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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON NOVEMBER 28, 2000
REGISTRATION NO. 333-[ ]
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM S-4
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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CEDAR BRAKES I, L.L.C.
(Exact name of registrant as specified in its charter)
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<S> <C> <C>
DELAWARE 4911 76-0613738
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of organization) Classification Code Number) Identification No.)
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1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
TEL: (713) 420-2131
(Address, including ZIP code, and telephone number, including area code
of registrant's principal executive offices)
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BRITTON WHITE JR.
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
TEL: (713) 420-2131
(Name, address, including ZIP code, and telephone number, including area code,
of agent for service)
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Copies of correspondence to:
A. ROBERT COLBY, ESQ.
CHADBOURNE & PARKE LLP
30 ROCKEFELLER PLAZA
NEW YORK, NEW YORK 10112
TEL.: (212) 408-5100
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE OF THE SECURITIES TO THE
PUBLIC: as soon as practicable after the effective date of this Registration
Statement.
If any of the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance with
General Instruction G, check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
CALCULATION OF REGISTRATION FEE
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TITLE OF EACH CLASS OF PROPOSED MAXIMUM PROPOSED MAXIMUM
SECURITIES AMOUNT TO BE OFFERING PRICE PER AGGREGATE OFFERING AMOUNT OF
TO BE REGISTERED REGISTERED(1) BOND(2) PRICE(2) REGISTRATION FEE
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<S> <C> <C> <C> <C>
8 1/2% Series B Senior Secured
Bonds due February 15,
2014......................... $310,600,000 100% $310,600,000 $81,999
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(1) Equals the aggregate principal amount of the securities being registered.
(2) Pursuant to Rule 457(f)(2), the registration fee has been calculated using
the book value of the securities being registered.
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THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THIS REGISTRATION STATEMENT
SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO
SECTION 8(a), MAY DETERMINE.
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THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE
MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH
THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS
NOT AN OFFER TO SELL THESE SECURITIES, AND WE ARE NOT SOLICITING AN OFFER
TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT
PERMITTED.
SUBJECT TO COMPLETION, DATED NOVEMBER 28, 2000
PRELIMINARY PROSPECTUS
CEDAR BRAKES I, L.L.C.
$310,600,000
OFFER TO EXCHANGE ALL OUTSTANDING
8 1/2% SENIOR SECURED BONDS DUE 2014
FOR
8 1/2% SERIES B SENIOR SECURED BONDS DUE 2014
THAT HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933
We are offering to exchange all of our outstanding 8 1/2% Senior Secured
Bonds due 2014 for our registered 8 1/2% Series B Senior Secured Bonds due 2014.
In this prospectus, we will call the original bonds the "Series A bonds" and the
registered bonds the "Series B bonds." The Series A bonds were issued on
September 26, 2000. The terms of the Series B bonds are substantially identical
to the terms of the Series A bonds, except that we have registered the Series B
bonds with the Securities and Exchange Commission. Because we have registered
the Series B bonds, the Series B bonds will not be subject to certain transfer
restrictions and will not be entitled to registration rights. The Series A bonds
and Series B bonds are collectively referred to in this prospectus as the
"bonds."
THE SERIES B BONDS
- The Series B bonds will mature on February 15, 2014.
- We will pay interest on the Series B bonds semi-annually on February 15
and August 15 of each year beginning February 15, 2001 at the rate of
8 1/2% per annum.
- We may redeem the Series B bonds at any time. The redemption prices we
will pay if we do redeem bonds are specified in the prospectus under
"Description of the Bonds -- Redemption at Our Option."
- The Series B bonds are secured obligations and senior to all our current
indebtedness and future indebtedness.
THE EXCHANGE OFFER
- Subject to certain customary conditions, which we may waive, the exchange
offer is not conditioned upon a minimum aggregate principal amount of
Series A bonds being tendered.
- Our offer to exchange Series A bonds for Series B bonds will be open
until 5:00 p.m., New York City time, on [ ], 2000, unless we
extend the expiration date.
- You should also carefully review the procedures for tendering the Series
A bonds beginning on page 59 of this prospectus.
- You may withdraw your tenders of Series A bonds at any time prior to the
expiration of the exchange offer, unless we have already accepted your
Series A bonds for exchange.
- If you fail to tender your Series A bonds, you will continue to hold
unregistered securities and your ability to transfer them could be
adversely affected.
- The exchange of Series A bonds for Series B bonds in the exchange offer
will not be a taxable event for U.S. federal income tax purposes.
YOU SHOULD CAREFULLY CONSIDER THE RISK FACTORS BEGINNING ON PAGE 18 OF THIS
PROSPECTUS BEFORE PARTICIPATING IN THE EXCHANGE OFFER.
NEITHER THE SEC NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR
DISAPPROVED 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 NOVEMBER 28, 2000
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TABLE OF CONTENTS
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PAGE
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AVAILABLE INFORMATION....................................... ii
NOTICE TO NEW HAMPSHIRE RESIDENTS ONLY...................... ii
FORWARD-LOOKING STATEMENTS.................................. iii
PROSPECTUS SUMMARY.......................................... 1
RISK FACTORS................................................ 18
RATIO OF EARNINGS TO FIXED CHARGES.......................... 23
USE OF PROCEEDS............................................. 23
CAPITALIZATION.............................................. 24
OUR COMPANY AND BUSINESS.................................... 24
SELECTED FINANCIAL DATA OF OUR COMPANY...................... 24
MANAGEMENT.................................................. 25
EL PASO ENERGY AND SELECTED FINANCIAL INFORMATION OF EL PASO
ENERGY.................................................... 27
EPM......................................................... 29
LIMESTONE................................................... 30
MESQUITE AND CHAPARRAL...................................... 30
CHAPARRAL MANAGEMENT........................................ 30
PSE&G....................................................... 30
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS................................. 31
REGULATION OF THE ELECTRIC INDUSTRY......................... 34
THE TRANSACTION............................................. 37
SECURITY OWNERSHIP OF CERTAIN OWNERS........................ 40
SUMMARY OF CERTAIN TRANSACTION DOCUMENTS.................... 41
AMENDED AND RESTATED PPA.................................... 41
POWER SERVICES AGREEMENT.................................... 47
ADMINISTRATIVE SERVICES AGREEMENT........................... 53
EL PASO ENERGY PERFORMANCE GUARANTY......................... 55
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 57
THE EXCHANGE OFFER.......................................... 57
DESCRIPTION OF THE BONDS.................................... 65
DESCRIPTION OF OUR PRINCIPAL FINANCING DOCUMENTS............ 84
CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES................ 85
CERTAIN ERISA CONSIDERATIONS................................ 88
PLAN OF DISTRIBUTION........................................ 90
LEGAL MATTERS............................................... 91
EXPERTS..................................................... 91
INDEX TO FINANCIAL STATEMENTS............................... F-1
ANNEX A -- POWER SERVICES AGREEMENT ASSESSMENT.............. A-1
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You may not transfer or resell the Series B bonds except as permitted under
the Securities Act of 1933 and applicable state securities laws.
You should rely only on the information contained in this document or any
supplement. We have not authorized anyone to provide you with any information
that is different. If you receive any unauthorized information, you must not
rely on it. You should disregard anything we said in an earlier document that is
inconsistent with what is in our prospectus.
You should not assume that the information in this prospectus or any
supplement or any of the information incorporated by reference in this
prospectus or any supplement is current as of any date other than the date on
the front page of this prospectus.
This document is not an offer to sell nor is it seeking an offer to buy
these securities in any state or jurisdiction where the offer or sale is not
permitted.
AVAILABLE INFORMATION
We are filing with the SEC a Registration Statement on Form S-4 relating to
the Series B bonds. This prospectus is a part of the Registration Statement, but
the Registration Statement includes additional information and also includes
exhibits that are referenced in this prospectus. You can review a copy of the
Registration Statement through the SEC's "EDGAR" System (Electronic Data
Gathering, Analysis and Retrieval) that is available on the SEC's web site
(http://www.sec.gov).
After our Registration Statement becomes effective, we will be required to
file publicly certain information under the Securities Exchange Act of 1934, as
amended. All our public filings will also be available on EDGAR, including
annual and quarterly reports and other information. You may also read and copy
all of our public filings at the SEC's public reference room in Washington, D.C.
or at their facilities in New York and Chicago. Please call the SEC at (800)
732-0330 for further information on the operation of the public reference rooms.
El Paso Energy Corporation is subject to the information requirements of
the Securities Exchange Act, and, in accordance therewith, files periodic
reports, proxy statements and other information with the SEC.
Reports, proxy statements and other information filed by El Paso Energy
with the SEC can be inspected, without charge, and copied at the public
reference facilities maintained by the SEC at 450 Fifth Street, N.W., Room 1024,
Washington D.C. 20549 and at the SEC's regional offices at Citicorp Center, 500
West Madison Street, Suite 1400, Chicago, Illinois 60661 and 7 World Trade
Center, Suite 1300, New York, New York 10048. The SEC also maintains a site on
the Internet at <http://www.sec.gov> that contains reports, proxies and other
information regarding registrants that file electronically with the SEC, and
certain filings by El Paso Energy are available at such web site. Copies of such
materials also can be obtained from the Public Reference Section of the SEC at
450 Fifth Street, N.W., Washington, D.C. 20549 at prescribed rates.
NOTICE TO NEW HAMPSHIRE RESIDENTS ONLY
NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A
LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES
WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY
REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A
FINDING BY THE SECRETARY OF STATE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS
TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN
EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT
THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS
OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSAC-
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TION. IT IS UNLAWFUL TO MAKE OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER,
CUSTOMER OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS
PARAGRAPH.
FORWARD-LOOKING STATEMENTS
Certain statements contained in this prospectus are forward-looking
statements. These forward-looking statements can be identified by the use of
words such as "expect," "intend," "plan," "project," "believe," "estimate" and
similar expressions. We have based these forward-looking statements on our
current expectations, and our and the independent energy consultant's
projections about future events based upon our knowledge of facts as of the date
of this prospectus and the independent energy consultant's assumptions about
future events. These forward-looking statements are subject to various risks and
uncertainties that may be outside our control and that may result in actual
results differing materially from projected results. These risks and
uncertainties including those described under "Risk Factors" indicate, among
other things:
- market volatility due to world and regional events;
- U.S. and world economic conditions;
- the enforceability of our contracts;
- governmental, statutory or regulatory changes or initiatives affecting us
or our contracts; and
- other unpredictable or unknown factors not discussed.
iii
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PROSPECTUS SUMMARY
In this prospectus, the words "Company," "we," "our," "ours" and "us" refer
only to Cedar Brakes I, L.L.C. and not to any of our parents or sister companies
or to anybody 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 Series B bonds that we are offering, you should read
carefully this entire prospectus and other documents that we will refer you to.
The term "El Paso Energy" refers to El Paso Energy Corporation. For a discussion
of certain factors to be considered in connection with an investment in the
bonds, see "Risk Factors." In this prospectus, the term "Series A bonds" refers
to the 8 1/2% Senior Secured Bonds due 2014 that were issued on September 26,
2000. The term "Series B bonds" refers to the 8 1/2% Series B Senior Secured
Bonds due 2014 that will be issued in the exchange offer. The term "bonds"
refers to the Series A bonds and the Series B bonds collectively. For the
definitions of certain terms used throughout this prospectus, see "Description
of the Bonds -- Defined Terms."
THE EXCHANGE OFFER
On September 26, 2000, we completed the private offering of $310,600,000 of
the Series A bonds. We entered into a registration rights agreement with the
initial purchasers in the private offering of the Series A bonds in which we
agreed, among other things, to deliver to you this prospectus and to complete
this exchange offer within 180 days of the original issuance of the Series A
bonds. You are entitled to exchange in this exchange offer Series A bonds that
you hold for registered Series B bonds with substantially identical terms. You
should read the discussion under the headings "Summary of the Terms of the
Series B Bonds" beginning on page 11 and "Description of the Bonds" beginning on
page 65 for further information regarding the Series B bonds.
We believe that the Series B bonds that will be issued in this exchange
offer may be resold by you without compliance with the registration and
prospectus delivery provisions of the Securities Act, subject to certain
conditions. You should read the discussion under the headings "Summary of the
Terms of the Exchange Offer" beginning on page 9 and "The Exchange Offer"
beginning on page 57 for further information regarding this exchange offer and
resale of the Series B bonds.
CEDAR BRAKES I, L.L.C.
