 16.91 23,821
-------------------------------------------------------
2005 20.50 1.48 19.02 26,794
-------------------------------------------------------
2006 21.77 1.55 20.22 28,480
-------------------------------------------------------
2007 20.17 1.48 18.69 26,324
-------------------------------------------------------
2008 19.85 1.47 18.38 25,885
-------------------------------------------------------
2009 20.31 1.49 18.82 26,512
-------------------------------------------------------
2010 19.84 1.50 18.34 25,830
-------------------------------------------------------
2011 20.29 1.60 18.70 26,332
-------------------------------------------------------
2012 20.53 1.55 18.97 26,723
-------------------------------------------------------
2013 20.75 1.55 19.20 27,040
-------------------------------------------------------
2014 21.70 1.59 20.11 28,325
-------------------------------------------------------
2015 23.18 1.66 21.51 30,302
-------------------------------------------------------
2016 20.68 1.57 19.11 26,911
-------------------------------------------------------
2017 22.74 1.66 21.08 29,695
-------------------------------------------------------
2018 23.67 1.69 21.97 30,951
-------------------------------------------------------
2019 24.20 1.72 22.48 31,661
-------------------------------------------------------
2020 21.95 1.66 20.29 28,579
-------------------------------------------------------
2021 23.36 1.69 21.66 30,513
-------------------------------------------------------
2022 21.53 1.63 19.91 28,039
-------------------------------------------------------
2023 21.39 1.62 19.77 27,850
-------------------------------------------------------
2024 22.52 1.72 20.80 29,296
-------------------------------------------------------
2025 21.83 1.57 20.26 28,540
-------------------------------------------------------
2026 23.85 1.77 22.08 31,099
-------------------------------------------------------
Avg. 21.96 1.63 20.33 28,634
-------------------------------------------------------
================================================================================
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The forecast monthly Project net volatility values outlined in Exhibit 16
illustrate that five out of the top seven average monthly volatility values
occur during the June to October period, with the months of January and March
accounting for the next highest values. Volatility values are forecast to be the
highest in the month of July. This value is four times higher than the next
highest monthly volatility value, which occurs in the month of January.
Exhibit 16: Project Monthly Volatility Value - Net of Insurance (1998 $)
================================================================================
- ----------------------------------------------------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total
Year $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000 $1000
- ----------------------------------------------------------------------------------------------------------------------------
2001 1,685 1,054 3,389 957 1,528 3,241 14,506 4,907 1,689 4,747 691 -- 38,395
- ----------------------------------------------------------------------------------------------------------------------------
2002 1,836 1,473 506 785 623 2,105 17,134 1,352 2,603 2,353 1,754 1,049 33,573
- ----------------------------------------------------------------------------------------------------------------------------
2003 814 905 1,627 1,908 759 962 11,009 1,316 4,949 2,594 -- 172 27,016
- ----------------------------------------------------------------------------------------------------------------------------
2004 555 367 722 86 1,769 2,782 13,295 628 1,438 1,784 46 348 23,821
- ----------------------------------------------------------------------------------------------------------------------------
2005 1,283 244 2,148 582 1,402 2,423 11,211 1,980 3,555 904 251 812 26,794
- ----------------------------------------------------------------------------------------------------------------------------
2006 1,190 1,611 1,048 779 1,733 1,952 8,841 4,868 1,992 2,427 1,645 394 28,480
- ----------------------------------------------------------------------------------------------------------------------------
2007 938 1,004 1,887 260 852 2,085 8,854 3,272 3,166 1,684 441 1,882 26,324
- ----------------------------------------------------------------------------------------------------------------------------
2008 873 1,093 1,151 1,018 497 2,515 10,590 2,278 1,189 1,313 851 2,518 25,885
- ----------------------------------------------------------------------------------------------------------------------------
2009 1,455 1,490 1,854 594 659 1,626 10,335 1,518 2,713 1,761 763 1,745 26,512
- ----------------------------------------------------------------------------------------------------------------------------
2010 831 1,442 1,738 191 349 1,470 11,479 1,197 3,443 1,765 1,139 787 25,830
- ----------------------------------------------------------------------------------------------------------------------------
2011 292 1,541 2,555 -- 350 715 12,967 2,731 153 1,458 1,136 2,435 26,332
- ----------------------------------------------------------------------------------------------------------------------------
2012 1,090 992 606 2,936 273 1,066 9,751 3,080 2,817 1,374 931 1,808 26,723
- ----------------------------------------------------------------------------------------------------------------------------
2013 3,910 1,430 1,598 255 -- 1,743 8,461 1,272 3,085 3,244 253 1,788 27,040
- ----------------------------------------------------------------------------------------------------------------------------
2014 4,866 332 1,569 1,519 42 1,907 8,997 1,784 2,676 1,651 1,151 1,832 28,325
- ----------------------------------------------------------------------------------------------------------------------------
2015 2,948 3,060 4,313 338 18 1,851 8,894 775 2,478 2,337 1,487 1,805 30,302
- ----------------------------------------------------------------------------------------------------------------------------
2016 3,073 2,271 1,790 348 50 1,534 10,399 2,355 1,094 2,454 435 1,109 26,911
- ----------------------------------------------------------------------------------------------------------------------------
2017 3,903 2,565 3,311 123 886 1,734 7,348 3,094 1,825 2,610 452 1,844 29,695
- ----------------------------------------------------------------------------------------------------------------------------
2018 5,158 2,111 2,869 -- 74 2,210 6,531 1,573 1,882 5,211 1,841 1,491 30,951
- ----------------------------------------------------------------------------------------------------------------------------
2019 3,164 1,334 3,262 635 1,465 1,831 6,997 1,518 3,827 3,857 1,057 2,714 31,661
- ----------------------------------------------------------------------------------------------------------------------------
2020 3,131 2,688 2,478 222 285 2,286 10,639 1,290 2,614 1,822 710 413 28,579
- ----------------------------------------------------------------------------------------------------------------------------
2021 3,506 2,122 3,104 1,872 420 2,159 8,680 1,021 2,109 2,853 1,347 1,320 30,513
- ----------------------------------------------------------------------------------------------------------------------------
2022 3,136 1,175 2,603 1,081 91 2,392 9,454 1,766 850 2,607 939 1,946 28,039
- ----------------------------------------------------------------------------------------------------------------------------
2023 4,052 3,057 2,126 -- 122 1,906 7,037 2,543 1,845 2,767 582 1,814 27,850
- ----------------------------------------------------------------------------------------------------------------------------
2024 3,121 1,024 2,294 28 621 2,029 10,854 1,107 2,550 3,876 142 1,652 29,296
- ----------------------------------------------------------------------------------------------------------------------------
2025 4,103 739 2,800 200 249 1,978 9,425 1,018 2,452 1,304 491 3,780 28,540
- ----------------------------------------------------------------------------------------------------------------------------
2026 4,605 3,470 1,255 848 316 1,761 7,957 1,319 2,685 3,492 1,010 2,381 31,099
- ----------------------------------------------------------------------------------------------------------------------------
Avg. 2,520 1,561 2,100 764 617 1,933 10,063 1,983 2,372 2,471 862 1,594 28,634
- ----------------------------------------------------------------------------------------------------------------------------
================================================================================
VOLATILITY VALUE ANALYSIS METHODOLOGY AND VALUATION
Volatility value is associated with the conversion of an MMBtu to an MWh at an
underlying asset's operating efficiency, given the regional power and fuel price
fluctuations. Pace performed the quantitative volatility valuation for Northern
Illinois or ComEd sub-region of the MAIN power market by forecasting the premium
ascribable to the generating option on an annual basis, tailored to the
generation facilities' dispatch economics.
Central to the volatility valuation is the development of a regional implied
volatility analysis of options transactions for both the power and gas forwards
contracts. This analysis forms the foundation for assessing historic, current
and potentially ascribed market value associated with power and fuel price
uncertainty.
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Other factors fundamental to valuing an assets' ability to extract volatility
premiums include the following:
o Variable costs of each facility (heat rate, variable O&M, and fuel
costs);
o Period and duration of plant dispatch;
o Anticipated fuel and power price levels over the term of the
analysis;
o Forecasted regional supply and demand balances that may affect
future market volatility for each commodity, including new capacity
additions, retirements, and reserve margin; and
o The regional historical and forecasted correlation between power and
fuel.
The project-specific variables, as stated above, form the inputs to a spread
option pricing model that calculates the extrinsic value obtained by selling
fully hedged call options on the asset's underlying "at-the-money" spark spread.
This is accomplished by calculating the value of at-the-money spark spread call
options(24) for each facility when its forecasted peak-hour(25) operating
economics are producing positive variable margins. In addition, periods with
negative variable margins may be valued as "out-of-the-money" call options on
the spark spread, with the underlying generating economics of the facility
serving as the strike price for the option valuation.
GAS MARKET
For the analysis, we have utilized the Henry Hub contract for the gas leg of the
spark spread volatility valuation, as this is the most liquid gas forward
trading point with a robust options transaction history. Although basis price
movements could serve to increase the region's observed volatility, there may
also be counter-balancing price movements that could dampen the region's
volatility. Furthermore, it is typical for a project to structure its gas
procurement contract with an index to Henry Hub, adjusting for a relatively
stable basis differential. Therefore, we believe that the Henry Hub contract is
an appropriate measure of the gas market's implied volatility for this analysis.
The Henry Hub natural gas contract typically exhibits lower levels of implied
volatility than power markets, averaging around 50% on an annual basis over the
past 2-3 years, with month-to-month variations as exhibited in Exhibit 17 below.
Pace's initial (year 2001) volatility values ascribed to natural gas, as shown
in Exhibit 20, reduce the annual average to 39% in 2001 and beyond, reflecting
what we believe is a relatively conservative, but more reliable, long-term
average for natural gas price volatility during the Study Period. While the gas
volatility values Exhibit 20 have been sculpted down on a projected basis to an
average of 39%, the relative monthly seasonal factors are maintained consistent
with those reflected in Exhibit 17.
- ----------
24 The spread between gas prices and power prices on a facility-specific per MWh
equivalent basis.
25 To remain consistent with the vast majority of currently traded options, each
unit is forecasted to receive volatility premiums during peak periods only.
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Exhibit 17: Long-term Monthly Henry Hub Implied Volatility Forecast
================================================================================
- --------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
- --------------------------------------------------------------------------------
67% 70% 60% 46% 38% 39% 39% 40% 39% 46% 55% 56%
- --------------------------------------------------------------------------------
================================================================================
We believe that the implied volatility level for natural gas presented in
Exhibit 17 is indicative of the long-term market implied volatility level for
natural gas, but acknowledge that short-term volatility may vary substantially
from that level.
COMMODITY PRICE CORRELATION
The correlation coefficient between the two underlying commodities is another
critical input to the spread option value. All other things equal, lower
correlation coefficients will produce higher volatility premiums. Regional
short-term power and gas price correlation coefficients tend to average
approximately 30% over terms of one year or longer, but with potentially
substantial month-to-month variation. As gas-fired generation becomes a larger
percentage of a region's total gas demand, we would expect the long-term
correlation to increase accordingly. In this analysis, we have forecasted an
average realized price correlation coefficient of 30% in MAIN, realizing that
short-term imbalances are likely to continue, making this price relationship
somewhat variable month-to-month. We have observed that a typical options'
volatility premium increases by about 7% when the correlation coefficient
changes from 30% to 0%.
POWER MARKET AND VALUATION RESULTS
In order to forecast the regional power market implied volatility, we define
power markets by trading hubs, pricing points, and available financial
instruments. For this analysis, we mainly used the ComEd pricing history and
observed volatility, while referencing the adjacent pricing points as provided
in Exhibit 18.
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Exhibit 18: Regional Power Trading Markets
================================================================================
Financial Markets Development
---------------------------------------------------
Options Futures Forwards Spot
---------------------------------------------------
MAP OF REGIONS REFERRED Cinergy Liquid Liquid Liquid Liquid
TO IN CHART. ---------------------------------------------------
ComEd Fair Liquid
---------------------------------------------------
Ameren Fair Fair
---------------------------------------------------
MAIN North Fair
---------------------------------------------------
MAIN South Fair
---------------------------------------------------
================================================================================
The regions shown in Exhibit 18 are physically well interconnected, and are
financially highly integrated. The major indicator for integration of the
regional trading markets is the correlation coefficient between the spot market
power prices. The correlation coefficients range from as high as 99% between
ComEd and Cinergy, to 96% between Ameren and Cinergy, and ComEd, and
approximately 80% for the remainder of the cross correlation. The three-tiered
structure of price correlation is explained by the different liquidity levels
for different pricing points, and to perhaps a lesser extent by the variance in
sub-regional supply demand balance and physical flow constraints.
Because of the high correlation level between Cinergy and ComEd, we relied
largely on the use of both a smoothed measurement (20-day average) on observed
spot market volatility and implied volatility as reflected in the Cinergy
options quotes with minor adjustments reflecting information from other
financial products to estimate anticipated implied volatility levels at Com Ed.
We also assume the portfolio to be fully hedged by selling into the term (3
months or less) and seasonal (4-12 month) forwards or corresponding options
markets, and correspondingly those two term structures are reflected in the
volatility term structure and value calculations. The resultant 2001 Com Ed
monthly term market implied volatility forecast is detailed in Exhibit 19 below.
Exhibit 19: Com Ed 2001 Term Power Market Implied Volatility Forecast
================================================================================
---------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
---------------------------------------------------------------------------
101% 101% 67% 54% 76% 123% 105% 123% 102% 65% 63% 73%
---------------------------------------------------------------------------
================================================================================
Exhibit 19 above shows a 2001 average annual power implied volatility estimate
based on un-weighted values, averaging 88%. The implied volatility values used
in the option valuation analysis reflects our projected volume-weighted
volatilities, which increase the average to 117%
- --------------------------------------------------------------------------------
Proprietary & Confidential 36
[LOGO] PACE | Global Energy Services
for 2001. This implied volatility level is reduced by 5% per annum over the
first five years of the Study Period, reflecting a liquidity factor discount
that is expected to reduce average implied volatility levels by over 25% as the
market's mature, bid-ask spreads narrow and liquidity increases. Offsetting this
projected decline in the volatility curve is a projected 10% increase over the
valuation horizon attributable to a projected declining reserve margin.(26)
Pace utilizes a 50% correlation coefficient to relate percentage annual declines
in reserve margin to increases in projected volatility. Thus, if reserve margin
is projected to decline by 10% from its base year level (e.g., 20% to 18%), the
impact on volatility is projected to be a 5% increase.
Key volatility value drivers, including commodity prices, market implied
volatilities, and variable O&M are illustrated in Exhibit 20. Throughout the
valuation horizon, the portfolio will mostly operate in summer peak months,
realizing relatively high power prices and price volatilities, but relatively
low natural gas prices and price volatilities.
Exhibit 20: Forecast of Key Volatility Drivers
================================================================================
---------------------------------------------------------------------
Average
Realized Average
Power Realized Average Average
Market Fuel Market Realized Realized Variable
Implied Implied Power Price Fuel Price O&M
Year Volatility Volatility $/MWh $/MMBtu $/MWh
---------------------------------------------------------------------
2001 117% 39% 529.28 5.14 1.20
---------------------------------------------------------------------
2002 112% 39% 424.30 3.98 1.20
---------------------------------------------------------------------
2003 105% 39% 425.36 3.42 1.20
---------------------------------------------------------------------
2004 102% 39% 414.28 3.14 1.20
---------------------------------------------------------------------
2005 98% 39% 272.94 2.95 1.20
---------------------------------------------------------------------
2006 100% 39% 234.65 2.80 1.20
---------------------------------------------------------------------
2007 101% 39% 273.88 2.70 1.20
---------------------------------------------------------------------
2008 100% 39% 297.27 2.67 1.20
---------------------------------------------------------------------
2009 102% 39% 277.83 2.66 1.20
---------------------------------------------------------------------
2010 102% 39% 300.71 2.65 1.20
---------------------------------------------------------------------
2011 101% 39% 336.87 2.67 1.20
---------------------------------------------------------------------
2012 102% 39% 263.21 2.66 1.20
---------------------------------------------------------------------
2013 102% 39% 184.19 2.57 2.38
---------------------------------------------------------------------
2014 102% 39% 170.89 2.60 2.38
---------------------------------------------------------------------
2015 104% 39% 144.00 2.60 2.38
---------------------------------------------------------------------
2016 104% 39% 179.94 2.60 2.38
---------------------------------------------------------------------
2017 103% 39% 153.24 2.63 2.94
---------------------------------------------------------------------
2018 102% 39% 136.74 2.64 3.50
---------------------------------------------------------------------
2019 103% 39% 140.61 2.65 3.50
---------------------------------------------------------------------
2020 104% 39% 168.36 2.65 3.50
---------------------------------------------------------------------
2021 104% 39% 144.08 2.67 3.50
---------------------------------------------------------------------
2022 104% 39% 170.38 2.67 3.50
---------------------------------------------------------------------
2023 103% 39% 172.45 2.65 3.50
---------------------------------------------------------------------
2024 104% 39% 180.69 2.67 3.50
---------------------------------------------------------------------
2025 104% 39% 181.51 2.70 3.50
---------------------------------------------------------------------
2026 105% 39% 160.11 2.71 3.50
---------------------------------------------------------------------
================================================================================
- ----------
26 Reserve Margin = (Total Capacity - Peak Demand) / Peak Demand.
- --------------------------------------------------------------------------------
Proprietary & Confidential 37
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INSURANCE
When an option is sold that utilizes the physical asset as a natural hedge, the
asset owner is well advised to protect the plant against unexpected outage risk.
Therefore, we have incorporated into this analysis the cost of insuring the
plant against outages, and have priced this product at 1/15th that of a daily
power call option, reflecting the incremental insurance premium associated with
portfolio, versus stand-alone generation assets. This insurance cost has been
deducted from the option sales revenues, to provide net of insurance option
values in all volatility valuations.
OTHER VOLATILITY VALUE MEASURES
Daily call options offer increased exercise opportunities to the owner, and
provide greater upside value by virtue of daily market price spikes relative to
traditional options on futures / forwards contracts. For these reasons, daily
options command a relatively high premium, typically in the range of two to
three times as high as equivalently struck monthly options. An analysis of the
potential value attainable though sales of daily power call options(27) can also
be conducted for the asset. This type of option sale, however lucrative compared
to a spark spread option, presents more risk to the asset, as the fuel position
is not fully hedged. The major fuel risk associated with these assets is in an
instance when (1) a daily call is sold, (2) the options holder does not call
upon the plant to dispatch, and (3) the plant is uneconomical given market power
prices. In this instance, the plant will have gas supply obligations that must
be resold, potentially at a loss.(28)
Other volatility value extraction measures include spark spread or single
commodity trading of positions in efforts to outperform market forecasts. This
activity, however profitable it may be in the short-term, is extremely risky in
nature and less likely to be sustained over time.
- ----------
27 A daily power call for peak hours only, exercisable once per weekday for the
following day's capacity output.
28 A daily put option on gas or a swing supply purchase contract could insure
this risk at a cost.
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================================================================================
MARKET AREA DEFINITION AND TRANSMISSION
================================================================================
Pace will model the MAIN region in its entirety, as well as those operating
systems within one transmission wheel of the Commonwealth Edison ("ComEd")
sub-region including portions of the Mid-Continent Area Power Pool ("MAPP") and
East Central Area Reliability Council ("ECAR"). The ComEd service area is the
dominant demand center in this region encompassing all of Chicago and the
surrounding area and supplying 41% of peak demand in the region. Pace will model
the region as five distinct, yet interconnected utility sub-regions, three
within MAIN, one in MAPP, and one in ECAR.(29)
The MAIN system encompasses portions of Wisconsin, Michigan, Missouri and the
majority of Illinois. Based on an analysis of wholesale power price
characteristics and existing transmission transfer capabilities, Pace assumes
three major intra-regional market areas of MAIN: Wisconsin Upper Michigan System
("WUM"), Northern Illinois ("NI"), (also referred to as ComEd), and South MAIN
("SMAIN")(30) while capturing the existing transfer capability between the
subregions. Exhibit 21 lists the primary utility companies in MAIN and their
respective subregional locations.
Exhibit 21: MAIN Sub-Regions and Major Utility Companies
================================================================================
- -------------------------------------------------------------------------------------------------
NI (ComEd) WUM SMAIN
- -------------------------------------------------------------------------------------------------
Commonwealth Edison Co. Wisconsin Public Service Co. Ameren
Wisconsin Power & Light Central Illinois Light Co.
Wisconsin Electric Power Co. Electric Energy, Inc.
Madison Gas & Electric Co. Geneseo Municipal Utilities
Upper Peninsula Power Co. Illinois Municipal Electric Agency
Menasha Electric & Water Utilities Illinois Power Co.
Manitowoc Public Utilities Rochelle Municipal Utilities
Kaukauna Electric & Water Dept. Southern Illinois Power Coop
Oconto Electric Coop Soyland Power Coop, Inc.
Wisconsin River Power Co. Springfield Water, Light & Power
Central Electric Power Coop
Columbia Water & Light Dept.
NE Missouri Electric Power Coop
- -------------------------------------------------------------------------------------------------
================================================================================
Pace will also explicitly model the two sub-regions that are directly
interconnected with ComEd. These two sub-regions and their major operating
systems are outlined in Exhibit 22.
- ----------
29 Collectively, Pace will refer to the five as the "First Tier" sub-regions.
30 The East Missouri ("EMO") and South Central Illinois ("SCI") sub-regions have
been combined to create SMAIN due to increased coordination and dependence
following the merger between Union Electric and Central Illinois Public Service.
Accordingly, Pace will simulate the three sub-regions of NI, WUM, and SMAIN.
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Exhibit 22: Other First Tier Sub-Regions and Major Utility Companies
================================================================================
---------------------------------------------------------
IOWA OECAR
---------------------------------------------------------
Alliant West Indiana-Michigan Power Co.
---------------------------------------------------------
Mid-American Energy Northern Indiana Public Service
---------------------------------------------------------
Muscatine Power & Water Indiana-Michigan Power Co.
---------------------------------------------------------
Exhibit 23 illustrates the MAIN region and its major investor-owned utility
("IOU") service areas as well as those portions of MAPP and ECAR that are
directly interconnected with ComEd.
Exhibit 23: MAIN Regional Map with Major IOUs
================================================================================
MAP ILLUSTRATING THE MAIN REGION
AND ITS MAJOR INVESTOR-OWNED UTILITY
SERVICE AREAS.
================================================================================
Exhibit 24 provides an overview of system coincident peaks, net energy for load,
and total installed capacity by Pace's modeled subdivision of the MAIN power
market.
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Exhibit 24: Overview of System Coincident Peaks
================================================================================
- --------------------------------------------------------------------------------
2001 2001 2001 2001
Summer Winter Estimated Installed
Peak Peak Net Energy Summer
Demand Demand for Load Capacity
Sub-region (MW) (MW) (GWh) (MW)
- --------------------------------------------------------------------------------
WUM 12,699 10,129 63,291 11,009
- --------------------------------------------------------------------------------
NI 18,737 14,946 93,386 24,496
- --------------------------------------------------------------------------------
SMAIN 19,619 15,649 97,783 21,235
- --------------------------------------------------------------------------------
OECAR 6,074 5,492 35,565 8,292
- --------------------------------------------------------------------------------
IOWA 7,941 6,161 41,481 9,007
- --------------------------------------------------------------------------------
TOTAL 65,070 52,377 331,506 74,039
- --------------------------------------------------------------------------------
================================================================================
Exhibit 25 provides a schematic topology of the intra-regional transfer
capability for the simulated region. The nature of both the inter-and
intra-regional transactions are described below:
o Intra-regional Transmission Transfer Capability. As depicted in
Exhibit 25, the arrows represent total transfer capability between
the sub-regions. The transfer capability is based on information
from utility reports of interconnection ratings and historical
inter-utility transfers (various operational and power quality
constraints may prevent the utilities from using certain connections
simultaneously). However, in some instances, the transfer capability
was adjusted from these reports in order to maintain the calibration
of Pace's dispatch model to historical inter-utility transfers.
o Inter-regional Transaction Modeling Assumptions. The inter-regional
transfers with utilities that are more than one wheel away from the
MAIN power market are modeled on a net transaction basis (i.e., net
purchases or sales). These assumptions, detailed in Exhibit 26, were
developed based on review of historical wholesale transactions as
reported to FERC for the years 1988 to 1998.
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Exhibit 25: Assumed Intra-regional Transmission Constraints
================================================================================
SCHEMATIC DRAWING OF THE TOTAL
TRANSFER CAPABILITY BETWEEN SUB-REGIONS.
* Sales to PJM from NI are wheeled through ECAR.
* Due to the addition of Lockport-Lombard 345 kV double circuit in-service on
June 5, 2000, the export capability from NI to WUM has increased by 1,700 MW.
The transfer capability from WUM to NI was unaffected by the Lockport-Lombard
transmission lines.
================================================================================
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Exhibit 26: Inter-regional Transactions Limits
================================================================================
----------------------------------------------
From To Summer MW Winter MW
----------------------------------------------
NI WUM 3,000 3,100
----------------------------------------------
NI SMAIN 3,000 3,500
----------------------------------------------
NI IOWA 1,200 2,100
----------------------------------------------
NI OECAR 500 500
----------------------------------------------
SMAIN NI 1,500 3,300
----------------------------------------------
WUM NI 1,600 1,700
----------------------------------------------
IOWA NI 1,600 1,700
----------------------------------------------
OECAR NI 500 500
----------------------------------------------
================================================================================
REGULATORY STATUS
Illinois
Illinois' current regulatory status is excellent for the development and
operation of merchant power generation. Specifically:
o Retail market deregulation began for the state's non-residential
customers in October 1999 with full retail access phased in for all
customers by May 2002. The supplier may be the current electric
utility, another Illinois electric utility, or an alternative retail
electric supplier certified by the Illinois Commerce Commission.
o The state's largest utility, ComEd, has divested its fossil
generation, paving the way for a liquid and truly competitive
wholesale generation market.
o Other state utilities are far along in the process to full
divestment via internal restructuring or acquisition by third
parties.
Illinois is one of the leaders in deregulation after California and
Pennsylvania. In December 1997, the state legislature passed "The Electric
Service Customer Choice and Rate Relief Act of 1997". This act set out a
phase-in schedule for retail open access with some industrial and commercial
customers beginning in October 1999, all other non-residential customers by
January 2001, and all consumers phased in by May 2002. Up until final
implementation in 2002 for residential customers, a number of rules determine
which customers are eligible for participation in deregulation. Further, the
bill required a 15% rate cut beginning August 1998 for ComEd and Illinois Power
customers saving customers over $200 million. Additional rate cuts, designed to
levelize the residential rates between utilities, have also been mandated. Very
few customers have switched suppliers in central Illinois, but about 40 percent
of eligible customers have shopped elsewhere in Chicago. Due to a disparity in
profit margins and the fact that Central Illinois Light Company ("CILCO") has
the lowest rates in the state, there has been little interest outside of the
Chicago Metro region.
Both the state legislature and the Illinois Commerce Commission, which has
regulatory authority over electrical utilities, have set guidelines to protect
customers and promote competition once the electricity sector is deregulated. In
July of 1999, legislation SB24 was enacted by the state
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legislature to amend the restructuring law. The rate cap for utilities was
increased by 2%, cogeneration was promoted and Commonwealth Edison was required
to allocate $250 million to a special environmental initiatives and energy
efficiency fund. The Illinois Commerce Commission approved an "Hourly Energy
Pricing" program for non-residential customers and has also issued a ruling that
prohibits the exploitation of the name, reputation or logo of utilities in
advertising or marketing.
Activity by the utilities is also strengthening competition. Voluntary
divestiture is occurring at a rapid pace. ComEd, in the nations' largest
generation asset sale, recently sold 9,772 MW of non-nuclear facilities to
Edison Mission Energy for $4.8 billion. In May 2000, Ameren transferred its
Illinois generating assets to an unregulated subsidiary, AmerenEnergy Generation
Company, which initially held 5,400 MW of generating capacity. Illinois Power
completed the sale of its 950 MW Clinton Nuclear Power Station to AmerGen Energy
Company in December 1999. Pace strongly believes that the independence resulting
from the separation of generation from the still regulated transmission and
distribution activities will promote wholesale competition and facilitate
customer choice.
Mergers and acquisitions have also occurred recently, indicating the increased
competition and opportunity in the area. Ameren was created in 1997 when
Illinois-based CIPSCO and Missouri-based Union Electric merged. While Ameren is
intent on its core utility business, it has also expanded into energy marketing
and energy information services. In October 1999, AES acquired CILCO, forming
AES CILCO. In recent years, AES CILCO has built a number of natural gas-fired
generating facilities in Illinois in anticipation that CILCO will continue to
enroll additional customers in a deregulated Illinois market. AES has also
acquired New Energy Ventures, a power marketer and client services firm. In
October 2000, Unicom Corporation, the parent company of ComEd, and PECO Energy
Company completed their merger to create Exelon Corporation, one of the nation's
largest electric utilities, with more than $12 billion in annual revenues.
Exelon Corporation is headquartered in Chicago and distributes electricity and
gas to approximately five million customers in Illinois and Pennsylvania.
MidAmerican has merged with independent power producer CalEnergy. Dynegy, who is
among the top five energy marketers, recently purchased Illinova, including its
utility subsidiary Illinois Power. These companies are looking for opportunities
in the deregulated market and have been active in promoting deregulation. CILCO
instituted a customer choice program for commercial and industrial customers in
October 1999 with residential customers becoming eligible to choose their
electric supplier from May 2002.
Michigan
Detroit Edison and Consumers Energy, which serve 90% of Michigan's electricity
consumers, have voluntarily started the implementation of retail choice within
their respective service territories. Detroit Edison and Consumers Energy's
voluntary retail access plan will be implemented in three phases. Currently in
the second phase, all consumers with a load of 150 MW and greater are allowed to
select their supplier. The third phase, providing retail access to all consumers
will be fully implemented by January 2002.
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In 1999, Michigan's electricity utilities engaged in significant merger and
acquisition activities. In January 1999, Great Lakes Electricity Co-op merged
with Top O'Michigan Electric Co-op. In June 1999, New Centuries Energies merged
with Northern States Power. In May 2001 Detroit Edison completed its merger with
MCN Energy.
During the 2000 session, the Michigan Public Service Commission (the "Michigan
PSC") issued a series of orders to implement the restructuring legislation,
which was signed into law on June 3 2000. In the orders, the Michigan PSC
directed Consumers Energy and Detroit Edison to file revised tariffs to
implement retail access programs; investor-owned utilities, other than Detroit
Edison and Consumers Energy, and cooperatives that have any customers with a
peak load of 1 MW or more, to file restructuring plans to implement retail
access. The Michigan PSC also required its own staff to consult with utility
owners, and other stakeholders to develop standards for the interconnection of
merchant plants. The Michigan PSC also required utilities to file reports when
they learn of any reductions in federal funding for low-income and energy
assistance programs, and electric generating facilities must file reports on
compliance with all applicable federal Environmental Protection Agency (the
"EPA") regulations governing mercury emissions. The Michigan PSC also issued an
order that established the framework for alternative electric suppliers to
participate in retail electric markets under the restructuring law.
In January of 2001, the Michigan PSC issued a final order authorizing Detroit
Edison to securitize $1.77 billion in costs by issuing bonds. The refinancing
will allow Detroit Edison to implement a 5% reduction in rates.
Missouri
Missouri's current `on-hold' regulatory status may not provide interesting
opportunities for the development and operation of new power generation in the
near future. In particular, Missouri's significantly inexpensive electricity
deters legislators and other key industry participants from pursuing
restructuring activities. In addition, the Missouri Public Service Commission
(the "Missouri PSC") is not enthusiastic about the implications of restructuring
citing other states' examples where electricity rates increased after the
implementation of deregulation and restructuring plans.
Missouri is not actively pursuing any power sector restructuring plans.
Legislation has been introduced every year in the Missouri General Assembly
since 1997. However, none of the bills gathered enough support to reach the
Governor's desk. Since the introduction of those bills, the Missouri PSC has
been examining many of the important issues that are part of the debate over
whether and how Missouri's electric industry should be restructured to introduce
competition.
In 1998, the task force established by the Missouri PSC issued its report
identifying the key issues in the restructuring debate. As a result, of the
diverse makeup of the task force, it did not provide a road map for implementing
restructuring, but rather it offered options and recommendations to help shape
future restructuring discussions.
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Low electricity rates coupled with increasing concerns of market participants
over rising energy costs in the Western states are among the key factors in the
slow progress of regulatory movement in Missouri.
On the mergers and acquisitions front, the Missouri PSC and the Kansas
Corporation Commission approved the proposed merger between Western Resources
and Kansas City Power & Light ("KCP&L") in November 1999. However, in January
2000, KCP&L called off the merger citing the sharp drop in the value of the
merged entity. KCP&L might be still viewed as a candidate for merger with
potential interested parties looming, including Utilicorp and Ameren.
Wisconsin
The future of regulatory activities in Wisconsin became uncertain particularly
after the Wisconsin Public Service Corp. ("WPS") announced it withdrew its
corporate restructuring plan filed with the Wisconsin Public Service Commission.
WPS cited customer identification with the electric shortages and high prices
that plague California. Whether WPS will revise its proposal and refile it is
unknown at this time.
WPS's plan, filed in December 2000, included the transfer of approximately 1,200
MW of wholly owned non-nuclear capacity into an unregulated generating company.
The initiative was an attempt to jump-start competition in Wisconsin while
allowing WPS to retain its generating units and continue to be a market player
in the state.
Over the past fewer summers, Wisconsin has become close to not having adequate
supply, for which large users, including industrials and large commercial
customers revealed a serious concern, especially if power reliability becomes
the responsibility of out-of-state power suppliers.
In response to concerns relating to the reliability of service in Wisconsin, WPS
was directed to ensure that necessary infrastructure improvements are made.
Therefore, the implementation of retail competition has been put on hold. No
timetable has been established as to if or when that issue will be addressed.
Two bills passed by the Wisconsin legislature in the last two years address some
other restructuring issues. Wisconsin Act 204 (enacted in May 1998) requires
Wisconsin transmission owning utilities to join an ISO by June 30, 2000. The act
also streamlined the review and approval process and established time limits on
the review of merchant power plants proposed by Independent Power Producers
("IPPs").
Wisconsin Act 9, which became law in October 1999, provides for fewer
restrictions on non-utility investments by electric utilities, for those
utilities that divest their transmission assets to a state transmission company
by January 1, 2001. Several of the state's largest utilities are among those
transmission-owning utilities that will divest their transmission assets to the
American
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Transmission Company LLC ("ATCLLC") that will become effective January 1, 2002.
ATCLLC will, in turn, join the Midwest ISO.
Midwest ISO
Most of the utilities in the region have supported emerging market structures to
support deregulation and retail competition. As the Midwest ISO received
regulatory approval in 1998, much of its operating infrastructure has been
assembled. This ISO is the largest independent transmission system operator in
the nation and is comprised of 14 electric utility companies covering more than
240,000 miles in 14 Midwestern states. The ISO will manage the flow of
electricity in the Midwest region it serves and is committed to facilitating the
smooth flow of electricity from provider to user. The ISO began initial
operations in June 2001 and is scheduled to be fully operational by December 15,
2001.