We were formed as a Delaware limited liability company on March 3, 2000
solely to
- acquire the right, title and interest to a long-term power purchase
agreement;
- sell electric energy and capacity under this power purchase agreement (as
amended and restated);
- enter into other related agreements, the indenture and the related
financing documents and undertake the transactions contemplated
thereunder;
- engage in other activities that are related to or incidental to the
foregoing; and
- issue the bonds.
Our sole business is the wholesale sale of electric capacity and electric
energy to Public Service Electric & Gas Company, a New Jersey corporation
("PSE&G"), under a long-term power purchase agreement. This power purchase
agreement was entered into on June 15, 1988, between PSE&G and Newark Bay
Cogeneration Partnership L.P., a New Jersey limited partnership ("NBCP") (the
"Original PPA"). In March 2000, we and PSE&G agreed to amend the Original PPA
effective upon the transfer of the Original PPA to us. Upon the consummation of
the offering of the Series A bonds, we used the proceeds of the offering of the
Series A bonds to pay NBCP the purchase price for the Original PPA, the Original
PPA was transferred to us and the amendment of its terms became effective. The
amended
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Original PPA was then restated in its entirety. In this prospectus, we refer to
the Original PPA after its amendment and restatement as the "Amended and
Restated PPA."
We are classified as a public utility subject to regulation by the Federal
Energy Regulatory Commission under the Federal Power Act. We have no employees.
Our material assets are comprised of the Amended and Restated PPA, receivables
that are generated or accrue under the Amended and Restated PPA, the proceeds of
such receivables, our interest in the amounts held in our accounts described in
this prospectus and the following additional contracts, which, together with the
Amended and Restated PPA, we refer to as our material agreements:
- our Power Services Agreement dated September 20, 2000, with El Paso
Merchant Energy L.P. ("EPM");
- our Administrative Services Agreement dated September 20, 2000, with EPM;
- the guaranty dated September 20, 2000 by El Paso Energy of EPM's
performance under the Power Services Agreement and the Administrative
Services Agreement;
- a Consent and Agreement with PSE&G and the trustee;
- a Consent and Agreement with EPM and the trustee; and
- a Consent and Agreement with El Paso Energy and the trustee.
For more information about our material agreements, see "Summary of Certain
Transaction Documents" below.
Our company is owned directly 100% by Mesquite Investors, L.L.C.
("Mesquite"). Mesquite is owned indirectly by El Paso Energy and Limestone
Electron Trust ("Limestone"). A wholly-owned subsidiary of El Paso Energy
manages the operations of Mesquite and us. See "-- Chaparral Management." Our
day-to-day operations are managed by officers and employees of EPM under the
Administrative Services Agreement with us. Our principal executive offices are
located at 1001 Louisiana Street, Houston, Texas 77002. Our telephone number is
(713) 420-2131.
For a more detailed description of our organization and ownership
structure, please see the chart below.
OWNERSHIP
EL PASO ENERGY
An El Paso Energy wholly-owned subsidiary manages our operations. See
"-- Chaparral Management." El Paso Energy is a diversified energy holding
company whose principal operations include the interstate and intrastate
transportation, gathering, processing and storage of natural gas; the marketing
of natural gas, power and other energy-related commodities; the generation of
power; the development and operation of energy infrastructure facilities
worldwide; and the domestic exploration for, and production of, natural gas and
oil. El Paso Energy owns or has interests in over 40,000 miles of interstate and
intrastate pipeline connecting the nation's principal natural gas supply regions
to the five largest consuming regions in the United States: the Gulf Coast,
California, the Northeast, the Midwest and the Southeast. El Paso Energy's
natural gas transmission operations represent the nation's largest and only
integrated coast-to-coast natural gas pipeline system. In addition, through El
Paso Merchant Energy Group L.L.C. and its subsidiaries ("Merchant Energy"), El
Paso Energy is a major intermediary in the wholesale natural gas and electric
power markets, and is engaged in buying and selling natural gas, pipeline
capacity, natural gas storage, electric power and other energy commodities
throughout North America. El Paso Energy had total assets as of September 30,
2000 of approximately $22 billion.
In January 2000, El Paso Energy announced it had entered into a definitive
agreement to merge a wholly-owned subsidiary with The Coastal Corporation. The
Coastal Corporation is a diversified energy
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holding company with operations in natural gas transmission, storage, gathering,
processing and marketing; natural gas and oil exploration and production;
petroleum refining, marketing and distribution; chemicals; power production; and
coal. Upon completion of the merger, the combined company's natural gas
transmission system will include approximately 58,000 miles of pipeline and
reach approximately 70% of the nation's population.
El Paso Energy believes that by combining the complementary assets and
operations of its business with those of The Coastal Corporation, the merger
will create one of the leading integrated natural gas and power companies in
North America. The combined company will be ranked among the top five companies
in each of the following sectors of the natural gas and power industries:
natural gas transmission, natural gas storage, merchant energy and power,
international power development, field services and exploration and production.
El Paso Energy believes that the combined company will be well positioned to
take advantage of cross-sector opportunities, particularly opportunities that
arise as a result of the continuing convergence of the natural gas and power
industries. The transaction is expected to close in the fourth quarter of 2000
and is subject to certain conditions, including receipt of certain required
governmental approvals.
El Paso Energy's senior unsecured debt is rated Baa2 by Moody's and BBB by
Standard & Poor's. For a more detailed description of El Paso Energy, see "El
Paso Energy and Selected Financial Information of El Paso Energy."
EPM
EPM is an indirect wholly-owned subsidiary of El Paso Energy that has acted
as a power marketer since 1996. As a power marketer, EPM acts as an intermediary
between the buyer and the seller of energy. EPM seeks to obtain the optimum
prices for the purchaser. EPM, in its power marketing capacity, also offers risk
management services by using derivative products, such as options, swaps and
forward contracts to enable customers to fix their rates. For the first nine
months in 2000, EPM reported a volume of approximately 87.1 million MW to the
Federal Energy Regulatory Commission and was ranked the thirteenth largest power
marketer in terms of volume by the Federal Energy Regulatory Commission for this
period. EPM and its affiliates have ownership interests or management
responsibilities in 40 power generation facilities with a total generating
capacity of over 5,000 MW. For a more detailed description of EPM, see "EPM."
LIMESTONE ELECTRON TRUST
Limestone is a statutory business trust formed in December 1999, under the
laws of the State of Delaware. Limestone was formed pursuant to the terms of the
Limestone Trust Agreement among El Paso Energy, Wilmington Trust Company in its
capacity as trustee, and Limestone, together with a financial investor. The
beneficial ownership interests of Limestone are evidenced by approximately $150
million of Limestone trust certificates held by institutional investors. El Paso
Energy has voting rights in Limestone with respect to certain bankruptcy
matters. Limestone was formed for the purpose of conducting limited activities,
including purchasing a membership interest in Chaparral Investors, L.L.C.
("Chaparral"), issuing senior notes in an aggregate principal amount of
approximately $1 billion and contributing most of the proceeds of that issuance
to Chaparral. For a more detailed description of Limestone, see "Limestone."
MESQUITE AND CHAPARRAL
Mesquite is our direct owner. Chaparral holds the sole membership interest
in Mesquite. In 1999, El Paso Energy formed Chaparral to fund the growth of its
unregulated domestic power generation and related businesses. Through Mesquite,
Chaparral owns interests in (1) 22 commercially operating gas-fired power
facilities in New Jersey, Rhode Island, Massachusetts, Colorado, Nevada and
California, and (2) two gas-fired power facilities under construction in
Connecticut and Florida. These facilities, in the aggregate, represent total
generating capacity of approximately 3,300 MW, of which El Paso Energy
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affiliates have a net equity interest in approximately 1,930 MW. El Paso
Chaparral Investor, L.L.C. ("El Paso Chaparral"), a wholly-owned indirect
subsidiary of El Paso Energy, is the managing member of Chaparral and makes all
decisions on behalf of Chaparral except for certain actions requiring unanimous
consent of the members and those matters delegated to Chaparral Management
pursuant to the Chaparral Management Agreement. For a more detailed description
of Mesquite and Chaparral, see "Mesquite and Chaparral."
CHAPARRAL MANAGEMENT
Pursuant to a management agreement among the members of Chaparral, Mesquite
and El Paso Chaparral Management L.P. ("Chaparral Management"), Chaparral
Management manages the operations of Chaparral and Mesquite and manages the
acquisition, operation and disposition of the assets held by those entities.
Chaparral Management is a wholly-owned indirect subsidiary of El Paso Energy.
For a more detailed description of Chaparral Management, see "Chaparral
Management."
[DIAGRAM REFLECTING OWNERSHIP STRUCTURE OF CEDAR BRAKES]
PSE&G
PSE&G is a public company and is subject to the informational requirements
of the Securities Exchange Act and, in accordance therewith, files reports,
proxy statements and other information, including financial reports, with the
SEC.
PSE&G's senior secured debt is rated A3 by Moody's, A- by Standard & Poor's
and A by Fitch.
BACKGROUND
NBCP owns a 135 MW cogeneration facility located in Newark, New Jersey
which we refer to in this prospectus as the Newark Bay Facility. NBCP is an
affiliate of ours. Pursuant to the Original PPA, NBCP sold generating capacity
and associated energy from the Newark Bay Facility to PSE&G. Under the Original
PPA, the Newark Bay Facility was required to be a qualifying facility under the
Public Utility Regulatory Policies Act of 1987 ("PURPA"). The managers of NBCP
and of PSE&G sought to amend the Original PPA in order to achieve a number of
benefits, including the elimination of this requirement that we must maintain
the status of the Newark Bay Facility as a qualifying facility under PURPA. The
benefits of the Amended and Restated PPA also include the right to meet our
capacity and energy obligations from any available source, not only from the
Newark Bay Facility, significantly more flexibility
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in scheduling energy deliveries, including a greater degree of daily delivery
flexibility and the substantial reduction of the energy and capacity rates under
the Amended and Restated PPA from those under the Original PPA.
NBCP sold the Original PPA to us and we paid NBCP the purchase price out of
the proceeds of the offering of the Series A bonds. The amendment of the
Original PPA became effective on September 26, 2000.
SUMMARY OVERVIEW OF THE TRANSACTION
The following chart depicts some of our material agreements and the
transaction structure which are described in more detail below:
[GRAPHIC DEPICTION OF THE TRANSACTION]
THE TRANSACTION
We were organized by El Paso Energy and its affiliates solely to:
- acquire the right, title and interest to the Original PPA;
- sell electric energy and capacity under the Amended and Restated PPA;
- enter into other material agreements, the indenture and the related
financing documents and undertake the transactions contemplated
thereunder;
- engage in other activities that are related to or incidental to the
foregoing; and
- issue the bonds.
We purchased the Original PPA from NBCP pursuant to a purchase and sale
agreement. The proceeds of the offering of the Series A bonds were used to pay
the purchase price for the Original PPA and certain transaction costs and to
fund the liquidity account. See "Use of Proceeds." We expect that interest and
principal on the bonds will be paid solely from capacity and energy payments
from PSE&G to us under the Amended and Restated PPA (as supplemented, under
certain circumstances, by funds in the liquidity account). All scheduled
payments of principal and interest on the bonds have been calculated so as to be
paid from the total amount of the payments that we expect to receive each year
from PSE&G. We have entered into the Power Services Agreement and the
Administrative Services Agreement with EPM in order to have EPM perform all of
our obligations and exercise all of our rights under all of our material
agreements and the indenture and the related financing documents under which the
Series A bonds were issued and the Series B bonds will be issued. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
AMENDED AND RESTATED PPA
Under the Amended and Restated PPA, which has a term expiring August 31,
2013, we are required to deliver minimum on-peak energy deliveries of at least
40,000 MWh per month during the on-peak
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hours of the summer months (June, July, August and September) and an aggregate
of 234,000 MWh during the on-peak hours for the rest of the year, which we refer
to in this prospectus as minimum energy deliveries. Further, under the Amended
and Restated PPA, we have the right to schedule and deliver at any time during
the year (subject to certain notification provisions and delivery rate
requirements) additional amounts of energy (varying by year) ranging from
176,519 MWh per year to 461,779 MWh per year, which we refer to in this
prospectus as additional energy deliveries. In this prospectus, we refer to the
sum of the minimum energy deliveries and the additional energy deliveries for
any year as the "annual energy deliveries" for that year. If we deliver energy
at the rate of 150MW/hour (the maximum permitted under ordinary circumstances),
the minimum energy deliveries will only require us to deliver during 77% of the
on-peak hours during the summer months and 56% of the on-peak hours of the other
months. Although we are not required to schedule any additional energy
deliveries under the Amended and Restated PPA, in order for us to have
sufficient funds to pay principal and interest on the bonds, we must deliver the
full amount of the annual energy deliveries each year. In addition to the
minimum energy deliveries, under the Amended and Restated PPA we are required to
make available to PSE&G capacity credits of 123 MW per day, which capacity
credits we refer to in this prospectus as the reserved capacity. We are allowed
to provide PSE&G with reserved capacity and energy deliveries from any source of
supply connected to the Pennsylvania-New Jersey-Maryland ("PJM") market,
including, but not limited to, the Newark Bay Facility.