Midwest RTO
On December 20, 1999, FERC issued its Order No. 2000. Order 2000 requires all
public utilities that own, operate or control interstate electric transmission
to file by October 15, 2000, a proposal for a Regional Transmission Organization
("RTO"), or, alternatively, a description of any efforts made by the utility to
participate in an RTO, the reasons for not participating and any obstacles to
participation, and any plans for further work toward participation. The RTOs are
scheduled to be operational by December 15, 2001. Commonwealth Edison, CILCO,
Ameren (the holding company of CIPSCO), and Illinois Power have announced their
intent to join either the Midwest ISO or the Alliance RTO.
Each RTO is designed to increase system coordination and improve reliability
through efficient scheduling of transactions as well as transmission and
generation unit maintenance. The RTO will provide a framework for low cost
energy to flow throughout the combined transmission network, making it easier
for both wholesale and retail transactions to take place over a broader market
area. This increased access will allow more participants to compete effectively
in the once monopoly controlled markets. The Midwest ISO and the Alliance RTO
are implementing the Inter-RTO Cooperation ("IRCA") to enhance their system
reliability further.
POWER MARKETING AND TRADING ACTIVITY
As reported by power marketers to FERC in 1997, and outlined in Exhibit 27,
there were over 40,000 GWh of electricity traded in the Midwest, equating to
4,300 MW on average during peak hours. Between 1995 and 1998, trading in the
Midwest experienced significant growth. However, in 1999 reported Midwest power
trading decreased slightly from 1998 levels. Pace believes that the reduced
power trading volumes in the Midwest in 1999 do not represent decreased
wholesale market activity in the region, but represents decreased power
marketers reporting. Due to confidentiality concerns, and to a lesser extent due
to a newly imposed fee on reported transactions by FERC, power marketers
minimize the reporting of their transactional
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volumes, while between 1995-1998, power marketers were motivated to project
themselves as major participants in the region, and consequently they maximized
the reported volume of transactions.
The MAIN electricity market is an actively traded market for wholesale power
transactions. Significant long-term capacity transfers take place between and
within the NERC sub-regions of MAIN. On a daily non-firm basis, economy energy
markets are active with lower cost utilities selling excess power supplies at or
near their marginal cost of production to utilities with higher incremental
costs. Exhibit 28 summarizes the historical net wholesale purchases and sales
for each of the four sub-regions.
Several competing electronic marketplaces for power focused on the MAIN power
market have been established:
o Enporion - whose initial members include Allegheny Energy, Inc.,
XCEL Energy (Northern States Power, Southwestern Public Service, and
Public Service of Colorado), Allete (formerly Minnesota Power), and
PPL Corp.
o Pantellos - whose initial members include American Electric Power,
Carolina Power & Light, Cinergy Corp., Consolidated Edison, Dominion
Resources, DTE Energy, Duke Energy, Edison International, El Paso
Energy, Entergy, FirstEnergy Corp., FPL Group, GPU, Ontario Power
Generation, PG&E Corporation, Public Service Enterprise Group,
Reliant Energy, Sempra Energy, Southern Company, TXU, and
Commonwealth Edison.
o eSpeed - whose equity owners include Dominion Resources, TXU,
Willams, Dynegy, Koch Energy Trading, Coral Energy, and Cantor
Fitzgerald.
o Several electronic exchanges operated by a single power marketer
including Enron Online and Dynegydirect.
o UtilityFrontier - an exchange for members of the American Public
Power Association.
Finally, in a partnership with Commonwealth Edison, Automated Power Exchange
Inc. ("APX") opened the APX Illinois Market, an internet-based exchange for
commercial and wholesale electricity buyers and sellers in the Midwest. Each of
these power exchanges will allow wholesale and retail trading through a computer
system that will facilitate informed management of power supply and increase
market liquidity.
The establishment of the APX and other power exchanges will facilitate trading
in the MAIN market by standardizing bids, providing instant price discovery, and
efficient bid matching. Currently, there is also a NYMEX futures contract with
the delivery point defined as Into Cinergy. However, the over-the-counter market
products are more actively traded.
The liquidity in MAIN is evident in the many quoted spot market prices
referenced in trade publications, such as Dow Jones, Bloomberg PowerLines, Power
Markets Week, and MegaWatt Daily. Pricing points for these indices include,
Northern MAIN, Southern MAIN, Into ComEd, Ameren, CILCO/IP and the ComEd Border.
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Exhibit 27: Power Marketers Volumes Traded in MAIN from 1997 to 1999
================================================================================
BAR GRAPH DISPLAYING POWER MARKETERS
VOLUMES TRADED IN MAIN FROM 1997 TO 1999
Exhibit 28: MAIN Net Wholesale Purchases/(Sales) - MWh
================================================================================
- ----------------------------------------------------------------------------------
Sub-region 1990 1991 1992 1993 1994
- ----------------------------------------------------------------------------------
EMO (808,156) (1,033,412) 1,736,376 3,612,303 3,327,947
- ----------------------------------------------------------------------------------
NI (5,619,593) (699,115) (1,867,162) (12,566,153) (6,436,010)
- ----------------------------------------------------------------------------------
SCI (121,408) (1,748,945) 2,215,128 816,256 3,510,408
- ----------------------------------------------------------------------------------
WUM (156,198) (537,587) 2,751,018 2,949,393 3,760,953
- ----------------------------------------------------------------------------------
Grand Total (6,705,355) (4,019,059) 4,835,360 (5,188,201) 4,163,298
- ----------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------
Sub-region 1995 1996 1997 1998 1999
- ---------------------------------------------------------------------------------
EMO 5,019,241 5,144,526 3,939,301 1,118,919 1,152,666
- ---------------------------------------------------------------------------------
NI (8,679,938) (5,783,388) 1,280,226 5,960,847 (8,076,177)
- ---------------------------------------------------------------------------------
SCI 977,291 (2,770,420) 2,706,498 (1,136,103) (1,017,578)
- ---------------------------------------------------------------------------------
WUM 4,733,352 1,426,727 7,505,488 5,557,470 4,745,127
- ---------------------------------------------------------------------------------
Grand Total 2,049,946 (1,982,555) 15,431,513 11,501,133 (3,195,962)
- ---------------------------------------------------------------------------------
Source : RDI PowerDat.
================================================================================
Exhibit 29 illustrates the daily average peak power price in MAIN through April
2001. MAIN pricing was relatively stable until the summers of 1998 and 1999,
which experienced price spikes resulting from the summer capacity shortages and
higher than average weather conditions, in addition to confusion and speculation
in the markets. After reaching average daily peak prices of over $2,500/MWh and
$1,500/MWh in 1998 and 1999, respectively, summer peak hour prices came down to
their 1997 levels, which were less than $40/MWh. However, due to overall high
gas prices in the region, 2001 average daily prices have so far been above 2000
annual average daily peak prices by nearly 20%. Pace views such high average
annual prices as unsustainable in the long term as new generation is added to
restore supply/demand equilibrium and gas prices
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are expected to revert to their historical averages. Still, price spikes may
continue to occur based on unit operations and outages, weather conditions, and
high demands.
Exhibit 29: Daily Average Peak Pricing in MAIN
================================================================================
GRAPH SHOWING DAILY AVERAGE PEAK PRICING IN
MAIN (IN $/MWh) FROM JANUARY 2, 1997 TO
APRIL 2, 2001.
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Exhibit 30 provides the historical annual average prices and average summer peak
prices for 1997-2001.(31) After nearly tripling in 1998 from 1997, average peak
summer prices reverted to their more stable levels below $40/MWh. However,
average annual peak prices in 2000 are close to summer peak prices, while the
first quarter winter prices are significantly higher than 1997 annual prices due
to high gas prices. As shown in Exhibit 30, there were a record number of 29
days in 2001 where average peak prices were above $50/MWh.
Exhibit 30: MAIN Peak Summer Power Pricing Data (1997-2001)
================================================================================
- ------------------------------------------------------------------------------------------
Year Avg. Peak Average # Of Days # Of Days # Of Days Avg. Peak without
Summer Price Annual Price >$50/MWh >$100/MWh >$150/MWh days >$100/MWh
- ------------------------------------------------------------------------------------------
1997 33.64 25.87 10 3 1 24.37
- ------------------------------------------------------------------------------------------
1998 104.23 50.17 23 11 9 27.90
- ------------------------------------------------------------------------------------------
1999 51.01 46.11 23 12 9 27.10
- ------------------------------------------------------------------------------------------
2000 38.87 37.72 24 2 1 36.35
- ------------------------------------------------------------------------------------------
2001 N/A 44.41 29 0 0 44.41
- ------------------------------------------------------------------------------------------
Source : Power Market Week
================================================================================
- ----------
31 Includes data through April 2001.
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================================================================================
ELECTRICITY DEMAND IN MAIN
================================================================================
Electricity prices in a given market are highly dependent on electricity demand.
To ensure the accuracy of this important variable, Pace developed an independent
demand forecast for each of the three sub-regions in MAIN. This section presents
the following:
o Existing demand profile;
o Published demand forecasts of regional utilities;
o Pace's forecast of future peak and energy demand; and
o Key input assumptions underlying the market study.
LOAD FORECASTING METHODOLOGY
Pace's independent demand forecast was developed according to the methodology
illustrated in Exhibit 31. 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 methodology is the translation of historical hourly
demand levels and forecasted peak demands to create predicted hourly load for
each forecast year.
Typically, the most accurate means of projecting future demand is not realized
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 31,
the foundation of Pace's load forecasting methodology is a bottom-up analytical
approach.
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Exhibit 31: Pace Load Forecasting Methodology
================================================================================
- ---------- ---------
POPULATION CONSUMERS |
- ---------- --------- | Component 1
| | |Peak Demand and
------------------------------------------- |Energy Forecasts
| |
V |
------------ |
Service Area |
Population |
------------ |
| |
- ----------- | -------------- |
Employment ------------]|[------------- Income |
- ----------- | -------------- |
| |
- ----------- | -------------- |
Seasonal ------------]|[------------- Historical |
Factors | Growth Factors |
- ----------- | -------------- |
V |
------------------- |
Multi-Variable |
Regression Analysis |
------------------- |
| |
V |
---------------- |
Peak and |
Energy Forecasts |
---------------- |
........................|......................................V
V
----------- ------------- | Component 2
Hourly Load Historical | Hourly Load
Forecast [--------Hourly Demand | Forecast
----------- Levels |
------------- V
================================================================================
Pace generated its demand forecast based on the historical relationships between
regional demand and multiple historic economic indicators (examples: population,
employment, and income) between 1989-1998. To generate this demand forecast,
Pace:
o Established the historical relationship between net energy for load,
population, employment, and disposable income in MAIN. Pace's
regression analysis indicated a strong correlation between
electricity demand and these economic indicators. Specifically,
Pace's regression analysis produced adjusted R(2), or "fit", in MAIN
of 0.981, 0.911, and 0.987 for WUM, SMAIN-MO, and NI/SMAIN-IL,
respectively.
o Forecast a base demand case based on the historical trends of
population, employment, and income.
o Calculated seasonal energy and summer/winter peaks according to
historical usage patterns and load factors.
Other issues considered with respect to Pace's independent forecast include:
o Normal weather conditions are assumed with no factors included to
simulate extreme weather conditions.
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o The forecast incorporated all demand and energy reductions from
utility dispatchable and non-dispatchable DSM programs as published
in utility demand forecasts. 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 their
stated goals.
ENERGY DEMAND FORECAST RESULTS
Pace developed an independent demand forecast for each of the three sub-regions
in MAIN (i.e., NI, SMAIN, and WUM) based on current and projected economic
conditions. Pace also utilized available forecasts for the inter-connected
sub-regions of IOWA and OECAR. Exhibit 32 illustrates graphically Pace's
backcast and forecast of the aggregated sub-regions in MAIN compared to the
utilities' historical energy demand. The tabular results are shown in Exhibit
33.
The summary of the demand forecast results are outlined below:
o Pace expects that regional electricity demand growth will slow from
historical long-term trends. Historically (1989-1999), MAIN demand
has grown at an average annual rate of 2.26% per year. Pace
forecasts that demand will grow in MAIN at an average annual growth
rate of 1.47% during the Study Period.
o In the near-term (2000-2009), Pace forecasts a higher energy growth
rate than the currently filed utility forecasts for MAIN. Pace
expects a 1.93% average annual growth rate over the period, versus a
utility forecast of 1.50%.
o Pace expects that during the Study Period, electricity demand will
grow at different levels among the sub-regions. SMAIN is expected to
have the lowest annual rate of growth at 1.19% while WUM is expected
to have the highest annual rate of growth at 1.76%. NI is expected
to have 1.55% annual rate of growth.
o Forecasts for the interconnected sub-regions of IOWA and OECAR
reflect annual average growth rates of 1.89% and 2.14%,
respectively, over the Study Period.
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Exhibit 32: Pace Aggregated Energy Demand Forecast (MAIN)
================================================================================
GRAPH OF PACE'S BACKCAST AND FORECAST
OF THE AGGREGATED SUB-REGIONS IN MAIN
COMPARED TO THE UTILITIES' HISTORICAL
ENERGY DEMAND.
================================================================================
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Exhibit 33: Pace MAIN Energy Demand Forecast
================================================================================
- --------------------------------------------------------------------------------
MAIN MAIN MAIN
Utilities' Pace Pace
Energy Forecastst Energy BackCast Energy Forecast
(GWh) (GWh) (GWh)
- --------------------------------------------------------------------------------
Historic Data
- --------------------------------------------------------------------------------
1989 194,535 201,350
1990 197,326 199,492
1991 205,880 202,353
1992 200,250 204,467
1993 208,340 208,575
1994 213,803 211,775
1995 224,380 226,527
1996 234,300 230,120
1997 236,143 234,872
1998 244,073 244,651
1999 243,278 244,701
- --------------------------------------------------------------------------------
Forecast
- --------------------------------------------------------------------------------
2000 248,310 249,532
2001 253,096 254,460
2002 257,057 259,489
2003 261,223 264,619
2004 265,485 269,853
2005 267,645 275,193
2006 271,150 279,824
2007 274,563 284,535
2008 279,284 289,326
2009 284,000 294,201
2010 299,159
2011 303,610
2012 308,128
2013 312,715
2014 317,373
2015 322,101
2016 326,261
2017 330,476
2018 334,747
2019 339,074
2020 343,459
2021 346,876
2022 350,328
2023 353,815
2024 357,338
2025 360,896
2026 364,491
- --------------------------------------------------------------------------------
Growth Rate 1989 - 1999 2.26% 1.97%
- --------------------------------------------------------------------------------
Growth Rate 2000 - 2009 1.50% 1.85%
- --------------------------------------------------------------------------------
Growth Rate 2000 - 2026 1.47%
- --------------------------------------------------------------------------------
================================================================================
Pace expects that the MAIN region will have a continued strong annual demand
growth averaging over 1.93% over the next 10 years. This is a conservative
estimate in comparison with historical MAIN demand, specifically, from 1989 to
1999 MAIN demand increased at a rate of 2.26% per year.
The MAIN energy forecast reflects an aggregation of Pace's independent view of
sub-regional forecasts for SMAIN, NI, and WUM. As shown in Exhibit 34, SMAIN is
expected to grow at an annual average rate of 1.19% from 96,234 GWh in 2000 to
130,928 GWh in 2026, NI is expected to have slightly higher average annual
growth rate of 1.55% to reach 136,288 GWh in
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2026, and WUM is expected to increase from year 2000 loads of 61,822 GWh to
97,275 GWh in 2026. This results in an average annual growth rate of 1.76%
making it the highest average annual growth rate of the MAIN sub-regions.
Exhibit 34: Pace's Sub-Regional Energy and Forecast for MAIN - GWh
================================================================================
- --------------------------------------------------------------------------------------------------------------
PACE'S ENERGY FORECAST UTILITIES'
(GWh) ENERGY
- --------------------------------------------------------------------------------------------------------------
NI SMAIN WUM Total Forecast
- --------------------------------------------------------------------------------------------------------------
2000 91,475 96,234 61,822 249,532 248,310
2001 93,386 97,783 63,291 254,460 253,096
2002 95,338 99,357 64,794 259,489 257,057
2003 97,330 100,956 66,333 264,619 261,223
2004 99,363 102,581 67,908 269,853 265,485
2005 101,440 104,233 69,521 275,193 267,645
2006 103,240 105,658 70,925 279,824 271,150
2007 105,073 107,104 72,358 284,535 274,563
2008 106,938 108,569 73,819 289,326 279,284
2009 108,837 110,054 75,310 294,201 284,000
2010 110,769 111,560 76,831 299,159
2011 112,503 112,906 78,200 303,610
2012 114,265 114,269 79,594 308,128
2013 116,054 115,648 81,013 312,715
2014 117,871 117,044 82,457 317,373
2015 119,717 118,457 83,927 322,101
2016 121,341 119,696 85,224 326,261
2017 122,988 120,948 86,541 330,476
2018 124,656 122,213 87,878 334,747
2019 126,347 123,491 89,236 339,074
2020 128,061 124,783 90,615 343,459
2021 129,397 125,787 91,692 346,876
2022 130,747 126,799 92,782 350,328
2023 132,111 127,819 93,886 353,815
2024 133,489 128,847 95,002 357,338
2025 134,881 129,884 96,132 360,896
2026 136,288 130,928 97,275 364,491
- --------------------------------------------------------------------------------------------------------------
Growth Rate 1989-1999 2.10% 2.17% 2.65% 2.26% 2.55%
- --------------------------------------------------------------------------------------------------------------
Growth Rate 2000-2009 1.95% 1.50% 2.22% 1.85% 1.50%
- --------------------------------------------------------------------------------------------------------------
Growth Rate 2000-2026 1.55% 1.19% 1.76% 1.47%
- --------------------------------------------------------------------------------------------------------------
================================================================================
To simplify analysis for non-MAIN demand regions, Pace utilized available
forecasts to depict demand for the sub-regions of IOWA and OECAR given their
direct interconnect with the NI sub-region of MAIN. Specifically, annual demand
forecasts for IOWA, consisting of the MidAmerican, Alliant West, and Muscatine
Power & Water control areas, were extracted from the Mid-Continent Area Power
Pool ("MAPP") 1999 MAPP Load and Capability Report. An annual energy forecast
for OECAR was compiled by aggregating the Northern Indiana Public Service
Company ("NIPS") forecast (as reported in the FERC Form 714) with Pace's
independent forecast of demand in the service territory of the Indiana Michigan
Power Company. Resulting forecasts are displayed in Exhibit 35.
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Exhibit 35: Annual Energy and Peak Demand Forecasts for Interconnected
Sub-Regions
================================================================================
- ------------------------------------------------------------------------------------------
IOWA OECAR
--------------------------------------------------------------------
Summer Winter Summer Winter
Net Peak Peak Net Peak Peak
Energy Demand Demand Energy Demand Demand
Year (GWh) (MW) (MW) (GWh) (MW) (MW)
- ------------------------------------------------------------------------------------------
2000 40,851 7,821 6,035 34,753 5,935 5,338
2001 41,481 7,941 6,161 35,565 6,074 5,492
2002 42,398 8,117 6,298 36,343 6,207 5,612
2003 43,261 8,282 6,426 37,115 6,339 5,732
2004 44,145 8,451 6,521 37,902 6,473 5,821
2005 45,031 8,621 6,689 38,694 6,608 5,976
2006 45,896 8,787 6,817 39,518 6,749 6,103
2007 46,769 8,954 6,947 40,369 6,895 6,234
2008 47,608 9,114 7,033 41,241 7,043 6,334
2009 48,500 9,285 7,204 42,115 7,193 6,504
2010 49,409 9,459 7,339 43,011 7,346 6,642
2011 50,335 9,637 7,477 43,927 7,502 6,784
2012 51,279 9,817 7,575 44,865 7,662 6,891
2013 52,240 10,001 7,760 45,825 7,826 7,077
2014 53,219 10,189 7,905 46,807 7,994 7,229
2015 54,216 10,380 8,053 47,813 8,166 7,384
2016 55,233 10,574 8,159 48,843 8,342 7,502
2017 56,268 10,772 8,358 49,897 8,522 7,706
2018 57,322 10,974 8,514 50,977 8,706 7,872
2019 58,397 11,180 8,674 52,082 8,895 8,043
2020 59,491 11,389 8,788 53,214 9,088 8,173
2021 60,585 11,598 8,902 54,346 9,281 8,303
2022 61,679 11,807 9,016 55,478 9,474 8,433
2023 62,773 12,016 9,130 56,610 9,667 8,563
2024 63,955 12,241 9,295 57,823 9,873 8,740
2025 65,160 12,471 9,463 59,061 10,084 8,920
2026 66,388 12,705 9,634 60,327 10,299 9,104
- ------------------------------------------------------------------------------------------
Growth Rate 2000-2009 1.73% 1.73% 1.79% 1.94% 1.94% 2.00%
- ------------------------------------------------------------------------------------------
Growth Rate 2000-2026 1.87% 1.87% 1.87% 2.13% 2.13% 2.13%
- ------------------------------------------------------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
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Pace also developed the summer and winter peak demand for each sub-region based
on historical sub-regional load factors. As shown in Exhibit 36, summer peak
demand in the MAIN power market is forecast to increase from 50,066 MW in 2000
to 73,131 MW by 2026, an average annual growth rate of 1.47%. In the NI
sub-region where the Project is located, summer peak demand is forecast to
increase at an annual average rate of 1.55% between 2000 and 2026.
Exhibit 36: Pace's Sub-Regional Peak Demand Forecast for MAIN - MW
================================================================================
- ------------------------------------------------------------------------------------------------------------------------
Pace
NI SMAIN WUM Non-Coincident Peak
- ------------------------------------------------------------------------------------------------------------------------
Year Summer Winter Summer Winter Summer Winter Summer Winter
- ------------------------------------------------------------------------------------------------------------------------
2000 18,353 14,640 19,308 15,402 12,404 9,894 50,066 39,935
2001 18,737 14,946 19,619 15,649 12,699 10,129 51,055 40,724
2002 19,128 15,258 19,935 15,901 13,000 10,370 52,063 41,529
2003 19,528 15,577 20,256 16,157 13,309 10,616 53,093 42,350
2004 19,936 15,902 20,582 16,417 13,625 10,868 54,143 43,188
2005 20,353 16,235 20,913 16,682 13,949 11,126 55,214 44,042
2006 20,714 16,523 21,199 16,910 14,230 11,351 56,143 44,783
2007 21,082 16,816 21,489 17,141 14,518 11,580 57,089 45,537
2008 21,456 17,115 21,783 17,376 14,811 11,814 58,050 46,304
2009 21,837 17,418 22,081 17,613 15,110 12,053 59,028 47,084
2010 22,224 17,728 22,383 17,854 15,415 12,296 60,023 47,878
2011 22,573 18,005 22,653 18,070 15,690 12,515 60,916 48,590
2012 22,926 18,287 22,927 18,288 15,970 12,738 61,822 49,313
2013 23,285 18,574 23,203 18,509 16,254 12,965 62,743 50,047
2014 23,650 18,864 23,484 18,732 16,544 13,197 63,677 50,793
2015 24,020 19,160 23,767 18,958 16,839 13,432 64,626 51,550
2016 24,346 19,420 24,016 19,156 17,099 13,639 65,460 52,215
2017 24,676 19,683 24,267 19,357 17,363 13,850 66,306 52,890
2018 25,011 19,950 24,521 19,559 17,632 14,064 67,163 53,573
2019 25,350 20,221 24,777 19,764 17,904 14,281 68,031 54,266
2020 25,694 20,495 25,036 19,970 18,181 14,502 68,911 54,968
2021 25,962 20,709 25,238 20,131 18,397 14,675 69,597 55,515
2022 26,233 20,925 25,441 20,293 18,616 14,849 70,289 56,067
2023 26,507 21,143 25,645 20,456 18,837 15,026 70,989 56,625
2024 26,783 21,364 25,852 20,621 19,061 15,204 71,696 57,189
2025 27,062 21,587 26,060 20,787 19,288 15,385 72,410 57,758
2026 27,345 21,812 26,269 20,954 19,517 15,568 73,131 58,334
- ------------------------------------------------------------------------------------------------------------------------
Growth Rate 2000-2009 1.95% 1.95% 1.50% 1.50% 2.22% 2.22% 1.85% 1.85%
- ------------------------------------------------------------------------------------------------------------------------
Growth Rate 2000-2026 1.55% 1.55% 1.19% 1.19% 1.76% 1.76% 1.47% 1.47%
- ------------------------------------------------------------------------------------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
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Exhibit 37 provides a summary of Pace's forecast of energy and peak demand for
the MAIN power market and the interconnected sub-regions of IOWA and OECAR.
Between 2000 and 2026, energy demand is forecast to increase at an annual
average rate of 1.60 % in the MAIN power market and the interconnected
sub-regions of IOWA and OECAR, while summer peak demand and winter peak demand
are forecast to increase by 32,251 MW and 26,037 MW respectively during the same
period.
Exhibit 37: Pace's Energy Demand and Peak Forecasts - MAIN & Interconnected
Sub-Regions
================================================================================
- --------------------------------------------------------------
Summer Winter
Peak Peak
Energy Demand Demand
Year (GWh) (MW) (MW)
- --------------------------------------------------------------
2000 325,136 63,822 51,308
2001 331,506 65,070 52,377
2002 338,230 66,387 53,439
2003 344,995 67,714 54,508
2004 351,901 69,067 55,530
2005 358,918 70,443 56,707
2006 365,238 71,679 57,703
2007 371,674 72,938 58,718
2008 378,175 74,207 59,671
2009 384,816 75,506 60,792
2010 391,578 76,828 61,859
2011 397,872 78,055 62,851
2012 404,272 79,301 63,779
2013 410,779 80,570 64,884
2014 417,399 81,860 65,927
2015 424,131 83,172 66,987
2016 430,336 84,376 67,876
2017 436,640 85,600 68,954
2018 443,046 86,843 69,959
2019 449,552 88,106 70,983
2020 456,165 89,388 71,929
2021 461,807 90,478 72,812
2022 467,485 91,572 73,700
2023 473,198 92,675 74,593
2024 478,990 93,793 75,499
2025 484,860 94,925 76,416
2026 490,811 96,073 77,346
- --------------------------------------------------------------
Growth Rate 2000-2009 1.89% 1.89% 1.90%
- --------------------------------------------------------------
Growth Rate 2000-2026 1.60% 1.59% 1.59%
- --------------------------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
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HOURLY LOAD FORECASTING
The forecast of overall energy growth is not the only element needed to
accurately characterize future energy 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 Pace's load forecasting methodology is the projection of hourly demand
values.
Pace's methodology applies 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 contains the highest level of
detail to reflect not only the cost to serve certain levels 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.
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:
o Step 1: The first step involves aggregating actual utility hourly
loads as reported to the FERC. This aggregation creates an
integrated hourly system load profile for the MAIN market area.
o Step 2: The second step involves applying annual growth factors and
seasonal peak demand forecasts to the base system hourly load file
(created in step 1) to create an hourly demand file for each year in
the Study Period.
Pace assumed that the system load shape that exists currently would be
maintained throughout the Study Period. 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.
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================================================================================
MAIN POWER GENERATION RESOURCES
================================================================================
The MAIN market is dominated by base-load coal-fired plants and large nuclear
stations, which comprised approximately 71%(32) of the installed capacity in the
region in 2001. For the most part, these generation resources operate at high
capacity factors, have low capital costs (with the exception of various nuclear
power stations), and are fueled by low priced fuels.
Pace reviewed and assessed the existing and expected power generation resource
mix for the MAIN region. This section presents the following:
o Profiles of existing generation resources;
o Determination of the fixed capital and operational costs of these
resources; and
o Outlines the assumptions underlying the type and cost of new
capacity additions.
DEMAND PROFILE
In 1999, total energy demand in MAIN was 243,278 GWh, approximately 6% of total
U.S. demand. Exhibit 38 lists the major utilities in the Midwest and their
respective 1999 estimated summer and winter peak demand and annual retail sales.
Exhibit 38: Major Utilities 1999 Demand
================================================================================
- --------------------------------------------------------------------------------
Peak Load Peak Load Retail
Summer Winter Sales
Company Name MW MW MWh
- --------------------------------------------------------------------------------
Commonwealth Edison Co. 21,243 19,424 83,500,597
- --------------------------------------------------------------------------------
Ameren 10,021 8,559 33,565,723
- --------------------------------------------------------------------------------
Wisconsin Electric Power Co. 5,974 5,497 26,877,397
- --------------------------------------------------------------------------------
Illinois Power Co. 3,694 3,398 18,215,452
- --------------------------------------------------------------------------------
Wisconsin Power & Light Co. 2,397 2,181 9,504,473
- --------------------------------------------------------------------------------
Wisconsin Public Service Corp. 1,751 1,611 9,971,356
- --------------------------------------------------------------------------------
Central Illinois Light Co. 1,235 1,142 6,073,448
- --------------------------------------------------------------------------------
Electrical Energy, Inc. 1,731 1,592 7,013,929
- --------------------------------------------------------------------------------
Madison Gas & Electric Co. 1,731 1,558 2,916,533
- --------------------------------------------------------------------------------
Wisconsin Public Power Inc. 602 560 1,014,298
- --------------------------------------------------------------------------------
Central Electric Power Coop. 571 525 962,068
- --------------------------------------------------------------------------------
Soyland Power Coop, Inc. 494 454 832,332
- --------------------------------------------------------------------------------
Springfield Water, Light & Power 395 367 1,684,179
- --------------------------------------------------------------------------------
Total 51,839 46,868 202,131,785
- --------------------------------------------------------------------------------
Source: EIA-411
================================================================================
- --------
32 Summer Capacity.
- --------------------------------------------------------------------------------
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As shown in Exhibit 39, Pace developed an independent forecast of seasonal peak
demand and net energy for load for purposes of the market simulation.
Exhibit 39 indicates that Pace expects both summer peak demand and net energy
for load to increase at an average rate of 1.88% per year over the next 9 years.
Specifically, summer peak demand is projected to grow from 65,070 MW in 2001 to
75,506 MW by the year 2009. Net energy for load is expected to escalate from a
base of 330,142 GWh in 2001 to 374,615 GWh by the year 2009.
Exhibit 39: MAIN Demand and Energy Requirements Forecast
================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006 2007 2008 2009
- ------------------------------------------------------------------------------------------------------------------------------------
Peak Demand Summer (MW) 65,070 66,387 67,714 69,067 70,443 71,679 72,938 74,207 75,506
- ------------------------------------------------------------------------------------------------------------------------------------
Peak Demand Winter (MW) 52,377 53,439 54,508 55,530 56,707 57,703 58,718 59,671 60,792
- ------------------------------------------------------------------------------------------------------------------------------------
Net Energy for Load (GWh) 331,506 338,230 344,995 351,901 358,918 365,238 371,674 378,175 384,816
- ------------------------------------------------------------------------------------------------------------------------------------
System Load Factor 58.16% 58.16% 58.16% 58.16% 58.16% 58.17% 58.17% 58.18% 58.18%
- ------------------------------------------------------------------------------------------------------------------------------------
Summer Change (MW) 1,318 1,326 1,353 1,376 1,236 1,258 1,269 1,299
Winter Change (MW) 1,062 1,069 1,022 1,178 996 1,015 953 1,121
Energy Change (GWh) 6,723 6,765 6,906 7,017 6,320 6,436 6,502 6,640
Summer Change % 2.03% 2.00% 2.00% 1.99% 1.75% 1.76% 1.74% 1.75%
Winter Change % 2.03% 2.00% 1.87% 2.12% 1.76% 1.76% 1.62% 1.88%
Energy Change % 2.03% 2.00% 2.00% 1.99% 1.76% 1.76% 1.75% 1.76%
- ------------------------------------------------------------------------------------------------------------------------------------
Avg. Summer Peak Growth (2001-2009) 1.88%
Avg. Winter Peak Growth (2001-2009) 1.88%
Avg. Energy Growth (2001-2009) 1.88%
- ------------------------------------------------------------------------------------------------------------------------------------
* Includes interconnected sub-regions of IOWA and OECAR.
================================================================================
Also shown in Exhibit 39, the MAIN market had a load factor of over 58.16% in
2001. The load factor is expected to stay stable through 2009.
Exhibit 40 illustrates that Pace is anticipating an overall system reserve
margin during the summer months of 24.72% of peak demand in 2001. (Winter
reserve margin projections are shown in Exhibit 41). Despite the addition of new
merchant projects, reserve margins are expected to decline as demand absorbs
excess supplies to reach 15.77% in 2009.
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Exhibit 40: MAIN Demand and Energy Reserve Margin Forecast - Summer
================================================================================
- -----------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006 2007 2008 2009
- -----------------------------------------------------------------------------------------------------------------
Net Peak Demand (MW) 65,070 66,387 67,714 69,067 70,443 71,679 72,938 74,207 75,506
- -----------------------------------------------------------------------------------------------------------------
Total Owned Capacity 74,966 75,995 78,099 78,099 78,099 79,466 80,355 82,239 82,827
Inoperable Capacity 0 0 0 0 0 0 0 0 0
Net Operable Capacity 74,966 75,995 78,099 78,099 78,099 79,466 80,355 82,239 82,827
Interruptible Demand 5,690 5,690 5,690 5,690 5,690 5,690 5,690 5,690 5,690
Net Capacity Purchases 500 500 300 300 300 -1100 -1100 -1100 -1100
Planned Capacity Reserve 81,156 82,185 84,089 84,089 84,089 84,056 84,945 86,829 87,417
- -----------------------------------------------------------------------------------------------------------------
Reserve Margin (MW) 16,086 15,797 16,375 15,022 13,645 12,377 12,007 12,622 11,911
Reserve Margin (%) 24.72% 23.80% 24.18% 21.75% 19.37% 17.27% 16.46% 17.01% 15.77%
- -----------------------------------------------------------------------------------------------------------------
* Includes interconnected sub-regions of IOWA and OECAR.
================================================================================
Exhibit 41: MAIN Demand and Energy Reserve Margin Forecast - Winter
================================================================================
- -----------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006 2007 2008 2009
- -----------------------------------------------------------------------------------------------------------------
Net Peak Demand (MW) 52,377 53,439 54,508 55,530 56,707 57,703 58,718 59,671 60,792
- -----------------------------------------------------------------------------------------------------------------
Total Owned Capacity 77,702 78,797 81,035 81,035 81,035 82,490 83,435 85,440 86,065
Inoperable Capacity 0 0 0 0 0 0 0 0 0
Net Operable Capacity 77,702 78,797 81,035 81,035 81,035 82,490 83,435 85,440 86,065
Interruptible Demand 2,331 2,331 2,331 2,331 2,331 2,331 2,331 2,331 2,331
Net Capacity Purchases 500 500 300 300 300 -1100 -1100 -1100 -1100
Planned Capacity Reserve 80,533 81,628 83,666 83,666 83,666 83,721 84,666 86,671 87,296
- -----------------------------------------------------------------------------------------------------------------
Reserve Margin (MW) 28,156 28,189 29,158 28,137 26,959 26,018 25,948 27,000 26,504
Reserve Margin (%) 53.76% 52.75% 53.49% 50.67% 47.54% 45.09% 44.19% 45.25% 43.60%
- -----------------------------------------------------------------------------------------------------------------
* Includes interconnected sub-regions of IOWA and OECAR
================================================================================
GENERATION PROFILE
Pace's forecast of projected capacity additions required to meet generation
requirements between 2001 and 2009 for the three MAIN sub-regions, and the two
interconnected sub-regions of IOWA and OECAR is outlined in Exhibit 42.