The Amended and Restated PPA requires PSE&G to pay us each month a combined
payment for the capacity and energy provided by us. The amount of the payment is
based, in part, on the amount of energy we actually deliver. The monthly
payments are deposited by PSE&G directly into a collections account established
by the trustee under the indenture under which the Series A bonds were issued
and the Series B bonds will be issued. Amounts in the collections account must
be used in the order of priority specified under "Description of the
Bonds -- Withdrawals from the Collections Account." Payments of interest and
principal on the bonds will be made solely from amounts in the collections
account (and in some limited circumstances, from funds in the liquidity account;
see "Description of the Bonds -- The Accounts"). The amount payable by PSE&G to
us in any month will be reduced by a credit to PSE&G if we fail to deliver all
or part of the energy scheduled for delivery or we fail to schedule and deliver
the minimum energy deliveries. The amount payable by PSE&G in any month will
also be reduced by a credit to PSE&G if we do not deliver energy at the Newark
Bay Facility or at certain other specified locations if or we fail to provide
all or part of the reserved capacity to PSE&G. Any such failure would reduce the
funds available to make payments on the bonds during the relevant period in the
event that EPM and El Paso Energy fail to perform their obligations under the
Power Services Agreement or the El Paso Energy Performance Guaranty,
respectively. See "Summary of Certain Transaction Documents -- Power Services
Agreement" and "Summary of Certain Transaction Documents -- El Paso Energy
Performance Guaranty."
POWER SERVICES AGREEMENT
In order to meet our obligations to provide reserved capacity and to
deliver energy under the Amended and Restated PPA, we have entered into the
Power Services Agreement with EPM, which became effective on September 26, 2000.
Under the Power Services Agreement, EPM must make available to us capacity
credits equal to the reserved capacity and must schedule and deliver the full
amount of the annual energy deliveries during each year. As is the case with us
under the Amended and Restated PPA, EPM may deliver energy to us at any point
within the PJM market.
In consideration for the reservation of capacity and delivery of energy by
EPM, we must make combined monthly energy and capacity payments to EPM. Our
monthly payments to EPM under the Power Services Agreement will be reduced by a
credit to us in the event that EPM fails to schedule and deliver the minimum
energy deliveries or to deliver energy as scheduled, EPM does not deliver energy
at the Newark Bay Facility or at other certain specified locations or if EPM
fails to provide all or part of the reserved capacity to us. These credits will
be calculated in the same manner and applied in the same months in which the
corresponding credits are applied under the Amended and Restated PPA. If at the
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<PAGE> 12
end of any month, the amount of the credits due to us is greater than the total
amount that we owe to EPM for that month, EPM will be obligated to pay us in
cash the excess portion of these credits, which we refer to in this prospectus,
collectively, as excess amounts.
If EPM does not schedule and deliver the annual energy deliveries to us in
any year, EPM will be required to pay to us by February 10th of the following
year an amount equal to the difference between the annual energy deliveries for
the preceding year and the energy actually delivered under the Power Services
Agreement in the preceding year multiplied by the difference between the price
that PSE&G pays to us for energy delivered under the Amended and Restated PPA
and the price that we pay to EPM under the Power Services Agreement. In this
prospectus, we refer to this differential as the spark spread and to these
payments by EPM as shortfall payments. In addition to the shortfall payments,
EPM will also be required to pay into a damages and indemnity account certain
other damages and indemnity payments and distribution surcharges that we may be
liable for under the Amended and Restated PPA. We or EPM have the right to
terminate the Power Services Agreement upon 10 days' written notice if we do not
pay amounts that we owe to EPM within 30 days of EPM's notice to us that our
payment is overdue. We or EPM may also terminate the Power Services Agreement
upon 10 days' written notice if the Amended & Restated PPA terminates as the
result of a bankruptcy or other default of PSE&G. The other provisions of the
Amended and Restated PPA and the Power Services Agreement, including the terms
during which they are effective, are substantially similar to each other. See
"Summary of Certain Transaction Documents -- Power Services Agreement."
EPM expects to reserve capacity and procure energy to be delivered on our
behalf under the Power Services Agreement through its power marketing
activities. See "EPM."
ADMINISTRATIVE SERVICES AGREEMENT
We have also entered into an Administrative Services Agreement with EPM
pursuant to which EPM has agreed to perform all of our administrative functions,
exercise and enforce all of our rights and perform our administrative and
management obligations or arrange for the performance of all of these
obligations, in each case, in accordance with our material agreements, the
indenture and the related financing documents. See "Summary of Certain
Transaction Documents -- Administrative Services Agreement."
EL PASO ENERGY PERFORMANCE GUARANTY
El Paso Energy has entered into a performance guaranty pursuant to which El
Paso Energy has agreed to unconditionally guarantee all obligations (including
payment obligations) of EPM under the Power Services Agreement and the
Administrative Services Agreement. See "Summary of Certain Transaction
Documents -- El Paso Energy Performance Guaranty."
CONSENTS
We entered into a consent and agreement with the trustee and each of the
other parties to our other material agreements. In each consent and agreement,
the other party consents to the trustee's security interest in the relevant
material agreement and agrees to permit the trustee to exercise our rights under
that material agreement under certain circumstances.
ACCOUNTS
Payments by PSE&G under the Amended and Restated PPA, shortfall payments
and excess amounts paid by EPM pursuant to the Power Services Agreement or by El
Paso Energy pursuant to the El Paso Energy Performance Guaranty, and transfer
payments from the liquidity account must be deposited directly into the
collections account. A portion of the proceeds of the offering of the Series A
bonds was deposited into the collections account. The trustee must disburse
funds from the collections account to pay our expenses (including capacity and
energy payments to EPM and principal and interest on the bonds) in a specific
order of priority. See "Description of the Bonds -- Withdrawals from the
Collections Account."
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<PAGE> 13
In order to offset any timing difference between our cash flows from the
additional energy deliveries, which may be received on an irregular basis
throughout the year, and our interest payments on the bonds, which are to be
made semi-annually, we have provided for the setting up and the funding of the
liquidity account with the trustee in an amount equal to the maximum interest
due on the bonds in any subsequent six-month period, which balance we refer to
in this prospectus as the liquidity reserve required balance. Amounts on deposit
in the liquidity account may also be used to pay principal if we do not have
sufficient funds in the collections account to pay these amounts. If certain
conditions are satisfied, El Paso Energy may withdraw all or a portion of the
cash in the liquidity account by providing a standby letter of credit or a
separate guaranty from El Paso Energy in the amount of the cash withdrawn.
Under certain circumstances, EPM may be required to pay us certain amounts
for damages or indemnity payments that we will have to make to PSE&G. Those
amounts will be paid into, and the corresponding payment to PSE&G will be
disbursed from, the damages and indemnity account. See "Description of the
Bonds -- The Accounts."
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<PAGE> 14
SUMMARY OF THE TERMS OF THE EXCHANGE OFFER
SECURITIES TO BE
EXCHANGED................ On September 26, 2000, we issued $310,600,000
aggregate principal amount of Series A bonds to the
initial purchaser in a transaction exempt from the
registration requirements of the Securities Act.
The terms of the Series B bonds and the Series A
bonds are substantially the same in all material
respects, except that the Series B bonds will be
freely transferable by the holders except as
otherwise provided in this prospectus. See
"Description of the Bonds" beginning on page 65 of
this prospectus.
THE EXCHANGE OFFER......... We are offering to exchange up to $310,600,000
principal amount of the Series B bonds for up to
$310,600,000 principal amount of the Series A
bonds. As of the date of this prospectus, Series A
bonds representing $310,600,000 aggregate principal
amount are outstanding. The Series B bonds will
evidence the same debt as the Series A bonds, and
the Series A bonds and the Series B bonds will be
governed by the same indenture.
The Series B bonds are described in detail under
the heading "Description of the Bonds" beginning on
page 65 of this prospectus.
RESALE..................... We believe that you will be able to freely transfer
the Series B bonds without registration or any
prospectus delivery requirement; however, certain
broker-dealers and certain of our affiliates may be
required to deliver copies of this prospectus if
they resell any Series B bonds.
EXPIRATION DATE............ The exchange offer will expire at 5:00 p.m., New
York City time, [ ] , 2000 or a later date
and time if we extend it (the "expiration date").
WITHDRAWAL................. You may withdraw the tender of any Series A bonds
pursuant to the exchange offer at any time prior to
the expiration date. We will return, as promptly as
practicable after the expiration or termination of
the exchange offer, any Series A bonds not accepted
for exchange for any reason without expense to you.
INTEREST ON THE SERIES B
BONDS AND THE SERIES A
BONDS.................... Interest on the Series B bonds will accrue from the
date of the original issuance of the Series A bonds
or from the date of the last payment of interest on
the Series A bonds, whichever is later. No
additional interest will be paid on Series A bonds
tendered and accepted for exchange.
CONDITIONS TO THE EXCHANGE
OFFER.................... The exchange offer is subject to certain customary
conditions, certain of which may be waived by us.
See "The Exchange Offer -- Conditions of the
Exchange Offer" beginning on page 63 of this
prospectus.
PROCEDURES FOR TENDERING
SERIES A BONDS........... If you wish to accept the exchange offer, you must
complete, sign and date the accompanying letter of
transmittal in accordance with the
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<PAGE> 15
instructions in the letter of transmittal, and
deliver the letter of transmittal, along with the
Series A bonds and any other required
documentation, to the exchange agent. By executing
the letter of transmittal, you will represent to us
that, among other things:
- any Series B bonds you receive will be acquired
in the ordinary course of business,
- you have no arrangement with any person to
participate in the distribution of the Series B
bonds, and
- you are not an affiliate of ours or, if you are
an affiliate, you will comply with the
registration and prospectus delivery requirements
of the Securities Act to the extent applicable.
If you hold your Series A bonds through The
Depository Trust Company ("DTC") and wish to
participate in the exchange offer, you may do so
through the DTC's Automated Tender Offer Program.
By participating in the exchange offer, you will
agree to be bound by the letter of transmittal as
though you had executed such letter of transmittal.
We will accept for exchange any and all Series A
bonds which are properly tendered (and not
withdrawn) in the exchange offer prior to the
expiration date. The Series B bonds issued pursuant
to the exchange offer will be delivered promptly
following the expiration date. See "The Exchange
Offer -- Acceptance of Series A Bonds for Exchange"
beginning on page 59 of this prospectus.
EFFECT OF NOT TENDERING.... Series A bonds that are not tendered or that are
tendered but not accepted will, following the
completion of the exchange offer, continue to be
subject to the existing restrictions upon transfer
thereof. We will have no further obligation to
provide for the registration under the Securities
Act of such Series A bonds.
SPECIAL PROCEDURES FOR
BENEFICIAL OWNERS........ If you are a beneficial owner whose Series A bonds
are registered in the name of a broker, dealer,
commercial bank, trust company or other nominee and
wish to tender such Series A bonds in the exchange
offer, please contact the registered holder as soon
as possible and instruct them to tender on your
behalf and comply with our instructions set forth
elsewhere in this prospectus.
GUARANTEED DELIVERY
PROCEDURES............... If you wish to tender your Series A bonds, you may,
in certain instances, do so according to the
guaranteed delivery procedures set forth elsewhere
in this prospectus under "The Exchange
Offer -- Procedures for Tendering Series A
Bonds -- Guaranteed Delivery" beginning on page 60
of this prospectus.
REGISTRATION RIGHTS
AGREEMENT................ We sold the Series A bonds on September 26, 2000,
to the initial purchaser in a transaction that was
exempt from the SEC's registration requirements. In
connection with the sale, we entered into a
registration rights agreement with the initial
purchaser which grants
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<PAGE> 16
the holders of the Series A bonds certain exchange
and registration rights. This exchange offer
satisfies those rights, which terminate upon
consummation of the exchange offer. You will not be
entitled to any exchange or registration rights
with respect to the Series B bonds.
CERTAIN U.S. FEDERAL INCOME
TAX CONSIDERATIONS....... We believe the exchange of Series A bonds for
Series B bonds pursuant to the exchange offer will
not constitute a sale or an exchange for federal
income tax purposes. See "Certain U.S. Federal
Income Tax Consequences" beginning on page 85 of
this prospectus.