The MAIN market is dominated by base-load capacity, with coal-fired, nuclear and
hydro capacity, representing 73% of installed generation capacity in 2001.
Combustion turbine plants and combined cycle plants with 19% and 4%
respectively, account for the majority of the remaining installed capacity.
By 2009, Pace forecasts that coal-fired, nuclear and hydro capacity will decline
to 67% of installed capacity, combustion turbine capacity will increase to 21%
of installed capacity, and combined cycle capacity will more than double is
share of installed capacity to 9%.
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Exhibit 42: MAIN Market Generation Summer Capacity - MW
================================================================================
- --------------------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006 2007 2008 2009
- --------------------------------------------------------------------------------------------------------------------------
Coal 37,849 37,849 37,849 37,849 37,849 37,849 37,849 37,849 37,849
Nuclear 15,810 15,810 15,810 15,810 15,810 15,810 15,810 15,810 15,810
Wind 53 53 53 53 53 53 53 53 53
Hydro 1,061 1,061 1,061 1,061 1,061 1,061 1,061 1,061 1,061
ST-Gas 2,725 2,725 2,725 2,725 2,725 2,725 2,725 2,725 2,725
ST-Oil 334 334 334 334 334 334 334 334 334
New CT 8,709 9,099 9,099 9,099 9,099 10,218 10,857 11,496 11,336
New CC 2,749 3,388 5,491 5,491 5,491 5,741 5,990 7,235 7,982
Old CT 5,677 5,677 5,677 5,677 5,677 5,677 5,677 5,677 5,677
Net Purchase 500 500 300 300 300 -1,100 -1,100 -1,100 -1,100
- --------------------------------------------------------------------------------------------------------------------------
Total Capacity 75,466 76,495 78,399 78,399 78,399 78,366 79,255 81,139 81,727
- --------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006 2007 2008 2009
- --------------------------------------------------------------------------------------------------------------------------
Coal 50.15% 49.48% 48.28% 48.28% 48.28% 48.30% 47.76% 46.65% 46.31%
Nuclear 20.95% 20.67% 20.17% 20.17% 20.17% 20.17% 19.95% 19.49% 19.34%
Wind 0.07% 0.07% 0.07% 0.07% 0.07% 0.07% 0.07% 0.07% 0.06%
Hydro 1.41% 1.39% 1.35% 1.35% 1.35% 1.35% 1.34% 1.31% 1.30%
ST-Gas 3.61% 3.56% 3.48% 3.48% 3.48% 3.48% 3.44% 3.36% 3.33%
ST-Oil 0.44% 0.44% 0.43% 0.43% 0.43% 0.43% 0.42% 0.41% 0.41%
New CT 11.54% 11.89% 11.61% 11.61% 11.61% 13.04% 13.70% 14.17% 13.87%
New CC 3.64% 4.43% 7.00% 7.00% 7.00% 7.33% 7.56% 8.92% 9.77%
Old CT 7.52% 7.42% 7.24% 7.24% 7.24% 7.24% 7.16% 7.00% 6.95%
Net Purchase 0.66% 0.65% 0.38% 0.38% 0.38% -1.40% -1.39% -1.36% -1.35%
- --------------------------------------------------------------------------------------------------------------------------
Total Capacity 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%
- --------------------------------------------------------------------------------------------------------------------------
* Includes interconnected sub-regions of IOWA and OECAR
================================================================================
Generating Unit Cost Profile
Pace reviewed the cost profile of the existing installed capacity base for the
MAIN market region. 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 to assess who the competitors will be in the market and
what cost advantages a power plant must have over existing facilities. Exhibit
43 summarizes regional fixed and variable generation costs up through 1999.
As shown, in 1996 WUM was the low cost sub-region at approximately $38.02/MWh
followed by SMAIN at $44.66/MWh and NI at $61.88/MWh. In 1999, the average cost
of generating power in SMAIN fell to $30.71/MWh, while WUM increased slightly to
$40.02/MWh and NI fell to $57.12/MWh, which was near its 1996 average after
climbing to $71.32/MWh in 1998. After 1997, SMAIN fell below WUM as the lowest
cost region due to the write-down of the Clinton nuclear plant by Illinois
Power. This write-down is reflected in the decrease in total fixed costs of
nuclear capacity of over $11/MWh and depicting an imprecise picture of SMAIN
generation fixed costs for 1997. However, given the sale of the Clinton nuclear
plant to AmerGen, Pace will maintain the facility in the generation mix. For the
entire region, total system costs averaged $44.47/MWh in 1999 with nearly
two-thirds of this cost attributable to fixed costs, or $29.52/MWh.
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Exhibit 43: MAIN Embedded Cost Summary
================================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
1996 1997 1998 1999
- ----------------------------------------------------------------------------------------------------------------------------------
Sub-Region Data 1996 1997 1998 1999 $/MWh $/MWh $/MWh $/MWh
==================================================================================================================================
NI Sum of Fuel Total $ 961,808,077 936,063,824 820,637,678 1,152,075,715 11.57 11.41 10.27 12.22
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Variable O&M Total $ 197,255,375 219,996,543 241,293,621 222,344,078 2.37 2.68 3.02 2.36
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Fixed O&M Total $ 789,032,278 879,997,926 965,779,231 889,380,525 9.49 10.73 12.09 9.43
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Fixed Total $ 2,962,418,187 3,038,364,139 3,669,238,827 3,118,544,666 35.63 37.03 45.93 33.08
- ----------------------------------------------------------------------------------------------------------------------------------
Total Variable 1,160,951,766 1,158,349,416 1,062,942,841 1,376,190,154 13.96 14.12 13.31 14.63
- ----------------------------------------------------------------------------------------------------------------------------------
Total Fixed 3,751,450,465 3,918,362,065 4,635,018,058 4,007,925,191 45.12 47.76 58.02 42.52
- ----------------------------------------------------------------------------------------------------------------------------------
Total Costs 4,912,402,231 5,076,711,481 5,697,960,899 5,384,115,345 59.08 61.88 71.32 57.12
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Total Gen 83,151,972 82,045,735 79,889,337 94,265,530
==================================================================================================================================
WUM Sum of Fuel Total $ 552,081,257 582,631,817 543,955,077 525,926,527 12.83 12.96 12.24 11.48
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Variable O&M Total $ 55,631,545 173,131,022 192,019,226 176,641,860 1.29 3.85 4.32 3.86
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Fixed O&M Total $ 226,280,266 254,913,651 271,691,668 278,672,751 5.26 5.67 6.11 6.08
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Fixed Total $ 802,525,593 822,834,626 832,330,669 852,124,350 18.64 18.31 18.72 18.64
- ----------------------------------------------------------------------------------------------------------------------------------
Total Variable 607,712,802 755,762,839 735,974,303 702,568,387 14.12 16.81 16.56 15.34
- ----------------------------------------------------------------------------------------------------------------------------------
Total Fixed 1,028,805,859 1,077,748,277 1,104,022,337 1,130,797,101 23.92 23.96 24.84 24.69
- ----------------------------------------------------------------------------------------------------------------------------------
Total Costs 1,636,518,661 1,833,511,116 1,839,996,640 1,833,365,488 38.02 40.77 41.39 40.02
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Total Gen 43,042,529 44,972,276 44,453,161 45,808,182
==================================================================================================================================
SMAIN Sum of Fuel Total $ 1,042,462,420 1,055,588,534 978,076,639 992,441,151 14.54 14.26 13.71 13.81
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Variable O&M Total $ 95,575,437 84,646,956 91,945,197 95,371,614 1.33 1.14 1.29 1.33
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Fixed O&M Total $ 382,636,889 338,935,302 368,015,974 381,935,884 5.34 4.58 5.16 5.31
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Fixed Total $ 1,681,964,041 959,876,784 955,929,404 736,454,876 23.46 12.97 13.39 10.25
- ----------------------------------------------------------------------------------------------------------------------------------
Total Variable 1,138,037,857 1,140,235,490 1,070,021,836 1,087,812,765 15.87 15.41 14.99 15.14
- ----------------------------------------------------------------------------------------------------------------------------------
Total Fixed 2,064,600,930 1,298,812,086 1,323,945,378 1,118,390,760 28.79 17.55 18.55 15.56
- ----------------------------------------------------------------------------------------------------------------------------------
Total Costs 3,202,638,787 2,439,047,576 2,393,967,214 2,206,203,525 44.66 32.96 33.54 30.71
- ----------------------------------------------------------------------------------------------------------------------------------
Sum of Total Gen 71,704,301 74,001,500 71,366,113 71,860,818
==================================================================================================================================
Total Sum of Fuel Total $ 2,556,351,754 2,574,284,175 2,342,669,394 2,670,443,393 12.92 12.81 11.97 12.60
- ----------------------------------------------------------------------------------------------------------------------------------
Total Sum of Variable O&M Total $ 348,462,357 477,774,521 525,258,044 494,357,552 1.76 2.38 2.68 2.33
- ----------------------------------------------------------------------------------------------------------------------------------
Total Sum of Fixed O&M Total $ 1,397,949,433 1,473,846,879 1,605,486,873 1,549,989,160 7.06 7.33 8.20 7.31
- ----------------------------------------------------------------------------------------------------------------------------------
Total Sum of Fixed Total $ 5,446,907,820 4,821,075,549 5,457,498,899 4,707,123,891 27.52 23.98 27.89 22.21
- ----------------------------------------------------------------------------------------------------------------------------------
Total Variable 2,906,702,425 3,054,347,745 2,868,938,980 3,166,571,306 14.69 15.19 14.66 14.94
- ----------------------------------------------------------------------------------------------------------------------------------
Total Fixed 6,844,857,253 6,294,922,428 7,062,985,772 6,257,113,051 34.59 31.31 36.09 29.52
- ----------------------------------------------------------------------------------------------------------------------------------
Total Costs 9,751,559,678 9,349,270,173 9,931,924,752 9,423,684,357 49.28 46.51 50.75 44.47
- ----------------------------------------------------------------------------------------------------------------------------------
Total Sum of Total Gen 197,898,802 201,019,511 195,708,611 211,934,530
- ----------------------------------------------------------------------------------------------------------------------------------
Source: RDI PowerDat.
================================================================================
Generating Unit Fuel Mix
Exhibit 44 represents Pace's forecast of the mix of fuels used for electrical
generation in the MAIN market (including the interconnected sub-regions of IOWA
and OECAR) through 2025. The following are our observations:
o In 2001, base-load generation dominates the MAIN market with 93.76% of
generation, with coal-fired generation accounting for 64.06%, nuclear
28.36%, hydro 1.21%, and
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wind 0.13%. By 2025, base-load generation is forecast to account for a
68.86% share of generation.
o In 2001, gas-fired generation accounts for only 6.21% of generation in the
MAIN market. This value is forecast to increase steadily, reaching 31.12%
by 2025, as gas-fired combined cycle and combustion turbine plants have
become the near universal choice for announced capacity additions in the
MAIN market.
Exhibit 44: MAIN Generation Mix by Fuel Type
================================================================================
- ----------------------------------------------------------------------------------
FUEL 2001 2005 2010 2015 2020 2025
- ----------------------------------------------------------------------------------
COAL 64.06% 60.71% 57.01% 54.08% 51.22% 48.50%
GAS 6.21% 11.78% 17.80% 22.70% 27.07% 31.12%
NUCLEAR 28.36% 26.29% 24.09% 22.21% 20.75% 19.49%
OIL 0.02% 0.02% 0.03% 0.02% 0.04% 0.02%
WATER 1.21% 1.08% 0.96% 0.89% 0.83% 0.78%
WIND 0.13% 0.12% 0.11% 0.10% 0.10% 0.09%
- ----------------------------------------------------------------------------------
Grand Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%
- ----------------------------------------------------------------------------------
* Includes interconnected sub-regions of IOWA and OECAR
================================================================================
MAIN Nuclear Unit Assessment
Accounting for approximately 50% of installed capacity in the Midwest in 2001,
nuclear capacity has a dominant presence in the Midwest power market. However,
the nuclear industry has been subject to significant changes in recent years and
there is still much uncertainty regarding future operations of a number of
nuclear units in the Midwest as well as throughout the U.S. Pace reviewed unit
operations, down time, historic plant performance, and recent market trends to
assess nuclear capacity in the Midwest and establish assumptions regarding
capacity retirement. Exhibit 45 provides a list of existing nuclear capacity
located in the Midwest, the current Nuclear Regulatory Commission ("NRC")
license expiration date, and a brief summary of changes in operating status. As
shown in Exhibit 45, the Zion nuclear plant was retired in 1998 and therefore
was not included in Pace's forecast.
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Exhibit 45: MAIN Nuclear Units
================================================================================
============================================================================================================
Unit Capacity License
Plant Name Utility (MW) Expiration
- ------------------------------------------------------------------------------------------------------------
Quad Cities Unit 1 Commonwealth Edison Co. Iowa/Illinois Gas & Electric 810 Dec 2012
- ------------------------------------------------------------------------------------------------------------
Quad Cities Unit 2 Commonwealth Edison Co. Iowa/Illinois Gas & Electric 810 Dec 2012
- ------------------------------------------------------------------------------------------------------------
La Salle Unit 1 Commonwealth Edison Co. 1,036 May 2022
- ------------------------------------------------------------------------------------------------------------
La Salle Unit 2 Commonwealth Edison Co. 1,036 Dec 2023
- ------------------------------------------------------------------------------------------------------------
Zion Commonwealth Edison Co. 1,040 Retired in 1998
- ------------------------------------------------------------------------------------------------------------
Clinton Illinois Power Co. 944 Sep 2026
- ------------------------------------------------------------------------------------------------------------
Callaway (MO) Ameren 1,174 Oct 2024
- ------------------------------------------------------------------------------------------------------------
Point Beach 1 Wisconsin Electric Power Co. 524 Oct 2010
- ------------------------------------------------------------------------------------------------------------
Point Beach 2 Wisconsin Electric Power Co. 524 Oct 2013
- ------------------------------------------------------------------------------------------------------------
Wisconsin Public Service Corp. Madison Gas &
Kewaunee Electric Co. Wisconsin Power & Light Co. 498 Dec 2013
- ------------------------------------------------------------------------------------------------------------
Dresden 2 Commonwealth Edison Co. 794 Jan 2010
- ------------------------------------------------------------------------------------------------------------
Dresden 3 Commonwealth Edison Co. 794 Jan 2011
- ------------------------------------------------------------------------------------------------------------
Byron 1 Commonwealth Edison Co. 1,175 Oct 2022
- ------------------------------------------------------------------------------------------------------------
Byron 2 Commonwealth Edison Co. 1,175 Nov 2026
- ------------------------------------------------------------------------------------------------------------
Braidwood 1 Commonwealth Edison Co. 1,175 Oct 2026
- ------------------------------------------------------------------------------------------------------------
Braidwood 2 Commonwealth Edison Co. 1,175 Dec 2027
- ------------------------------------------------------------------------------------------------------------
Source: RDI PowerDat.
================================================================================
Though three of the plants (Clinton, LaSalle, and Quad Cities) were included on
the NRC's 1998 Watch List, Pace expects that all three will operate at least
through their license term. Commonwealth Edison restarted La Salle Unit 2 in the
spring of 1999, has improved the performance of all its nuclear plants, and
implemented changes in management in a marked effort to become a top nuclear
operator. For these reasons as well as to maintain a level of conservativeness,
Pace will not assume the retirement of any nuclear units prior to license
expiration.
EXPANSION UNIT CHARACTERIZATION AND COSTS
In evaluating potential generation technologies for meeting future demand
requirements in the MAIN region, Pace assessed each technology's maturity level,
operating history, and duty cycle. Based on Pace's review of available
generation technologies and consultation with equipment manufacturers, three
generic types of technologies were designated as potential candidates for
meeting future demand requirements for purposes of this analysis:
o Pulverized-Coal--to meet base load requirements.
o Combined Cycle--to meet intermediate through base load requirements.
o Combustion Turbine--to meet peak load requirements.
The characteristics of these standard units are detailed in Exhibit 46. These
expansion unit costs drive the expansion-planning module to determine the
necessary capacity additions to meet projected demand and provide reserves. The
expansion-planning module determines the optimum mix of combustion turbine and
combined cycle capacity to meet projected demand.
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Exhibit 46: Expansion Unit Characteristics
================================================================================
================================================================================
Item Unit CT CC CC Coal
================================================================================
Model or Technology F G
================================================================================
Assumptions
================================================================================
Available Year Year 2005
================================================================================
Capacity MW 170 530 530 500
================================================================================
Cost $/kW 355 525 536 1,150
================================================================================
Variable O&M $/MWh 3.50 1.75 1.75 2.50
================================================================================
Fixed O&M $/kW-yr 8.00 14.00 18.20 29.00
================================================================================
Heat Rate (Winter) Btu/kWh 10,400 7,050 6,850 9,600
================================================================================
Heat Rate (Summer) Btu/kWh 10,600 7,262 7,056 9,888
================================================================================
Percent Equity % 50 40 40 40
================================================================================
Interest % 8.5 8.5 8.5 8.5
================================================================================
After Tax Return on Equity % 15 15 15 15
================================================================================
Debt Term Years 15 15 15 15
================================================================================
Forced Outage % 2.5 2.5 2.5 2.5
================================================================================
Annual Maintenance Weeks 2.0 3.0 3.5 4.5
================================================================================
================================================================================
Pace increases these standard unit costs to account for regional variations in
land values, labor costs, property taxes, and other potential cost adders.
Pace's assumption of the regional costs and their associated adders for the MAIN
sub-regions are shown in Exhibit 47. These expansion unit profiles drive the
expansion-planning module to determine the optimum mix of combustion turbine and
combined cycle capacity to meet projected demand and provide reserves.
Exhibit 47: Regional Cost Adjustments
================================================================================
============================================================================================================================
Resulting Fixed O&M Resulting Installed Cost
($/kW-yr.) ($/kW)
Multiple of ---------------------------------------------------------------------------------------
Area Model Zone Standard CT CC CC Coal CT CC CC Coal
Cost ---------------------------------------------------------------------------------------
Assumption F G F G
- ---------------------------------------------------------------------------------------------------------------------------
MAIN NI 1.155 9.24 16.17 21.02 33.50 410 606 619 1,328
- ---------------------------------------------------------------------------------------------------------------------------
MAIN SMAIN 1.110 8.88 15.54 20.20 32.19 394 583 595 1,277
- ---------------------------------------------------------------------------------------------------------------------------
MAIN WUM 1.110 8.88 15.54 20.20 32.19 394 583 595 1,277
- ---------------------------------------------------------------------------------------------------------------------------
MAIN IOWA 1.055 8.44 14.77 19.20 30.60 375 554 565 1,213
- ---------------------------------------------------------------------------------------------------------------------------
MAIN OECAR 1.075 8.60 15.05 19.57 31.18 382 564 576 1,236
- ---------------------------------------------------------------------------------------------------------------------------
================================================================================
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ELWOOD PROJECT CHARACTERIZATION AND COSTS
Pace will simulate the operations of the Project in accordance with the
assumptions in Exhibit 48.
Exhibit 48: Elwood Project Specifications
================================================================================
- -----------------------------------------------------------------------------------------------------------------
Item Units Actual Exelon PSA Aquila PSA
- -----------------------------------------------------------------------------------------------------------------
Units 1-9 1-4,9 5-8
- -----------------------------------------------------------------------------------------------------------------
Location (city/state) Elwood, IL Elwood, IL Elwood, IL
- -----------------------------------------------------------------------------------------------------------------
Technology Combustion Turbine Combustion Turbine Combustion Turbine
- -----------------------------------------------------------------------------------------------------------------
Unit 5-6 : 8/31/2021
PSA Termination Date NA 12/31/2012 Unit 7-8 : 8/31/2022
- -----------------------------------------------------------------------------------------------------------------
Winter Net Capacity MW 167.8 167.8 167.8
- -----------------------------------------------------------------------------------------------------------------
Summer Net Capacity MW 156.5 156.5 156.5
- -----------------------------------------------------------------------------------------------------------------
Winter Heat Rate - (HHV) Btu/kWh 10,400 10,900 10,400
- -----------------------------------------------------------------------------------------------------------------
Summer Heat Rate - (HHV) Btu/kWh 10,600 10,900 10,600
- -----------------------------------------------------------------------------------------------------------------
Fuel Adder $/MMBtu NA $0.32 $0.10
- -----------------------------------------------------------------------------------------------------------------
Variable O&M - 1998 Dollars $/MWh $3.50 $1.37 $0.98
- -----------------------------------------------------------------------------------------------------------------
Min Up Hours Hours 4 4 4
- -----------------------------------------------------------------------------------------------------------------
Min Down Hours Hours 2 2 2
- -----------------------------------------------------------------------------------------------------------------
Jun-Sep: 80
Maximum Operating Hours per Day Hours NA Oct-May: 60 NA
- -----------------------------------------------------------------------------------------------------------------
Units 1-4 : 1,500
Maximum Operating Hours per Year Hours Units 5-9 : 2,500 1,500 2,500
- -----------------------------------------------------------------------------------------------------------------
Cost per CT Start - 1998 Dollars $/Start NA $2,974 $2,439
- -----------------------------------------------------------------------------------------------------------------
Forced Outage Rate % 2.5% 2.5% 2.5%
- -----------------------------------------------------------------------------------------------------------------
Summer Planned Maintenance Weeks 0 0 0
- -----------------------------------------------------------------------------------------------------------------
Winter Planned Maintenance Weeks 2 2 2
- -----------------------------------------------------------------------------------------------------------------
Primary Fuel Gas Gas Gas
- -----------------------------------------------------------------------------------------------------------------
Power Sub-region MAIN-NI MAIN-NI MAIN-NI
- -----------------------------------------------------------------------------------------------------------------
Fuel Sub-Region Chicago Chicago Chicago
- -----------------------------------------------------------------------------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
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================================================================================
FUEL PRICING
================================================================================
Pace developed fuel price forecasts for each major fuel (natural gas, #2
distillate fuel oil, #6 residual fuel oil, coal, and uranium) in the MAIN market
region. The base year fuel prices and annual escalation rates in the forecast
are based on Pace's analysis of historical price data and the fundamental
factors driving each fuel market. All forecast prices are in 1998 real dollars
and represent a regional benchmark market price.(33)
A more extensive evaluation of the fuel arrangements for the Project may be
obtained by referring to Pace's Independent Fuel Consultant's Report for the
Project.
Pace's forecasting methodology recognizes that actual prices to existing
facilities often vary from the regional benchmark due to
advantages/disadvantages in supply contract terms or transportation rates. To
develop plant-specific fuel forecasts for these facilities, the regional
benchmark price is adjusted to reflect plant-specific cost factors. These
plant-specific cost factors are maintained throughout the forecast.
Pace applies monthly fuel adjustment factors as shown in Exhibit 49 to reflect
monthly fluctuations in fuel prices. For the first three years of the natural
gas forecast, the seasonal factors change each year to reflect a relatively
steep decline in annual prices to the longer-term forecast.
Exhibit 49: Monthly Fuel Price Adjustment Factors
================================================================================
- ----------------------------------------------------------------------------------------------------------------------
Month Gas 2001 Gas 2002 Gas 2003 Gas 2004-25 Coal #2 Oil #6 Oil
- ----------------------------------------------------------------------------------------------------------------------
Jan 144% 126% 131% 112% 102% 100% 108%
- ----------------------------------------------------------------------------------------------------------------------
Feb 118% 117% 120% 108% 101% 97% 93%
- ----------------------------------------------------------------------------------------------------------------------
Mar 108% 102% 103% 103% 99% 96% 92%
- ----------------------------------------------------------------------------------------------------------------------
Apr 102% 94% 93% 96% 95% 98% 95%
- ----------------------------------------------------------------------------------------------------------------------
May 98% 95% 94% 94% 101% 97% 96%
- ----------------------------------------------------------------------------------------------------------------------
Jun 90% 94% 93% 94% 102% 93% 94%
- ----------------------------------------------------------------------------------------------------------------------
Jul 89% 90% 87% 95% 102% 95% 97%
- ----------------------------------------------------------------------------------------------------------------------
Aug 88% 91% 90% 95% 102% 100% 98%
- ----------------------------------------------------------------------------------------------------------------------
Sep 91% 91% 89% 95% 102% 106% 101%
- ----------------------------------------------------------------------------------------------------------------------
Oct 93% 94% 93% 96% 94% 109% 108%
- ----------------------------------------------------------------------------------------------------------------------
Nov 91% 101% 101% 104% 100% 105% 109%
- ----------------------------------------------------------------------------------------------------------------------
Dec 89% 106% 107% 109% 98% 103% 108%
- ----------------------------------------------------------------------------------------------------------------------
================================================================================
The remainder of this section reviews Pace's major conclusions and Base Case
assumptions regarding fuel pricing.
- --------------
33 Gas-fired expansion plants are assigned the natural gas regional benchmark
price.
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NATURAL GAS
Pace's independent forecast of delivered natural gas prices in MAIN is comprised
of commodity prices, as represented by the price for gas on the New York
Mercantile Exchange ("NYMEX") at the Henry Hub in Louisiana, plus a regional
basis adjustment to reflect price differentials between the Gulf Coast and
various MAIN delivered price sub-regions.
Commodity Prices
In general, Pace expects Henry Hub commodity prices to peak in 2001 and then
decline through 2009. Thereafter, Pace expects a 0.5 percent annual real price
increase throughout the Study Period. Fundamental factors driving Pace's Henry
Hub commodity forecast are:
o Supply from a year of record drilling is beginning to enter the
market. The gas industry has entered a cycle of lower prices and
higher injections, which may lead to further price declines. Pace
expects natural gas prices at the Henry Hub to average about
$4.00/MMBtu for the remainder of the 2001, although cash market
prices on a given day may be higher or lower due to short-term
technical factors.
o Leading gas supply indicators are currently at record levels,
signaling that a significant rebound is likely under way. The U.S.
gas-directed rig count stood at over 1,000 in June 2001, compared to
a count just above 600 eighteen months previously. Assuming a six to
eighteen month lag between drilling and new production, and normal
summer weather patterns, Pace expects continued, if not
intensifying, increased downward pressure on prices throughout 2001.
o As of June 1, 2001, the industry has added over 770 Bcf to gas
inventories. This is 451 Bcf greater than injections during the same
period last year and inventories are now over 50 percent full.
o Pace expects that substantial incremental gas demand from new
Greenfield gas-fired power generation during the next three years
will offset some of the downward price pressure exerted by new
supply from increased drilling. Pace estimates that new gas fired
generation will add almost 5.4 Bcf/d in incremental natural gas
consumption by 2004.
o Expansion of the North American pipeline grid and productive
capacity from the Gulf Coast and the Western Canadian Sedimentary
Basin will increase competition, particularly in the Midwest and
Northeast. By 2004, several new pipeline projects, such as
Millennium and Independence should be completed, which will
encourage gas-on-gas competition causing Henry Hub prices to decline
further from current levels.
o Both onshore and offshore Gulf Coast production will increase in
2001 and 2002 due to record drilling during 2000. Increases in deep
water offshore drilling will offset production declines from the
shallow offshore.
o Over the long term, Pace does not anticipate in its Base Case
commodity forecast sustained natural gas shortfalls as producers
respond to higher prices. Higher prices
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support a greater and faster expected return on drilling
investments, high rig counts, and future production growth.
o Environmental regulations requiring the use of cleaner, more
efficient fuels have shifted consumption preferences to natural gas
thereby contributing to a higher long-term real price escalation
rate relative to other fuels.
o In the long run, technologically driven declines in exploration and
production costs, and increases in finding rates will increase
productive capacity. These supply-side fundamentals will keep real
gas prices from escalating too high relative to other fuels.
Regional Basis
The delivered gas price forecast incorporates general price differentials and
the cost of transportation to MAIN gas price sub-regions, as depicted in Exhibit
50.
Exhibit 50: Pace Gas Price MAIN Sub-regions
================================================================================
MAP OF MAIN GAS PRICE SUB-REGIONS.
================================================================================
Each gas price region is defined by its primary liquid supply source, interstate
transporter, and that transporter's applicable market-based transportation
rates. The regional basis from the Henry Hub to these gas price regions is
driven primarily by the following fundamentals:
o Numerous pipelines deliver supply from the Gulf of Mexico and the
Mid-Continent to the Midwest region. Much of this supply is
otherwise destined for markets in Chicago and Michigan. As such,
these markets greatly influence the pricing for this region.
Therefore, Pace forecasts this region's price as an average of
Chicago and Michigan delivered pricing.
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o The Chicago region receives supply from most of the major North
American basins, including the Gulf Coast, Mid-Continent, Western
Canada, Rockies and Permian. These supplies can be supplemented with
local production in Illinois and Michigan. As such, Chicago is
considered to have a high degree of gas on gas competition. Prices
in Chicago are at a slight discount to the Midwest region because of
the lack of influence by the Michigan markets on pricing and the
addition of inexpensive Western Canadian supply.
o The South Plains region is dominated by mid-stream supply on
Panhandle Eastern Pipeline Company. This region will trade at a
slight discount to the Michigan region because of the lower
transportation rates on Panhandle associated with shorter transport
paths from the Mid-continent supply basin.
o East Wisconsin currently receives supply primarily from ANR
Pipeline. Looking ahead, the region is the target of expansion
projects such as Guardian Pipeline, which has recently received
approval from the FERC and is on track for an in-service date of
November 2002. Increased competition and deliverability will guard
against rising real basis values in this region.
o The Upper Midwest receives nearly all of its supply from Northern
Natural Pipeline, which receives its supply from the Mid-Continent
directly and from Western Canada via interconnects with Viking Gas
Transmission and Northern Border Pipeline. The Alliance pipeline is
not designed to make any deliveries in this region. Because of the
competition between inexpensive Canadian supply and nearby
Mid-Continent supply, receipt point gas in the Upper Midwest is
competitively priced at an annual average of $0.10/MMBtu discount to
the Henry Hub. Maximum tariff rates, used because of the captive
nature of the region to Northern Natural, are applied to the supply
price to calculate a delivered gas price for this region.
o The Great Lakes region is primarily served by Great Lakes Gas
Transmission ("GLGT"). Imported supply from Western Canada delivered
at Emerson, a border point between the U.S. and Canada, is the chief
supply source for the region. Pace forecasts a transportation rate
of $0.20/MMBtu on GLGT, which is consistent with market-based rates
applicable to markets located further downstream in Michigan.
Exhibit 51 provides a summary of Pace's independent forecast of annual Henry Hub
and delivered prices to each respective MAIN fuel sub-region.
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Exhibit 51: MAIN Natural Gas Price Forecasts (1998 $/MMBtu)
================================================================================
===========================================================================================
South East Upper
Year Henry Hub Chicago Great Lakes Midwest Plains Wisconsin Midwest
- -------------------------------------------------------------------------------------------
2001 4.98 5.05 4.47 5.10 5.14 5.33 5.14
- -------------------------------------------------------------------------------------------
2002 3.80 3.86 3.81 3.91 3.96 4.15 3.96
- -------------------------------------------------------------------------------------------
2003 3.28 3.33 3.28 3.38 3.44 3.63 3.44
- -------------------------------------------------------------------------------------------
2004 2.94 3.00 2.95 3.05 3.10 3.29 3.10
- -------------------------------------------------------------------------------------------
2005 2.72 2.79 2.74 2.84 2.88 3.07 2.88
- -------------------------------------------------------------------------------------------
2006 2.57 2.64 2.59 2.69 2.73 2.92 2.73
- -------------------------------------------------------------------------------------------
2007 2.47 2.54 2.49 2.59 2.63 2.82 2.63
- -------------------------------------------------------------------------------------------
2008 2.41 2.48 2.43 2.53 2.57 2.76 2.57
- -------------------------------------------------------------------------------------------
2009 2.40 2.47 2.42 2.52 2.56 2.75 2.55
- -------------------------------------------------------------------------------------------
2010 2.41 2.48 2.43 2.53 2.57 2.76 2.57
- -------------------------------------------------------------------------------------------
2011 2.42 2.49 2.44 2.54 2.58 2.77 2.58
- -------------------------------------------------------------------------------------------
2012 2.43 2.50 2.45 2.55 2.59 2.78 2.59
- -------------------------------------------------------------------------------------------
2013 2.45 2.52 2.47 2.57 2.61 2.80 2.60
- -------------------------------------------------------------------------------------------
2014 2.46 2.53 2.48 2.58 2.62 2.81 2.61
- -------------------------------------------------------------------------------------------
2015 2.47 2.54 2.49 2.59 2.63 2.82 2.63
- -------------------------------------------------------------------------------------------
2016 2.48 2.55 2.50 2.60 2.64 2.83 2.64
- -------------------------------------------------------------------------------------------
2017 2.50 2.57 2.52 2.62 2.66 2.85 2.65
- -------------------------------------------------------------------------------------------
2018 2.51 2.58 2.53 2.63 2.67 2.86 2.66
- -------------------------------------------------------------------------------------------
2019 2.52 2.59 2.54 2.64 2.68 2.87 2.68
- -------------------------------------------------------------------------------------------
2020 2.53 2.60 2.55 2.65 2.69 2.88 2.69
- -------------------------------------------------------------------------------------------
2021 2.55 2.62 2.57 2.67 2.71 2.90 2.70
- -------------------------------------------------------------------------------------------
2022 2.56 2.63 2.58 2.68 2.72 2.91 2.71
- -------------------------------------------------------------------------------------------
2023 2.57 2.64 2.59 2.69 2.73 2.92 2.73
- -------------------------------------------------------------------------------------------
2024 2.58 2.65 2.60 2.70 2.74 2.93 2.74
- -------------------------------------------------------------------------------------------
2025 2.60 2.67 2.62 2.72 2.76 2.95 2.75
- -------------------------------------------------------------------------------------------
2026 2.61 2.68 2.63 2.73 2.77 2.96 2.77
===========================================================================================
================================================================================
FUEL OIL
Pace forecasts prices for #2 oil, #2 Low Sulfur ("LS"), #6 1.0% Sulfur, and #6
3.0% Sulfur oil for MAIN based on the consumption profile of the generators in
the region. The forecast prices are comprised of the following components, which
are detailed in the remainder of this section:
o Commodity prices as represented by the price for West Texas
Intermediate ("WTI") crude oil on the NYMEX in Cushing, Oklahoma,
o Location basis, and
o Crack spreads.