USE OF PROCEEDS............ We will not receive any proceeds from the exchange
of bonds pursuant to the exchange offer.
EXCHANGE AGENT............. We have appointed Bankers Trust Company as the
exchange agent for the exchange offer (the
"exchange agent"). The mailing address and
telephone number of the exchange agent are BT
Services Tennessee, Inc., Reorganization Unit, P.O.
Box 292737, Nashville, Tennessee 37229-2737. See
"The Exchange Offer -- Exchange Agent" beginning on
page 65 of this prospectus.
SUMMARY OF THE TERMS OF THE SERIES B BONDS
The form and term of the Series B bonds are substantially the same as the
form and terms of the Series A bonds, except that the Series B bonds are
registered under the Securities Act. As a result, the Series B bonds will not
bear legends restricting their transfer and will not contain the registration
rights contained in the Series A bonds.
Issuer..................... Cedar Brakes I, L.L.C., a Delaware limited
liability company.
Bonds Offered.............. $310,600,000 aggregate principal amount of 8 1/2%
Series B Senior Secured Bonds due February 15,
2014.
Maturity Date.............. February 15, 2014.
Interest Payment Dates..... The fifteenth calendar day of each February and
August (or if that day is not a business day, then
the next succeeding business day), commencing on
February 15, 2001. A business day is a day on which
banks are not required or authorized to close in
the City of New York.
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<PAGE> 17
Principal Payment Dates and
Amortization............. We are required to pay principal on the bonds
annually on the fifteenth calendar day of each
February (or if that day is not a business day,
then the next succeeding business day), commencing
on February 15, 2002:
<TABLE>
<CAPTION>
PERCENTAGE OF PRINCIPAL
PRINCIPAL PAYMENT DATE AMOUNT PAYABLE
---------------------- -----------------------
<S> <C>
February 15, 2002 1.9
February 15, 2003 2.5
February 15, 2004 3.5
February 15, 2005 4.9
February 15, 2006 5.8
February 15, 2007 6.7
February 15, 2008 7.7
February 15, 2009 8.8
February 15, 2010 11.3
February 15, 2012 12.6
February 15, 2013 14.3
February 15, 2014 10.1
</TABLE>
Ratings.................... Baa2 by Moody's, BBB by Standard & Poor's and BBB
by Fitch.
Limited Recourse
Obligations................ The obligations to pay principal of, interest and
Make-Whole Premium, if any, on the bonds will be
solely our obligations. You will not have any other
recourse against our affiliates or any
incorporator, stockholder, member, officer,
employee or director of ours or any such affiliate
for any failure by us to satisfy obligations under
the bonds.
Collateral................. We granted to the trustee at the closing date of
the offering of the Series A bonds, on behalf of
and for the benefit of the holders of bonds, all of
our right, title and interest in all of our assets,
namely:
- our material agreements;
- our collections and all amounts payable to us
arising out of, attributable to, in respect of or
otherwise in connection with our collections;
- all other amounts payable to us pursuant to our
material agreements;
- the accounts and all funds and all investments
and proceeds on deposit therein from time to
time;
- all damages and other amounts payable to us in
respect of the foregoing;
- all of our rights, claims, powers, privileges and
remedies with respect to the foregoing; and
- all present and future claims and demands in
respect of any or all of the foregoing.
In this prospectus, "collections" means all amounts
payable to us from PSE&G pursuant to the Amended
and Restated PPA and amounts payable by:
- EPM pursuant to Article V(F) of the Power
Services Agreement to cover any shortfall
payments;
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<PAGE> 18
- EPM pursuant to Article IV(B) and Article V(E) of
the Power Services Agreement to cover any excess
amounts;
- El Paso Energy pursuant to the El Paso Energy
Performance Guaranty to cover any shortfall
payments and excess amounts of EPM under Article
IV(B) and Article V(E) of the Power Services
Agreement; and
- all earnings on permitted investments from
amounts in the collections account and the
liquidity account.
Redemption at Our Option... We may choose to redeem the bonds, in whole or in
part, at any time, at our option on not less than
30 nor more than 60 days' notice to the bond
holders at a redemption price equal to the
outstanding principal amount of the bonds to be
redeemed, plus accrued interest on these bonds to
the date of the redemption, plus a Make-Whole
Premium, if any. The Make-Whole Premium is based on
the rates of treasury securities with average lives
comparable to the remaining average lives of the
applicable bonds, plus 50 basis points.
Accounts................... Pursuant to the indenture, the trustee established
the following accounts: (1) the collections
account, (2) the liquidity account and (3) the
damages and indemnity account. See "Description of
the Bonds -- The Accounts -- Establishment of
Accounts."
Collections Account........ All collections and all transfer payments from the
liquidity account will be deposited into the
collections account. An amount equal to $2,396,509
from the proceeds of the offering of the Series A
bonds was deposited into the collections account.
Amounts on deposit in the collections account must
be used to make payments in accordance with the
priorities set forth in "-- Withdrawals from the
Collections Account" below.
Liquidity Account.......... On the closing date of the offering of the Series A
bonds, we deposited into the liquidity account an
amount equal to the liquidity reserve required
balance out of the proceeds from the Series A bonds
offering. In the event sufficient funds are not
available in the collections account to pay the
principal or interest on the bonds, amounts in the
liquidity account will be transferred into the
collections account and used by the trustee to pay
this shortfall. Amounts withdrawn from the
liquidity account will be replenished from the
collections account in accordance with the priority
set forth in "-- Withdrawals from the Collections
Account" below. El Paso Energy may withdraw the
cash on deposit in the liquidity account by
replacing the cash withdrawn with one or more
letters of credit or a guaranty from El Paso
Energy, in the amount of the cash withdrawn.
Amounts in excess of the liquidity reserve required
balance on deposit in the liquidity account on any
Interest Payment Date will be transferred on the
next Principal Payment Date (but no earlier than
February 15, 2003) to the collections account.
Damages and Indemnity
Account.................... All payments to be made by EPM pursuant to the
Power Services Agreement and by El Paso Energy
pursuant to the El Paso Energy Performance Guaranty
to cover:
- damages payable by us to PSE&G pursuant to
Article XIV of the Amended and Restated PPA;
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<PAGE> 19
- indemnity payments payable by us to PSE&G
pursuant to Article XII of the Amended and
Restated PPA; and
- distribution surcharges payable by us to PSE&G
pursuant to Article II(E) of the Amended and
Restated PPA must be made to the damages and
indemnity account. Amounts must be drawn from the
damages and indemnity account to pay such
damages, indemnity payments and distribution
charges.
Withdrawals from the
Collections Account........ The trustee must apply amounts in the collections
account as follows and in the following order of
priority:
- monthly, to transfer to the trustee the amount of
the trustee's monthly fees;
- monthly, to pay EPM for the capacity and energy
that EPM sold to us under the Power Services
Agreement;
- semi-annually, to the payment of interest due on
the bonds;
- annually, to the payment of principal and
Make-Whole Premium (if any) due on the bonds;
- semi-annually, to replenish any amounts drawn
from the liquidity account so as to maintain the
liquidity account required balance;
- semi-annually, to EPM an amount equal to the
accrued and unpaid fees and expenses owed EPM
under the Administrative Services Agreement; and
- annually, to us for distribution to our members;
provided that (a) no Event of Default (or other
event which would with notice or lapse of time or
both become an Event of Default) has occurred and
is continuing and (b) the Debt Service Coverage
Ratio for the preceding six-month period is equal
to or exceeds 1.03 to 1.00.
Principal Covenants........ The indenture contains certain covenants on our
part, among them:
- restrictions on the incurrence of additional
Indebtedness;
- limitations on liens and encumbrances, except to
the extent the failure to comply could not
reasonably be expected to result in a Material
Adverse Effect;
- restrictions on the payments of distributions to
our members or any owner of a beneficial interest
in us;
- limitations on the sale or transfer of the
collateral, mergers, changes in legal form or
other fundamental changes;
- a prohibition on undertaking obligations with
respect to any guaranty;
- limitations on transactions entered into with
affiliates;
- limitations on investments in other persons;
- an obligation to maintain our existence;
- an obligation to comply with laws;
- restrictions on our use of the proceeds from the
issuance of the bonds;
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<PAGE> 20
- limitations on the assignment of our rights and
obligations under any of our material agreements,
amendment of our material agreements and our
entering into additional contracts; and
- an obligation to schedule and deliver the annual
energy deliveries.
See "Description of the Bonds -- Certain
Covenants."
Events of Default and
Remedies................... An Event of Default will occur under the indenture
if, among other things,
- we fail to pay any principal of or Make-Whole
Premium, if any, on the bonds when due and
payable and this default continues for a period
of five days or more;
- we fail to pay any interest or any other amount
required to be paid with respect to the bonds and
this default continues for a period of 15 days or
more;
- we, El Paso Energy or PSE&G fail to perform any
material term, covenant or obligation contained
in any of our material agreements or any
financing document, unless in each case failure
to perform could not reasonably be expected to
result in a Material Adverse Effect, and such
failure continues for 30 days or more after we
are provided notice of such failure;
- any of our material agreements or financing
documents becomes or is found to be unenforceable
or illegal and that event could reasonably be
expected to result in a Material Adverse Effect;
- (1) the liens on any material portion of the
collateral cease to be valid and perfected first
priority security interests or (2) any other of
our creditors asserts any rights or interest with
respect to the collateral, or our right to
receive payments with respect to the collateral
is otherwise terminated or impaired and the
assertion of rights or interests or the
termination or impairment of our right to receive
payments could reasonably be expected to result
in a Material Adverse Effect;
- certain events occur related to our insolvency;
- it becomes unlawful for us to perform any of our
obligations under the indenture or the bonds, or
any of our obligations under the indenture or the
bonds ceases to be valid, binding or enforceable,
unless such event or occurrence could not
reasonably be expected to result in a Material
Adverse Effect;
- any of the Amended and Restated PPA or the El
Paso Energy Performance Guaranty terminates
before the end of its term;
- one or more judgments or decrees are entered
against us in excess of $15 million in the
aggregate which have not been vacated,
discharged, stayed or bonded pending appeal
within 60 days from the entry thereof; or
- we fail to observe or perform certain covenants
in the registration rights agreement with the
initial purchaser, and such failure continues for
a period of 30 days after notice is given to us.
If an Event of Default (other than an Event of
Default caused by our bankruptcy -- a "Bankruptcy
Event of Default") occurs and is
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<PAGE> 21
continuing, then the trustee, upon the direction of
no less than 25% (for an Event of Default with
respect to failure to make payments on the bonds)
or the Majority Holders (for any other Event of
Default), must declare the principal amount of all
the bonds to be due and payable immediately, and
upon any such declaration the principal amount, any
accrued and unpaid interest, any Make-Whole Premium
and all other amounts payable under the bonds will
become immediately due and payable. If a Bankruptcy
Event of Default occurs, the principal amount of,
any accrued interest on, any Make-Whole Premium and
all other amounts payable under the bonds will
automatically become immediately due and payable.
See "Description of the Bonds -- Remedies."
Indenture Trustee.......... Bankers Trust Company
Paying Agent, Registrar and
Transfer Agent........... Bankers Trust Company serves as the paying agent,
security registrar and transfer agent for the
bonds.
Governing Law and
Jurisdiction............. The bonds, the indenture and the other financing
documents are governed by the laws of the State of
New York.
POWER SERVICES AGREEMENT ASSESSMENT
Pace Global Energy Services LLC ("Pace"), an energy consulting firm that
specializes in, among other things, market forecasts in the electric power and
natural gas industries, prepared a Power Services Agreement Assessment dated
September 20, 2000, included as Annex A to this prospectus. The Power Services
Agreement Assessment reviews whether (i) the "all-in" energy and capacity prices
under the Power Services Agreement reasonably reflect market pricing in the PJM
region, adjusted for energy delivery flexibility that EPM has under the Power
Services Agreement and (ii) capacity resources within the PJM market are
sufficient to ensure EPM can meet its contractual obligations under the Power
Services Agreement. In order to provide an opinion as to the reasonableness of
the annual Power Services Agreement contract prices, in conjunction with
forecasting the PJM market clearing prices over the term of the Power Services
Agreement, Pace performed two analyses: a bid strategy analysis and an option
value analysis. The bid strategy analysis assesses the potential value to EPM of
selling power into the PJM market during hours when EPM is not obligated to sell
power to us under the Power Services Agreement. The option value analysis
quantifies the value to EPM derived from the delivery flexibility provided for
in the Power Services Agreement. The Power Services Agreement Assessment is
meant to be read only in its entirety and is subject to certain restrictions set
forth in the Legal Notice on its cover page. The Power Services Assessment and
the Legal Notice should be read by all prospective investors in their entirety.
Subject to the information and assumptions contained in the Power Services
Agreement Assessment, Pace expressed the following opinions:
- The PJM market operates a competitive wholesale energy market and
facilitates open access to transmission. With over 170 members including
every segment of the electric power industry, the PJM market has become
one of the most liquid and active energy markets in the country.
- As of 1998, there were 52,000 MW of existing capacity present in the PJM
power market. The contract capacity specified in the Power Services
Agreement of approximately 123 MW represents approximately 0.2%-0.3% of
the total existing capacity in this market. The low market share coupled
with a well-developed and highly-reliable electrical transmission system,
capable of transferring high quantities of power between
generators/sellers and buyers, will allow EPM to access numerous power
purchasers for capacity and energy sales and purchases. EPM will
therefore have many options to fulfill its on-peak and off-peak
obligations under the Power Services
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<PAGE> 22
Agreement and exploit the energy delivery flexibility of the Power
Services Agreement. There may be times when the PJM electric transmission
system may experience disruptions due to system component failures or
act-of-god events. However, these events are highly unlikely to affect
EPM's overall ability to fulfill its on-peak and off-peak obligations
under the Power Services Agreement, given the design and overall size of
the PJM transmission system, as well as the makeup energy provisions in
the Power Services Agreement.
- Incremental capacity is needed in the region to match energy demand
growth, which is estimated to average 1.64% per year over the term of the
13-year contract based on PJM forecasts and similar forecasts conducted
by Pace.
- Given the structure of the Power Services Agreement, EPM has the
flexibility to sell to the market during volatile peak periods and
conversely put power to us during lower pricing periods. The implicit
capacity factor based on contracted energy delivery requirements of the
Power Services Agreement is 77% during summer peak hours and 56% during
non-summer peak periods. The implicit capacity factor based on contract
delivery quantities during non-peak periods is 57%.
- Based on the scheduling flexibility in the Power Services Agreement and
imputing the PJM market price by eliminating the volatile peak periods,
the average market price is $22.09/MWh under the bid strategy analysis
and $20.63/MWh under the option value analysis in the East PJM market for
the September through December 2000 period.
- For the 2001 through 2006 period, Pace believes the Power Services
Agreement contract price is in line with Pace's adjusted market price.
For the remainder of the forecast period (2007-2013), Pace estimates that
the contract prices under the Power Services Agreement are slightly lower
than Pace's adjusted market price. However, given the increasing level of
uncertainty as the time horizon becomes more distant, Pace believes that
the contract prices are not significantly different from market
expectations. Accordingly, on a net present value basis, the value
ascribed to the differential between the Pace-adjusted market prices and
the Power Services Agreement contract prices is approximately 4%,
assuming a discount rate of 10% and a 13-year term of the Power Services
Agreement.
- Based upon Pace's analysis of the PJM power market and a review of the
relevant portions of the our transaction documents, Pace believes that
the contract rates stipulated in the Power Services Agreement reasonably
reflect market prices in the PJM market, adjusted for energy delivery
flexibility that EPM has under the Power Services Agreement. Moreover,
the PJM market has sufficient power resources to allow EPM to meet its
contractual obligations under the Power Services Agreement.
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<PAGE> 23
RISK FACTORS
An investment in the bonds involves a significant degree of risk, including
the risks described below. You should carefully consider the following
information about these risks, together with the other information in this
prospectus, prior to exchanging your Series A bonds for the Series B bonds.
WE ARE RELYING ON PAYMENTS FROM PSE&G UNDER THE AMENDED AND RESTATED PPA FOR OUR
PRIMARY SOURCE OF REVENUES.
PSE&G is our sole customer for purchases of electric generating capacity
and energy. PSE&G's payments pursuant to the Amended and Restated PPA are
expected to provide 100% of our revenues. There can be no assurance that PSE&G
will fulfill its payment obligations under the Amended and Restated PPA. In
addition, in the event of a bankruptcy of PSE&G, PSE&G or the bankruptcy trustee
could reject its payment obligations under the Amended and Restated PPA. If
PSE&G fails to meet its payment obligations under the Amended and Restated PPA,
we will not be able to meet our obligations to make payments of principal and
interest on the bonds. Further, under the Amended and Restated PPA, PSE&G may
suspend its obligations to accept delivery of energy if certain specified events
beyond the control of PSE&G occur, such as a system emergency, adverse weather
conditions or labor disputes. Accordingly, we will have no revenues for the
duration of these events and there can be no assurance that we will be able to
make payments of principal and interest on the bonds during the continuance of
these events.
Under the Amended and Restated PPA, we only receive payment from PSE&G to
the extent that we actually deliver energy. If we do not schedule the full
amount of the annual energy deliveries for delivery to PSE&G each year, we will
not receive enough revenue from PSE&G to meet our obligations to make payments
of principal and interest on the bonds. In that situation, unless EPM is excused
by force majeure from its delivery obligations, we will be entitled to receive
shortfall payments from EPM under the Power Services Agreement for its failure
to schedule energy deliveries (or from El Paso Energy under the El Paso Energy
Performance Guaranty). There can be no assurance that EPM or El Paso Energy will
be able to make these payments. In the event that EPM or El Paso Energy does not
make these shortfall payments, we will not be able to meet our obligations to
make payments of principal and interest on the bonds.
In addition, under the Power Services Agreement, EPM is excused from its
obligation to schedule energy deliveries if certain specified events beyond the
control of EPM, such as adverse weather conditions or labor disputes, occur. In
this event EPM will not be obligated to make shortfall payments. In the event
that EPM is not obligated to make these shortfall payments, we will not be able
to meet our obligations to make payments of principal and interest on the bonds.
THE TIMING OF THE CAPACITY AND ENERGY PAYMENTS UNDER THE AMENDED AND RESTATED
PPA MAY AFFECT OUR ABILITY TO MAKE PAYMENTS ON THE BONDS.
With the exception of the minimum energy deliveries, we can schedule and
deliver energy at any time of the year. Accordingly, our cash flows and revenues
under the Amended and Restated PPA may not be received on a regular basis
throughout the year. Interest payments on the bonds are semi-annual and there
can be no assurance that amounts received for the corresponding six-month period
pursuant to the Amended and Restated PPA will be sufficient to make the interest
payments on the bonds. We have provided for the funding of a liquidity account
in an amount equal to the maximum interest due on the bonds on any subsequent
Interest Payment Date. Amounts drawn from the liquidity account will only be
replenished out of cash otherwise available in the collections account. There
can be no assurance that amounts withdrawn from the liquidity account can be
replenished. If cash flows are not sufficient to meet our obligations to make
interest payments on the bonds and the liquidity account has not been
replenished, we will not be able to make payments of principal and interest on
the bonds.
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<PAGE> 24
THE AMENDED AND RESTATED PPA MAY TERMINATE PRIOR TO THE MATURITY OF THE BONDS.
If we cause or permit to occur certain events of default under the Amended
and Restated PPA, PSE&G may have the right to terminate the Amended and Restated
PPA. The Amended and Restated PPA expressly provides that with respect to
defaults that are a result of our failure to deliver energy and capacity, PSE&G
shall be entitled to deduct certain amounts from payments due to us as
liquidated damages. Although the Amended and Restated PPA provides that these
liquidated damages are the only damages that PSE&G can claim as a result of any
failure by us to deliver energy or provide capacity, the Amended and Restated
PPA does not limit PSE&G's remedies to damages upon the occurrence of these
events or any other default by us under the Amended and Restated PPA. Therefore,
if one of our defaults has occurred and is continuing, PSE&G could claim that it
is entitled to terminate the Amended and Restated PPA.
If the Amended and Restated PPA is terminated by PSE&G as the result of our
default and that default is the result of a default by EPM under the Power
Services Agreement or the Administrative Services Agreement, we will be able to
exercise our remedies under the Power Services Agreement, the Administrative
Services Agreement and the El Paso Energy Performance Guaranty. However, there
can be no assurance that amounts received by us from either EPM or El Paso
Energy or both will be sufficient to satisfy our obligations to make payments of
principal and interest on the bonds.
WE ARE RELYING UPON EPM AND EL PASO ENERGY TO PERFORM OUR OBLIGATIONS UNDER OUR
MATERIAL AGREEMENTS AND TO MAKE CERTAIN PAYMENTS TO US.
Under the Power Services Agreement and the Administrative Services
Agreement, EPM is obligated to exercise our rights and perform all of our
administrative and management obligations under our material agreements,
including exercising our right to schedule, sell and deliver the minimum energy
deliveries and the additional energy deliveries each year. If EPM fails to
perform its obligations under the Power Services Agreement or the Administrative
Services Agreement, we will not be able to perform our obligations to PSE&G
under the Amended and Restated PPA and our obligations under our other material
agreements. In that situation, EPM would be required to pay us for our damages.
However, there can be no assurance that EPM will be able to make these payments.
In the event that EPM cannot make these payments, El Paso Energy is
required to pay these damages pursuant to the El Paso Energy Performance
Guaranty. There can be no assurance that El Paso Energy will fulfill its
obligations under the El Paso Energy Performance Guaranty. If, to the extent
called upon, El Paso Energy fails to meet its obligations under the El Paso
Energy Performance Guaranty, we will not be able to meet our obligations to make
payments of interest and principal on the bonds.
Further, the Power Services Agreement and the Administrative Services
Agreement expressly provide that the respective agreement may be terminated
prior to its scheduled expiration date upon the occurrence of certain events,
such as payment default. We are a special purpose entity, and we do not have any
employees or our own source of capacity and energy. In the event of the
termination of the Administrative Services Agreement or the Power Services
Agreement, there can be no assurance that replacement services can be obtained
on terms as favorable as those under the current agreements. If the
Administrative Services Agreement or the Power Services Agreement terminates, we
may not be able to make payments of principal and interest on the bonds.
THERE WILL BE CONFLICTS OF INTEREST UNDER OUR AGREEMENTS WITH EPM AND EL PASO
ENERGY.
EPM and El Paso Energy are affiliates of each other and an affiliate of
each of them manages us. In negotiating the Administrative Services Agreement,
the Power Services Agreement and the El Paso Energy Performance Guaranty, we
intended to provide terms that are substantially similar to those that might
have been obtained from unaffiliated third parties. However, we cannot assure
you that those documents actually meet that standard.
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<PAGE> 25
Furthermore, in carrying out their obligations under our material
agreements to which they are parties, EPM and El Paso Energy may face conflicts
of interest in making decisions that affect us. In some situations, EPM may be
required under the Administrative Services Agreement to enforce our rights
against itself under the Power Services Agreement or against its ultimate
parent, El Paso Energy, under the El Paso Energy Performance Guaranty. Although
EPM and El Paso Energy have agreed to carry out their obligations to us in a
manner that is nondiscriminatory to us, as a practical matter our ability to
monitor compliance is limited. As a result, we cannot guarantee that EPM and El
Paso Energy will carry out their obligations to us in a manner that is
nondiscriminatory to us. If they do not, we may not be able to fulfill our
obligations under the Amended and Restated PPA and PSE&G may have the right to
terminate the Amended and Restated PPA. In the event that PSE&G terminates the
Amended and Restated PPA due to our inability to fulfill our obligations under
that agreement, we will not be able to make payments of principal and interest
on the bonds.
IF WE DEFAULT ON THE BONDS YOUR RECOURSE AND YOUR ABILITY TO ACT MAY BE LIMITED.
We are the only party required to make payments on the bonds. We conduct no
other business and have no other significant assets other than our rights under
our material agreements and the issuing of the bonds. We have no operating
history and no experience in the purchase or sale of energy. No entity,
including PSE&G, EPM or El Paso Energy, and none of our affiliates,
shareholders, members, officers, directors or employees will be required to make
payments on the bonds or will in any way guarantee the payment on the bonds.
Certain actions, such as acceleration of the principal, interest and
Make-Whole Premium on the bonds, may be taken by the trustee only with the
approval of holders of specified percentage of outstanding principal amounts of
the bonds. These requirements of holder approval may limit the ability of the
trustee to exercise certain remedies or prolong the time required for the
trustee to act. See "Description of the Bonds -- Remedies."
OUR BUSINESS IS SUBJECT TO SUBSTANTIAL REGULATIONS AND PERMITTING REQUIREMENTS
AND MAY BE ADVERSELY AFFECTED BY OUR INABILITY TO COMPLY WITH EXISTING
REGULATIONS OR REQUIREMENTS OR CHANGES IN APPLICABLE REGULATIONS OR
REQUIREMENTS.