Commodity Prices
The strength of crude oil prices in 2000 can be attributed to low inventory
levels and demand growth stemming from a continued strong U.S. economy and
economic recovery in Asia. Prices were at levels that, if sustained, will
stimulate non-OPEC production and encourage OPEC members to exceed current quota
levels and expand production capacity. Therefore, it is Pace's view that world
prices will eventually fall to levels that are comparable to the average real
price
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for the five-year period prior to the 1998 price collapse. Pace's WTI forecast
is based on the following key fundamentals:
OPEC Production
o The OPEC price-band mechanism that was agreed upon in March 2000
will remain in effect. The agreement requires OPEC to meet if a
basket of OPEC crude falls below $22.00 or rises above $28.00 per
barrel over a 20-day period. OPEC's largest producer, Saudi Arabia,
has voiced its desire for a $25 per barrel price and aggressively
increased production in the latter half of 2000 to meet that goal.
Prices began to soften in late 2000 in response to this increase in
supply.
o In spite of bearish price trends during the late fourth quarter of
2000, the market remains concerned over Middle East tensions,
unreliable Iraqi exports, and possible OPEC production cuts.
Therefore, Pace expects the world price of oil to rise to the upper
bounds of OPEC's price band. However, global crude demand growth,
expected to slow during 2001, will preclude prolonged price spikes
over $30.00 per barrel.
o OPEC, led by swing producer Saudi Arabia, will attempt to avoid
future sustained prices above $25.00, which inhibit global economic
growth and lead to increased exploration and production in non-OPEC
countries. The price of crude will be driven toward the long-term
equilibrium price of approximately $21.00.
o OPEC was producing at nearly its maximum capacity in 2000, and will
undertake relatively ambitious capacity expansion programs in order
to accommodate the projected rise in long term. Much of the
expansion will occur in the Persian Gulf where the
reserves-to-production ratio already exceeds 80 years.
o OPEC's relative market share will grow from its current level of
approximately 40 percent, but will not surpass the historic high of
53 percent reached in 1973.
Non-OPEC Production
o Non-OPEC production was surprisingly resilient in the low price
environment prior to mid-1999, largely due to innovations in
exploration and drilling technologies and investment-friendly
government policies. While the prices in Pace's forecasted range are
sufficient not only to sustain but in some regions expand output by
non-OPEC producers, the relative share of non-OPEC output will fall
due to expected strong growth in OPEC production.
o U.S. crude oil output, which has been declining since 1985 due to a
combination of lower prices and rising production costs, will
continue falling at a rate of about 1 percent annually. The impact
of sharply lower Alaskan oil output, which has historically
represented about 25 percent of total U.S. crude oil production, is
tempered somewhat by
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technological innovations that improve success rates and lower costs
for deepwater exploration and production in the Gulf of Mexico.(34)
o Optimism remains high concerning the long-term resource potential of
the Former Soviet Union ("FSU") region, but production growth will
be slow until after 2005 due to the startup delays of many Caspian
Basin projects as well as a generally pessimistic outlook for
investment in Russia.
o North Sea production, the largest supply component in the European
Union, is expected to enter a decline phase soon.
Oil Demand
o Demand growth in industrialized countries is projected to be flat to
modest due to lower expected GDP growth and a gradual shift away
from oil for non-transportation uses such as power generation and
space heating.
o Dramatic demand increases in developing countries are anticipated
largely due to higher assumed rates of GDP growth as well as the
greater tendency in developing countries to use oil for a wider
variety of applications. GDP growth is expected to be strongest in
the developing economies of Asia, particularly China.
o FSU and Eastern Europe are projected to have relatively rapid GDP
growth, but the impact on petroleum demand will be modest because
the transition to a market system will lead to offsetting
improvements in energy efficiency.
Exhibit 52 shows Pace's crude oil price forecast for WTI for the period of
2001-2026.
Exhibit 52: WTI Crude Oil Price Forecast (1998 $/MMBtu)
================================================================================
---------------------------------
Year WTI Price Forecast
---------------------------------
2001 4.76
---------------------------------
2002 4.52
---------------------------------
2003 4.28
---------------------------------
2004 4.04
---------------------------------
2005 3.80
---------------------------------
2006-2026 3.60
---------------------------------
================================================================================
Location Basis
An adjustment for WTI crude oil prices must be made to reflect the price
differentials between Cushing, Oklahoma, and the oil regions presented in
Exhibit 53. The location adjustment for each region is calculated by reviewing
the differential between prices for oil products in Oklahoma and each oil
sub-region.
- ----------
34 Combined with the expected growth in U.S. oil demand, the decline in U.S.
production implies an increase in U.S. oil imports.
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Exhibit 53: Pace Oil Price Sub-regions for MAIN
================================================================================
MAP OF PACE'S OIL PRICE SUB-REGIONS FOR MAIN.
================================================================================
A local delivery charge is also applied to crack pricing to reflect transport
charges to the plant sites. The final regional Location Basis is presented in
Exhibit 54.
Exhibit 54: MAIN Fuel Oil Location Basis (1998 $/MMBtu)
================================================================================
======================================
Cushing, OK to: Location Basis
--------------------------------------
Chicago (0.05)
--------------------------------------
Missouri 0.05
--------------------------------------
Minnesota 0.23
--------------------------------------
Iowa 0.21
======================================
================================================================================
Refined Product Crack Spreads
Ten years of historical U.S. Gulf Coast and New York Harbor spot prices were
used to determine the average crack spreads between crude oil and #2 fuel oil,
#6 1.0%, and #6 0.3% oil. The average crack spreads shown in Exhibit 55 are
forecasted to determine the refined product prices in each region.
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Exhibit 55: Crude Oil to Refined Product Crack Spreads (1998 $/MMBtu)
================================================================================
- -----------------------------------------------------------------------------------------------
Year LS #2 Oil #2 Oil #6 0.3% Oil #6 1.0% Oil #6 3.0% Oil
- -----------------------------------------------------------------------------------------------
2001 1.22 1.09 0.16 (0.70) (1.38)
- -----------------------------------------------------------------------------------------------
2002 1.10 0.99 0.07 (0.68) (1.28)
- -----------------------------------------------------------------------------------------------
2003 0.98 0.89 (0.01) (0.66) (1.18)
- -----------------------------------------------------------------------------------------------
2004 0.86 0.79 (0.09) (0.64) (1.07)
- -----------------------------------------------------------------------------------------------
2005 0.86 0.79 (0.09) (0.64) (1.07)
- -----------------------------------------------------------------------------------------------
2006-2026 0.86 0.79 (0.09) (0.64) (1.07)
- -----------------------------------------------------------------------------------------------
================================================================================
Delivered Oil Price Forecasts
Exhibit 56 provides Pace's forecast of annual delivered oil prices resulting
from the summation of the components detailed above.
Exhibit 56: Fuel Oil Price Forecast by MAIN Sub-region (1998 $/MMBtu)
================================================================================
===========================================================================================================
Chicago Missouri
Year ------------------------------------------------------------------------------------------------
#2 LS #2 #6 1.0% #6 3.0% #2 LS #2 #6 1.0% #6 3.0%
- -----------------------------------------------------------------------------------------------------------
2001 5.80 5.93 4.01 3.33 5.90 6.03 4.11 3.43
- -----------------------------------------------------------------------------------------------------------
2002 5.46 5.57 3.79 3.19 5.56 5.67 3.89 3.29
- -----------------------------------------------------------------------------------------------------------
2003 5.12 5.21 3.57 3.05 5.22 5.31 3.67 3.15
- -----------------------------------------------------------------------------------------------------------
2004 4.78 4.85 3.35 2.92 4.88 4.95 3.45 3.02
- -----------------------------------------------------------------------------------------------------------
2005 4.54 4.61 3.11 2.68 4.64 4.71 3.21 2.78
- -----------------------------------------------------------------------------------------------------------
2006-2026 4.34 4.41 2.90 2.48 4.44 4.51 3.00 2.58
===========================================================================================================
===========================================================================================================
Minnesota Iowa
Year ------------------------------------------------------------------------------------------------
#2 LS #2 #6 1.0% #6 3.0% #2 LS #2 #6 1.0% #6 3.0%
- -----------------------------------------------------------------------------------------------------------
2001 6.08 6.21 4.29 3.61 6.06 6.19 4.27 3.59
- -----------------------------------------------------------------------------------------------------------
2002 5.74 5.85 4.07 3.47 5.72 5.83 4.05 3.45
- -----------------------------------------------------------------------------------------------------------
2003 5.40 5.49 3.85 3.33 5.38 5.47 3.83 3.31
- -----------------------------------------------------------------------------------------------------------
2004 5.06 5.13 3.63 3.20 5.04 5.11 3.61 3.18
- -----------------------------------------------------------------------------------------------------------
2005 4.82 4.89 3.39 2.96 4.80 4.87 3.37 2.94
- -----------------------------------------------------------------------------------------------------------
2006-2026 4.62 4.69 3.18 2.76 4.60 4.67 3.16 2.74
===========================================================================================================
================================================================================
COAL
Historical, weighted-average delivered coal prices for generating facilities are
presented in Exhibit 57. Pace's forecast reflects the market outlook for various
sulfur grades of coal, trends in the cost of coal transportation, historical
data on the composition of coal deliveries by sulfur grade, and supply basin.
Pace used the following procedure to generate its forecast:
o Step 1: A coal consumption profile was developed for MAIN indicating
the shares of coal consumption by sulfur grade and supply area.
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o Step 2: National trends in coal supply and demand were reviewed to
forecast escalation rates for coal commodity prices as a function of
sulfur grade.
o Step 3: A base year average delivered coal cost was estimated and
escalated according to the consumption profile and escalation rates
obtained in Steps 1 and 2.
Exhibit 57: Historical Delivered Coal Prices for MAIN by Sulfur Content (1998
$/MMBtu)
================================================================================
GRAPH OF HISTORICAL DELIVERED
COAL PRICES FOR MAIN BY SULFUR
CONTENT FROM 1989 TO 1999.
Sources Pace and RDI COALdat.
================================================================================
MAIN Coal Consumption Profile
To reflect variations in coal quality, Pace divided coal consumption by power
generators into four categories based on three sulfur grades, with the lowest
sulfur grade split between Western sub-bituminous coal from the Powder River
Basin ("PRB") and bituminous coal. The defined grades are:
o Low Sulfur (Non-PRB) - less than or equal to 1.2 pounds
SO(2)/MMBtu, or the average) emission rate that utilities were
required to meet by January 1, 2000, under the Clean Air Act
Amendments of 1990 ("CAAA").
o PRB (from the Powder River Basin) - less than or equal to 1.2
pounds SO(2)/MMBtu.
o Medium Sulfur - greater than 1.2 pounds but less than or equal to
3.34 pounds SO(2)/MMBtu.
o High Sulfur - greater than 3.34 pounds SO(2)/MMBtu.
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The composition of coal consumption for power generation in MAIN is shown in
Exhibit 58. PRB coal accounts for nearly 65 percent of MAIN coal consumption, up
from less than 30 percent in 1990. Meanwhile, consumption of high sulfur coal
has declined from over 40 percent in 1990 to about 15 percent currently. The
remaining 20 percent are closely split between low and medium sulfur grades.
Exhibit 58: MAIN Coal Consumption by Sulfur Grade
================================================================================
GRAPH OF MAIN COAL CONSUMPTION
SEGREGATED BY SULPHUR GRADE IN
1990, 1995,
AND 1998.
================================================================================
As shown in Exhibit 59, Northern Wyoming and Montana, the location of the Powder
River Basin, supply a large majority of the low sulfur coal consumed in MAIN.
The Central Rockies, primarily Colorado and Southern Wyoming, supply most of the
remaining low sulfur coal, while the Illinois Basin is the source for most of
the medium and high sulfur coal.
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Exhibit 59: MAIN Coal Consumption by Source Region, 1999
================================================================================
PIE CHART DISPLAYING MAIN
COAL CONSUMPTION BY SOURCE REGION
IN 1999.
================================================================================
Coal Price Escalation Rates
In order to reflect both the overall decline in coal prices and grade-specific
variations and trends, Pace applied the real escalation rates by coal type in
Exhibit 60.
Exhibit 60: Pace Delivered Real Coal Price Escalation Rates
================================================================================
- -----------------------------------------------------------------------------------------------------------------------
Coal Type 2001 2002 2003 2004 2005-2010 2011-2020 2021 2001-2026
- -----------------------------------------------------------------------------------------------------------------------
Low Sulfur 40.00% -5.00% -1.00% -1.00% -0.80% -0.50% 0.00% 0.80%
- -----------------------------------------------------------------------------------------------------------------------
Medium Sulfur 35.00% -10.00% -5.00% -1.80% -1.30% -0.90% 0.00% -0.21%
- -----------------------------------------------------------------------------------------------------------------------
High Sulfur 20.00% -20.00% -5.00% -2.00% -1.50% -1.00% 0.00% -1.43%
- -----------------------------------------------------------------------------------------------------------------------
PRB Sub-bituminous 70.00% -5.00% -20.00% -5.00% -0.30% -0.30% 0.00% 0.75%
- -----------------------------------------------------------------------------------------------------------------------
================================================================================
Coal Supply, Demand, and Transportation Trends
Pace's long-term coal market outlook is based on a review of fundamental market
drivers affecting overall coal prices and the relative values of specific coal
grades.
Fundamental Drivers Affecting General Delivered Coal Prices
o Abundant domestic coal reserves are sufficient to sustain current
production levels for over 200 years.
o Labor and mining productivity enhancements of recent years, in both
underground and surface mines, will continue to moderate extraction
costs. The Energy Information
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Administration ("EIA") reports that national growth in mining
productivity, measured in tons per miner per hour, averaged 6.2
percent per year from 1977 to 1998.
o Competition among coal producers and transporters will stimulate
innovation and technological advancement that will lower production
and transportation costs, particularly in regions east of the
Mississippi River.
o Increased cross-fuel competition from cleaner and more efficient
natural gas will put downward pressure on coal prices because of a
shift in the power generation sector toward gas.
o The expiration of long-term contracts priced "over market" and a
trend toward shorter-term contracts that are better indexed to spot
market prices will result in lower average pricing.
o U.S. producers face intensified competition from foreign producers,
either directly penetrating U.S. markets (e.g., Colombia) or
displacing U.S. exports to European and Asian markets e.g.,
Indonesia and South Africa.
Fundamental Drivers Affecting Grade-Specific Coal Prices
o Compliance with stricter air quality standards under Phase II of the
CAAA is expected to increase demand for coal with a sulfur content
of 1.2 lbs. of SO(2)/MMBtu or less. This in turn will have a
mitigating effect on the expected real decline of the price of low
sulfur coal.
o Absolute demand, and hence the rate of price decline for low-sulfur
coal will be determined by the balance of the market value of
emission allowances, capital cost of scrubbers, and the amount of
emission allowances banked by an individual generator. However, most
utilities have found the use of low sulfur coal to be the most cost
efficient way to comply with the CAAA.
o The price for higher sulfur coal is expected to decline faster than
other grades as utilities and IPPs comply with stricter emission
standards, which entered into force on January 1, 2000. However, the
decline in demand for high sulfur coal is expected to level off
starting in 2005-2006 when some electric power generators,
particularly in regions producing high sulfur coal, plan to install
scrubbers to meet stricter emission standards.
o Real price declines for medium sulfur coal will be bounded by the
economics of burning cleaner coal without scrubbing, versus
consuming higher sulfur coals with scrubbing or utilizing emission
allowances.
o The outlook for various sulfur grades of coal is reflected in
current coal production forecasts. As shown in Exhibit 61,
production is expected to grow in the West (where most low sulfur
coal is mined), to remain generally stable in the Interior region
(where most high sulfur coal is mined), and to decline gently in the
Appalachian region (which produces a cross-section of coals that are
medium sulfur on average).
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Exhibit 61: Projected Coal Production Growth by Region(35)
================================================================================
GRAPH OF PROJECTED COAL PRODUCTION
GROWTH BY REGION FROM 1998 TO 2020.
Source: EIA, Annual Energy Outlook 2001.
================================================================================
Fundamental Drivers Affecting Transportation Rates
o Productivity gains through consolidation and the application of new
technology in the rail transportation industry will keep
transportation costs low or declining.
o The use of aluminum rail cars, improved scheduling and fleet
management, utilization of electronic control mechanisms, and better
locomotive engineering are factors expected to contribute to
decreased cycle times and enhanced rail productivity.
o Barge rates are expected to continue to be more volatile than rail
rates. However, the retirement of old vessels and the construction
of new terminals, as well as rehabilitation of old terminals, will
keep barge rates on a declining trend.
Delivered Coal Price Forecast
In developing the plant-by-plant coal price forecast, Pace examined the coal
purchasing characteristics underlying each MAIN coal-fired power plant, as well
as the overall market for steam coal, to determine the likely delivered coal
costs to each plant in the future. Pace also
- ----------
35 Appalachia production includes production from Alabama, Eastern Kentucky,
Maryland, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia.
Interior production includes production from Arkansas, Illinois, Indiana,
Kansas, Western Kentucky, Louisiana, Missouri, Oklahoma, and Texas.
Western production includes production from Alaska, Arizona, Colorado,
Montana, New Mexico, North Dakota, Utah, Washington, and Wyoming.
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reviewed the monthly coal deliveries to each of the facilities (as reported by
FERC Form 423 and RDI COALdat) and incorporated into the delivered price
forecast an assessment of the level of "over-market" coal contracts at these
plants and the assumptions regarding the timing of "over-market" coal contract
expiration and phase-out periods, as well as spot coal price escalation. Pace
applied the escalator set, as weighted by these factors, to arrive at the plant
specific delivered price forecasts.
URANIUM
Pace expects uranium prices to remain constant in real terms over the next 20
years. Therefore, Pace assumed utility uranium prices would be equal to their
1996 average value (zero percent annual real rate of escalation).
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================================================================================
APPENDIX A - SENSITIVITIES
================================================================================
HIGH GAS CASE
Given the recent rise in natural gas prices and the resulting uncertainty in gas
price levels, Pace conducted a high natural gas sensitivity to evaluate the
effect of higher natural gas prices on the Project. Pace's High Natural Gas Case
forecast represents an average 57% increase over Pace's Base Case gas forecast
as outlined in Exhibit 62.
Exhibit 63 and Exhibit 64 illustrate the effect that this sensitivity has on
forecast Northern Illinois market-clearing prices. Over the Study Period,
average market-clearing prices are forecast to average $38.79/MWh per year, an
increase of $8.38/MWh or 27.5% over Base Case average market-clearing prices.
On-peak prices average $47.85 /MWh per year, an increase of $8.17/MWh or 20.6%,
while off-peak prices average $30.56/MWh per year, an increase $ 8.56/MWh or
38.9%.
The effect of this sensitivity is to increase average market-clearing prices as
a whole, as gas-fired capacity increasingly becomes the dominant fuel on the
margin and thus the marginal price setter. The effect is slightly more
pronounced on off-peak prices than on-peak prices as gas becomes increasingly on
the margin not only in on-peak periods but in off-peak periods as well.
Exhibit 65 and Exhibit 66 outline and summarize the impact that the High Natural
Gas Case has on the generation and revenue profile of the Project over the Study
Period.(36)
Increases in natural gas prices as simulated in this sensitivity place gas-fired
generators at a competitive disadvantage compared to low-cost, coal-fired
generators, non-gas-fired based purchases, and lower priced gas regions outside
of the Project's transmission region. These factors cause the Project to move
higher up dispatch curve resulting in slightly decreased capacity factors and
generation.
The following summarizes the effects of this sensitivity on the Project compared
to the Base Case:
o Average annual capacity factors decrease to 11.08% per year from
11.93% per year.
o Average annual generation decreases to 1,367 GWh per year from 1,472
GWh per year.
o Average energy and capacity revenues increase to $153.2 million per
year from $134.3 million per year.
o Average energy and capacity revenues per MWh increase to $116.06/MWh
per year from $95.12/MWh per year.
- ----------
36 The comparison to the Project Base Case revenue forecast excludes forecast
volatility values from the calculation.
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o Average gross margins increase to $88.54 million per year or
$62.86/kW-year compared to $88.18 million per year or
$62.60/kW-year.
The impact of the High Gas Case on the operational results for the Exelon and
Aquila PSAs are similar to those outlined previously: decreased capacity factors
and generation, but increased revenues due to higher average market-clearing
prices, leading to a small change in gross margins.
Exhibit 62: Comparison of Base Case and High Gas Case Henry Hub Prices - (1998
$/MMBtu)
================================================================================
--------------------------------------------------
Base High Gas %
Year Case Case Difference
--------------------------------------------------
2001 4.98 5.71 15%
--------------------------------------------------
2002 3.80 5.13 35%
--------------------------------------------------
2003 3.28 4.61 41%
--------------------------------------------------
2004 2.94 4.27 45%
--------------------------------------------------
2005 2.72 4.05 49%
--------------------------------------------------
2006 2.57 3.90 52%
--------------------------------------------------
2007 2.47 3.80 54%
--------------------------------------------------
2008 2.41 3.74 55%
--------------------------------------------------
2009 2.40 3.73 55%
--------------------------------------------------
2010 2.41 3.77 56%
--------------------------------------------------
2011 2.42 3.80 57%
--------------------------------------------------
2012 2.43 3.84 58%
--------------------------------------------------
2013 2.45 3.88 58%
--------------------------------------------------
2014 2.46 3.92 59%
--------------------------------------------------
2015 2.47 3.96 60%
--------------------------------------------------
2016 2.48 4.00 61%
--------------------------------------------------
2017 2.50 4.04 62%
--------------------------------------------------
2018 2.51 4.08 63%
--------------------------------------------------
2019 2.52 4.12 64%
--------------------------------------------------
2020 2.53 4.16 64%
--------------------------------------------------
2021 2.55 4.20 65%
--------------------------------------------------
2022 2.56 4.25 66%
--------------------------------------------------
2023 2.57 4.29 67%
--------------------------------------------------
2024 2.58 4.33 68%
--------------------------------------------------
2025 2.60 4.37 68%
--------------------------------------------------
2026 2.61 4.42 69%
--------------------------------------------------
================================================================================
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Exhibit 63: MAIN - NI Annual System Average Market Price - High Gas Case (1998
$/MWh)
================================================================================
-------------------------------------------------------
Off-Peak On-Peak Average
Year $/MWh $/MWh $/MWh
-------------------------------------------------------
2001 29.34 51.59 39.93
-------------------------------------------------------
2002 29.40 50.36 39.38
-------------------------------------------------------
2003 27.54 45.82 36.25
-------------------------------------------------------
2004 26.02 44.57 34.85
-------------------------------------------------------
2005 26.52 44.73 35.19
-------------------------------------------------------
2006 25.58 45.14 34.90
-------------------------------------------------------
2007 25.98 43.89 34.51
-------------------------------------------------------
2008 27.20 43.53 34.97
-------------------------------------------------------
2009 27.04 43.69 34.97
-------------------------------------------------------
2010 28.38 44.70 36.15
-------------------------------------------------------
2011 28.28 46.80 37.10
-------------------------------------------------------
2012 29.26 46.39 37.41
-------------------------------------------------------
2013 29.66 46.24 37.55
-------------------------------------------------------
2014 30.41 46.38 38.01
-------------------------------------------------------
2015 30.89 47.36 38.73
-------------------------------------------------------
2016 31.01 47.98 39.09
-------------------------------------------------------
2017 31.99 48.68 39.94
-------------------------------------------------------
2018 32.06 49.19 40.22
-------------------------------------------------------
2019 33.54 49.55 41.17
-------------------------------------------------------
2020 33.48 49.68 41.19
-------------------------------------------------------
2021 33.30 49.59 41.06
-------------------------------------------------------
2022 34.47 50.11 41.92
-------------------------------------------------------
2023 34.60 50.57 42.20
-------------------------------------------------------
2024 35.33 52.27 43.40
-------------------------------------------------------
2025 36.02 51.94 43.60
-------------------------------------------------------
2026 37.29 53.39 44.96
-------------------------------------------------------
Avg. 30.56 47.85 38.79
-------------------------------------------------------
================================================================================
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Exhibit 64: Difference - Base Case & High Gas Case Market Prices (1998 $/MWh)
================================================================================
-------------------------------------------------------
Off-Peak On-Peak Average
Year $/MWh $/MWh $/MWh
-------------------------------------------------------
2001 2.35 2.31 2.33
-------------------------------------------------------
2002 5.07 4.97 5.02
-------------------------------------------------------
2003 5.20 4.95 5.08
-------------------------------------------------------
2004 5.05 5.13 5.09
-------------------------------------------------------
2005 5.58 5.67 5.62
-------------------------------------------------------
2006 5.40 6.03 5.70
-------------------------------------------------------
2007 5.85 5.74 5.80
-------------------------------------------------------
2008 6.49 5.63 6.08
-------------------------------------------------------
2009 6.74 6.10 6.44
-------------------------------------------------------
2010 7.34 6.54 6.96
-------------------------------------------------------
2011 7.57 7.08 7.34
-------------------------------------------------------
2012 7.96 7.69 7.83
-------------------------------------------------------
2013 8.18 7.73 7.97
-------------------------------------------------------
2014 8.74 8.02 8.39
-------------------------------------------------------
2015 9.08 8.43 8.77
-------------------------------------------------------
2016 9.53 9.32 9.43
-------------------------------------------------------
2017 10.02 9.58 9.81
-------------------------------------------------------
2018 10.15 10.05 10.10
-------------------------------------------------------
2019 11.09 10.45 10.79
-------------------------------------------------------
2020 11.20 10.45 10.84
-------------------------------------------------------
2021 11.22 10.84 11.04
-------------------------------------------------------
2022 11.91 11.27 11.61
-------------------------------------------------------
2023 12.00 11.41 11.72
-------------------------------------------------------
2024 12.42 12.11 12.27
-------------------------------------------------------
2025 12.89 12.13 12.53
-------------------------------------------------------
2026 13.62 12.86 13.26
-------------------------------------------------------
Avg. 8.56 8.17 8.38
-------------------------------------------------------
================================================================================
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Exhibit 65: Project Annual Operational Summary - High Natural Gas Case (1998 $)
================================================================================
- ------------------------------------------------------------------------------------------------------------------
Capacity Capacity
Variable and and
O&M Energy Energy Gross Gross
Capacity Generation Capacity Fuel Costs Costs Revenue Revenue Margin Margin
Year MW GWh Factor $1000 $1000 $1000 $/MWh $1000 $/KW
- ------------------------------------------------------------------------------------------------------------------
2001 1,409 983 7.97% 60,934 1,030 170,111 172.99 108,147 76.78
- ------------------------------------------------------------------------------------------------------------------
2002 1,409 1,088 8.82% 60,514 1,133 163,002 149.85 101,354 71.96
- ------------------------------------------------------------------------------------------------------------------
2003 1,409 915 7.42% 45,556 959 135,753 148.33 89,238 63.36
- ------------------------------------------------------------------------------------------------------------------
2004 1,409 842 6.83% 39,318 894 125,148 148.57 84,936 60.30
- ------------------------------------------------------------------------------------------------------------------
2005 1,409 1,110 9.00% 49,566 1,168 135,852 122.38 85,118 60.43
- ------------------------------------------------------------------------------------------------------------------
2006 1,409 1,131 9.17% 48,609 1,199 135,452 119.75 85,643 60.80
- ------------------------------------------------------------------------------------------------------------------
2007 1,409 1,115 9.04% 46,941 1,169 129,694 116.29 81,584 57.92
- ------------------------------------------------------------------------------------------------------------------
2008 1,409 1,191 9.66% 49,688 1,255 135,413 113.66 84,470 59.97
- ------------------------------------------------------------------------------------------------------------------
2009 1,409 1,212 9.83% 50,349 1,275 132,950 109.66 81,326 57.74
- ------------------------------------------------------------------------------------------------------------------
2010 1,409 1,107 8.97% 46,354 1,178 133,989 121.02 86,457 61.38
- ------------------------------------------------------------------------------------------------------------------
2011 1,409 922 7.47% 38,892 976 133,800 145.15 93,932 66.69
- ------------------------------------------------------------------------------------------------------------------
2012 1,409 1,079 8.75% 45,830 1,154 135,714 125.75 88,730 63.00
- ------------------------------------------------------------------------------------------------------------------
2013 1,409 1,499 12.15% 63,296 3,204 153,208 102.21 86,707 61.56
- ------------------------------------------------------------------------------------------------------------------
2014 1,409 1,633 13.23% 70,049 3,472 160,787 98.49 87,266 61.96
- ------------------------------------------------------------------------------------------------------------------
2015 1,409 1,739 14.09% 74,859 3,836 165,380 95.12 86,685 61.54
- ------------------------------------------------------------------------------------------------------------------
2016 1,409 1,447 11.73% 62,905 3,209 151,606 104.78 85,492 60.70
- ------------------------------------------------------------------------------------------------------------------
2017 1,409 1,768 14.33% 77,716 3,864 169,991 96.14 88,410 62.77
- ------------------------------------------------------------------------------------------------------------------
2018 1,409 1,709 13.85% 75,781 3,754 166,558 97.43 87,023 61.78
- ------------------------------------------------------------------------------------------------------------------
2019 1,409 1,944 15.76% 87,028 4,180 178,517 91.82 87,308 61.99
- ------------------------------------------------------------------------------------------------------------------
2020 1,409 1,654 13.40% 74,544 3,664 167,493 101.27 89,285 63.39
- ------------------------------------------------------------------------------------------------------------------
2021 1,409 1,672 13.55% 76,004 3,840 165,643 99.07 85,799 60.92
- ------------------------------------------------------------------------------------------------------------------
2022 1,409 1,587 12.86% 72,827 4,724 163,729 103.16 86,178 61.18
- ------------------------------------------------------------------------------------------------------------------
2023 1,409 1,477 11.97% 67,978 5,171 160,580 108.69 87,431 62.07
- ------------------------------------------------------------------------------------------------------------------
2024 1,409 1,517 12.30% 70,521 5,310 168,296 110.93 92,465 65.65
- ------------------------------------------------------------------------------------------------------------------
2025 1,409 1,528 12.38% 71,910 5,348 166,795 109.16 89,537 63.57
- ------------------------------------------------------------------------------------------------------------------
2026 1,409 1,670 13.53% 79,520 5,845 176,899 105.94 91,534 64.99
- ------------------------------------------------------------------------------------------------------------------
Avg. 1,409 1,367 11.08% 61,827 2,800 153,168 116.06 88,541 62.86
- ------------------------------------------------------------------------------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
Proprietary & Confidential 90
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Exhibit 66: Difference - Base Case & High Natural Gas Case Project Results
(1998 $)
- --------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------
Capacity Capacity
Variable and and
O&M Energy Energy Gross Gross
Capacity Generation Capacity Fuel Costs Costs Revenue Revenue Margin Margin
Year MW GWh Factor $1000 $1000 $1000 $/MWh $1000 $/KW
- ------------------------------------------------------------------------------------------------------------------
2001 0 -14 -0.11% 6,654 -21 6,223 8.69 -410 -0.29
- ------------------------------------------------------------------------------------------------------------------
2002 0 -40 -0.33% 13,440 -44 13,958 17.75 563 0.40
- ------------------------------------------------------------------------------------------------------------------
2003 0 -42 -0.34% 11,307 -44 11,470 18.54 207 0.15
- ------------------------------------------------------------------------------------------------------------------
2004 0 -95 -0.77% 8,601 -100 8,396 23.95 -104 -0.07
- ------------------------------------------------------------------------------------------------------------------
2005 0 -189 -1.53% 9,561 -204 9,278 24.94 -78 -0.06
- ------------------------------------------------------------------------------------------------------------------
2006 0 -188 -1.53% 10,165 -204 10,098 24.75 137 0.10
- ------------------------------------------------------------------------------------------------------------------
2007 0 -221 -1.79% 9,460 -231 8,667 25.73 -562 -0.40
- ------------------------------------------------------------------------------------------------------------------
2008 0 -224 -1.82% 10,576 -237 10,461 25.38 122 0.09
- ------------------------------------------------------------------------------------------------------------------
2009 0 -167 -1.36% 12,310 -183 11,728 21.80 -399 -0.28
- ------------------------------------------------------------------------------------------------------------------
2010 0 -132 -1.07% 12,265 -139 12,607 23.03 482 0.34
- ------------------------------------------------------------------------------------------------------------------
2011 0 -104 -0.84% 10,459 -112 9,819 24.29 -529 -0.38
- ------------------------------------------------------------------------------------------------------------------
2012 0 -119 -0.97% 12,639 -127 12,741 23.16 230 0.16
- ------------------------------------------------------------------------------------------------------------------
2013 0 -223 -1.81% 16,580 -442 16,007 22.55 -132 -0.09
- ------------------------------------------------------------------------------------------------------------------
2014 0 -103 -0.84% 22,597 -257 22,939 19.08 599 0.43
- ------------------------------------------------------------------------------------------------------------------
2015 0 -147 -1.20% 23,285 -341 23,229 19.75 285 0.20
- ------------------------------------------------------------------------------------------------------------------
2016 0 -135 -1.10% 19,606 -289 20,009 21.61 692 0.49
- ------------------------------------------------------------------------------------------------------------------
2017 0 -98 -0.80% 26,152 -250 26,731 19.38 829 0.59
- ------------------------------------------------------------------------------------------------------------------
2018 0 -118 -0.96% 25,098 -305 25,116 20.03 323 0.23
- ------------------------------------------------------------------------------------------------------------------
2019 0 -74 -0.60% 30,857 -127 31,100 18.77 370 0.26
- ------------------------------------------------------------------------------------------------------------------
2020 0 -34 -0.28% 27,563 -113 28,645 19.01 1,194 0.85
- ------------------------------------------------------------------------------------------------------------------
2021 0 -28 -0.23% 28,225 -72 28,684 18.51 531 0.38
- ------------------------------------------------------------------------------------------------------------------
2022 0 -42 -0.34% 27,190 -72 27,980 19.83 861 0.61
- ------------------------------------------------------------------------------------------------------------------
2023 0 -71 -0.58% 24,865 -249 26,174 21.90 1,558 1.11
- ------------------------------------------------------------------------------------------------------------------
2024 0 -7 -0.06% 27,873 -25 28,218 19.03 370 0.26
- ------------------------------------------------------------------------------------------------------------------
2025 0 -35 -0.29% 27,609 -124 28,667 20.81 1,181 0.84
- ------------------------------------------------------------------------------------------------------------------
2026 0 -70 -0.57% 30,069 -245 31,003 22.09 1,180 0.84
- ------------------------------------------------------------------------------------------------------------------
Avg. 0 -105 -0.85% 18,654 -175 18,844 20.94 365 0.26
- ------------------------------------------------------------------------------------------------------------------
* The comparison to the Project Base Case revenue forecast excludes forecast
volatility values from the calculation.