Our business, as well as those of EPM, PSE&G and El Paso Energy, is subject
to extensive energy regulation by federal, state and local authorities. These
regulations impose numerous requirements on the performance of our, PSE&G's,
EPM's and El Paso Energy's obligations under the Amended and Restated PPA and
the Power Services Agreement, and failure to comply with these requirements
could prevent the performance of our respective obligations under these
agreements.
The Federal Energy Regulatory Commission currently considers contracts for
the wholesale sale of electric power to be subject to its jurisdiction.
Consequently, any proposed transfer of either or both the Amended and Restated
PPA and the Power Services Agreement, including a transfer to the trustee upon
foreclosure, is subject to Federal Energy Regulatory Commission approval, and
any modification of the Amended and Restated PPA and the Power Services
Agreement may require Federal Energy Regulatory Commission approval as well. The
Federal Energy Regulatory Commission has pre-approved all of our currently
contemplated future security issuances and assumptions of liability (including
the issuance of the bonds offered hereby). Any further security issuances and
assumptions of liability by us would require pre-approval by the Federal Energy
Regulatory Commission in the event that our power marketing authorization from
the Federal Energy Regulatory Commission is revoked.
The negotiated rates contained in the Amended and Restated PPA and the
Power Services Agreement require approval by the Federal Energy Regulatory
Commission. Although the Federal Energy Regulatory Commission has approved the
rates to be charged in the Amended and Restated PPA and the Power Services
Agreement, the Federal Energy Regulatory Commission has continuing jurisdiction
over those rates. The Federal Energy Regulatory Commission would have to meet a
high burden in order to modify the rates, and, as a matter of practice and
policy, the Federal Energy Regulatory Commission has
20
<PAGE> 26
steadfastly refused to modify rates after initial approval. There can be no
assurance, however, that the Federal Energy Regulatory Commission will permit
those rates to remain in place for the term of the Amended and Restated PPA and
the Power Services Agreement.
Marketing power at market-based or negotiated rates requires a power
marketing authorization issued by the Federal Energy Regulatory Commission based
on several criteria, including a showing that the applicant lacks market power
and that there is no opportunity for abusive transactions involving regulated
affiliates of the marketer. Although EPM has received these power marketing
authorizations from the Federal Energy Regulatory Commission, these
authorizations could be revoked if EPM fails in the future to satisfy the
applicable criteria or if the Federal Energy Regulatory Commission changes its
rate making policies.
We cannot assure you that the existing laws and regulations will not be
revised or reinterpreted, that new laws and regulations will not be adopted or
become applicable to us or the parties on whom we are relying in this
transaction or that future changes in laws and regulations will not have a
detrimental effect on our business. In addition, the structure of federal and
state energy regulation is currently, and may continue to be, subject to
challenges and restructuring proposals. Although not currently required,
additional regulatory approvals may be required in the future due to a change in
laws and regulations or for other reasons. We cannot assure you that we, PSE&G,
EPM or El Paso Energy will be able to obtain all required regulatory approvals
that may be required in the future, or any necessary modifications to existing
regulatory approvals, or maintain all required regulatory approvals.
If there is a change in regulations, or a delay in obtaining any regulatory
approvals or we, PSE&G, EPM or El Paso Energy fail to obtain or comply with any
required regulatory approvals, then we may not be able to comply with our
obligations under our material agreements and we will be unable to meet our
obligations to make payments of principal and interest on the bonds.
OUR ABILITY TO MAKE PAYMENT ON THE BONDS MAY BE AFFECTED BY CERTAIN BANKRUPTCY
LAW ISSUES AND A DIFFICULTY OF FORECLOSURE.
The Amended and Restated PPA, Power Services Agreement, Administrative
Services Agreement or the El Paso Energy Performance Guaranty may be treated as
executory contracts by any bankruptcy court having jurisdiction over them. As a
result, in the event of our bankruptcy or the bankruptcy of PSE&G, EPM or El
Paso Energy, the bankrupt party or the bankruptcy trustee could reject any or
all of the Amended and Restated PPA, Power Services Agreement, Administrative
Services Agreement or the El Paso Energy Performance Guaranty, as the case may
be, if they are found to be executory contracts. Rejection of a contract is
treated as a breach of the contract and would result in the nondebtor
counterparty (i.e., PSE&G, EPM or El Paso Energy) having an unsecured claim
against the estate of the debtor for damages as a result of the breach.
In the event of our bankruptcy, the holders would have a secured claim
against us for the amounts due under the bonds. The holders' claim would be
secured by their interest in the collateral. Absent relief granted by the
bankruptcy judge from the automatic stay in bankruptcy, however, the holders
could not foreclose on any of the collateral and there may not be sufficient
funds to pay amounts due in respect of the bonds.
IT MAY BE DIFFICULT TO REALIZE THE VALUE OF THE COLLATERAL PLEDGED TO SECURE THE
BONDS.
Our obligation to make payments on the bonds is secured only by the
collateral described in this prospectus. The trustee's ability to foreclose on
the collateral on your behalf may be subject to perfection, the consent of
certain third parties, priority issues and practical problems associated with
the realization of the trustee's security interest in the collateral. In
addition, pursuant to the consent and agreement with PSE&G, in the event that
the trustee or any designee and assignee succeeds to our interests under the
Amended and Restated PPA, this successor will assume liability for our
obligations under the Amended and Restated PPA, including those obligations
arising prior to such succession. We cannot assure you that foreclosure on the
collateral will be sufficient to make all payments on the bonds.
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<PAGE> 27
THERE IS NO EXISTING MARKET FOR THE BONDS AND WE CANNOT ASSURE YOU THAT AN
ACTIVE TRADING MARKET WILL DEVELOP FOR THE BONDS.
We have been informed by the initial purchaser of the Series A bonds that
it intends to make a market in the bonds after the completion of this offering.
However, the initial purchaser is not required to make a market in the bonds,
and it may cease market-making at any time without notice. We cannot assure you
that an active market for the bonds will develop. Moreover, even if a market for
the bonds does develop, the bonds could trade at a discount from their face
amount. If a market for the bonds does not develop, you may be unable to resell
the 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.
FAILURE TO EXCHANGE SERIES A BONDS -- IF YOU DO NOT PROPERLY TENDER YOUR SERIES
A NOTES, YOU WILL CONTINUE TO HOLD UNREGISTERED SERIES A BONDS AND YOUR ABILITY
TO TRANSFER SERIES A BONDS WILL BE ADVERSELY AFFECTED.
We will only issue Series B bonds in exchange for Series A bonds that are
timely received by the exchange agent together with all required documents,
including a properly completed and signed letter of transmittal. Therefore, you
should allow sufficient time to ensure timely delivery of the Series A bonds and
you should carefully follow the instructions on how to tender your Series A
bonds. Neither we nor the exchange agent are required to tell you of any defects
or irregularities with respect to your tender of the Series A bonds. If you do
not tender your Series A bonds or if we do not accept your Series A bonds
because you did not tender your Series A bonds properly, then, after we
consummate the exchange offer, you may continue to hold Series A bonds that are
subject to the existing transfer restrictions. In addition, if you tender your
Series A bonds for the purpose of participating in a distribution of the Series
B bonds, you will be required to comply with the registration and prospectus
delivery requirements of the Securities Act in connection with any resale of the
Series B bonds. If you are a broker-dealer that receives Series B bonds for your
own account in exchange for Series A bonds that you acquired as a result of
market-making activities or any other trading activities, you will be required
to acknowledge that you will deliver a prospectus in connection with any resale
of such Series B bonds. After the exchange offer is consummated, if you continue
to hold any Series A bonds, you may have difficulty selling them because there
will be fewer Series A bonds outstanding.
THE MARKET VALUE OF THE SERIES B BONDS COULD BE MATERIALLY ADVERSELY AFFECTED IF
ONLY A LIMITED NUMBER OF SERIES B BONDS ARE AVAILABLE FOR TRADING
To the extent that a large amount of the Series A bonds are not tendered or
are tendered and not accepted in the exchange offer, the trading market for the
Series B bonds could be materially adversely affected. Generally, a limited
amount, or "float," of a security could result in less demand to purchase such
security and, as a result, could result in lower prices for such security. We
cannot assure you that a sufficient number of Series A bonds will be exchanged
for Series B bonds so that this does not occur.
WE ARE RELYING ON PROJECTIONS AND ASSUMPTIONS ABOUT THE FUTURE WHICH MAY PROVE
TO BE INACCURATE.
We have included forward-looking statements in this prospectus which may
materially differ from actual results, events or performance. Information
contained in this prospectus or incorporated herein by reference includes
forward-looking statements that are not historical facts and that involve risks
and uncertainties, including those under the captions "Forward-Looking
Statements," "Risk Factors," and "Prospectus Summary -- Power Services Agreement
Assessment," and including those contained in Annex A. Actual results, events
and performance could differ materially from those contemplated by these
forward-looking statements as a result of these risks and uncertainties.
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<PAGE> 28
RATIO OF EARNINGS TO FIXED CHARGES
For the period from March 3, 2000 to September 30, 2000, our ratio of
earnings to fixed charges was 1.30. Because we began operations on March 3,
2000, we cannot calculate a ratio of earnings to fixed charges for any prior
periods. For the purposes of calculating the ratio of earnings available to
cover fixed charges:
- earnings consist of income from continuing operations and fixed charges,
and
- fixed charges consist of interest on borrowings (whether expensed or
capitalized) and related amortization.
USE OF PROCEEDS
We will not receive any cash proceeds from the issuance of the Series B
bonds. In consideration for issuing the Series B bonds as contemplated in this
prospectus, we will receive, in exchange, Series A bonds in like principal
amount, which will be canceled, and as such will not result in any increase in
our indebtedness.
Our net proceeds from the offering of the Series A notes were approximately
$307,882,250. We used the net proceeds as follows:
(1) to pay the purchase price of $289,830,150 for the Original PPA;
(2) to fund the liquidity account in an amount equal to $13,200,500;
(3) to fund the collections account in an amount equal to $2,396,509;
and
(4) to pay costs, fees and expenses incurred in connection with the
transactions contemplated by the indenture.
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<PAGE> 29
CAPITALIZATION
The capitalization of our company as of September 30, 2000 consisted of ten
membership interests totaling approximately $88,000.
OUR COMPANY AND BUSINESS
We were formed as a Delaware limited liability company on March 3, 2000
solely to:
- acquire the right, title and interest to the Original PPA;
- sell electric energy and capacity under the Amended and Restated PPA;
- enter into other material agreements, the indenture and the related
financing documents and undertake the transactions contemplated
thereunder;
- engage in other activities that are related to or incidental to the
foregoing; and
- issue the bonds.
Our sole business is the wholesale sale of electric capacity and electric
energy to PSE&G under the Amended and Restated PPA. In March 2000, we and PSE&G
agreed to amend the Original PPA. Upon the consummation of the offering of the
Series A bonds, we used the proceeds of the offering of the Series A bonds to
pay NBCP the purchase price for the Original PPA, the Original PPA was
transferred to us and the amendment of its terms became effective. The amended
Original PPA was then restated in its entirety as the Amended and Restated PPA.
We are classified as a public utility subject to regulation by the Federal
Energy Regulatory Commission under the Federal Power Act. We have no employees.
Our material assets are comprised of the Amended and Restated PPA, receivables
that are generated by or accrue under the Amended and Restated PPA, the proceeds
of such receivables, our interest in the amounts held in our accounts described
in this prospectus and the following additional material agreements:
- the Power Services Agreement;
- the Administrative Services Agreement;
- the El Paso Energy Performance Guaranty;
- a Consent and Agreement with PSE&G and the trustee;
- a Consent and Agreement with EPM and the trustee;
- a Consent and Agreement with El Paso Energy and the trustee.
For more information about our material agreements, see "Summary of Certain
Transaction Documents" below.
SELECTED FINANCIAL DATA OF THE COMPANY
Set forth below is summary financial data of our company as of September
30, 2000 and for the period from March 3, 2000 to September 30, 2000. This
summary financial data has been extracted from our audited financial statements
which are included in this prospectus.
<TABLE>
<S> <C>
SUMMARY BALANCE SHEET DATA (in thousands):
Total assets.............................................. $311,691
Long-term liabilities..................................... 311,603
Member's equity........................................... 88
SUMMARY STATEMENT OF INCOME DATA (in thousands):
Operating revenues........................................ $ 849
Operating income.......................................... 386
Net income................................................ 88
</TABLE>
We engaged in no operations between our formation in March 2000 and
September 27, 2000.