================================================================================
- --------------------------------------------------------------------------------
Proprietary & Confidential 91
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OVERBUILD CASE
In addition to a High Natural Gas Case, Pace also analyzed the performance of
the Project using a capacity overbuild scenario. Pace's Overbuild Case assumes
that an additional 2,739 MW of gas-fired combined cycle capacity (equivalent to
5% of 2005 peak demand) is in operation in 2005.
The addition of this incremental capacity in the Overbuild Case increases the
MAIN annual reserve margin from 19.78% in 2005 under the Base Case to 23.89% and
the 2009 Base Case value from 16.22% to 17.61%.
The impact of this overbuild is concentrated during the period 2005-2012. During
this period, excess capacity lowers market-clearing prices in the region as well
as generation and revenues for the Project. As demand increases, and excess
capacity represents an increasingly smaller proportion of system resources, the
market gradually returns to an equilibrium point by 2013.
Exhibit 67 and Exhibit 68 illustrate the effect that this sensitivity has on
forecast Northern Illinois market-clearing prices. Over the Study Period,
average market-clearing prices are forecast to average $30.07/MWh per year, a
decrease of $0.35/MWh or 1.14% compared to Base Case average market-clearing
prices. On-peak prices average $39.16/MWh per year, a decrease of $0.51 /MWh or
1.30%, while off-peak prices average $21.80 /MWh per year, a decrease of
$0.19/MWh or 0.88%.
Exhibit 69 and Exhibit 70 outline and summarize the impact that the Overbuild
Case has on the generation and revenue profile of the Project over the Study
Period.(37)
The introduction of additional gas-fired combined cycle generators to the MAIN
market, together with the consequential reduction in market-clearing prices as
the market returns to equilibrium, leads to reductions in generation, capacity
factors, revenues and gross margins for the Project.
The following summarizes the effects of this sensitivity on the Project compared
to the Base Case:
o Average annual capacity factors decrease to 11.07% per year from
11.93% per year.
o Average annual generation decreases to 1,366 GWh per year from to
1,472 GWh per year.
o Average energy and capacity revenues decrease to $128.4 million per
year from $134.3 million per year.
o Average revenues per MWh increase to $100.11/MWh per year from
$95.12/MWh per year.
- ----------
37 The comparison to the Project Base Case revenue forecast excludes forecast
volatility values from the calculation.
- --------------------------------------------------------------------------------
Proprietary & Confidential 92
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o Average gross margins, decrease to $85.46 million per year or
$60.68/kW-year compared to $88.18 million per year or
$62.60/kW-year.
The impact of the Overbuild Case on the operational results for the Exelon and
Aquila PSAs are similar to those outlined above: reduced capacity factors,
generation, total revenues and gross margins.
Exhibit 67: MAIN-NI Annual Price Summary - Overbuild Case (1998 $/MWh)
================================================================================
---------------------------------------------
Off-Peak On-Peak Average
Year $/MWh $/MWh $/MWh
---------------------------------------------
2001 26.98 49.28 37.60
---------------------------------------------
2002 24.33 45.40 34.37
---------------------------------------------
2003 22.34 40.87 31.16
---------------------------------------------
2004 20.96 39.44 29.76
---------------------------------------------
2005 19.67 35.55 27.23
---------------------------------------------
2006 19.46 35.76 27.22
---------------------------------------------
2007 19.52 35.76 27.25
---------------------------------------------
2008 19.61 36.15 27.49
---------------------------------------------
2009 19.95 36.51 27.83
---------------------------------------------
2010 20.53 37.68 28.69
---------------------------------------------
2011 20.64 39.18 29.47
---------------------------------------------
2012 20.92 38.42 29.25
---------------------------------------------
2013 21.48 38.51 29.59
---------------------------------------------
2014 21.67 38.36 29.62
---------------------------------------------
2015 21.81 38.93 29.96
---------------------------------------------
2016 21.48 38.66 29.66
---------------------------------------------
2017 21.97 39.09 30.13
---------------------------------------------
2018 21.91 39.14 30.11
---------------------------------------------
2019 22.45 39.10 30.38
---------------------------------------------
2020 22.28 39.23 30.35
---------------------------------------------
2021 22.08 38.74 30.01
---------------------------------------------
2022 22.56 38.84 30.31
---------------------------------------------
2023 22.60 39.16 30.49
---------------------------------------------
2024 22.91 40.16 31.13
---------------------------------------------
2025 23.13 39.80 31.07
---------------------------------------------
2026 23.67 40.53 31.70
---------------------------------------------
Avg. 21.80 39.16 30.07
---------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
Proprietary & Confidential 93
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Exhibit 68: Difference - Base Case & Overbuild Case Market Prices (1998 $/MWh)
================================================================================
---------------------------------------------
Off-Peak On-Peak Average
Year $/MWh $/MWh $/MWh
---------------------------------------------
2001 0.00 0.00 0.00
---------------------------------------------
2002 0.00 0.00 0.00
---------------------------------------------
2003 0.00 0.00 0.00
---------------------------------------------
2004 0.00 0.00 0.00
---------------------------------------------
2005 -1.27 -3.51 -2.34
---------------------------------------------
2006 -0.72 -3.35 -1.98
---------------------------------------------
2007 -0.61 -2.39 -1.46
---------------------------------------------
2008 -1.10 -1.75 -1.41
---------------------------------------------
2009 -0.35 -1.07 -0.70
---------------------------------------------
2010 -0.51 -0.49 -0.50
---------------------------------------------
2011 -0.07 -0.55 -0.30
---------------------------------------------
2012 -0.38 -0.27 -0.33
---------------------------------------------
2013 0.00 0.00 0.00
---------------------------------------------
2014 0.00 0.00 0.00
---------------------------------------------
2015 0.00 0.00 0.00
---------------------------------------------
2016 0.00 0.00 0.00
---------------------------------------------
2017 0.00 0.00 0.00
---------------------------------------------
2018 0.00 0.00 0.00
---------------------------------------------
2019 0.00 0.00 0.00
---------------------------------------------
2020 0.00 0.00 0.00
---------------------------------------------
2021 0.00 0.00 0.00
---------------------------------------------
2022 0.00 0.00 0.00
---------------------------------------------
2023 0.00 0.00 0.00
---------------------------------------------
2024 0.00 0.00 0.00
---------------------------------------------
2025 0.00 0.00 0.00
---------------------------------------------
2026 0.00 0.00 0.00
---------------------------------------------
Avg. -0.19 -0.51 -0.35
---------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
Proprietary & Confidential 94
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Exhibit 69: Project Annual Operational Summary - Overbuild Case (1998 $)
================================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
Capacity Capacity
Variable and and
O&M Energy Energy Gross Gross
Capacity Generation Capacity Fuel Costs Costs Revenue Revenue Margin Margin
Year MW GWh Factor $1000 $1000 $1000 $/MWh $1000 $/KW
- ----------------------------------------------------------------------------------------------------------------------------------
2001 1,409 998 8.08% 54,280 1,051 163,889 164.29 108,557 77.07
- ----------------------------------------------------------------------------------------------------------------------------------
2002 1,409 1,128 9.14% 47,074 1,178 149,044 132.11 100,792 71.56
- ----------------------------------------------------------------------------------------------------------------------------------
2003 1,409 958 7.76% 34,249 1,002 124,283 129.79 89,031 63.21
- ----------------------------------------------------------------------------------------------------------------------------------
2004 1,409 937 7.59% 30,717 994 116,752 124.62 85,041 60.38
- ----------------------------------------------------------------------------------------------------------------------------------
2005 1,409 596 4.83% 18,037 626 86,254 144.68 67,591 47.99
- ----------------------------------------------------------------------------------------------------------------------------------
2006 1,409 821 6.65% 23,930 861 94,112 114.69 69,322 49.22
- ----------------------------------------------------------------------------------------------------------------------------------
2007 1,409 941 7.63% 26,290 992 97,298 103.36 70,016 49.71
- ----------------------------------------------------------------------------------------------------------------------------------
2008 1,409 928 7.52% 25,378 970 100,253 108.08 73,905 52.47
- ----------------------------------------------------------------------------------------------------------------------------------
2009 1,409 1,019 8.26% 27,771 1,069 104,390 102.40 75,550 53.64
- ----------------------------------------------------------------------------------------------------------------------------------
2010 1,409 1,201 9.73% 32,925 1,264 116,862 97.29 82,673 58.70
- ----------------------------------------------------------------------------------------------------------------------------------
2011 1,409 918 7.44% 25,393 975 117,671 128.14 91,303 64.82
- ----------------------------------------------------------------------------------------------------------------------------------
2012 1,409 1,051 8.52% 29,110 1,117 117,177 111.47 86,950 61.73
- ----------------------------------------------------------------------------------------------------------------------------------
2013 1,409 1,722 13.96% 46,716 3,646 137,201 79.65 86,839 61.65
- ----------------------------------------------------------------------------------------------------------------------------------
2014 1,409 1,736 14.07% 47,452 3,729 137,848 79.41 86,667 61.53
- ----------------------------------------------------------------------------------------------------------------------------------
2015 1,409 1,886 15.29% 51,575 4,177 142,151 75.36 86,400 61.34
- ----------------------------------------------------------------------------------------------------------------------------------
2016 1,409 1,582 12.82% 43,299 3,498 131,597 83.17 84,800 60.21
- ----------------------------------------------------------------------------------------------------------------------------------
2017 1,409 1,866 15.13% 51,564 4,115 143,260 76.76 87,581 62.18
- ----------------------------------------------------------------------------------------------------------------------------------
2018 1,409 1,827 14.81% 50,683 4,059 141,442 77.40 86,700 61.55
- ----------------------------------------------------------------------------------------------------------------------------------
2019 1,409 2,018 16.36% 56,171 4,307 147,416 73.05 86,938 61.72
- ----------------------------------------------------------------------------------------------------------------------------------
2020 1,409 1,688 13.68% 46,981 3,776 138,848 82.26 88,091 62.54
- ----------------------------------------------------------------------------------------------------------------------------------
2021 1,409 1,700 13.78% 47,779 3,912 136,959 80.56 85,268 60.54
- ----------------------------------------------------------------------------------------------------------------------------------
2022 1,409 1,629 13.20% 45,637 4,795 135,749 83.33 85,317 60.57
- ----------------------------------------------------------------------------------------------------------------------------------
2023 1,409 1,549 12.55% 43,112 5,420 134,406 86.79 85,873 60.97
- ----------------------------------------------------------------------------------------------------------------------------------
2024 1,409 1,524 12.35% 42,648 5,335 140,078 91.90 92,095 65.39
- ----------------------------------------------------------------------------------------------------------------------------------
2025 1,409 1,564 12.67% 44,300 5,472 138,129 88.34 88,356 62.73
- ----------------------------------------------------------------------------------------------------------------------------------
2026 1,409 1,740 14.10% 49,451 6,090 145,896 83.85 90,355 64.15
- ----------------------------------------------------------------------------------------------------------------------------------
Avg. 1,409 1,366 11.07% 40,097 2,863 128,422 100.11 85,462 60.68
- ----------------------------------------------------------------------------------------------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
Proprietary & Confidential 95
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Exhibit 70: Difference - Base Case & Overbuild Case Project Results (1998 $)
================================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
Capacity Capacity
Variable and and
O&M Energy Energy Gross Gross
Capacity Generation Capacity Fuel Costs Costs Revenue Revenue Margin Margin
Year MW GWh Factor $1000 $1000 $1000 $/MWh $1000 $/KW
- ----------------------------------------------------------------------------------------------------------------------------------
2001 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2002 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2003 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2004 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2005 0 -703 -5.70% -21,968 -746 -40,320 47.24 -17,605 -12.50
- ----------------------------------------------------------------------------------------------------------------------------------
2006 0 -499 -4.04% -14,514 -542 -31,241 19.70 -16,185 -11.49
- ----------------------------------------------------------------------------------------------------------------------------------
2007 0 -395 -3.20% -11,191 -408 -23,729 12.80 -12,130 -8.61
- ----------------------------------------------------------------------------------------------------------------------------------
2008 0 -488 -3.95% -13,733 -521 -24,698 19.80 -10,444 -7.41
- ----------------------------------------------------------------------------------------------------------------------------------
2009 0 -360 -2.92% -10,268 -390 -16,832 14.55 -6,175 -4.38
- ----------------------------------------------------------------------------------------------------------------------------------
2010 0 -38 -0.30% -1,164 -53 -4,519 -0.70 -3,301 -2.34
- ----------------------------------------------------------------------------------------------------------------------------------
2011 0 -108 -0.87% -3,040 -114 -6,310 7.28 -3,157 -2.24
- ----------------------------------------------------------------------------------------------------------------------------------
2012 0 -148 -1.20% -4,081 -163 -5,796 8.88 -1,551 -1.10
- ----------------------------------------------------------------------------------------------------------------------------------
2013 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2014 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2015 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2016 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2017 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2018 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2019 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2020 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2021 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2022 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2023 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2024 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2025 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
2026 0 0 0.00% 0 0 0 0.00 0 0.00
- ----------------------------------------------------------------------------------------------------------------------------------
Avg. 0 -105 -0.85% -3,075 -113 -5,902 4.98 -2,713 -1.93
- ----------------------------------------------------------------------------------------------------------------------------------
* The comparison to the Project Base Case revenue forecast excludes forecast
volatility values from the calculation.
================================================================================
- --------------------------------------------------------------------------------
Proprietary & Confidential 96
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AQUILA PSA EXTENSION CASE
In addition to the High Natural Gas and Overbuild Cases, Pace also analyzed the
performance of the Project assuming that Aquila would not extend the initial
terms of each of the Aquila PSAs for additional 5-year terms as assumed in the
Base Case. The Base Case assumes that the term of the Aquila PSA 1 would be
extended to August 31, 2021 and that the term of the Aquila PSA 2 would be
extended to August 31, 2022. This scenario assumes that the Aquila PSA 1 would
terminate on August 31, 2016, rather than on August 31, 2021 and that the Aquila
PSA2 would terminate on August 31, 2017 rather than on August 31, 2022.
The impact of the non-extension of the Aquila PSAs is concentrated during the
period 2016-2026. During this period, Units 5-8 are no longer dispatched
according to the Aquila PSAs and are operated on a merchant basis by Elwood
using the specifications outlined in Exhibit 48.
Exhibit 67 and Exhibit 68 illustrate the effect that this sensitivity has on
forecast Northern Illinois market-clearing prices. The non-extension of the
Aquila PSAs has a negligible impact on market-clearing prices.
Exhibit 69 and Exhibit 70 outline and summarize the impact that the Aquila PSA
Extension Case has on the generation and revenue profile of the Project over the
Study Period.(38)
The following summarizes the effects of this sensitivity on the Project compared
to the Base Case:
o Average annual capacity factors decrease to 11.63% per year from
11.93% per year.
o Average annual generation decreases to 1,435 GWh per year from to
1,472 GWh per year.
o Average energy and capacity revenues decrease to $133.3 million per
year from $134.3 million per year.
o Average revenues per MWh increase to $96.23/MWh per year from
$95.12/MWh per year.
o Average gross margins, decrease to $87.94 million per year or
$62.43/kW-year compared to $88.18 million per year or
$62.60/kW-year.
- ----------
38 The comparison to the Project Base Case revenue forecast excludes forecast
volatility values from the calculation.
- --------------------------------------------------------------------------------
Proprietary & Confidential 97
[LOGO] PACE | Global Energy Services
Exhibit 71: MAIN-NI Annual Price Summary - Aquila PSA Extension Case (1998
$/MWh)
================================================================================
--------------------------------------------
Off-Peak On-Peak Average
Year $/MWh $/MWh $/MWh
--------------------------------------------
2001 26.98 49.28 37.60
--------------------------------------------
2002 24.33 45.40 34.37
--------------------------------------------
2003 22.34 40.87 31.16
--------------------------------------------
2004 20.96 39.44 29.76
--------------------------------------------
2005 20.94 39.06 29.57
--------------------------------------------
2006 20.18 39.12 29.20
--------------------------------------------
2007 20.13 38.15 28.71
--------------------------------------------
2008 20.71 37.90 28.89
--------------------------------------------
2009 20.30 37.59 28.53
--------------------------------------------
2010 21.04 38.16 29.19
--------------------------------------------
2011 20.71 39.73 29.76
--------------------------------------------
2012 21.29 38.69 29.58
--------------------------------------------
2013 21.48 38.51 29.59
--------------------------------------------
2014 21.67 38.36 29.62
--------------------------------------------
2015 21.81 38.93 29.96
--------------------------------------------
2016 21.47 38.66 29.65
--------------------------------------------
2017 21.98 39.09 30.13
--------------------------------------------
2018 21.92 39.14 30.12
--------------------------------------------
2019 22.44 39.11 30.38
--------------------------------------------
2020 22.28 39.22 30.35
--------------------------------------------
2021 22.07 38.72 30.00
--------------------------------------------
2022 22.55 38.83 30.31
--------------------------------------------
2023 22.60 39.16 30.49
--------------------------------------------
2024 22.91 40.16 31.13
--------------------------------------------
2025 23.13 39.80 31.07
--------------------------------------------
2026 23.67 40.53 31.70
--------------------------------------------
Avg. 22.00 39.68 30.42
--------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
Proprietary & Confidential 98
[LOGO] PACE | Global Energy Services
Exhibit 72: Difference - Base Case & Aquila Extension Case Market Prices (1998
$/MWh)
================================================================================
--------------------------------------------
Off-Peak On-Peak Average
Year $/MWh $/MWh $/MWh
--------------------------------------------
2001 0.00 0.00 0.00
--------------------------------------------
2002 0.00 0.00 0.00
--------------------------------------------
2003 0.00 0.00 0.00
--------------------------------------------
2004 0.00 0.00 0.00
--------------------------------------------
2005 0.00 0.00 0.00
--------------------------------------------
2006 0.00 0.00 0.00
--------------------------------------------
2007 0.00 0.00 0.00
--------------------------------------------
2008 0.00 0.00 0.00
--------------------------------------------
2009 0.00 0.00 0.00
--------------------------------------------
2010 0.00 0.00 0.00
--------------------------------------------
2011 0.00 0.00 0.00
--------------------------------------------
2012 0.00 0.00 0.00
--------------------------------------------
2013 0.00 0.00 0.00
--------------------------------------------
2014 0.00 0.00 0.00
--------------------------------------------
2015 0.00 0.00 0.00
--------------------------------------------
2016 -0.01 0.00 -0.01
--------------------------------------------
2017 0.01 0.00 0.00
--------------------------------------------
2018 0.01 0.00 0.00
--------------------------------------------
2019 -0.02 0.01 0.00
--------------------------------------------
2020 0.00 -0.01 0.00
--------------------------------------------
2021 -0.01 -0.02 -0.01
--------------------------------------------
2022 0.00 -0.01 -0.01
--------------------------------------------
2023 0.00 0.00 0.00
--------------------------------------------
2024 0.00 0.00 0.00
--------------------------------------------
2025 0.00 0.00 0.00
--------------------------------------------
2026 0.00 0.00 0.00
--------------------------------------------
Avg. 0.00 0.00 0.00
--------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
Proprietary & Confidential 99
[LOGO] PACE | Global Energy Services
Exhibit 73: Project Annual Operational Summary - Aquila PSA Extension Case (1998
$)
================================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
Capacity Capacity
Variable and and
O&M Energy Energy Gross Gross
Capacity Generation Capacity Fuel Costs Costs Revenue Revenue Margin Margin
Year MW GWh Factor $1000 $1000 $1000 $/MWh $1000 $/KW
- ----------------------------------------------------------------------------------------------------------------------------------
2001 1,409 998 8.08% 54,280 1,051 163,889 164.29 108,557 77.07
- ----------------------------------------------------------------------------------------------------------------------------------
2002 1,409 1,128 9.14% 47,074 1,178 149,044 132.11 100,792 71.56
- ----------------------------------------------------------------------------------------------------------------------------------
2003 1,409 958 7.76% 34,249 1,002 124,283 129.79 89,031 63.21
- ----------------------------------------------------------------------------------------------------------------------------------
2004 1,409 937 7.59% 30,717 994 116,752 124.62 85,041 60.38
- ----------------------------------------------------------------------------------------------------------------------------------
2005 1,409 1,299 10.53% 40,005 1,372 126,574 97.44 85,196 60.49
- ----------------------------------------------------------------------------------------------------------------------------------
2006 1,409 1,320 10.69% 38,444 1,403 125,353 95.00 85,507 60.71
- ----------------------------------------------------------------------------------------------------------------------------------
2007 1,409 1,336 10.83% 37,480 1,401 121,027 90.56 82,146 58.32
- ----------------------------------------------------------------------------------------------------------------------------------
2008 1,409 1,415 11.47% 39,111 1,492 124,951 88.28 84,348 59.89
- ----------------------------------------------------------------------------------------------------------------------------------
2009 1,409 1,380 11.18% 38,039 1,458 121,222 87.85 81,725 58.02
- ----------------------------------------------------------------------------------------------------------------------------------
2010 1,409 1,239 10.04% 34,089 1,317 121,381 97.99 85,975 61.04
- ----------------------------------------------------------------------------------------------------------------------------------
2011 1,409 1,026 8.31% 28,433 1,088 123,981 120.86 94,460 67.06
- ----------------------------------------------------------------------------------------------------------------------------------
2012 1,409 1,199 9.72% 33,192 1,281 122,973 102.58 88,501 62.83
- ----------------------------------------------------------------------------------------------------------------------------------
2013 1,409 1,722 13.96% 46,716 3,646 137,201 79.65 86,839 61.65
- ----------------------------------------------------------------------------------------------------------------------------------
2014 1,409 1,736 14.07% 47,452 3,729 137,848 79.41 86,667 61.53
- ----------------------------------------------------------------------------------------------------------------------------------
2015 1,409 1,886 15.29% 51,575 4,177 142,151 75.36 86,400 61.34
- ----------------------------------------------------------------------------------------------------------------------------------
2016 1,409 1,573 12.75% 42,957 3,724 131,350 83.52 84,669 60.11
- ----------------------------------------------------------------------------------------------------------------------------------
2017 1,409 1,740 14.10% 47,573 5,168 139,279 80.06 86,538 61.44
- ----------------------------------------------------------------------------------------------------------------------------------
2018 1,409 1,736 14.07% 47,647 5,629 139,018 80.07 85,742 60.87
- ----------------------------------------------------------------------------------------------------------------------------------
2019 1,409 1,717 13.92% 47,188 6,009 139,011 80.97 85,813 60.93
- ----------------------------------------------------------------------------------------------------------------------------------
2020 1,409 1,580 12.81% 43,476 5,531 135,895 86.00 86,889 61.69
- ----------------------------------------------------------------------------------------------------------------------------------
2021 1,409 1,513 12.26% 41,925 5,296 131,864 87.14 84,643 60.09
- ----------------------------------------------------------------------------------------------------------------------------------
2022 1,409 1,519 12.31% 42,347 5,317 132,471 87.19 84,807 60.21
- ----------------------------------------------------------------------------------------------------------------------------------
2023 1,409 1,535 12.44% 42,732 5,372 133,889 87.23 85,785 60.90
- ----------------------------------------------------------------------------------------------------------------------------------
2024 1,409 1,534 12.43% 42,897 5,370 139,651 91.03 91,384 64.88
- ----------------------------------------------------------------------------------------------------------------------------------
2025 1,409 1,560 12.64% 44,134 5,459 138,384 88.72 88,791 63.04
- ----------------------------------------------------------------------------------------------------------------------------------
2026 1,409 1,723 13.97% 48,977 6,032 145,135 84.21 90,126 63.99
- ----------------------------------------------------------------------------------------------------------------------------------
Avg. 1,409 1,435 11.63% 42,027 3,288 133,253 96.23 87,937 62.43
- ----------------------------------------------------------------------------------------------------------------------------------
================================================================================
- --------------------------------------------------------------------------------
Proprietary & Confidential 100
[LOGO] PACE | Global Energy Services
Exhibit 74: Difference - Base Case & Aquila PSA Extension Case Project Results
(1998 $)
================================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
Capacity Capacity
Variable and and
O&M Energy Energy Gross Gross
Capacity Generation Capacity Fuel Costs Costs Revenue Revenue Margin Margin
Year MW GWh Factor $1000 $1000 $1000 $/MWh $1000 $/KW
- ----------------------------------------------------------------------------------------------------------------------------------
2001 0 0 0 0 0 0 0 0 0
- ----------------------------------------------------------------------------------------------------------------------------------
2002 0 0 0 0 0 0 0 0 0
- ----------------------------------------------------------------------------------------------------------------------------------
2003 0 0 0 0 0 0 0 0 0
- ----------------------------------------------------------------------------------------------------------------------------------
2004 0 0 0 0 0 0 0 0 0
- ----------------------------------------------------------------------------------------------------------------------------------
2005 0 0 0 0 0 0 0 0 0
- ----------------------------------------------------------------------------------------------------------------------------------
2006 0 0 0 0 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
- ----------------------------------------------------------------------------------------------------------------------------------
2016 0 -10 0 -342 226 -248 0 -131 0
- ----------------------------------------------------------------------------------------------------------------------------------
2017 0 -127 0 -3,991 1,053 -3,981 3 -1,043 -1
- ----------------------------------------------------------------------------------------------------------------------------------
2018 0 -91 0 -3,036 1,570 -2,424 3 -959 -1
- ----------------------------------------------------------------------------------------------------------------------------------
2019 0 -301 0 -8,983 1,702 -8,405 8 -1,124 -1
- ----------------------------------------------------------------------------------------------------------------------------------
2020 0 -108 0 -3,505 1,754 -2,953 4 -1,202 -1
- ----------------------------------------------------------------------------------------------------------------------------------
2021 0 -187 0 -5,854 1,385 -5,095 7 -625 0
- ----------------------------------------------------------------------------------------------------------------------------------
2022 0 -110 0 -3,290 522 -3,278 4 -510 0
- ----------------------------------------------------------------------------------------------------------------------------------
2023 0 -14 0 -380 -48 -517 0 -89 0
- ----------------------------------------------------------------------------------------------------------------------------------
2024 0 10 0 250 35 -427 -1 -712 -1
- ----------------------------------------------------------------------------------------------------------------------------------
2025 0 -4 0 -166 -13 256 0 435 0
- ----------------------------------------------------------------------------------------------------------------------------------
2026 0 -17 0 -474 -58 -761 0 -229 0
- ----------------------------------------------------------------------------------------------------------------------------------
Avg. 0 -37 -0.30% -1,145 313 -1,071 1.10 -238 -0.17
- ----------------------------------------------------------------------------------------------------------------------------------
* The comparison to the Project Base Case revenue forecast excludes forecast
volatility values from the calculation.
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Proprietary & Confidential 101
Annex C-2
Fuel Consultant's Report
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4401 Fair Lakes Court, Suite 400
Fairfax, Virginia 22033-3848 USA
Phone: 703-818-9100
Fax: 703-818-9103
Independent Fuel Consultant's Report
Prepared for
Elwood Energy LLC
August 21, 2001
================================================================================
This Report was produced by Pace Global Energy Services, LLC ("Pace") and 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
prior written consent of Pace is forbidden. Except for its stated purpose, this
Report may not be copied or distributed in whole or in part without Pace's prior
written consent.
This Report and the information and statements herein are based in whole or in
part on information obtained from various sources as of August 21, 2001. While
Pace believes such information to be accurate, it makes no assurances,
endorsements or warranties, express or implied, as to the validity, accuracy or
completeness of any such information, any conclusions based thereon, or any
methods disclosed in this Report. Pace assumes no responsibility for the results
of any actions taken on the basis of this Report. By a party using, acting or
relying on this Report, such party consents and agrees that Pace, its
employees, directors, officers, contractors, advisors, members, affiliates,
successors and agents shall have no liability with respect to such use, actions
or reliance.
This Report does contain some forward-looking opinions. Certain unanticipated
factors could cause actual results to differ from the opinions contained herein.
Forward-looking opinions are based on historical and/or current information that
relate to future operations, strategies, financial results or other
developments. Some of the unanticipated factors, among others, that could cause
the actual results to differ include regulatory developments, technological
changes, competitive conditions, new products, general economic conditions,
changes in tax laws, adequacy of reserves, credit and other risks associated
with Elwood Energy LLC and/or other third parties, significant changes in
interest rates and fluctuations in foreign currency exchange rates.
Further, certain statements, findings and conclusions in this Report are based
on Pace's interpretations of various contracts. Interpretations of these
contracts by legal counsel or a jurisdictional body could differ.
================================================================================
20 years of setting the pace in energy
- ----------------------------------------------------------------------------
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================================================================================
TABLE OF CONTENTS
================================================================================
Executive Summary ......................................................... 1
Key Findings ............................................................ 1
Project Overview and Fuel Requirements .................................. 2
Fuel Plan ............................................................... 4
Gas Supply ............................................................ 6
Natural Gas Transportation ............................................ 6
Fuel Management ....................................................... 7
Natural Gas Market Assessment ........................................... 7
Midwest Gas Supply .................................................... 7
Midwest Gas Transportation and Storage ................................ 8
Midwest Gas Pricing and Liquidity ..................................... 8
Pro Forma Model Review .................................................. 8
Risks and Risk Mitigation ............................................... 9
Adequacy of Supply .................................................... 9
Reliability of Transportation Services ................................ 9
Fuel Management ....................................................... 10
Price of Gas Supply ................................................... 10
Fuel Plan Assessment ...................................................... 12
Management Plan Review .................................................. 13
Cinergy Fuel Management Experience and Capability ....................... 14
Fuel Management Requirements ............................................ 15
Initial Agreement Review ................................................ 16
Midwest Natural Gas Market Assessment ..................................... 18
Key Findings ............................................................ 18
Midwest Natural Gas Market Structure .................................. 18
Regional Transportation Infrastructure ................................ 19
Assessment of Nicor and PGL Transportation Services ................... 20
Midwest Gas Market Structure ............................................ 20
Supply Assessment ..................................................... 21
Demand Assessment ..................................................... 27
Pricing and Liquidity Assessment ...................................... 29
Regional Transportation Infrastructure .................................. 34
Midwest Pipeline Infrastructure ....................................... 34
Expansion Overview .................................................... 36
Illinois Utilization Rates ............................................ 39
Gas Storage ........................................................... 40
Capacity Availability ................................................. 41
Assessment of Transportation Services ................................... 49
Pro Forma Fuel Pricing .................................................... 51
Pace Fuel Price Forecast ................................................ 51
Fuel-Related Pro Forma Inputs ........................................... 53
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EXHIBITS
================================================================================
Exhibit 1: Project Location .............................................. 3
Exhibit 2: Elwood Fuel Plan Overview ..................................... 5
Exhibit 3: Overview of Nicor T&B Transportation Rights ................... 6
Exhibit 4: Elwood Organization ........................................... 14
Exhibit 5: Initial Contract Summary ...................................... 16
Exhibit 6: Sources of Natural Gas Supply ................................. 22
Exhibit 7: Natural Gas Resource Base Accessible to the Midwest Region .... 23
Exhibit 8: North American Natural Gas Reserves and Production, 1999 ...... 24
Exhibit 9: Forecast of Lower 48 Natural Gas Demand by Sector (Bcf/yr) .... 28
Exhibit 10: Forecast of Midwest Gas Demand by Sector (Bcf/yr) ............. 29
Exhibit 11: Midwest Trading Points ........................................ 30
Exhibit 12: Chicago and Henry Hub Gas Prices .............................. 31
Exhibit 13: Monthly Contract Index Volumes Traded in the Midwest
('000 MMBtu/d) ................................................ 33
Exhibit 14: Daily Volumes at Relevant Midwest Liquid Trading Points
('000 MMBtu/d) ................................................ 34
Exhibit 15: Midwest Region Pipeline Corridors ............................. 36
Exhibit 16: Announced Midwest Pipeline Expansions ......................... 37
Exhibit 17: Illinois Pipeline Utilization Trends .......................... 39
Exhibit 18: Overview of Midwest Storage Operations, 1999 .................. 40
Exhibit 19: Location of Proposed Midwest Storage Projects ................. 41
Exhibit 20: Decontracting Schedules of Select Interstate Pipelines
Serving Chicago ............................................... 43
Exhibit 21: Historic Summer and Winter Basis Values (1997 - 2001) ......... 45
Exhibit 22: Summary of Historical Capacity Release Transactions ........... 46
Exhibit 23: Availability and Pricing of Released Capacity ................. 47
Exhibit 24: Key Nicor and PGL Receipt Capabilities (Mcf/d) ................ 49
Exhibit 25: Chicago Area Pipeline System Map .............................. 50
Exhibit 26: Chicago Area Pipeline Deliverability Attributes ............... 50
Exhibit 27: Sub-Regional Delivered Gas Price Forecasts (1998 $/MMBtu) ..... 53
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================================================================================
EXECUTIVE SUMMARY
================================================================================
Pace Global Energy Services, LLC ("Pace") has prepared this independent fuel
consultant's report on behalf of the lenders to assess the Fuel Plan and
regional natural gas market fundamentals that apply to the 1,409 megawatt ("MW")
Elwood Energy LLC ("Elwood") merchant power plant (the "Project").(1) The
Project is located in the Mid-American Interconnected Network ("MAIN") power
region and is being developed by Elwood Energy LLC, a joint venture of Dominion
Energy Inc. ("Dominion") and Peoples Energy Resources Corp. ("Peoples"). This
location falls within the U.S. Midwest natural gas market region, as discussed
in this report.
In performing its independent due diligence, Pace reviewed the following market
issues affecting the Project: the proposed integrated fuel strategy ("Fuel
Plan"), the initial fuel-related agreements, the fundamental drivers of natural
gas supply and transportation markets in the Midwest Region(2), and the
fuel-related inputs to Elwood's financial pro forma model.
KEY FINDINGS
Pace makes the following key conclusions regarding the fuel-related aspects of
the Project:
o The robust spot market at the Chicago hub will provide Elwood Energy
LLC ("Elwood") with a highly reliable natural gas supply at
market-sensitive prices for the Project.
o Pace expects that natural gas supply and transportation market
liquidity will continue to grow in the Midwest United States with
the introduction of new pipeline capacity, the geographic
availability of aquifer storage capacity, the integration of new
pipeline interconnections, and the development of new interstate and
utility retail service offerings, thus enabling Elwood to procure
reliable supply on the spot market at the Chicago hub for the
Project. Trading activity at the Chicago hub approximates 2 billion
cubic per day ("Bcf/d"), or about ten times the threshold Pace uses
to define a liquid trading points.
o Elwood will purchase all of the Project's natural gas supplies on a
delivered basis from Cinergy Marketing and Trading LLC ("Cinergy"),
a nationally recognized natural gas and electricity marketer, under
a one-year, executed Fuel Supply and Management Agreement ("FMA") at
a published Chicago daily spot price, plus a nominal premium.
o Elwood intends to negotiate a new multi-year FMA for the Project
with Cinergy or another national energy marketing company. A number
of reputable and creditworthy natural gas suppliers and marketers
operate in the Midwest United States natural gas
- ----------
1 This Report and the information and statements herein are based in whole or in
part on information obtained from various sources as of August 21, 2001. Plant
output assumption based on summer rating.
2 For the purposes of this analysis, Pace defines the Midwest Region to include
the following states: Ohio; West Virginia; Kentucky; Indiana; Illinois;
Michigan; Wisconsin; Iowa; Minnesota; North Dakota; South Dakota; and Nebraska.
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Proprietary & Confidential 1
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markets that will be financially motivated to provide fuel
management and natural gas supply services at competitive prices to
Elwood for the Project upon the expiration of the current FMA.
o Based on its experience in competitive power markets and regional
natural gas markets, Cinergy is highly qualified to provide adequate
fuel management and natural gas procurement expertise to match the
Project's natural gas and power dispatch requirements. Moreover,
Cinergy's compensation and required communications protocols
identified in the executed FMA are appropriate and consistent with
industry norms.
o Potential natural gas commodity price risk to Elwood for the Project
is fully mitigated by the energy payment terms contained in the
executed Power Sales Agreements ("PSAs") and the FMA. The overall
effect of these contracts is to index energy pricing to the market
price of the natural gas commodity obtained by Elwood for the
Project.
o Elwood has entered into a long-term transportation and storage
balancing service agreement for the Project with Northern Illinois
Gas Company ("Nicor") for firm (non-interruptible) hourly delivery
of natural gas supplies to meet the firm power dispatch obligations
at the facility. Initial terms under the Transportation and
Balancing Agreement with Nicor ("T&B Agreement") range from 41
months (Units 1-4) to 5 years (Units 5-9), but the T&B Agreement can
be extended for up to 5 years by giving 180 days written notice
prior to expiration of the respective initial terms. The T&B
Agreement provides Elwood access to purchase, rights to transport,
and rights to store Chicago hub spot supplies for the Project.
o Access to the Chicago hub via the T&B Agreement is facilitated
through the Peoples Gas Light & Coke system ("PGL") through a
companion agreement that contains substantially the same terms and
conditions as the T&B Agreement.
o The Project benefits from existing access to Alliance Pipeline
("APL") and Northern Border Pipeline Company ("NBPL") receipts
through PGL as well as the potential to establish direct connections
with high pressure interstate pipelines in close proximity to Elwood
such as Vector Pipeline, L.P. ("Vector") and ANR Pipeline Co.
("ANR").
PROJECT OVERVIEW AND FUEL REQUIREMENTS
As shown in Exhibit 1, the Project is located in Elwood, Illinois in Will
County, 50 miles southwest of Chicago. The 1,409 MW Project consists of nine
operating gas-fired peaking combustion turbine units, which commenced commercial
operations in stages between 1999 and 2001.
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Exhibit 1: Project Location
================================================================================
NBPL : 1050 psig
|
|
-------
Meter
-------
Alliance: 750 psig |
|
| |
------- |
Meter <-------------------> | ------------->
------- ----------------------------------------><----------
| | PGL 24" line: 650 psig PGL
250 ft. | |
|---><-----|
| Nicor Chromatograph
| -------->
|-----------------------
0.8 mile lateral
------- -------
Meter Nicor Meter Nicor
------- -------
| |
| |
| |
------------ ------------
Units 1 - 4 Units 5 - 9
------------ ------------
[MAP OF MIDWEST DISPLAYING THE LOCATION OF THE PROJECT]
Sources: Pace, RDI, and Peoples Energy.
================================================================================
Pace estimates that the plant will consume 238,966 million Btu per day
("MMBtu/d") of natural gas at maximum burn over a 16-hour day, if all units are
dispatched.(3) According to the Pace's Power Market Assessment, the Project is
expected to dispatch at an average annual capacity factor of 11.93 percent.(4)
The Project will undergo a level of natural gas volume variance during the
course of a particular day or week subject to the plant's availability and
prevailing market prices. Elwood will sell all of the Project's output at
indexed pricing under executed long-term PSAs with Exelon Generation Company,
LLC ("Exelon") and Aquila Energy Marketing Corporation ("Aquila").
The primary term for the PSA between Elwood and Exelon is March 1, 2001 through
December 31, 2012.
- ----------
3 Average heat rate derived from unit performance test results in Table 4-2,
Draft Independent Technical Review report by Stone & Webster, July 13, 2001. The
fuel requirements calculation is based on the following equation: 156.5 MWs * 9
units * 10,600 Btu/kWh heat rate * 100 percent capacity factor * 16 hour day /
1,000,000).
4 Based on Pace's MAIN Power Market Assessment, dated as of August 17, 2001.
Results include the periods covered by the Exelon and Aquila PSA's, including
all contract extension periods, plus a merchant period which commences no later
than 2022 for any of the units.
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The primary terms for the PSAs between Elwood and Aquila are bifurcated: the
agreement for Units 5 and 6 runs from June 1, 2001 to August 31, 2016 and the
agreement for Units 7 and 8 runs from July 1, 2001 through August 31, 2017.
Aquila has the unilateral right to extend each of these agreements for another 5
years if Aquila provides written notice two years prior to the expiration of the
respective initial terms.
Under both of the PSAs, capacity and energy are provided to Exelon and Aquila in
exchange for fixed capacity payments and variable charges for energy. The
variable charge is composed of a natural gas index and an O&M charge designed to
pass through the variable costs of plant operations to Exelon and Aquila.
PGL is the owner and operator of the natural gas pipeline delivering to the
Project, but Nicor holds the utility franchise to provide natural gas utility
services in this region. Elwood has initially contracted with Nicor for a
negotiated (bypass) retail service on behalf of the Project (the "Nicor-Elwood
Agreement" within the T&B Agreement), but may elect to directly connect to
nearby interstate pipelines for service in the future. Nicor only owns meters at
the Project and Nicor renders this service with the support of PGL, through a
companion agreement between Nicor and PGL that contains substantially the same
terms and conditions as the Nicor-Elwood agreement. Because the Project is
located within 3.5 miles or less of several interstate pipelines - APL, NBPL,
ANR, and Vector - opportunities exist to ultimately bypass LDC service and
establish direct connections.
The PGL system has substantial high pressure receipt capabilities that can
support the upstream natural gas requirement of the Project. As shown in Exhibit
1, PGL's 24-inch pipeline operates at pressures of approximately 650 psig. Both
APL and NBPL can deliver 600 MMcf/d of natural gas into PGL, although PGL's
24-inch line has an aggregate deliverability of 600 MMcf/d. Under the T&B
Agreement executed with Nicor and the companion agreement between Nicor and PGL,
the Project can also utilize Natural Gas Pipeline Company of America ("NGPL")
capacity through displacement.(5)
FUEL PLAN
An overview of Elwood's Fuel Plan is presented in Exhibit 2. As shown, Elwood
relies primarily on market-based, firm, spot supplies to be arranged for
transportation and delivery to the Project using the transportation and storage
capacity obtained from Nicor. The fuel manager will act as agent to optimize the
T&B Agreement and will supply the correct balance of interstate natural gas
supply, storage and Nicor system supply to meet the Project's natural gas
requirements from day-to-day.
- ----------
5 Gas Transportation and Balancing Agreement between Nicor and Elwood Energy,
executed May 1, 2001.
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Proprietary & Confidential 4
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Exhibit 2: Elwood Fuel Plan Overview
================================================================================
- -------------------------------------------------------------------------------------------------------------
Natural Gas Supply Transportation Project
- -------------------------------------------------------------------------------------------------------------
Upstream Pipeline Options Supply Laterals & Interconnections Site
- --------------------------------------- --------------------------------------------
Northern Border -->
NGPL --> (1)
Alliance --> Fuel Supply --> (2) (3) Nicor --> Interconnection and --> Elwood
Agreement Lateral (5)
PGL --> 238,966 MMBtu/d
ANR --> Maximum Fuel
Requirement
Vector -->
- -------------------------------------------------------------------------------------------------------------
Gas Supply Agreements
(1) Cinergy Marketing & Trading LLC - Fuel Supply and Management Agreement
o Cinergy to make all gas supply arrangements on behalf of the Project.
o Gas supply priced at Gas Daily Chicago Large End Users index plus
$0.04/MMBtu.
o Access numerous interstate pipelines through Nicor and Peoples gas
interconnects.
Gas Transportation Agreements
(2) Nicor Gas Company - Transportation and Balancing Agreement
o Primary Terms: 5/01/01-9/30/04 for Phase I (Units 1-4) and 5/1/01-5/31/06
for Phase II (Units 5-9).
o Elective Extensions: 10/1/04-3/31/06 for Phase I Units and 6/1/06-3/31/11
for Phase II Units. Jointly, terms for Phase I and Phase II Units can be
extended from 04/01/06 to 03/31/11.
o Firm MDQ of 241,600 MMBtu/d (Summer) and 284,400 MMBtu/d (Non-Summer).
o Firm MHQ of 15,100 MMBtu/hr (Summer) and 17,775 MMBtu/d (Non-Summer).
o Reservation and volumetric charges for Nicor and upstream transportation
charges.
o Minimum Annual Bill of $4.35 Million.
(3) Cinergy Marketing & Trading LLC - Fuel Supply and Management Agreement
o Additional non-firm capacity above Nicor T&B Agreement Firm MDQ.
o Additional balancing flexibility priced at the lowest rate in the Nicor
T&B Agreement.
o Balancing volumes in excess of 241,600 Dth (Summer) or 88,895 Dth (Winter)
subject balancing charges in the Nicor T&B Agreement.
Laterals & Interconnections
(4) Nicor Gas Company - Transportation and Balancing Agreement
o Nicor to own meter facilities.
o Elwood holds an option to buy out the Nicor T&B Agreement early and
purchase the interconnect facilities from Nicor.
o PGL owns the pipeline serving the Project.
Management Agreement
(5) Cinergy Marketing & Trading LLC - Fuel Supply and Management Agreement
o One year primary term.
o Cinergy responsible for acquiring gas commodity and providing fuel
management services.
o Cinergy will manage and administer the Nicor T&B Agreement.
o Monthly reservation fees equivalent to $65,000 June - September; $10,000
October - April.
Source: Pace.
================================================================================
Elwood will continue to evaluate the competitiveness and reliability of
interstate pipeline bypass cases. The Project will use such options to ensure
the competitiveness of the Nicor services and the negotiation of more favorable
terms in the extension period.
The Fuel Plan will utilize highly liquid natural gas hubs and multiple
interstate and intrastate pipeline systems to source natural gas from major U.S.
and Canadian natural gas supply basins.
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Proprietary & Confidential 5
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Gas Supply
The Project's proximity to the Chicago hub facilitates primary access to
natural gas supplied from the following areas: Gulf Coast, Mid-Continent(6),
Western Canada Sedimentary Basin ("WCSB"), the Rockies, and to a lesser extent
the Permian Basin, and local supply. The Chicago region contains substantial
aquifer storage capacity, bringing ample supplies to the region for injections.
Through existing interconnections to PGL's 24-inch diameter pipeline and the
overall resources of Nicor, as well as potential direct connections to major
interstate pipelines (i.e., ANR, APL, NBPL, NGPL, and Vector), the Project or
its agent/fuel manager should be able to purchase reliable supplies of natural
gas at market-based prices. Under the FMA with Cinergy, delivered natural gas
will be priced according to the Midpoint of Gas Daily's Chicago Large End Users
daily index plus a $0.04/MMBtu supplier margin.
Natural Gas Transportation
The T&B Agreement establishes the terms and conditions under which Nicor will
provide firm natural gas transportation services and no-notice balancing
services that allow the Project to receive delivery of natural gas supplies at
hourly rates to meet the peaking requirements.
The T&B Agreement provides Elwood with interstate natural gas supply receipt
points delivered from APL, NBPL and NGPL. Although contractually Elwood has
transportation service with Nicor, the physical transportation of natural gas is
provided by PGL's 24-inch pipeline, which is connected to the interstate
pipelines of APL and NBPL.(7) Nicor provides natural gas transportation and
delivery services to the Project via a companion agreement with PGL and on
substantially the same terms and conditions as the Nicor-Elwood Agreement. As
outlined in Exhibit 3, the T&B Agreement provides Elwood with firm natural gas
delivery rights for specified daily and hourly terms.
Exhibit 3: Overview of Nicor T&B Transportation Rights
================================================================================
- --------------------------------------------------------------------------------
Maximum Hourly
Daily Firm Transportation Rights Transportation Rights
Season (MMBtu/Day) (MMBtu/Hour)
- --------------------------------------------------------------------------------
Summer 241,600 15,100
- --------------------------------------------------------------------------------
Winter 284,400 17,775
- --------------------------------------------------------------------------------
Source: Pace.
================================================================================
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6 The Mid-Continent producing basin is also referred to as the Anadarko/Arkoma
Basin.
7 Developed originally to transport synthetic natural gas.
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Proprietary & Confidential 6
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Natural gas transportation is scheduled for delivery by the fuel manager with
daily input from Nicor on the maximum level to deliver from interstate
pipelines. Natural gas transportation is firm and subject to the terms of the
T&B Agreement and the general terms of Nicor's tariff for retail transportation
services. As such, natural gas supplies must be nominated in accordance with
Nicor and FERC/GISB guidelines. Elwood's transportation and balancing services
provide for up to 16 hours of natural gas supply per day on a no-notice basis.
The PGL system has substantial high pressure receipt capabilities that can
support the upstream natural gas requirements of the Project. For example, both
APL and NBPL can deliver 600 million cubic feet per day ("MMcf/d") of natural
gas into PGL, although PGL's 24-inch line (approximately 650 psig) has an
aggregate deliverability of 600 MMcf/d. Under the T&B Agreement executed with
Nicor and the companion agreement between Nicor and PGL, Elwood can also utilize
NGPL capacity through displacement.
Fuel Management
Initially, Elwood's fuel management arrangements will be administered by
Cinergy. Cinergy has expertise involving financial and physical transactions of
natural gas in the Midwest Region. As fuel manager, Cinergy will handle all
day-to-day responsibilities for procuring, scheduling, and delivering sufficient
natural gas to Nicor and/or PGL to meet the Project's natural gas requirements
as well as administering a portfolio of supply and transportation agreements to
meet the Project's daily/hourly natural gas requirements, including the T&B
Agreement.
NATURAL GAS MARKET ASSESSMENT
The Midwest natural gas market in which the Project will operate offers the
required liquidity to execute the Fuel Plan in support of the power marketing
strategy in a cost-effective manner. The supply and transportation sectors
consist of numerous participants (marketers, interstate pipelines, and
producers) that compete to provide services across different natural gas routes
in the Midwest Region. The general interconnectivity of the pipeline grid within
the Midwest Region coupled with the availability of market area storage services
and the Project's access to multiple pipeline systems will help ensure that
natural gas is competitively priced and reliable.
Midwest Gas Supply
o Pace projects supply availability in the general Midwest Region
will exceed demand through the 25-year financing term ("Financing
Term").
o An orderly commodity market exists in North America that enables
natural gas buyers to procure natural gas at market clearing prices
at numerous locations.
o Power generators in the Midwest marketplace have access to nearly
all major North American producers and natural gas marketing
companies.
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Proprietary & Confidential 7
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o Prolific aggregate supplies of natural gas are available for
delivery into the Midwest from the following resource areas: Gulf
Coast, Permian, Mid-Continent, Rockies, WCSB, Appalachia, and to a
lesser extent local production.
Midwest Gas Transportation and Storage
o The Chicago hub is the heart of the Midwest natural gas
infrastructure. Numerous high-pressure pipeline systems are designed
to transport natural gas to or through this market. Numerous parties
offer services that leverage access to Chicago receipt liquidity.
These entities can provide special hub services to assist customers
with balancing their regional natural gas requirements.
o Market area storage offered by LDCs and interstate natural gas
pipelines augments liquidity and seasonal deliverability
requirements.
o New pipeline expansions on NBPL and APL have added up to 2.3 Bcf/d
of new deliverability of natural gas into Chicago since 1998.
o Numerous additional pipeline expansions have been announced recently
to optimize natural gas deliveries within the Midwest and to deliver
fast-growing Rockies production into the region either directly or
through interconnecting pipelines in the Mid-Continent. Over the
long term, Pace forecasts significant new capacity expansions into
the Midwest.
Midwest Gas Pricing and Liquidity
o Midwest natural gas supply markets are liquid and competitive, and
provide flexibility and reliability. Each of these characteristics
is valuable to the long-term operations of a merchant power project.
o Because natural gas is so widely traded in the region, prices
referenced at the Chicago and Dawn(8) hubs have become the primary
market indices for the Midwest.
PRO FORMA MODEL REVIEW
Pace reviewed the fuel-related inputs in the pro forma financial model and makes
the following findings.(9)
o Pace's long-term average annual delivered price to power generators
near Chicago is $0.07/MMBtu over the Henry Hub index.
o The Project's pro forma accurately incorporates Pace's natural gas
price forecast.
o Fuel management costs have been accurately reflected in the pro
forma model.
o Base Case balancing provisions have been accounted for appropriately
in the pro forma.
- ----------
8 Dawn is a gas-trading hub in Western Ontario that provides liquid pricing.
9 Stone & Webster Pro Forma Model, July 19, 2001.
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RISKS AND RISK MITIGATION
Adequacy of Supply
Risk: Natural gas commodity supply will not be sufficiently available to meet
the Project's requirements throughout the Financing Term.
Risk Mitigation: Because of its access to the Chicago hub, the Project has the
flexibility to acquire abundant natural gas supplies from numerous sources
including the Gulf Coast, Mid-Continent, WCSB, Rockies, Permian, and local
production basins. Numerous high-pressure, high deliverability natural gas
pipelines interconnect near Chicago and link this market to prolific natural gas
reserves in upstream basins. Pace expects, conservatively, that natural gas
resources supplied from these basins will exceed the natural gas supplies
required for the Project during the initial Financing Term. The extensive
development of liquid trading points throughout the U.S. and Canada, and the
Midwest's favorable location on the natural gas transportation grid, facilitate
inter-basin transfers and flexibility in meeting specific supply requirements.
Reliability of Transportation Services
Risk: Elwood will not be able to obtain the transportation service reliability
necessary to meet the peak hourly dispatch requirements under the executed power
sales agreements for the Project.
Risk Mitigation: The Fuel Plan incorporates the flexibility required to adjust
to the hourly dispatch requirements of the Project. Pace finds that the executed
transportation and balancing arrangements with Nicor and the fuel and fuel
management arrangements with Cinergy provide adequate terms and conditions of
service to enable Elwood to meet potential variation in load requirements
expected by the Project during the intermediate term. Several elements of the
Fuel Plan enable Elwood to flexibly respond to off-takers' requests for
short-notice power: (1) Elwood maintains a total storage inventory of 725,000
MMBtu or enough natural gas to fuel all 9 turbines at the facility for
approximately 50 hours, (2) Elwood can inject/withdrawal up to 181,200 MMBtu/d
of natural gas in the Summer and 88,875 MMBtu/d of natural gas in the Non-Summer
Period,(10) and (3) Elwood can purchase Requested Authorized Use natural gas
from
- ----------
10 Non-Summer Period comprises the months October, November, December, January,
February, March, April, and May. Assuming all 9 units are dispatched at maximum
load these provisions provide Elwood with 12 hours of fuel during the Summer and
6 hours of fuel during the Non-Summer Period. Cinergy is obligated to provide
Elwood with enough firm natural gas to satisfy the plant's Summer peak day
requirements for up to 16 hours on as little as one hour's notice; during the
Non-Summer Period Cinergy is only responsible for delivering 88,875 MMBtu/d plus
transportation gas under a 4 hour notice period (or enough fuel to operate all 5
Exelon units for no more than 16 hours in a day).
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Proprietary & Confidential 9
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Nicor if the Project exceeds its firm service and overrun withdrawal rights from
storage.(11) Moreover, if transportation reliability is attributable to
Cinergy's failure to perform, Elwood has the right to purchase natural gas at
reasonable cover costs and be reimbursed through liquidated damages from
Cinergy.
In addition to these agreements, PGL's substantial receipt capabilities from
APL, Northern Border, and NGPL (via displacement) provide Elwood with redundant
access to Chicago hub gas supplies in the event of an upstream mainline
disruption on one of the high capacity pipelines.
Fuel Management
Risk: The existing Fuel Supply and Management Agreement with Cinergy is for a
term of one year.
Risk Mitigation: Numerous creditworthy natural gas marketers and suppliers
provide bundled natural gas delivery services into the Midwest, particularly at
the Chicago hub. As such, by the end of 2001 Elwood intends to solicit proposals
for a three to five year natural gas supply and management agreement to replace
the current arrangement with Cinergy. Further, Pace concludes that the Project
will be able to acquire these services from credit-worthy natural gas marketers
at market-based prices upon the expiration of the anticipated 3 to 5 year FMA
contract through the end of the Financing Term and beyond.
Price of Gas Supply
Risk: Delivered natural gas prices into the Midwest market are sustained at
current high levels and affect the dispatch of gas-fired units relative to other
types of generation.
Risk Mitigation: Elwood's natural gas commodity price risk is fully mitigated
because energy payments in the PSAs executed with Exelon and Aquila are based on
the same fuel index - Midpoint for Gas Daily's Chicago Large End Users daily
index - referenced in the FMA with Cinergy. Hence, the natural gas commodity
portion of the Project's fuel cost is effectively passed through under the PSAs.
In addition, while natural gas market prices are not material for Elwood during
the term of the PSAs, Pace's outlook is for natural gas prices to fall to more
historical levels over the mid-term. Pace expects Henry Hub commodity prices to
peak in 2001 and then decline rapidly as the natural gas market moves from a
shortage and back into balance. Over the long run, high natural gas prices that
are disconnected from prices for other fuels, including coal, distillate, fuel
oil, and
- ----------
11 Elwood has a unilateral right to purchase Requested Authorized Use supplies
from Nicor at the higher of (1) Nicor's Gas Cost (2) or the "market price" of
gas (the midpoint of the Gas Daily's daily index for Chicago Large End Users on
flow day) plus $0.20/MMBtu during the Summer; Elwood requires Nicor's consent,
however, to purchase Requested Authorized Use natural gas during the non-Summer
period. In addition, Elwood has the flexibility to purchase natural gas from
Nicor to cover Forecast Variances and authorized overruns of Elwood's Balancing
and Storage Service at negotiated prices.
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more exotic sources of natural gas, such as LNG imports, are unsustainable.
Competing coal technologies suggest a long-term cap on natural gas prices in the
$3.50 to $4.00 MMBtu range at the Henry Hub, while LNG imports would cap natural
gas prices below this level. Additionally, Pace expects the supply response from
recent high natural gas prices, coupled with technologically driven declines in
exploration and production costs, and increases in finding rates, will generally
increase U.S. productive capacity. Coupled with higher natural gas imports,
these supply-side fundamentals will keep real natural gas prices from escalating
too high relative to other fuels.
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================================================================================
FUEL PLAN ASSESSMENT
================================================================================
Pace's assessment of Elwood's Fuel Plan for the Project is based on a review of
the written Fuel Plan and discussions with Elwood's representatives for the
Project.(12) The following are key findings related to that review:
o Gas commodity price risk exposure is fully mitigated through energy
payment terms in the executed long-term PSAs. Under payment terms
detailed in the PSAs, the Project is reimbursed for the full cost of
the natural gas commodity based on the Midpoint of Gas Daily's
Chicago Large End Users daily index. Because natural gas is
purchased under the FMA using this same index, natural gas commodity
costs are a pass-through to Exelon and Aquila. Additional Project
costs related to natural gas transportation under the T&B Agreement
are not directly reimbursed by the PSAs fuel-related payments.
o The Fuel Plan is focused on achieving a competitive, market-based
natural gas supply while ensuring the reliability required to
fulfill hourly dispatch requirements under the PSAs.
o Transportation reliability has been assured in the following ways:
o Acquiring pressure guarantees from Nicor.
o Establishing Chicago as the primary receipt point for the
Project and thus minimizing upstream capacity risk.
o Executing a transportation agreement with Nicor that provides
firm, no-notice rights that satisfy Elwood's anticipated peak
natural gas needs for the Project.
o Obtaining balancing and storage services that will enable
Elwood to meet intra-day natural gas swings on behalf of the
Project.
o Based on its regional experience in competitive Midwest power
markets and natural gas markets, Cinergy is highly qualified to
provide adequate fuel management and natural gas procurement
expertise to match Elwood's natural gas and power dispatch
requirements for the Project.
o The proposed fuel management costs are reasonable.
o Cinergy's required communications protocols identified in the
executed FMA are appropriate and consistent with industry norms.
o The Fuel Plan incorporates the flexibility required to adjust to the
hourly dispatch requirements of the Project.
o Elwood intends to secure a 3 to 5 year fuel management agreement
upon the expiration of the current agreement with Cinergy in April
2002. This will bring this agreement substantially in line with the
term of the existing T&B agreement.
- ----------
12 "Elwood Fuel Plan - Phase II Development" prepared as part of an August 22,
2000 report to the Elwood Management Committee on the merits of various fuel
approaches for the Project.
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o Elwood has significant potential leverage to secure competitive
supply costs because of its proximity to multiple nearby
high-pressure interstate pipelines and the Chicago hub. Pace
understands that Elwood is unlikely to renew the existing T&B
Agreement under prevailing Phase II terms. Rather, Elwood will
continue to negotiate for a cost effective bypass of Nicor or
establish more favorable pricing terms for the Project.
MANAGEMENT PLAN REVIEW
Pace finds that the Project's structural organization related to the Fuel Plan
is reasonable and consistent with other frameworks for contract and merchant
energy management. Pace understands that Elwood will oversee long-term,
strategic responsibilities involving fuel arrangements for the Project such as
negotiating fuel supply and management agreements with third-parties,
determining the kinds of services needed under these agreements, evaluating
bypass opportunities to establish direct connections to nearby interstate
pipelines, and monitoring fuel-related regulatory and market developments.
Day-to-day operational responsibilities (e.g., nominating natural gas and
resolving imbalances) will be assigned to an experienced, creditworthy
third-party, fuel manager. In performing these duties, the fuel manager is
solely responsible for procuring all natural gas on behalf of the Project at
market-based indices for delivery into Chicago citygates. Initially, Elwood will
employ separate power and fuel managers, however at some point, Elwood may hire
a single toller that would be responsible for all fuel arrangements and
marketing all of the Project's output.
An overview of Elwood's management structure is illustrated in Exhibit 4.
- ----------
13 "Elwood Fuel Plan - Phase II Development" prepared as part of an August
22, 2000 report to the Elwood Management Committee on the merits of
various fuel approaches for the Project.
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Exhibit 4: Elwood Organization
================================================================================
--------------------------------------
_ Elwood Energy LLC
| --------------------------------------
| |
| --------------------------------------
| Elwood Energy LLC
| "Asses Operator"
| --------------------------------------
| |
Power | --------------------------------------
Sales [---|-- Aquila/Exelon
Agreement | "Power Manager"
| --------------------------------------
| |
Fuel Supply | --------------------------------------
& Management -- Cinergy Marketing and Trading
Agreement [------ "Fuel Manager"
--------------------------------------
|
|
|
[MAP OF -------------------] [GRAPHIC OF
PIPELINES POWER PLANT.]
NEAR PROJECT
SITE.] ELWOOD
Will County, IL
[GRAPHIC } Gas arrangements
OF GAS 2,42,000 MMBtu/d } structured to fulfill terms
WELL] Chicago Gas Supply } of PSAs
---------------------------------
Firm transportation and balancing
Nicor --] services provided under existing
agreements between Elwood and
Nicor/Cinergy
---------------------------------
Source: Pace.
================================================================================
CINERGY FUEL MANAGEMENT EXPERIENCE AND CAPABILITY
Cinergy is a leading marketer of natural gas within the Midwest Region. The
Midwest and contiguous regions are Cinergy's target markets for its financial
and physical energy commodities trading business. Cinergy maintains a 24-hour,
7-day per week trading operation. In 2000, Cinergy's non-regulated natural gas
sales exceeded $2.4 billion. Cinergy is a creditworthy counterpart; as of
January 31, 2001, Cinergy Corp's S&P credit ratings met or exceeded BBB+ for
corporate credit, senior unsecured debt, and commercial paper. Gas trading
volumes were about 15.3 Bcf/d in 2000.
In addition, Cinergy has the eighth largest electric trading organization in the
U.S. The New York Mercantile Exchange's "into Cinergy" hub for Midwest
electricity futures trading is the most active in the United States. Cinergy
owns, operates or has under development over 21,000 MW of electrical and
combined heat and power plant generation. Electric trading volumes equaled 166
million MW hours in 2000.
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FUEL MANAGEMENT REQUIREMENTS
The Project's fuel management requirements are driven by PSA commitments
regarding dispatch and contractual arrangements for fuel deliveries.
The key attributes of the PSAs pertaining to fuel requirements are the
following:
o The Project's actual natural gas commodity costs are directly
reimbursed in the PSA through an energy payment. The PSA utilizes a
daily natural gas price index - the midpoint of Gas Daily's Chicago
Large End Users - for determining the reimbursement of fuel
commodity costs.
o Elwood's nine units are fully dispatchable by Aquila and Exelon,
within certain limitations:
o During the Summer Period (as defined in the PSAs) the units
can be dispatched with as little as one hour's notice subject
to certain conditions.
o The PSAs obligate both Exelon and Aquila to provide a
day-ahead schedule of anticipated dispatch.
o The Exelon PSA obligates the Project to operate a maximum of
16 hours per day during the Summer Period and 12 hours per day
during the Non-Summer Period (as defined in the PSAs). For
dispatch during the Summer Off-Peak Period and the Non-Summer
Period (as defined in the PSAs), Exelon must provide 4-hours
notice. During the Summer Peak Periods, Exelon may provide as
little as one hour's notice.
o The Aquila PSA requires the Project to respond to changes in
dispatch during the Summer On-Peak hours with as little as one
hour's notice. For dispatch during the Non-Summer Period and
the Summer Off-Peak hours, Aquila must provide notice
according to the day-ahead schedule.
The Fuel Plan and initial agreements contain the following attributes to enable
Elwood to fulfill its obligations under the PSAs as described above:
o Elwood's Fuel Plan has a "no-notice" capability to meet natural gas
dispatch requirements through use of a 725,000 MMBtu market area
storage inventory or "bank" under the T&B Agreement.
o Elwood has secured firm service for its maximum load for up to a
16-hour period on a given day through the T&B Agreement.
o Under the FMA, Cinergy is obligated to provide a no-notice natural
gas supply to the Project based on the Project's maximum output for
up to a 16-hour period on a given day.
These agreements are discussed in more detail below.
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INITIAL AGREEMENT REVIEW
Pace has reviewed all key available transportation, supply and energy management
agreements executed by Elwood on behalf of the Project. This section summarizes
the key clauses in current executed agreements (Exhibit 5).
Exhibit 5: Initial Contract Summary
================================================================================
- -------------------------------------------------------------------------------------------------------------------
Contracted Nicor Gas Company Cinergy Marketing & Trading LLC
Party
- -------------------------------------------------------------------------------------------------------------------
Contract Transportation and Balancing Agreement Fuel Supply and Management Agreement
Type
- -------------------------------------------------------------------------------------------------------------------
Contract Primary Terms: 5/01/01-9/30/04 for Phase I (Units May 1, 2001 to April 30, 2002
Term 1-4) and 5/1/01-5/31/06 for Phase II (Units 5-9).
Elective Extensions: 10/1/04-3/31/06 for Phase I
Units and 6/1/06-3/31/11 for Phase II Units.
Jointly, terms for Phase I and Phase II Units can
be extended from 04/01/06 to 03/31/11.
- -------------------------------------------------------------------------------------------------------------------
Volume Max. Daily Contract Quantity Summer = 241,600 Max. Daily Quantity Summer = 362,400 Dth/d
Dth/d (241,600 firm and 120,800 non-firm)
Max. Daily Contract Quantity Non-Summer = Max. Daily Quantity Non-Summer = 426,600
284,400 Dth/d Dth/d (213,300 firm and 213,300 non-firm)
Max. Hourly Quantity Summer = 15,100 Dth/hr Max. Hourly Quantity Summer= 15,100
Max. Hourly Quantity Non-Summer = 17,775 Dth/d
Dth/hr Max. Hourly Quantity Non-Summer = 17,775
Dth/d
- -------------------------------------------------------------------------------------------------------------------
Balancing Nicor provides no-notice balancing service on a Competitive balancing services. Elwood
firm basis. Service may be reduced during pays Nicor $0.05/MMBtu up to the Forecast
Critical Days on Nicor's system or when heating Variance listed below:
degree-days exceed 60. Balancing charges Forecast Variance Summer = 241,600 Dth
increase with variance level. Firm variance Forecast Variance Non-Summer = 88,895
quantities differ by season, as follows: Dth
Max. Balancing Service Account Balance =
725,000 Dth
Max. Firm Balancing Quantity Summer = 181,200
Dth
Max. Firm Balancing Quantity Non-Summer =
88,875 Dth
- -------------------------------------------------------------------------------------------------------------------
Pricing Includes summer reservation fees for Monthly Fuel Manager Fee of $65,000
transportation and balancing on Nicor and year- (Summer) and $10,000 (Winter).
round reservation charge for transportation on Gas Priced at Gas Daily Midpoint Citygate
upstream pipelines. Volumetric transportation, price (Chicago LDC's, large end users) plus
storage and balancing charges apply year-round. $0.04 per MMBtu. Variable balancing
Contract specifies minimum annual bill charges may also apply.
requirements.
- -------------------------------------------------------------------------------------------------------------------
Other Gas must come from NBPL, NGPL or APL. Cinergy obligated to procure, schedule and
Elwood has options to purchase Nicor equipment deliver to Nicor and/or PGL volumes
in order to connect directly with interstate sufficient to meet Elwood's natural gas
pipelines and to buy out the contract early. requirements and to manage and administer
the T&B Agreement.
- -------------------------------------------------------------------------------------------------------------------
================================================================================
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The T&B Agreement secures the Project's interconnection to the interstate
pipeline grid through Nicor's intrastate system. Nicor interconnects upstream to
NBPL, NGPL and APL. The Project will also have access to natural gas and storage
from PGL. The contractual arrangements under the Fuel Plan include the necessary
flexibility to buy out the interconnect facilities and T&B Agreement from Nicor
and pursue alternative transportation arrangements, if market fundamentals make
such options economic. The supply and transportation portfolio will be reviewed
periodically by the fuel manager and modified as necessary to ensure cost
competitiveness and reliability.
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================================================================================
MIDWEST NATURAL GAS MARKET ASSESSMENT
================================================================================
This section presents an analysis of the Midwest natural gas commodity and
transportation markets relevant to the Project. The market analysis is divided
into the following subsections:
o Key Findings
o Midwest Gas Market Structure
o Regional Transportation Infrastructure
o Assessment of Transportation Services
KEY FINDINGS
Midwest Natural Gas Market Structure
Supply
o The Midwest market has access to all major producing basins in North
America. These include the Gulf Coast, Permian, Mid-Continent,
Rockies, WCSB, Appalachian basins, and to a lesser extent local
production.
o The Midwest Region's linkage by interstate pipelines to all major
North American gas basins provides assurance of long-term access to
supply. That supply historically has originated predominantly from
the Gulf Coast, Mid-Continent, Permian and Western Canadian basins.