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<PAGE> 30
MANAGEMENT
We are a wholly-owned direct subsidiary of Mesquite. Mesquite is owned
indirectly by El Paso Energy and Limestone. A wholly-owned subsidiary of El Paso
Energy manages the operations of Mesquite and us. See "Chaparral Management."
Pursuant to our limited liability company agreement, all management powers of
our company are vested in a management committee comprised of five managers,
consisting of three Class A managers and two Class B managers. The Class A
managers are designated by Mesquite. The Class B managers must be independent
and cannot be associated with any of our affiliates. A voluntary bankruptcy
petition cannot be filed by us unless the Class B managers vote to file this
bankruptcy petition. Except for bankruptcy, dissolution and similar limited
matters, the Class B managers do not exercise any power over the management,
conduct or control of the business, operations or affairs of the company, and
the vote of a majority of the Class A managers present at a meeting constitutes
the act of the management committee. Our day-to-day operations are managed by
officers and employees of EPM under the Administrative Services Agreement with
us. Our principal executive offices are located at 1001 Louisiana Street,
Houston, Texas 77002. Our telephone number is (713) 420-2131.
The following table sets forth certain information concerning our executive
officers and Class A managers:
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Clark C. Smith................ 46 President
John L. Harrison.............. 41 Vice President, Senior Managing
Director and Class A Manager
Cecilia T. Heilmann........... 32 Vice President, Managing
Director and Controller
Timothy Sullivan.............. 38 Class A Manager
Kurt Regulski................. 42 Class A Manager
</TABLE>
Clark C. Smith, our President, is also President of EPM, which includes the
combined unregulated natural gas and power service businesses of El Paso Energy.
Mr. Smith has over 22 years of industry experience. He has been with EPM since
2000. Mr. Smith was formerly President and Chief Executive Officer of Engage
Energy, Inc., a natural gas and power services venture of The Coastal
Corporation, and Westcoast Energy Inc. of Vancouver, British Columbia. In 1988,
Mr. Smith joined The Coastal Corporation as President and Chief Executive
Officer of Coastal Gas Marketing Company, and later assumed responsibility for
the formation of Coastal Gas Marketing Canada and Coastal Electric Services
Company. Mr. Smith began his business career with El Paso Natural Gas Company in
1978, where he held various positions in regulatory affairs, systems development
and gas accounting. He joined Enron Corp. the next year as Director of Marketing
for Transwestern Pipeline Company. Later, he became Executive Vice President of
Transwestern Pipeline Company's marketing, gas supply and state regulatory
affairs. Mr. Smith earned bachelor and master degrees in business administration
from the University of Texas at Austin.
John L. Harrison is our Vice President, Senior Managing Director and a
Class A Manager. He is also Senior Managing Director and Chief Financial Officer
of EPM. Mr. Harrison has over 20 years of energy industry experience. Prior to
joining EPM, Mr. Harrison was an audit partner with Coopers & Lybrand, LLP,
where he specialized in the energy industry with an emphasis in trading and
control environments. Mr. Harrison received a bachelor's degree in business
administration from Texas A&M University and is a certified public accountant.
Cecilia T. Heilmann is our Vice President, Managing Director and
Controller. She is also Vice President, Managing Director and Controller of EPM.
Ms. Heilmann has over 8 years of industry experience. Ms. Heilmann began her
business career with El Paso Energy in 1992, where she held various positions in
corporate accounting and strategic planning. In 1998, Ms. Heilmann became
Director of Corporate Planning for El Paso Energy, and, in 1999, she joined EPM
as Controller. As Controller for
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<PAGE> 31
EPM, she oversees accounting, planning and credit activities. Ms. Heilmann
received a bachelor's degree in Accounting from the University of Texas at El
Paso, and is a certified public accountant.
Timothy Sullivan, a Class A Manager, is Managing Director of Restructuring
for EPM. He has over 18 years of industry experience. Mr. Sullivan is primarily
responsible for EPM's financial structuring and restructuring activities
throughout North America. The group he leads is successfully acquiring and
restructuring non-utility generation power projects in the United States.
Currently, this group has $900 million of project financings either in process
or closed. Mr. Sullivan joined El Paso Merchant Energy Company in 1998. Mr.
Sullivan was previously a Senior Vice President with Citizens Power in Boston
from 1995-1997, during which time he participated in and led financing
activities relating to project financings. During 1994, Mr. Sullivan was a
Manager for Enron Power Marketing in Houston, Texas, where he had responsibility
for the marketing of wholesale electric power in the northeast. Prior to joining
Enron, Mr. Sullivan held various positions over a twelve-year period with
Niagara Mohawk Power Corporation in Syracuse, New York, where he was responsible
for negotiating non-utility and wholesale electric power purchase and sale
agreements. Mr. Sullivan holds a Bachelor of Science and a Master of Business
Administration degree from Syracuse University.
Kurt Regulski, a Class A Manager, is responsible for managing EPM's
cross-commodity positions, which consist of power and gas positions related to
power plant assets. Mr. Regulski has over 20 years of experience in the energy
industry. Mr. Regulski began in the energy industry as an engineer for Southern
Natural Gas Company, where he worked in a variety of engineering and technical
support positions, including Division Manager and Manager of Process
Reengineering from 1980 to 1994. Mr. Regulski joined Sonat Marketing in 1995 as
Manager, Southeast Trading, with responsibilities for managing storage, basis
and physical gas positions in the southeast U.S. He joined Sonat Power Marketing
in 1997 as Director, Power Trading, with management and trading responsibilities
for the term power trading desk. Sonat merged with El Paso Energy in December,
1999, and Mr. Regulski joined EPM thereafter. Mr. Regulski has a degree in
Mechanical Engineering from Vanderbilt University.
Our Class A Managers and our officers are also officers of El Paso Energy
or its affiliates. Such managers and officers may spend a substantial amount of
time managing the business and affairs of El Paso Energy and its affiliates.
Since our day-to-day operations are managed by employees of EPM pursuant to the
Administrative Services Agreement, we do not expect that our managers and
officers will face a conflict regarding the allocation of their time between our
interests and the other business interests of El Paso Energy and its affiliates.
Our Class A Managers and officers do not receive any compensation from us.
We do not sponsor any employee benefit plans or arrangements. Our officers and
managers receive compensation from and participate in benefit plans sponsored by
El Paso Energy and its affiliates. The Class B Managers receive a nominal annual
fee for serving on our management committee. EPM receives a fee of $50,000 semi-
annually for the services it performs under the Administrative Services
Agreement and is entitled to reimbursement for all expenses other than internal
and overhead costs. EPM is responsible for the compensation of its employees.
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<PAGE> 32
EL PASO ENERGY AND SELECTED FINANCIAL INFORMATION OF EL PASO ENERGY
EL PASO ENERGY
A wholly-owned subsidiary of El Paso Energy manages our operations (see
"Chaparral Management") and El Paso Energy indirectly owns approximately 20% of
the ownership interest in us, subject to reduction upon certain events. El Paso
Energy is a global energy company with a significant presence in the rapidly
evolving wholesale energy industry.
El Paso Energy's principal operations include:
- the interstate and intrastate transportation, gathering, processing and
storage of natural gas;
- the marketing of natural gas, electric power and other energy-related
commodities;
- the generation of electric power;
- the development and operation of energy infrastructure facilities
worldwide; and
- the domestic exploration for, and production of, oil and natural gas.
El Paso Energy owns or has interest in over 40,000 miles of interstate and
intrastate pipeline connecting the nation's principal natural gas supply regions
to the five largest consuming regions in the United States: the Gulf Coast,
California, the Northeast, the Midwest and the Southeast. El Paso Energy's
natural gas transmission operations represent the nation's largest and only
integrated coast-to-coast mainline natural gas transmission system comprised of
interests in the Florida Gas Transmission pipeline and the Portland Natural Gas
Transmission pipeline system and six wholly-owned interstate pipeline systems:
- the Tennessee Gas pipeline;
- the El Paso Natural Gas pipeline;
- the Southern Natural Gas pipeline;
- the South Georgia Natural Gas pipeline;
- the Midwestern Gas Transmission pipeline; and
- the Mojave pipeline systems.
Through its merchant energy business segment, El Paso Energy is a major
intermediary in the wholesale natural gas and electric power markets, and is
engaged in buying and selling natural gas, pipeline capacity, natural gas
storage, electric power and other energy commodities throughout North America.
El Paso Energy has also become one of the largest non-utility owners of electric
generating capacity in the United States. In its operations, El Paso Energy uses
sophisticated systems and financial modeling capabilities to evaluate risks
inherent in its markets, then seeks to mitigate those risks using its presence
in and knowledge of the financial and physical commodity markets.
In January 2000, El Paso Energy announced it had entered into a definitive
agreement to merge a wholly-owned subsidiary with The Coastal Corporation. The
transaction will be accounted for as a pooling of interests and is expected to
close in the fourth quarter of 2000. The merger is subject to certain
conditions, including receipt of certain required governmental approvals. The
Coastal Corporation is a diversified energy holding company with operations in
natural gas transmission, storage, gathering, processing and marketing; natural
gas and oil exploration and production; petroleum refining, marketing and
distribution; chemicals; and power and coal production. Upon completion of the
merger, the combined company's natural gas transmission system will include
approximately 58,000 miles of pipeline and reach approximately 70% of the
nation's population.
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<PAGE> 33
El Paso Energy's international activities focus on the development and
operation of international energy infrastructure projects. These activities
include ownership interests in three major operating natural gas transmission
systems in Australia and natural gas transmission systems and power generation
facilities currently in operation or under construction in Argentina,
Bangladesh, Bolivia, Brazil, Chile, China, the Czech Republic, Hungary, India,
Indonesia, Korea, Mexico, Pakistan, Peru, the Philippines and the United
Kingdom.
El Paso Energy had total assets as of September 30, 2000 of approximately
$22 billion. El Paso Energy's senior unsecured debt is rated Baa2 by Moody's and
BBB by Standard & Poor's.
SELECTED FINANCIAL INFORMATION OF EL PASO ENERGY
We present below selected consolidated historical financial data for El
Paso Energy as of and for each of the periods indicated. These financial
statements reflect the merger with Sonat Inc. in October 1999 in a transaction
accounted for as a pooling of interests.
We derived the operating results data for the years ended December 31,
1999, 1998 and 1997 and the financial position data as of December 31, 1999 and
1998 from El Paso Energy's audited consolidated financial statements included in
El Paso Energy's Annual Report on Form 10-K for the year ended December 31,
1999. We derived the financial data as of and for the nine months ended
September 30, 2000 and 1999 from El Paso Energy's third quarter Form 10-Q. We
derived the remaining financial data by combining selected financial data from
the separate audited historical consolidated financial statements of El Paso
Energy and Sonat to give effect to the Sonat merger.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
---------------- --------------------------------------------
2000 1999 1999 1998 1997 1996 1995
------- ------ ------- ------ ------- ------ ------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
OPERATING RESULTS DATA:(a)(b)
Operating revenues................................... $14,320 $8,137 $10,581 $9,500 $10,015 $6,217 $2,941
Merger-related, restructuring, and asset impairment
charges(c)......................................... 46 193 557 15 50 99
Ceiling test charges(d).............................. 352 352 1,035
Depreciation, depletion and amortization............. 443 434 609 624 639 490 447
Income (loss) from continuing operations............. 436 (64) (242) (306) 405 294 354
Basic earnings (loss) per common share from
continuing operations(e)........................... 1.89 (0.28) (1.06) (1.35) 1.81 1.61 1.98
Diluted earnings (loss) per common share from
continuing operations(e)(f)........................ 1.83 (0.28) (1.06) (1.35) 1.77 1.59 1.97
Cash dividends declared per common share(g).......... 0.62 0.60 0.80 0.76 0.73 0.70 0.66
Basic average common shares outstanding.............. 230 227 228 226 224 183 179
Diluted average common shares outstanding(f)......... 242 227 239 237 229 185 180
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
AS OF SEPTEMBER 30, ----------------------------------------------
2000 1999 1998 1997 1996 1995
--------------------- ------- ------- ------- ------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
FINANCIAL POSITION DATA:(a)(b)
Total assets................................... $21,746 $16,657 $14,443 $14,784 $13,206 $6,548
Short-term debt (including current maturities
of long-term debt)........................... 1,825 1,344 1,650 1,353 1,064 534
Long-term debt, less current maturities........ 4,566 5,223 3,692 3,404 3,251 1,640
Company-obligated preferred securities of a
consolidated trust........................... 625 325 325
Minority interest.............................. 1,581 1,368 374 380 347 9
Stockholders' equity........................... 3,431 2,947 3,437 3,921 3,514 2,428
</TABLE>
---------------
(a) The operating results and financial position reflect El Paso Energy's
merger with Sonat Inc. in October 1999 and Sonat's merger with Zilkha
Energy Company in January 1998. Each of these transactions was accounted
for as a pooling of interests and, accordingly, the operating results and
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<PAGE> 34
financial position data have been restated to include the accounts and
operations of Sonat and Zilkha Energy for all periods presented.