Pace forecasts an increased reliance on Canadian supplies and
incremental volumes from the Rocky Mountain region between 2001 and
2030 (the "Forecast Period").
o Midwest customers have access to nearly all leading producers and
natural gas marketing companies in North America.
o Pace projects natural gas supply availability to surpass demand
throughout the Financing Term.
Demand
o The Midwest constitutes approximately 21 percent of total U.S.
natural gas consumption. Illinois, Michigan and Ohio represent 70
percent of this consumption. Residential and commercial/industrial
loads have historically accounted for about 39 and 38 percent of
this consumption, respectively.
o Aggregate demand is highly seasonal, with strong wintertime peaks to
meet space heating requirements and dramatic dips during the
non-heating season. Demand swings above 600 Bcf/month during peak
winter periods and can fall below 200 Bcf/month during the
non-heating season.
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o The Midwest Region has historically had one of the lowest ratios of
power generation by natural gas of any U.S. region. In 1999, for
example, natural gas constituted only 20 percent of the fuel used by
electric utilities. That ratio is increasing as economic and
environmental requirements make natural gas the primary fuel for new
power generation.
o Pace projects natural gas-fired power generation demand to increase
significantly during the Forecast Period, from 362 MMcf/d in 2000 to
1,500 MMcf/d in 2004, 2,500 MMcf/d in 2010, 4,500 MMcf/d in 2020,
and 5,800 MMcf/d in 2030.
Pricing and Liquidity
o The region is the focus of increasing competition and natural gas
market activity. Chicago has developed as a major downstream hub and
liquid pricing point; nearly 3 Bcf/d of gas transactions took place
at the Chicago hub during a typical day in 2000. Growing regional
demand for natural gas, coupled with additional pipeline capacity,
has fostered a robust liquid market for short and mid-term natural
gas transactions in the Midwest.
o Because gas is so widely traded in Chicago, transactions based on
"Chicago index" plus some premium are commonplace.
o Pace forecasts the average annual Chicago citygate basis to be
approximately $0.07/MMBtu above natural gas commodity prices
reported at the Henry Hub throughout the Forecast Period.
o Additional key pricing points include the Northern interconnect at
Ventura, Viking at Emerson, large LDC citygates in Michigan, and
Columbia Gas Transmission in the Appalachian sub-region. Pace
forecasts prices at Ventura and Emerson to fall approximately
$0.15/MMBtu to $0.25/MMBtu below Chicago, while prices at Michigan
citygates and off Columbia Gas Transmission will range from
$0.10/MMBtu to $0.15/MMBtu above Chicago citygate prices.
Regional Transportation Infrastructure
o While localized constraints exist, the Midwest Region natural gas
market is characterized by excess pipeline capacity and
comparatively low utilization rates on key pipelines. Since 1998,
two large-scale pipeline expansions accounting for more than 2 Bcf/d
have been placed into service to serve this market - APL and the
NBPL Expansion - and other projects have been proposed.
o Historically, the value of transportation capacity has remained
significantly below maximum tariff rates and this trend is likely to
continue. Basis between the Henry Hub and Chicago hub will generally
remain in the $0.00 to $0.10/MMBtu range, while climbing only
marginally at other regional trading points.
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o Large quantities of primary capacity rights are becoming available
as existing contracts expire and "turnback capacity" is made
available to new shippers. Key pipelines in this regard include ANR,
CMS Panhandle Eastern Pipeline Company ("PEPL"), Great Lakes Gas
Transmission ("Great Lakes"), NGPL, Northern Natural Gas Company
("NNG"), and Columbia Gas Transmission.
o The Midwest Region provides a robust secondary capacity release
market where capacity trades significantly below maximum tariffs.
Cumulative, short-term capacity trades last year exceeded 8.7 Bcf/d
on ANR, 1.1 Bcf/d on NGPL, and 1.0 Bcf/d on Panhandle.
o The Midwest Region has the largest working gas storage capacity of
any region, with daily deliverability exceeding 43 Bcf. Both
interstate pipelines and LDCs own and offer storage services. These
services are being restructured to more specifically address the
peaking and balancing requirements of private power generators. The
largest natural gas storage-holding states are Michigan, Illinois,
West Virginia and Ohio. Nearly 147 Bcf of incremental storage
capacity has been proposed recently in the Midwest.
o Unbundling transportation services for small-volume LDC customers
will intensify the trend toward shifting primary capacity rights on
interstate pipelines from LDCs to marketers and large-volume
customers. The result will be more efficient optimization of
pipeline capacity and continued downward pressure on the value of
interstate capacity.
Assessment of Nicor and PGL Transportation Services
o Together, Nicor and PGL have access to multiple market hubs and
basins through interconnections with major interstate pipelines -
APL, ANR, NGPL, NBPL, NNG, Midwestern Gas Transmission Company
("Midwestern") and PEPL - enabling them to deliver Gulf Coast, WCSB,
Rockies, Mid-Continent, Permian, and local supply.
o Provisions in the balancing services offered by Nicor will enable
Elwood to obtain the flexibility required to meet variable dispatch
loads. Nicor can provide this flexibility through its ownership of
seven market-area underground storage facilities.
o Pressure and deliverability on PGL's 24-inch line are sufficient to
meet Elwood's fuel requirements for the Project.
o Through the T&B Agreement Nicor will provide firm service to meet
Elwood's contracted energy output under the executed long-term PSAs
with Exelon and Aquila for the Project.
MIDWEST GAS MARKET STRUCTURE
Pace's assessment of the overall market place for gas-fired generators and other
gas consumers in the Western region focuses on the following components:
o Supply Assessment - Natural gas supplied to the Midwest Region will
exceed demand within the region because of the Midwest Region's
access to multiple supply basins with abundant resources.
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o Demand Assessment - Natural gas demand from power generators in the
Midwest Region will rise from 3 to 22 percent of the region's total
annual natural gas consumption during the Forecast Period.
o Liquidity and Pricing - The Midwest Region has access to numerous
natural gas supply sources as well as high demand downstream
markets, creating liquid term and spot trading.
A combination of these market fundamentals and the continuing development of
competitive energy markets will foster the further development and continuation
of a liquid, short-term market for gas supply in the Midwest Region.
Supply Assessment
The Midwest Region has a limited indigenous natural gas resource base and
therefore produces only a fraction of its own supply. Numerous major interstate
pipelines, however, traverse the region providing Midwestern natural gas users
access to virtually all major North American production basins, including the
Gulf Coast, Mid-Continent, WCSB, Rockies, Permian, and the Appalachian.
Consequently, the Midwest Region is one of the most liquid natural gas trading
areas in North America.
Resources and Production Trends
Due to its limited indigenous natural gas resource base, the Midwest Region
relies extensively upon natural gas supply basins in the Southwestern and
Western United States as well as Western Canada. Exhibit 6 illustrates the
principal natural gas supply basins serving the Midwest Region.
- ----------
14 The Mid-Continent producing basin is also referred to as the
Anadarko/Arkoma Basin.
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Exhibit 6: Sources of Natural Gas Supply
================================================================================
MAP OF PRINCIPAL
NATURAL GAS SUPPLY BASINS SERVING
THE MIDWEST REGION.
Source: Pace and RDI.
================================================================================
According to the Potential Gas Committee ("PGC"), the major basins supplying the
Midwest Region have over 830 Tcf of potential natural gas resources. Exhibit 7
presents PGC's estimates of the resource base for each of the natural gas supply
basins accessible to the Midwest Region.
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Exhibit 7: Natural Gas Resource Base Accessible to the Midwest Region
- --------------------------------------------------------------------------------
Resource Estimate
Basin/Source (Bcf) Percent of Total
- --------------------------------------------------------------------------------
Mid-Continent 70,164 8.45%
- --------------------------------------------------------------------------------
Gulf Coast Basin
- --------------------------------------------------------------------------------
Onshore 105,358 12.68%
- --------------------------------------------------------------------------------
Offshore 113,433 13.65%
- --------------------------------------------------------------------------------
Subtotal 218,791 26.34%
- --------------------------------------------------------------------------------
Appalachian Basin
- --------------------------------------------------------------------------------
Onshore 41,050 4.94%
- --------------------------------------------------------------------------------
Coalbed 12,945 1.56%
- --------------------------------------------------------------------------------
Subtotal 53,995 6.50%
- --------------------------------------------------------------------------------
Michigan Basin 6,035 0.73%
- --------------------------------------------------------------------------------
Illinois Basin
- --------------------------------------------------------------------------------
Onshore 5,360 0.65%
- --------------------------------------------------------------------------------
Coalbed 2,137 0.26%
- --------------------------------------------------------------------------------
Subtotal 7,497 0.90%
- --------------------------------------------------------------------------------
Rocky Mountain Area
- --------------------------------------------------------------------------------
Onshore 125,487 15.11%
- --------------------------------------------------------------------------------
Coalbed Methane 58,604 7.05%
- --------------------------------------------------------------------------------
Subtotal 184,091 22.16%
- --------------------------------------------------------------------------------
Permian 39,169 4.71%
- --------------------------------------------------------------------------------
Western Canadian
Sedimentary Basin 251,000 30.21%
- --------------------------------------------------------------------------------
Total Midwest Market 830,742 100.00%
- --------------------------------------------------------------------------------
Source: Potential Gas Committee.
================================================================================
Reserves
Of the supply basins accessible to the Midwest Region, the Appalachian Basin,
Rocky Mountain Area, and WCSB generally have higher reserve/production ("R/P")
ratios than the Lower 48 average, as shown in Exhibit 8.(15) The lower R/P
ratios in the Gulf of Mexico are representative of a mature production basin
with sophisticated management practices that do not require a large proven
reserve base to maintain annual production levels. A developing basin, such as
the Rockies, will experience a higher R/P ratio as drilling and production
practices progress.
- ----------
15 The R/P ratio is a measure in years of the existing volume of proved reserves
divided by the current production per year expressed as follows: R/P ratio
(years) = Proved Reserves (Bcf) / Current Production (Bcf/yr). It is a very
rough measure since the amount of wellhead deliverability will typically decline
as reserves are drawn down.
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Exhibit 8: North American Natural Gas Reserves and Production, 1999
================================================================================
GRAPH OF RESERVE/PRODUCTION RATIOS
FOR SUPPLY BASINS ACCESSIBLE TO THE
MIDWEST REGION.
Source: U.S. EIA and Statistics Canada.
================================================================================
Pace views the current R/P ratios as a sign of a competitive natural gas supply
sector and not an indication of scarcity. Based on independent estimates of
North American gas resources, Pace expects sufficient natural gas supply to be
available to the Project throughout the Financing Term.
Production
Production within the Midwest Region is concentrated in the Michigan and
Illinois Basins. Overall, Midwest production accounts for only 14 percent of
current annual regional consumption. The remainder of this section examines
activity in the gas supply basins outside the Midwest Region and their future
production potential.
Gulf Coast - The Gulf Coast is the most important producing region in North
America. In 1998, total Gulf Coast production of 8.8 Tcf represented over one
third of North American production. Many new fields have been added during the
1990s to replace depleting fields and the region is currently faced with the
challenge of maintaining and developing sufficient natural gas transportation
infrastructure to bring natural gas from new, discovered fields.
As the second largest U.S. supply basin, the Onshore Gulf Coast accounts for 18
percent of total Lower 48 production. In 1998, the region produced 3.4 Tcf, more
than any other onshore region.
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Unlike many other supply regions, the Gulf Coast Onshore has access to an
abundance of interstate and intrastate pipeline capacity to move natural gas
from the wellhead to market.
Because production decline rates from new wells average 10 to 20 percent per
year, new fields must constantly be found to replace depleting fields. Looking
ahead, Pace expects a high degree of exploration activity to continue in this
region. Exploration and development innovations, such as horizontal drilling,
multilateral completions, optimization of well locations via 3-D seismic
technology and monitoring-while-drilling will be instrumental in boosting the
region's production levels and reducing finding and production costs.
Included as part of the Gulf Coast onshore, the East Texas basin is comprised of
Northern Louisiana and parts of Northeast Texas. Production from this basin
accounts for approximately 5 percent of total Lower 48 supplies. One-half of
East Texas's production and reserves are in just five fields: Carthage, Oak
Hill, Willow Springs, Whelan, and Hawkins. In recent years, this region has been
one of the few onshore regions to register substantial new fields, including at
least 550 Bcf of reserves recently found in the Cotton Valley Lime reef.
Gulf Coast onshore and offshore production levels began to fall in 1997, with
declines continuing into 1998 and 1999. With large initial production rates and
decline rates of 10 to 20 percent a year, offshore wells have high net present
values and relatively quick payouts. However, a slow down in drilling, as
occurred in 1998 and 1999, will result in significant production declines, which
requires a recovery in drilling to reverse. This effect has contributed to the
current high price environment, although this year's drilling recovery in
response to the high market price will ultimately lead to increased production
and a downward price correction closer to the long-run cost of production.
The deep waters of the Gulf of Mexico supply an increasing share of Gulf Coast
production. Deepwater wells produce at very high rates (30-100 MMcf), and recent
drilling added over 100 Bcf of production in 1997 and 179 Bcf in 1998. Also, due
to high initial flow rates, fewer wells need to be drilled to replace depleted
reserves and maintain strong production growth. The deep offshore currently
accounts for over 500 Bcf per year of production. For the time being, further
production growth is limited by the lack of an adequate offshore gathering
infrastructure to bring the natural gas ashore. As more infrastructure is added,
Pace expects total offshore production to grow from 4.9 Tcf currently to almost
5.9 Tcf by 2010.
Mid-Continent - This region includes three of the ten largest natural gas fields
in the Lower 48 States, and accounts for 13 percent of total Lower 48 supplies.
A sharp decline in Oklahoma's productive capacity occurred during the 1990s and
is expected to continue to decline at a rate of 2 to 3 percent per year.
Production for the region as a whole is declining gradually as existing natural
gas fields are depleted. Output gains through drilling and further exploration
are needed to maintain Anadarko/Arkoma production. Mobil and Anadarko Petroleum
have planned to jointly exploit deeper horizons in Hugoton, the second largest
natural gas field in the Lower 48 states. The Hugoton field is located in
western Kansas, parts of Oklahoma, and the Texas
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Panhandle. Production has been declining gradually, and well completions remain
low compared to 1997 levels.
Permian - The Permian basin produces approximately 8 percent of Lower 48 natural
gas supplies with a majority of deliveries staying within the South Central
region. One third of Permian basin production had historically been shipped to
California, but it is being replaced by stiff competition from other basins.
These volumes are now being delivered to Gulf and Texas pipelines to serve more
eastern natural gas markets. Permian natural gas production has continued to
decline throughout the decade. However, Pace expects improvements in seismic
technology and drilling methods to revive production in the basin. For example,
an aggressive campaign is currently underway to develop the Val Verde area.
Rocky Mountain - Rocky Mountain production represents approximately 12 percent
of total Lower 48 supply and is largely untapped. The region is diverse and
complex with many low permeability formations. Federal tax credits, to be
phased-out by 2002, have made coalbed methane gas an important and growing facet
of Colorado gas production. Pipeline expansions into the Midwest and West will
bring increasing amounts of inexpensive Rocky Mountain supply to large markets
in these regions. The Rocky Mountain basin is the fastest growing producing
region in the U.S., regardless of any obstacles the region faces from expiring
coalbed methane tax credits, saturation of Western markets, and the capital
expense of building additional pipeline capacity.
Rocky Mountain natural gas production grew from less than 100 Bcf per month in
1990 to almost 160 Bcf per month by the end of 1999. Historically, natural gas
production in this area has been restricted by the area's take-away capacity, or
the ability to move natural gas out of the region. The increase in production
reflects the expansion of the take-away capacities. After a slump in 1999 due to
low prices, the rig count recovered to over 80 by the summer of 2000. This
biggest constraint on low cost Rocky Mountain natural gas production is the
amount of exporting pipeline capacity.
WCSB - Canadian natural gas resources are located across the western provinces
of British Columbia, Alberta, and Saskatchewan. Canadian imports have increased
sharply in response to a number of market-oriented regulation changes. The 1985
Agreement on Natural Gas Markets and Prices, which allowed for market-oriented
pricing, was followed two years later by a market-based change in procedure to
determine export volumes to the U.S. The U.S.-Canadian Free Trade Agreement
("CFTA") of 1988 also encouraged Canadian exports by prohibiting most trade
restrictions on energy products. Production costs in the WCSB area have been
relatively low, resulting in a lower regional natural gas price. However, with
APL connecting the additional WCSB natural gas resources to the U.S. market, the
local natural gas price has tended to increase in response to a higher U.S.
market price.
WCSB production accounted for 23 percent of total North American production in
1999. An R/P ratio of 10.5 indicates that production in this area can be
increased to feed expanding pipelines serving the Midwest and Eastern U.S.
markets. Canadian exports are expected to
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exceed 4 Tcf by 2005 due to a variety of pipeline expansion projects in both the
U.S. and Canada.
Gas Basin Flows
Historically, most natural gas imported into the Midwest Region has flowed from
the Gulf Coast and Mid-Continent. During the past decade, however, Canadian
deliveries into the Midwest Region have significantly increased. As discussed
above, Michigan and Appalachia are regional sources that also contribute to
local supply. Pace estimates that approximately 67 percent of natural gas
flowing into the Midwest has been supplied from the Gulf Coast and Mid-Continent
supply areas, and 28 percent has been from Canada. The remainder has originated
primarily in the Rocky Mountains and the Permian basin.
Pace expects the Midwest Region's reliance on Canadian supplies to increase in
the near-term and remain at elevated levels from historical amounts. Pace
projects aggregate Canadian imports into the Midwest to grow between 1.0 to 1.3
percent annually from 2001 through 2015 to balance the region's natural gas
demands, particularly from the power generation sector. Canadian export capacity
into the U.S. Midwest exceeded 5.2 Bcf/d at the end of 2000. Estimates by
Natural Resources Canada show that about 50 percent of the growth in Canadian
export volumes between 2000 and 2010 will be attributed to deliveries into the
U.S. Midwest.(16)
Demand Assessment
Current U.S. natural gas consumption exceeds 20 Tcf per year.(17) Most industry
forecasters expect natural gas consumption to grow to 30 Tcf between 2015 and
2020 depending on assumptions about economic growth, fuel prices, production
trends and deregulation in the power industry. Pace forecasts natural gas demand
of 30 Tcf by 2016.(18) Excluding lease and plant fuel, demand from the power
sector accounts for 37 percent of consumption by 2020, compared to 21 percent in
2000. The compound annual growth rate of power sector demand over this period
averages 5.2 percent.
Other sectors grow less robustly. Residential natural gas consumption increases
1.4 percent annually, from 4.8 to 6.3 Tcf by 2020. Commercial consumption grows
1.3 percent annually, from 3.1 to 4.1 Tcf, and industrial consumption grows 1.0
percent annually, from 8.2 to 10.0 Tcf by 2020.
Exhibit 9 illustrates Pace's long-range natural gas demand forecast by sector
for the Lower 48.
- ----------
16 Canadian Natural Gas Market Review and Outlook, Natural Resources Canada,
2000.
17 This section refers to total natural gas demand as the sum of residential,
commercial, industrial, and power generation sectors.
18 When including natural gas consumption for plant and lease fuel, Pace's
demand forecast reaches 30 Tcf by 2012.
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Exhibit 9: Forecast of Lower 48 Natural Gas Demand by Sector (Bcf/yr)
================================================================================
GRAPH ILLUSTRATING PACE'S LONG-RANGE
NATURAL GAS DEMAND FORECAST BY SECTOR
FOR THE LOWER 48 STATES (THROUGH 2030).
Source: Pace.
================================================================================
Demand for natural gas will grow significantly in the Midwest over the next two
decades. Total natural gas demand for the region is projected to rise from 4.7
Bcf/yr in 2000 to 7.7 Bcf/yr in 2020. Over this same period power generators
located in the Midwest are expected to increase their share of the area's total
annual gas consumption from 3 percent to 22 percent. The residential, commercial
and industrial sectors are expected to increase by approximately 1.4 percent
annually throughout the Forecast Period. Pace's projection of Midwest demand
growth is shown in Exhibit 10.
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Exhibit 10: Forecast of Midwest Gas Demand by Sector (Bcf/yr)
================================================================================
GRAPH ILLUSTRATING PACE'S PROJECTION OF
MIDWEST GAS DEMAND THROUGH 2030.
Source: Pace.
================================================================================
Pricing and Liquidity Assessment
The Midwest is characterized by a strong correlation between market-area and
Henry Hub natural gas prices, and increasing market liquidity. Chicago is by far
the most liquid market, averaging nearly 3 Bcf/d in average volumes. Chicago's
significance has intensified since the commencement of APL's commercial
operations in December 2000. APL is also likely to reduce the basis differential
of Western Canadian supply, which is already approaching zero. Other high-volume
trading points in the Midwest include the interconnect points of Northern at
Ventura, Viking at Emerson, and the Michigan LDC citygates of Michigan
Consolidated Gas and Michigan Consumers Energy. The latter two LDCs are
referenced cumulatively in the exhibits below as "Michigan Citygates."
Midwest Market Prices
The Midwest natural gas market has a number of active liquid trading points, as
illustrated in Exhibit 11.
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Exhibit 11: Midwest Trading Points
================================================================================
MAP SHOWING MIDWEST
Source: Pace. TRADING POINTS.
================================================================================
Pricing Determinants and Differentials
Key factors driving natural gas prices in the Midwest are:
o Increased market competition and continued access to all of North
America's producing regions.
o Increased flow of Canadian supply at competitive prices.
o Increased flow of Rocky Mountain supply at competitive prices.
o Ability of supply to surpass demand throughout the Forecast Period.
o Less excess pipeline capacity and competition in the Appalachian
sub-region, reflecting higher projected prices at the TCO Pool.
o Less liquidity and competition at Michigan Citygates than at
Chicago, reflecting the consistently higher differential in
Michigan.
Midwest Points
Trends toward greater gas-on-gas competition and gas-fired generation increases
have led to the development of liquidity in several Midwest locations. Of
primary importance:
o APL, coincident with incremental capacity to move natural gas from
APL to eastern markets, will further enhance Chicago-area liquidity.
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o Liquid Chicago-area pricing points are relied upon for a significant
portion of natural gas contracts in the Midwest.
o Published Chicago-area indexes such as Gas Daily and Inside
F.E.R.C.'s Gas Market Report exhibit a strong correlation to natural
gas prices at Henry Hub. Natural gas differentials between the Henry
Hub and Chicago, however, have been extremely volatile and
weather-driven on a short-term basis during peak winter seasons.
o Liquidity at Northern Border's Ventura interconnect and other
Midwest pricing points has increased, resulting in high volumes
traded on the spot market.
o Large-volume purchases at Michigan LDC citygates sometimes exceed
Chicago-area volumetric transactions and serve as an alternate
pricing point.
Exhibit 12 illustrates the correlation between a daily-published Chicago index
and the price at Henry Hub. Prices at these two liquid trading centers are
highly correlated.(19)
Exhibit 12: Chicago and Henry Hub Gas Prices
================================================================================
GRAPH SHOWING THE CORRELATION BETWEEN A
DAILY-PUBLISHED CHICAGO INDEX AND THE GAS
PRICE AT HENRY HUB FROM JANUARY 2000 AND MAY
2001.
Source: RDI's GasDat.
================================================================================
- ----------
19 Analysis of the relationship between daily spot prices over the past eighteen
months at the Henry Hub and Chicago-LDC's, large end users indicates an
R-squared of 0.969. That is, 96.9 percent of the variance in pricing at Chicago
is explained by price variance at the Henry Hub.
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Midwest Trading Volumes
Gas Daily defines a highly liquid pricing point as having Monthly Contract Index
trade volumes in excess of 200,000 MMBtu/d, while volumes under 25,000 MMBtu/d
characterize low liquidity. The Monthly Contract Index table is published in Gas
Daily on the first business day of each month. The indexes, which are
volume-weighted average costs of natural gas, are calculated from data collected
during bid week. Monthly contract indexes do not change after they have been
set. The Daily Price Survey lists price ranges for packages of spot gas of about
5 MMcf/d, with many larger and some smaller packages.
Historically, marketed volumes based on the Chicago Large End-Users and Michigan
Citygates indices have demonstrated a high degree of liquidity. In fact, monthly
traded volumes for natural gas purchased in markets defined by these indices
have equaled about 2.5 Bcf/d typically or about ten times the high liquidity
threshold.(20) As a pricing point becomes more liquid, up to one-half of the
volumes traded on the spot market are not physically flowing through the point.
Paper trades account for these additional volumes. Exhibit 13 shows volumes of
natural gas, as reported by Gas Daily, traded under the monthly contract index
price for a given month at various Midwest liquid-trading points.
- ----------
20 The fuel price indices referenced in the PSAs and the FMA are based on
daily midpoint of Gas Daily's Chicago Large End Users index not the month
contract index price.
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Exhibit 13: Monthly Contract Index Volumes Traded in the Midwest ('000 MMBtu/d)
================================================================================
- -------------------------------------------------------------------------------------------------
Chicago-
Henry LDCS, Large Michigan ANR ML-7 Viking Dawn,
Flow Date Hub End-Users Citygates (Entire Zone) (Emerson) Ontario
- -------------------------------------------------------------------------------------------------
Jun-99 3,384 2,691 2,946 434 69 145
- -------------------------------------------------------------------------------------------------
Jul-99 3,225 3,481 3,634 547 47 628
- -------------------------------------------------------------------------------------------------
Aug-99 3,916 3,542 3,349 275 24 1,540
- -------------------------------------------------------------------------------------------------
Sep-99 3,967 2,856 3,164 759 56 651
- -------------------------------------------------------------------------------------------------
Oct-99 3,464 2,938 3,430 668 81 758
- -------------------------------------------------------------------------------------------------
Nov-99 3,444 2,939 3,879 509 44 955
- -------------------------------------------------------------------------------------------------
Dec-99 3,378 3,244 3,978 560 90 996
- -------------------------------------------------------------------------------------------------
Jan-00 2,767 2,051 2,363 424 25 324
- -------------------------------------------------------------------------------------------------
Feb-00 2,643 2,868 3,140 638 155 906
- -------------------------------------------------------------------------------------------------
Mar-00 3,276 2,752 2,333 437 5 531
- -------------------------------------------------------------------------------------------------
Apr-00 2,297 2,405 2,434 372 12 555
- -------------------------------------------------------------------------------------------------
May-00 3,432 2,623 1,992 525 12 766
- -------------------------------------------------------------------------------------------------
Jun-00 1,980 2,451 1,317 225 5 440
- -------------------------------------------------------------------------------------------------
Jul-00 2,787 2,022 1,403 206 5 301
- -------------------------------------------------------------------------------------------------
Aug-00 1,886 1,896 1,199 231 5 135
- -------------------------------------------------------------------------------------------------
Sep-00 2,311 2,024 2,120 563 41 231
- -------------------------------------------------------------------------------------------------
Oct-00 1,799 1,725 1,704 435 5 246
- -------------------------------------------------------------------------------------------------
Nov-00 2,366 1,531 1,627 552 5 450
- -------------------------------------------------------------------------------------------------
Dec-00 2,103 2,481 2,687 645 0 714
- -------------------------------------------------------------------------------------------------
Jan-01 1,776 1,753 1,252 120 5 643
- -------------------------------------------------------------------------------------------------
Feb-01 1,527 1,195 1,599 200 100 300
- -------------------------------------------------------------------------------------------------
Mar-01 1,560 1,357 2,330 526 55 366
- -------------------------------------------------------------------------------------------------
Apr-01 1,365 1,906 3,160 498 99 579
- -------------------------------------------------------------------------------------------------
May-01 1,718 1,326 2,188 471 18 353
- -------------------------------------------------------------------------------------------------
Average 2,599 2,336 2,468 451 40 563
- -------------------------------------------------------------------------------------------------
Note: Michigan Citygates equals the sum of Michigan-MichCon and
Michigan-Consumers Energy index volumes.
Sources: Pace and RDI's GasDat.
================================================================================
On the daily market, Chicago Large End-Users and Michigan Citygates pricing
points continue to have the highest liquidity of points in the Midwest. Exhibit
14 illustrates daily volumes traded at designated liquid points between January
2000 and May 2001, as reported by Gas Daily. Daily volumes reported by Gas Daily
at the Chicago Large End Users index averaged about 2,000,000 MMBtu/d during
this period or nearly ten times the Project's estimated peak day summer natural
gas requirements.
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Exhibit 14: Daily Volumes at Relevant Midwest Liquid Trading Points ('000
MMBtu/d)
================================================================================
GRAPH ILLUSTRATING DAILY VOLUMES TRADED AT
RELEVANT MIDWEST LIQUID TRADING POINTS
BETWEEN JANUARY 2000 AND MAY 2001.
Source: RDI's GasDat.
================================================================================
REGIONAL TRANSPORTATION INFRASTRUCTURE
The three primary pipeline corridors into the Midwest are the Gulf Coast,
Mid-Continent and Western Canada. Secondary natural gas routes are represented
by the Rocky Mountain, Permian, and Appalachian basins. The key pipelines
constituting these corridors are listed below:
Midwest Pipeline Infrastructure
1) Gulf Coast Corridor:
o Natural Gas Pipeline Company of America
o CMS Trunkline Gas Co. o Midwestern Gas Transmission Co.
o Texas Gas Transmission Corp.
o ANR Pipeline Company
o Texas Eastern Transmission Corp.
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2) Mid-Continent Corridor:
o Natural Gas Pipeline Company of America
o ANR Pipeline Company
o CMS Panhandle Eastern Pipeline Co.
o Northern Natural Gas Co.
3) Western Canadian Corridor:
o Northern Border Pipeline Company
o Alliance Pipeline Company
o Great Lakes Gas Transmission
4) Rocky Mountain Corridor:
o Colorado Interstate Gas Co.
o Trailblazer Pipeline Co.
5) Permian Corridor:
o Natural Gas Pipeline Company of America
o Northern Natural Gas Co.
6) Appalachian Corridor:
o Columbia Gas Transmission Corp.
o Dominion Transmission Inc.
The main gas transportation routes or pipeline corridors serving the Midwest
market are illustrated in Exhibit 15.
Over the past several decades, Chicago has grown into a major natural gas market
hub. The Chicago hub offers diverse, convenient and efficient access to premium
markets for both natural gas buyers and sellers with direct connections with six
major interstate pipelines including ANR, NGPL, NBPL, NNG, Midwestern, and PEPL.
Energy service providers are offering a host of services at the Chicago hub
including interruptible transportation, parking, loaning, wheeling and
balancing.
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Exhibit 15: Midwest Region Pipeline Corridors
================================================================================
MAP OF THE GAS TRANSPORTATION ROUTES OR
PIPELINE CORRIDORS SERVING THE MIDWEST
MARKET.
Source: Pace and RDI.
================================================================================
Expansion Overview
Pursuit of higher netback prices for producers and stronger than expected demand
growth in electric generation has led to substantial expansion of the pipeline
grid to and from the Midwest.(21) Several expansion projects either have been
recently completed or are under way and will increase pipeline deliverability
into the Midwest Region, particularly from Western Canada and the Rocky
Mountains. Producers in these supply regions are likely to realize higher
commodity prices as a result of improved deliverability to natural gas markets.
If all planned projects are completed, deliverability to the Midwest will
increase by more than 3 Bcf/d, fostering the availability of natural gas
supplies at the Chicago hub. Pace believes that the overall incremental gas
capacity brought into the Midwest Region exceeds outflows; consequently, the
majority of proposed pipeline expansion projects in the Midwest Region are
targeted at delivering natural gas downstream of Chicago. Exhibit 16 illustrates
announced inter and intra-regional pipelines for the Midwest.
- ----------
21 Netback Price: The effective wellhead price to the producer of natural gas,
based on the downstream market price for the natural gas less the charges for
delivering the gas to market.
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Exhibit 16: Announced Midwest Pipeline Expansions
================================================================================
MAP OF ANNOUNCED MIDWEST PIPELINE EXPANSIONS
Estimated
# Project Capacity In Service Sponsor Start End
(MMcf/d) Date State State
- ---------------------------------------------------------------------------------------------------------------------------
1 SupplyLink 750 2002 ANR IL OH
- ---------------------------------------------------------------------------------------------------------------------------
2 Guardian Pipeline 730 2002 Viking Gas Transmission, CMS IL WI
Energy, and WICOR
- ---------------------------------------------------------------------------------------------------------------------------
3 Horizon Pipeline 370 2002 Kinder Morgan IL IL
- ---------------------------------------------------------------------------------------------------------------------------
4 Independence 1,000 2002 ANR OH PA
- ---------------------------------------------------------------------------------------------------------------------------
5 Trailblazer 308 2002 Kinder Morgan CO NE
- ---------------------------------------------------------------------------------------------------------------------------
6 WestLeg Expansion Project TBD 2003 ANR IL WI
- ---------------------------------------------------------------------------------------------------------------------------
Sources: Pace and RDI.
================================================================================
Impact of Pipeline Expansion Project
The APL project has added 1,350 MMcf/d of capacity from Western Canada to the
Chicago hub. A large percentage of the natural gas from the APL project is
destined for end users in the Northeast. To move this natural gas eastward, two
competing corridors have developed in the eastern portion of the Midwest Region.
The more northerly of the two corridors is comprised of the recently completed
Vector pipeline, which extends from Joliet, Illinois, to Dawn, Ontario, and the
proposed Millennium Pipeline ("Millennium"), which would commence at Dawn and
terminate in Westchester County, New York. The second, more southerly corridor
begins with the SupplyLink project, which will loop ANR's existing pipeline from
Joliet to Defiance, Ohio. At Defiance, the proposed Independence Pipeline would
begin and transport supply for 400 miles to Leidy, Pennsylvania, where the
proposed MarketLink project would then move supply to the New York City area.
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Based upon recent regulatory developments, Pace believes that the projects
associated with both of these corridors will be completed. The southern corridor
will likely enter into service late in 2003, whereas the northern corridor will
not be complete until probably late 2004, with a significant chance for further
delays. The recent swelling of political support for Millennium Pipeline's
revised route, however, bodes well for the eventual completion of the more
northerly corridor. Both corridors will enhance considerably the deliverability
into the eastern portion of the Midwest.
Additional major pipeline expansions affecting the Midwest Region include
Guardian Pipeline, Horizon Pipeline, and ANR's WestLeg Expansion. The first two
projects, which recently received the approval of the Federal Energy Regulatory
Commission ("FERC"), will augment deliverability from Joliet, Illinois to
southern Wisconsin and northern Illinois, respectively. Finally, ANR held in May
2001 an open season to determine market interest in a possible expansion of its
system in south-central Wisconsin.
Pipeline Utilization Rates
Future Midwest capacity requirements and basis pricing will hinge on the
utilization of existing and proposed pipeline capacity. Midwest pipelines
reflect a wide range of load factors. Overall, however, capacity utilization
serving the Midwest is comparatively low. During 1998, utilization on
U.S.-sourced pipelines averaged approximately 70 percent.
Many factors influence the utilization of pipeline capacity including:
o Type of load (e.g., industrial process versus seasonal space heat
demand),
o End user portfolio strategies,
o Pipeline maintenance/repairs at compressor stations,
o Customer mix,
o Availability of capacity at alternate receipt/interconnect points,
o Liquidity of primary and secondary markets,
o Availability and proximity of market area storage,
o Level of rates and surcharges,
o Rate design, and
o Flexibility of operational business practices (i.e., nomination and
scheduling procedures, alternate receipt and delivery point use,
balancing/cashout provisions, segmentation practices, and pooling
practices).
Illinois consumes the most natural gas of any state in the Midwest. The next
section discusses recent trends affecting the utilization of pipeline capacity
in the state.
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Illinois Utilization Rates
Recent historical load factors for key pipelines delivering into Illinois are
presented in Exhibit 17.(22) NBPL has the highest load factor for deliveries
into the state.(23) When considered in terms of its total capacity into
Illinois, ANR's annual average annual load factors are relatively low due to the
pipeline's bi-directional capability. During the summer, natural gas on ANR
flows north into Illinois and Michigan to meet summer load and injections into
ANR's storage fields located in Michigan. In the winter, natural gas from
storage flows south, reducing annual average flows into Michigan and adding
capacity for natural gas to flow south into Illinois. When only considering
capacity flowing north into Illinois, ANR's average annual load factor has
ranged from 83 to 95 percent.
Exhibit 17: Illinois Pipeline Utilization Trends
================================================================================
- -------------------------------------------------------------------------------------------------------
ANR Trunkline PEPL
- -------------------------------------------------------------------------------------------------------
Load Load Load
Year Flow Capacity Factor Flow Capacity Factor Flow Capacity Factor
- -------------------------------------------------------------------------------------------------------
1990 570 2,313 25% 1,020 1,799 57% 1,115 1,361 82%
- -------------------------------------------------------------------------------------------------------
1994 925 2,403 38% 1,088 1,799 60% 982 1,361 72%
- -------------------------------------------------------------------------------------------------------
1995 1,221 2,453 50% 919 1,799 51% 1,248 1,361 92%
- -------------------------------------------------------------------------------------------------------
1996 794 2,453 32% 1,241 1,799 69% 1,304 1,361 96%
- -------------------------------------------------------------------------------------------------------
1997 766 2,587 30% 1,178 1,799 65% 1,160 1,361 85%
- -------------------------------------------------------------------------------------------------------
1998 727 2,587 28% 975 1,799 54% 922 1,361 68%
- -------------------------------------------------------------------------------------------------------
1999 727 2,696 27% 1,142 1,799 63% 1,010 1,361 74%
- -------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------
NGPL Northern Border*
----------------------------------------------------------------------------
Load Load
Year Flow Capacity Factor Flow Capacity Factor
----------------------------------------------------------------------------
1990 1,993 3,221 62% N/A N/A N/A
----------------------------------------------------------------------------
1994 2,449 3,315 74% N/A N/A N/A
----------------------------------------------------------------------------
1995 2,565 3,315 77% N/A N/A N/A
----------------------------------------------------------------------------
1996 2,603 3,315 79% N/A N/A N/A
----------------------------------------------------------------------------
1997 2,589 3,315 78% N/A N/A N/A
----------------------------------------------------------------------------
1998 2,324 3,425 68% N/A N/A N/A
----------------------------------------------------------------------------
1999 1,997 3,425 58% 581 663 88%
----------------------------------------------------------------------------
*Natural gas began flowing on Northern Border into Illinois in December
1998.
Source: EIA.
================================================================================
- ----------
22 APL, which is omitted from Exhibit 17, commenced commercial operations on
December 1, 2000. From December 2000 through April 2001 capacity
utilization on APL has varied from 96 percent to 114 percent or from 1.4
to 1.6 Bcf/d.
23 NBPL extended its system into the Chicago area in 1998.
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Gas Storage
Key characteristics of Midwest natural gas storage are the following:
o The Midwest represents nearly 50 percent of U.S. storage capacity.
o The Midwest contains the largest amount of working gas capacity and
deliverability of any U.S. region.
o Michigan, Illinois, West Virginia and Ohio lead respectively in
total storage capacity, while Wisconsin, North and South Dakota are
the only states with no storage fields.
o The Midwest's natural gas storage fields are aquifers, depleted oil
and natural gas fields as well as salt caverns.
An overview of key states providing storage deliverability to the Midwest Region
is shown in Exhibit 18.
Exhibit 18: Overview of Midwest Storage Operations, 1999
================================================================================
- ----------------------------------------------------------------------------------------
Total Gas Estimated Daily Percent of
Number of Capacity Deliverability U.S.
State Active Sites (Bcf) (MMcf/d) Capacity
- ----------------------------------------------------------------------------------------
Iowa 4 273 3,033 3.32%
Illinois 30 899 9,989 10.92%
Indiana 28 113 1,256 1.38%
Kentucky 25 220 2,444 2.67%
Michigan 49 1,072 11,408 13.02%
Minnesota 1 7 78 0.09%
Nebraska 1 39 433 0.48%
Ohio 24 575 6,389 6.99%
West Virginia 36 733 8,144 8.91%
- ----------------------------------------------------------------------------------------
Total Midwest 198 3,931 43,174 47.78%
- ----------------------------------------------------------------------------------------
Total Lower 48 413 8,229 90,930 100.00%
- ----------------------------------------------------------------------------------------
Source: EIA.
================================================================================
Storage projects have been proposed in the Midwest Region in the locations
designated in Exhibit 19.
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Exhibit 19: Location of Proposed Midwest Storage Projects
================================================================================
MAP OF LOCATIONS OF PROPOSED MIDWEST STORAGE PROJECTS
Source: Pace and RDI.
================================================================================
Michigan and Kentucky, followed by Ohio, are the principal states where new
working gas capacity has been proposed. About 400 MMcf/d of new withdrawal
capability has been proposed at one large project in Michigan; a total of 230
MMcf/d at four projects in Kentucky; and 156 MMcf/d, consisting of numerous
sites, in Ohio. Several projects are also underway in West Virginia, but total
withdrawal capacity is much less significant.
Capacity Availability
Two major markets for interstate pipeline capacity exist: a primary market and a
secondary market.(24) Primary market capacity consists of firm transportation
contracts between shippers and interstate pipelines exceeding one-year in
duration. Secondary market capacity, on the other hand, comprises an array of
services including short-term firm (less than one-year), interruptible, or
released capacity. Firm primary capacity is usually available on pipelines that
are not fully subscribed, or may become available through pipeline expansions or
future contract expirations. Both types of capacity are discussed below.
Primary Capacity
The expiration of long-term firm transportation ("FT") agreements between
interstate pipelines and their customers, or "capacity turnback," will play an
important role in satisfying potential requirements for new capacity
deliverability on a firm basis. LDCs, the traditional purchasers of firm
capacity in the Midwest, are gradually exiting the merchant natural gas business
because of
- ----------
24 Capacity can also be acquired as part of a bundled or delivered gas
arrangement with a gas marketer.
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state unbundling initiatives and revised corporate objectives. As this trend
progresses, capacity held by LDCs will become available to other large volume
customers, especially marketers.
Capacity Turnback
Besides acquiring capacity from pipelines expanding their systems or developing
greenfield projects, opportunities exist to purchase turnback capacity from
pipelines, made available by shippers who have not exercised their rights of
first refusal to retain capacity.
Pace's analysis of primary capacity availability on ANR, NGPL, NBPL, and
Trunkline indicates that a significant amount of capacity is likely to become
available under expiring contracts during the short- and mid-term. Of these
pipelines, between 2002 and 2005 NGPL will experience the greatest potential
turnback of capacity-3,600 MMcf/d. During the same period ANR, NBPL, and
Trunkline will have contracts expire for 1,900 MMcf/d, 1,400 MMcf/d, and 1,100
MMcf/d of firm capacity, respectively. Pace expects the majority of this
capacity to be resubscribed in the future. However, Pace believes that the new
agreements may be for shorter periods and subject to selective discounting. The
outlook for potential capacity turnback on ANR, NGPL, NBPL, and Trunkline is
depicted in Exhibit 20.(25)
- ----------
25 Capacity on APL was subscribed under contracts; therefore it has not been
included in the analysis above.
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Exhibit 20: Decontracting Schedules of Select Interstate Pipelines Serving
Chicago
================================================================================
GRAPH DEPICTING OUTLOOK FOR
POTENTIAL CAPACITY TURNBACK ON
ANR, NGPL, NBPL AND TRUNKLINE PIPELINES.
- -------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011-2030
- -------------------------------------------------------------------------------------------------------------
ANR 1264 438 754 498 178 146 30 314 27 418 587
- -------------------------------------------------------------------------------------------------------------
Trunkline 792 761 162 138 31 0 30 0 0 20 135
- -------------------------------------------------------------------------------------------------------------
NGPL 2441 769 2097 231 485 80 267 441 20 57 137
- -------------------------------------------------------------------------------------------------------------
NBPL 135 0 1154 170 120 81 60 950 338 160 152
- -------------------------------------------------------------------------------------------------------------
Sources: Pace and RDI.
================================================================================
Secondary Capacity
The marketplace for trading released capacity in the Midwest is robust. Pace
finds that secondary market transactions often reflect the following
characteristics:
o Marketers control a growing share of total capacity in the Midwest
and are significant holders of released capacity.
o Capacity deals are usually structured so that receipt points are
located at liquid upstream pooling points.
o The release market is a vital component of the overall fuel plans of
large volume customers in the Midwest.
o After removing long-term deals, use of the release market is
seasonal, peaking in the summer.
Midwest shippers have adopted a varied approach to buying and selling released
capacity. For example, many shippers' short-term release portfolio often
includes transactions with the following terms: one year; seasonal deals that
last 5 to 7 months for peak (i.e., Winter) and off-peak (i.e., Summer) periods;
one month; or intra-month deals.
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Pipeline Transportation Rates
In addition to capacity availability, pipelines experience large differences
between primary and secondary market pricing. Maximum tariff firm transportation
rates are used as a benchmark for transportation pricing in the primary market
while basis values, interruptible transportation, and prices for released
capacity provide indicators of secondary market valuation.
Primary Market
The primary transportation market consists of capacity obtained directly from
the pipelines and priced at either full tariff or at a discount. Pipelines tend
to make discounts available, when competitive alternatives and/or excess
capacity on a specific line exists. Discounts to full tariff are frequently
available in Midwest markets since pipelines compete to increase their
respective load factors. Discounts are also obtained in the secondary capacity
release market, which is discussed below.
The following characteristics are indicative of transportation pricing in
the Midwest market:
o There is a slight seasonal variation in the basis between the
Midwest Region and the Henry Hub, ranging approximately from
$0.05/MMBtu to $0.15/MMBtu.
o Basis and transportation prices generally are facing downward
pressure as incremental pipeline capacity in the region is brought
on line. As a result, the basis differentials between key liquid
downstream points in the Midwest and the Henry Hub are narrowing.
o Growing competition among pipelines and suppliers is driving costs
down to the marginal cost of transporting supply from the Gulf Coast
to Chicago. As a result, transportation rates from the Gulf Coast
will likely be a significantly lower percentage of the total
delivered natural gas price in the Midwest when compared to rates
from Western Canada.
o Transportation rates from Western Canada during peak days will be
valued by the market at or slightly above maximum tariff rates,
while rates from the Gulf Coast will be valued at a significant
discount to maximum tariff rates.
Secondary Market
The value of Midwest transportation capacity, as reflected in secondary release
markets, tends to be substantially less than the maximum tariff rate. This
reflects both the general mildness of recent winters, and the nature of pipeline
capacity to be bid down to variable cost if excess capacity exists, and to be
bid up well above actual costs if capacity is tight.
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Exhibit 21 provides a side-by-side comparison of basis values for the past four
winters and summers. Average basis values in the Chicago market have traded
around $0.07/MMBtu in the summer and $0.15/MMBtu in the winter between 1997 and
the first few months of 2001. The introduction of new pipeline capacity into the
region during this period has resulted in a highly competitive transportation
market. Michigan basis values trade within a few cents per MMBtu of the Chicago
market.
Exhibit 21: Historic Summer and Winter Basis Values (1997 - 2001)
================================================================================
GRAPH COMPARING BASIS VALUES FOR
THE PAST FOUR WINTERS AND SUMMERS
AT VARIOUS TRADING POINTS.
Source: Pace.
================================================================================
Interruptible Transportation Rates
Secondary market value can also be determined based on the actual rates charged
for interruptible transportation (IT) on an interstate pipeline. Maximum tariff
IT rates are often equivalent to firm transportation rates on a 100 percent load
factor firm transportation rate. The price advantage for contracting IT capacity
is achieved by avoiding fixed monthly charges and contracting higher discounts
to maximum tariff rates. Since IT discounts were not publicly available,
short-term capacity release deals are a fair indicator for the value of IT
capacity.
Capacity Release Rates
Liquid secondary market trading exists on most Midwest pipelines, and plays a
key role in determining actual transportation costs to the region. Deals are
transacted with an array of terms:
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single day, intra-month, monthly, seasonal, and long-term. Most capacity is
traded under one-month or long-term (deals greater than 6-months) deals. Using
released capacity is an important tool for shippers in the Midwest to augment
their natural gas supply needs.
The single most important factor affecting capacity release rates is
weather-driven temperatures that produce a tightening of capacity, particularly
in the winter, but also during the summer cooling season on some pipelines as
demand for gas-fired electric generation increasingly competes with storage
injections. The intensity and significance of this factor differs among
pipelines and along specific pipeline paths.
A summary of the availability and pricing of released capacity in the Midwest is
presented in Exhibit 22.
Exhibit 22: Summary of Historical Capacity Release Transactions
================================================================================
GRAPH DISPLAYING THE AVAILABILITY AND PRICING
OF RELEASED CAPACITY FOR THE NGPL PIPELINE
FROM JANUARY 1, 1997 TO APRIL 1, 2001.
================================================================================
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GRAPH DISPLAYING THE AVAILABILITY AND
PRICING OF RELATED CAPACITY FOR THE
ANR PIPELINE FROM JANUARY 1, 1997 TO
APRIL 1, 2001.
Sources: Pace and RDI.
================================================================================
Exhibit 23 compares monthly pricing of released capacity on ANR's Illinois Line,
NGPL, PEPL, Trunkline, and NBPL. Historically ANR capacity has traded for about
50 percent of its maximum tariff value. Typically about 300,000 MMBtu/d of
capacity is traded in the Upper Midwest zones on ANR's system. Recently,
released capacity volumes on NGPL near Chicago have declined. Pace attributes
this decline in trades starting in 1999 to a two-year negotiated capacity
contract. Through this agreement, a large natural gas marketer acquired capacity
for 500,000 MMBtu/d, or approximately 15 percent of NGPL's throughput into
Chicago, for a term of two years. Pace believes this marketer is using this
capacity to provide delivered natural gas arrangements to large end users and
power generators, who otherwise would be entering the short-term capacity
release market.
Exhibit 23: Availability and Pricing of Released Capacity
================================================================================
- -------------------------------------------------------------------------------------------------------
NGPL ANR
- -------------------------------------------------------------------------------------------------------
Percent of Percent of
Date Volume Price Bid Rate Volume Price Bid Rate
- -------------------------------------------------------------------------------------------------------
01/97 34,349 $0.11 21% 3,000 $0.42 100%
02/97 59,024 $0.14 31% 3,000 $0.42 100%
- -------------------------------------------------------------------------------------------------------
03/97 178,285 $0.11 24% 218,738 $0.18 55%
- -------------------------------------------------------------------------------------------------------
04/97 381,385 $0.12 30% 225,752 $0.14 40%
- -------------------------------------------------------------------------------------------------------
05/97 178,214 $0.17 42% 182,223 $0.17 53%
- -------------------------------------------------------------------------------------------------------
06/97 346,772 $0.17 42% 73,802 $0.23 81%
- -------------------------------------------------------------------------------------------------------
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- ----------------------------------------------------------------------------------------------------------
NGPL ANR
- ----------------------------------------------------------------------------------------------------------
Percent of Percent of
Date Volume Price Bid Rate Volume Price Bid Rate
- ----------------------------------------------------------------------------------------------------------
07/97 299,280 $0.17 40% 115,656 $0.19 65%
- ----------------------------------------------------------------------------------------------------------
08/97 303,220 $0.17 41% 201,829 $0.14 50%
- ----------------------------------------------------------------------------------------------------------
09/97 335,119 $0.15 36% 169,434 $0.16 49%
- ----------------------------------------------------------------------------------------------------------
10/97 213,188 $0.22 51% 292,268 $0.12 37%
- ----------------------------------------------------------------------------------------------------------
11/97 122,730 $0.29 56% 154,614 $0.15 51%
- ----------------------------------------------------------------------------------------------------------
12/97 38,240 $0.16 33% 71,733 $0.20 91%
- ----------------------------------------------------------------------------------------------------------
01/98 35,985 $0.13 28% 107,769 $0.16 68%
- ----------------------------------------------------------------------------------------------------------
02/98 46,985 $0.12 29% 346,214 $0.12 55%
- ----------------------------------------------------------------------------------------------------------
03/98 122,604 $0.07 17% 407,557 $0.10 37%
- ----------------------------------------------------------------------------------------------------------
04/98 287,471 $0.11 34% 525,353 $0.08 29%
- ----------------------------------------------------------------------------------------------------------
05/98 301,224 $0.15 47% 502,401 $0.14 44%
- ----------------------------------------------------------------------------------------------------------
06/98 356,849 $0.14 45% 349,416 $0.11 40%
- ----------------------------------------------------------------------------------------------------------
07/98 561,659 $0.20 62% 550,668 $0.09 34%
- ----------------------------------------------------------------------------------------------------------
08/98 547,180 $0.20 62% 492,161 $0.09 32%
- ----------------------------------------------------------------------------------------------------------
09/98 619,434 $0.23 70% 689,890 $0.09 33%
- ----------------------------------------------------------------------------------------------------------
10/98 539,466 $0.26 77% 622,154 $0.08 30%
- ----------------------------------------------------------------------------------------------------------
11/98 382,920 $0.28 80% 501,804 $0.15 51%
- ----------------------------------------------------------------------------------------------------------
12/98 59,767 $0.20 51% 244,216 $0.18 52%
- ----------------------------------------------------------------------------------------------------------
01/99 75,855 $0.18 44% 246,893 $0.21 74%
- ----------------------------------------------------------------------------------------------------------
02/99 136,642 $0.14 36% 255,220 $0.20 75%
- ----------------------------------------------------------------------------------------------------------
03/99 99,180 $0.10 25% 325,828 $0.19 67%
- ----------------------------------------------------------------------------------------------------------
04/99 222,066 $0.05 17% 501,655 $0.07 31%
- ----------------------------------------------------------------------------------------------------------
05/99 60,000 $0.08 27% 392,853 $0.06 32%
- ----------------------------------------------------------------------------------------------------------
Jun-99 10,000 $0.01 2% 329,430 $0.08 37%
- ----------------------------------------------------------------------------------------------------------
Jul-99 2,475 $0.00 0% 464,788 $0.06 29%
- ----------------------------------------------------------------------------------------------------------
Aug-99 16,781 $0.23 37% 441,067 $0.06 29%
- ----------------------------------------------------------------------------------------------------------
Sep-99 15,975 $0.24 39% 435,417 $0.06 28%
- ----------------------------------------------------------------------------------------------------------
Oct-99 13,500 $0.28 46% 460,548 $0.07 35%
- ----------------------------------------------------------------------------------------------------------
Nov-99 -- $0.00 0% 242,197 $0.12 55%
- ----------------------------------------------------------------------------------------------------------
Dec-99 140,190 $0.35 93% 207,421 $0.16 70%
- ----------------------------------------------------------------------------------------------------------
Jan-00 -- $0.00 0% 222,029 $0.14 66%
- ----------------------------------------------------------------------------------------------------------
Feb-00 -- $0.00 0% 229,435 $0.15 65%
- ----------------------------------------------------------------------------------------------------------
Mar-00 -- $0.00 0% 205,476 $0.14 66%
- ----------------------------------------------------------------------------------------------------------
Apr-00 109,099 $0.28 87% 256,772 $0.14 60%
- ----------------------------------------------------------------------------------------------------------
May-00 10,000 $0.05 18% 222,956 $0.17 71%
- ----------------------------------------------------------------------------------------------------------
Jun-00 10,000 $0.05 18% 206,475 $0.11 42%
- ----------------------------------------------------------------------------------------------------------
Jul-00 10,000 $0.05 18% 285,137 $0.12 51%
- ----------------------------------------------------------------------------------------------------------
Aug-00 30,000 $0.03 10% 257,890 $0.13 56%
- ----------------------------------------------------------------------------------------------------------
Sep-00 30,000 $0.03 10% 231,589 $0.09 29%
- ----------------------------------------------------------------------------------------------------------
Oct-00 30,000 $0.03 10% 155,165 $0.15 57%
- ----------------------------------------------------------------------------------------------------------
Nov-00 50,000 $0.11 28% 114,712 $0.18 84%
- ----------------------------------------------------------------------------------------------------------
Dec-00 50,000 $0.15 35% 172,946 $0.18 84%
- ----------------------------------------------------------------------------------------------------------
Jan-01 50,000 $0.13 31% 159,901 $0.23 104%
- ----------------------------------------------------------------------------------------------------------
Feb-01 50,000 $0.13 31% 196,483 $0.23 99%
- ----------------------------------------------------------------------------------------------------------
Mar-01 50,000 $0.13 31% 250,038 $0.23 92%
- ----------------------------------------------------------------------------------------------------------
Apr-01 10,000 $0.17 49% 163,084 $0.12 66%
- ----------------------------------------------------------------------------------------------------------
May-01 1,000 $0.03 9% 215,045 $0.10 56%
- ----------------------------------------------------------------------------------------------------------
Note: Evaluation of the short-term market for released capacity on APL,
Vector, and NBPL is not possible because of the lack of historical time series
data.
Sources: Pace and RDI.
================================================================================
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ASSESSMENT OF TRANSPORTATION SERVICES
Overall, Pace believes that Elwood can obtain adequate delivery of natural gas
supply to support the Project's power sales arrangements. Nicor and PGL have
adequate pipeline deliverability at sufficient pressure to meet reliably the
Project's natural gas requirements. Pace also finds that the Project's upstream
link via Nicor and PGL to NBPL, NGPL, and APL and provides access to adequate
supply diversity.
Nicor, a local distribution company, delivers 278 Bcf of natural gas annually to
nearly 2 million customers in northern Illinois. Nicor's 29,000-mile
distribution system transports natural gas from major production regions in
North America. Nicor has seven underground natural gas storage facilities and
over the last three years has withdrawn an average of 123 Bcf annually and
injected an average of 126 Bcf annually. Nicor interconnects with multiple
interstate pipelines, including NBPL, NGPL, Midwestern, ANR, Panhandle, and APL.
PGL, a local distribution company, delivers 90 Bcf of natural gas annually to
835,000 customers in Chicago. PGL is connected to major pipelines such as ANR,
NGPL, and NBPL, which provide access to every major natural gas production area
in the U.S. and Canada. PGL has one underground natural gas storage facility and
over the last three years has withdrawn an average of 60 Bcf annually and
injected an average of 55 Bcf annually.
Exhibit 24 illustrates the interconnect capacities of various pipelines to the
LDCs. In addition to the transportation capacity, PGL and Nicor have extensive
market area storage capabilities. For example, peak day natural gas delivery for
PGL and Nicor, respectively, is 900 MMcf/d and 2,600 MMcf/d, or a total of 3,500
MMcf/d. Aggregate working gas storage capacity for these LDC is about 170
Bcf/year.
Exhibit 24: Key Nicor and PGL Receipt Capabilities (Mcf/d)
================================================================================
Interconnecting Pipeline Deliveries to PGL Deliveries to Nicor
(MMcf/d) (MMcf/d)
ANR 300 200 (Shorewood)
200 (Hampshire)
APL 600 300 - 350
Midwestern 300 268
NBPL 600 400 (Troy Grove)
400 (Minooka)
NGPL 1,500 1,200 - 1,400
Northern Natural N/A 200
Trunkline 300 N/A
Sources: Pace and LDC representatives.
================================================================================
Elwood is located within Nicor's natural gas utility franchise area. As a
result, Elwood has entered into an agreement with Nicor to transport natural gas
to Elwood; separately Nicor and PGL have entered into a companion agreement to
support Nicor's service to Elwood.
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As shown in Exhibit 25 numerous pipelines could meet the natural gas
requirements of the Project.
Exhibit 25: Chicago Area Pipeline System Map
================================================================================
[GRAPHIC]
Sources: Pace and RDI.
================================================================================
In addition to the Nicor and PGL local distribution company systems, numerous
interstate pipelines deliver natural gas into the Chicago area. Upon the
expiration of the existing agreement with Nicor, Pace finds that Elwood has
numerous transportation alternatives.
The deliverability attributes of these interstate pipeline systems are presented
in Exhibit 26.
Exhibit 26: Chicago Area Pipeline Deliverability Attributes
================================================================================
- -------------------------------------------------------------------------------------------------------------------------
Approximate Estimated Mainline
Distance from Capacity Pressure Diameter Primary Sources of Supply
Pipeline Project (Miles) (MMcf/d) (PSIG) (Inches)
- -------------------------------------------------------------------------------------------------------------------------
ANR 2.0 505* 450-745 2x30" Mid-Continent, Gulf Coast
- -------------------------------------------------------------------------------------------------------------------------
NBPL 2.8 618 760-980 1x30" WCSB
- -------------------------------------------------------------------------------------------------------------------------
Midwestern 3.0 650 936 1x30" Gulf Coast
- -------------------------------------------------------------------------------------------------------------------------
NGPL 5.0 1,705 450 2x30" Permian, Mid-Continent, Gulf Coast
1x36"
- -------------------------------------------------------------------------------------------------------------------------
APL Less than 1/4 mile 1,250 1,740 1x36" WCSB
- -------------------------------------------------------------------------------------------------------------------------
Vector 1.7 1,000 1,000 1x30" Any supply delivered into Chicago or Dawn
(Permian, Mid-Continent, Gulf Coast,
WCSB, Rockies, etc.)
- -------------------------------------------------------------------------------------------------------------------------
*As measured in Will County.
Source: Pace.
================================================================================
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================================================================================
PRO FORMA FUEL PRICING
================================================================================
This section of the report addresses Pace's review of fuel-related cost and
revenue price inputs used in the pro forma model. Projections of the Project's
natural gas commodity and transportation costs, both regional and plant specific
are also discussed.
PACE FUEL PRICE FORECAST
The Project is located in the Pace Chicago Citygate natural gas price region.
Pace's forecast of natural gas commodity prices at the Henry Hub and regional
benchmark delivered basis is discussed below.
The Base Year prices and annual escalation rates in the forecast are based on
Pace's analysis of historical price data and the fundamental factors driving the
natural gas market. All forecast prices are in 1998 dollars and represent a
regional benchmark market price.(26)
Pace's forecasting methodology recognizes that actual prices to existing
facilities often vary from the regional benchmark due to
advantages/disadvantages in supply contract terms or transportation rates. To
develop plant-specific fuel forecasts for these facilities, the regional
benchmark price is adjusted to reflect plant-specific cost factors. These
plant-specific cost factors are maintained throughout the Forecast Period.
Pace's independent forecast of delivered natural gas prices is comprised of
commodity prices, represented by the price for natural gas on the New York
Mercantile Exchange ("NYMEX") at the Henry Hub in Louisiana, plus a regional
basis adjustment to reflect price differentials between the Gulf Coast and
various delivered price sub-regions.
In general, Pace expects Henry Hub commodity prices to peak in 2001 and then
decline through 2009. Thereafter, Pace expects a 0.5 percent annual real price
increase throughout the remainder of the Forecast Period. Fundamental factors
driving Pace's Henry Hub commodity forecast are:
o Supply from a year of record drilling is beginning to enter the
market. The industry has entered a cycle of lower prices and higher
injections, which may lead to further price declines. Pace expects
natural gas prices at the Henry Hub to average about $4.00/MMBtu for
the remainder of the 2001, although cash market prices on a given
day may be higher or lower due to short-term technical factors.
o Leading natural gas supply indicators are currently at record
levels, signaling that a significant rebound is likely under way.
The U.S. natural gas-directed rig count stood at over 1,000 in June
2001, compared to a count just above 600 eighteen months previously.
Assuming a six to eighteen month lag between drilling and new
production, and normal
- ----------
26 Gas-fired expansion plants are assigned the natural gas regional benchmark
price.
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summer weather patterns, Pace expects continued, if not
intensifying, increased downward pressure on prices throughout 2001.
o As of June 1, 2001, the industry has added over 770 Bcf to natural
gas storage inventories. This is 451 Bcf greater than injections
during the same period last year and inventories are now over 50
percent full.
o Pace expects that substantial incremental natural gas demand from
new greenfield gas-fired power generation during the next three
years will offset some of the downward price pressure exerted by new
supply from increased drilling. Pace estimates that new gas fired
generation will add almost 5.4 Bcf/d in incremental natural gas
consumption by 2004.
o Expansion of the North American pipeline grid and productive
capacity from the Gulf Coast and the Western Canadian Sedimentary
Basin will increase competition, particularly in the Midwest and
Northeast. By 2004, several new pipeline projects, such as
Millennium and Independence should be completed, which will
encourage gas-on-gas competition causing Henry Hub prices to decline
further from current levels.
o Both onshore and offshore Gulf Coast production will increase in
2001 and 2002 due to record drilling during 2000. Increases in deep
water offshore drilling will offset production declines from the
shallow offshore.
o Over the long term, Pace does not anticipate in its Base Case
commodity forecast sustained natural gas shortfalls as producers
respond to higher prices. Higher prices support a greater and faster
expected return on drilling investments, high rig counts, and future
production growth.
o Environmental regulations requiring the use of cleaner, more
efficient fuels have shifted consumption preferences to natural gas
thereby contributing to a higher long-term real price escalation
rate relative to other fuels.
o In the long run, technologically driven declines in exploration and
production costs, and increases in finding rates will increase
productive capacity. These supply-side fundamentals will keep real
natural gas prices from escalating too high relative to other fuels.
Pace's long-term forecast of Midwest Regional natural gas prices is presented in
Exhibit 27.
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Exhibit 27: Sub-Regional Delivered Gas Price Forecasts (1998 $/MMBtu)
================================================================================
- ---------------------------------------------------------------------------------------------------------
Chicago Great South East Upper
Year Henry Hub Citygate* Lakes Midwest Plains Wisconsin Midwest
- ---------------------------------------------------------------------------------------------------------
2001 4.98 5.05 4.47 5.10 5.14 5.33 5.14
- ---------------------------------------------------------------------------------------------------------
2002 3.80 3.86 3.81 3.91 3.96 4.15 3.96
- ---------------------------------------------------------------------------------------------------------
2003 3.28 3.33 3.28 3.38 3.44 3.63 3.44
- ---------------------------------------------------------------------------------------------------------
2004 2.94 3.00 2.95 3.05 3.10 3.29 3.10
- ---------------------------------------------------------------------------------------------------------
2005 2.72 2.79 2.74 2.84 2.88 3.07 2.88
- ---------------------------------------------------------------------------------------------------------
2006 2.57 2.64 2.59 2.69 2.73 2.92 2.73
- ---------------------------------------------------------------------------------------------------------
2007 2.47 2.54 2.49 2.59 2.63 2.82 2.63
- ---------------------------------------------------------------------------------------------------------
2008 2.41 2.48 2.43 2.53 2.57 2.76 2.57
- ---------------------------------------------------------------------------------------------------------
2009 2.40 2.47 2.42 2.52 2.56 2.75 2.55
- ---------------------------------------------------------------------------------------------------------
2010 2.41 2.48 2.43 2.53 2.57 2.76 2.57
- ---------------------------------------------------------------------------------------------------------
2011 2.42 2.49 2.44 2.54 2.58 2.77 2.58
- ---------------------------------------------------------------------------------------------------------
2012 2.43 2.50 2.45 2.55 2.59 2.78 2.59
- ---------------------------------------------------------------------------------------------------------
2013 2.45 2.52 2.47 2.57 2.61 2.80 2.60
- ---------------------------------------------------------------------------------------------------------
2014 2.46 2.53 2.48 2.58 2.62 2.81 2.61
- ---------------------------------------------------------------------------------------------------------
2015 2.47 2.54 2.49 2.59 2.63 2.82 2.63
- ---------------------------------------------------------------------------------------------------------
2016 2.48 2.55 2.50 2.60 2.64 2.83 2.64
- ---------------------------------------------------------------------------------------------------------
2017 2.50 2.57 2.52 2.62 2.66 2.85 2.65
- ---------------------------------------------------------------------------------------------------------
2018 2.51 2.58 2.53 2.63 2.67 2.86 2.66
- ---------------------------------------------------------------------------------------------------------
2019 2.52 2.59 2.54 2.64 2.68 2.87 2.68
- ---------------------------------------------------------------------------------------------------------
2020 2.53 2.60 2.55 2.65 2.69 2.88 2.69
- ---------------------------------------------------------------------------------------------------------
2021 2.55 2.62 2.57 2.67 2.71 2.90 2.70
- ---------------------------------------------------------------------------------------------------------
2022 2.56 2.63 2.58 2.68 2.72 2.91 2.71
- ---------------------------------------------------------------------------------------------------------
2023 2.57 2.64 2.59 2.69 2.73 2.92 2.73
- ---------------------------------------------------------------------------------------------------------
2024 2.58 2.65 2.60 2.70 2.74 2.93 2.74
- ---------------------------------------------------------------------------------------------------------
2025 2.60 2.67 2.62 2.72 2.76 2.95 2.75
- ---------------------------------------------------------------------------------------------------------
2026 2.61 2.68 2.63 2.73 2.77 2.96 2.77
- ---------------------------------------------------------------------------------------------------------
*Price equivalent to Gas Daily's published index Midpoint of Chicago Large
End Users.
Source: Pace.
================================================================================
FUEL-RELATED PRO FORMA INPUTS
Pace reviewed the fuel-related inputs in the pro forma financial model and makes
the following findings.(27)
o The Project's pro forma accurately incorporates Pace's natural gas
price forecast throughout the Financing Term.
o The monthly reservation and volumetric charges applied to utilizing
local transportation and storage/balancing contracts identified in
the in the pro forma have been accounted for accurately. The pro
forma conservatively assumes that these costs are required
throughout the Financing Term.
o Storage and balancing agreements have been appropriately
incorporated into the pro forma model.
- ----------
27 Stone & Webster Pro Forma Model, July 19, 2001.
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o The 3.0 percent annual escalation factor for local transportation
and balancing services beyond the initial contract periods is
reasonable.
o Fuel management costs have been accurately reflected in the pro
forma model. Even though the Cinergy FMA has only a 1-year term,
Pace finds that it is appropriate that the pro forma accounts for
fuel management costs throughout the Financing Term.
- --------------------------------------------------------------------------------
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