(b) The operating results and financial position reflect the acquisition in
September 1995 of Eastex Energy, Inc., in December 1995 of Premier Gas
Company, in June 1996 of Cornerstone Natural Gas, Inc., in December 1996 of
El Paso Tennessee Pipeline Co. (formerly Tenneco Inc.), and in August 1998
of DeepTech International Inc. These acquisitions were accounted for as
purchases and, therefore, operating results of these acquired entities are
included in the operating results prospectively from the date of
acquisition.
(c) El Paso Energy included, under merger-related, restructuring, and asset
impairment charges, in 1999, a pretax charge of $557 million ($407 million
after tax) for El Paso Energy's merger with Sonat and the impairment of
long-lived assets; in 1998, a pretax charge of $15 million ($9 million
after tax) for the reorganization of Sonat's natural gas and oil production
segment; in 1997, a pretax charge of $50 million ($33 million after tax)
for Sonat's merger with Zilkha Energy; and, in 1996, a pretax charge of $99
million ($60 million after tax) for El Paso Energy's implementation of a
workforce reduction plan and the impairment of long-lived assets.
(d) Ceiling test charges are reductions in earnings that result when
capitalized costs of natural gas and oil properties exceed the upper limit,
or ceiling, on the value of these properties. The ceiling is determined
based on the future cash flows we estimate will be derived from these
properties, discounted at a rate of 10 percent. For 1999, these charges
were $352 million pretax ($257 million after tax), and, in 1998, these
charges were $1,035 million pretax ($642 million after tax).
(e) If El Paso Energy had not recorded the merger-related, restructuring, and
asset impairment charges and the ceiling test charges discussed above, its
basic earnings per common share from continuing operations for 1999, 1998,
1997 and 1996, would have been $1.85, $1.53, $1.96 and $1.93, respectively.
The diluted earnings per common share from continuing operations, excluding
these charges for those same periods, would have been $1.81, $1.49, $1.91
and $1.91, respectively.
(f) As required by the accounting rules, El Paso Energy calculated diluted
earnings (loss) per common share for 1999 and 1998 based on basic average
common shares outstanding. If El Paso Energy had made this calculation
based on diluted average common shares outstanding, El Paso Energy would
have shown less of a loss per common share.
(g) El Paso Energy assumed that cash dividends declared per common share are
the same as the historical dividends declared by it during the periods
presented.
EPM
EPM is an indirect wholly-owned subsidiary of El Paso Energy that has acted
as a power marketer since 1996. As a power marketer, EPM acts as an intermediary
between the buyer and the seller of electricity. EPM seeks to obtain the optimum
prices for the purchaser. EPM, in its power marketing capacity, also offers risk
management services by using derivative products, such as options, swaps and
forward contracts to enable customers to fix their rates.
EPM has a 24-hour trading, scheduling and dispatching capability. For the
first nine months in 2000, EPM reported a volume of approximately 87.1 million
MW to the Federal Energy Regulatory Commission and was ranked the thirteenth
largest power marketer in terms of volume by the Federal Energy Regulatory
Commission for this period.
EPM buys, sells, and trades power, power generation and transmission
capacity and other energy-related commodities and intermediates risk in its
markets using sophisticated integrated risk management techniques. EPM's
merchant activities provide customers with flexible solutions to meet their
energy supply and financial risk management requirements by utilizing its
knowledge of the marketplace, natural gas pipelines and power transmission
infrastructure, supply aggregation, transportation management and valuation,
storage, and integrated price risk management. It also acquires, develops,
constructs, owns,
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<PAGE> 35
operates and manages domestic power generation facilities and other power
related assets and joint ventures.
EPM and its affiliates have ownership interests or management
responsibilities in 40 power generation facilities with a total generating
capacity of over 5,000 megawatts.
LIMESTONE
Limestone indirectly owns approximately 80% of the ownership interests in
us, subject to increase upon certain events. Limestone is a statutory business
trust formed in 1999 under the laws of the State of Delaware. Limestone was
formed pursuant to the terms of the Limestone Trust Agreement among El Paso
Energy, Wilmington Trust Company in its capacity as trustee, and Limestone,
together with a financial investor. The beneficial ownership interests of
Limestone are evidenced by approximately $150 million of Limestone trust
certificates held by institutional investors. El Paso Energy has voting rights
in Limestone with respect to certain bankruptcy matters. Limestone was formed
for the purpose of conducting limited activities, including purchasing a
membership interest in Chaparral, issuing senior notes in an aggregate principal
amount of approximately $1 billion and contributing most of the proceeds of this
issuance to Chaparral.
MESQUITE AND CHAPARRAL
Mesquite is our direct owner. Chaparral holds the sole membership interest
in Mesquite. In 1999, El Paso Energy formed Chaparral to fund the growth of its
unregulated domestic power generation and related businesses. Chaparral is a
Delaware limited liability company, the members of which are Chaparral Investor
and El Paso Chaparral Holding II Company, each of which is a wholly-owned
indirect subsidiary of El Paso Energy, and Limestone. Through Mesquite,
Chaparral owns interests in (1) 22 commercially operating gas-fired power
facilities in New Jersey (including the Newark Bay Facility), Rhode Island,
Massachusetts, Colorado, Nevada and California and (2) one gas-fired power
facility under construction in Connecticut. These facilities in the aggregate
represent total generating capacity of approximately 3,300 MW, of which El Paso
Energy affiliates have a net equity interest in approximately 1,930 MW. El Paso
Chaparral, a wholly-owned indirect subsidiary of El Paso Energy, is the managing
member of Chaparral and will make all decisions on behalf of Chaparral (except
for certain actions requiring unanimous consent of the members.)
CHAPARRAL MANAGEMENT
Pursuant to the Chaparral management agreement among the members of
Chaparral, Mesquite and Chaparral Management, Chaparral Management manages the
operations of Chaparral and Mesquite and, subject to the terms of the Chaparral
management agreement, manages the acquisition, operation and disposition of the
assets held by such entities. Chaparral Management is a wholly-owned indirect
subsidiary of El Paso Energy.
PSE&G
PSE&G is a public company and is subject to the informational requirements
of the Securities Exchange Act and, in accordance therewith, files reports,
proxy statements and other information, including financial reports, with the
SEC.
PSE&G's senior secured debt is rated A3 by Moody's, A- by Standard & Poor's
and A by Fitch.
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<PAGE> 36
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion contains forward-looking statements about us.
These statements are based on our current plans and expectations and involve
risks and uncertainties that could cause actual future results to be materially
different from those set forth in the forward-looking statements. Important
factors that could cause actual results to differ include risks set forth in
"Forward-Looking Statements" and "Risk Factors."
GENERAL
Our company was formed on March 3, 2000 as a Delaware limited liability
company solely to:
- acquire the right, title and interest to the Original PPA;
- sell electric energy and capacity under the Amended and Restated PPA;
- enter into other material agreements, the indenture and the related
financing documents and undertake the transactions contemplated
thereunder;
- engage in other activities that are related to or incidental to the
foregoing; and
- issue the bonds.
We have no employees and are relying upon EPM to perform our obligations
under our material agreements. Our material assets are comprised of the Amended
and Restated PPA, receivables that are generated by or accrue under the Amended
and Restated PPA, the proceeds of such receivables, our interest in the amounts
held in our accounts described in this prospectus and our material agreements.
We have no material obligations other than those under the bonds, the indenture
and our material agreements.
RESULTS OF OPERATIONS
We have included in this prospectus our audited financial statements, which
consist of a balance sheet dated as of September 30, 2000 and statements of
income, of cash flows and of member's equity from our formation, March 3, 2000,
through September 30, 2000. We have engaged in operations only since September
27, 2000 and do not have an operating history. Under the Amended and Restated
PPA, electricity rates are set annually in accordance with a schedule to the
Amended and Restated PPA. See "Summary of Certain Transaction
Documents -- Amended and Restated PPA -- Purchase and Sale of Capacity and
Energy -- Purchase Price and Payment Conditions." Our results of operations in
the future will depend primarily on revenues from the sale of energy and
capacity and the level of our expenses.
LIQUIDITY AND CAPITAL RESOURCES
We pay certain operating expenses, including trustee fees and fees to EPM
under the Administrative Services Agreement. The annual trustee and securities
intermediary fees are established in our agreement with the trustee and are a
total of $20,000 annually. The annual fees to EPM under the Administrative
Services Agreement are established in our agreements and are initially a total
of $100,000 annually. These fees to EPM are only due and payable to the extent
that there are amounts on deposit in the collections account after payment of
all current and past due amounts ranking prior to the payment of these fees. See
"Summary of Certain Transaction Documents -- Administrative Services
Agreement -- Fee."
Our sole source of liquidity and capital resources is the payments to be
made by PSE&G under the Amended and Restated PPA, shortfall payments and excess
amounts required to be paid to us by EPM under the Power Services Agreement and
guaranteed by El Paso Energy under the El Paso Energy Performance Guaranty, and
amounts on deposit in the liquidity account or acceptable credit support
provided in place of cash deposits. All scheduled payments of principal and
interest on the bonds have been calculated so as to be paid solely from the
collections account payments to be made each year by PSE&G for the full amount
of the annual energy deliveries.
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<PAGE> 37
The maximum amount of the annual energy payments for any year can be
readily determined. Payments to us under the Amended and Restated PPA are
determined by multiplying the contract rate by the amount of energy delivered.
The contract rate for each year is established under the Amended and Restated
PPA. Pursuant to the Amended and Restated PPA, we have the right to schedule and
deliver amounts of energy up to the annual energy deliveries for each year. In
order to meet our payments of principal and interest on the bonds, EPM is
required, pursuant to the Power Services Agreement, to schedule and deliver the
full amount of the annual energy deliveries during each year.
The annual energy deliveries may be scheduled and delivered at any time
during the calendar year (subject to meeting the minimum energy deliveries
requirement, certain notification provisions and maximum delivery rate limits).
Although our revenues, determined on an annual basis, should remain stable, our
monthly revenues may vary significantly. We receive our last monthly payment
from PSE&G for each year on January 31 of the following calendar year. Interest
payments are made semi-annually, each February 15 and August 15 of each year and
principal payments are made annually on February 15 of each year.
In order to offset any timing differences between our cash flows from the
energy deliveries, which may be received on an irregular basis, and our interest
and principal payments on the bonds, we funded the liquidity account with the
trustee in an amount equal to the liquidity reserve required balance out of the
proceeds of the offering of the Series A bonds. If we have not scheduled and
delivered enough energy during any six month period from January through July to
make the interest payment due on the Interest Payment Date in August, we will be
able to withdraw amounts from the liquidity account or seek to make this payment
to the extent that funds are in the liquidity account. Similarly, if we do not
have sufficient funds in the collections account to pay the principal payment
due on the Principal Payment Date in February, we will be able to draw on the
funds available in the liquidity account. Once funds have been withdrawn from
the liquidity account, those funds will only be replenished out of funds
otherwise available in the collections account. If surplus funds are not
available from the collections account, the liquidity reserve required balance
will not be maintained.
El Paso Energy has the right from time to time to withdraw all or a portion
of the cash on deposit in the liquidity account if El Paso Energy replaces that
cash with acceptable credit support. This is described in "The
Transaction -- Accounts."
Assuming that we schedule and deliver all of the annual energy deliveries
each year, the minimum debt service coverage ratio for any year is expected to
be 1.03 to 1.00 and the average debt service coverage ratio for any year is
expected to be 1.03 to 1.00. The following table sets forth on an annual basis
cash available for debt service and debt service for the bonds commencing in the
year 2000.
<TABLE>
<CAPTION>
CASH AVAILABLE DEBT
YEAR FOR DEBT SERVICE(1) SERVICE(2)
---- ------------------- ----------
($ MILLIONS)
<S> <C> <C>
2000...................................... $11.3(3) $11.0
2001...................................... 33.2 32.3
2002...................................... 34.8 33.8
2003...................................... 37.4 36.3
2004...................................... 40.8 39.6
2005...................................... 42.1 40.9
2006...................................... 43.6 42.3
2007...................................... 45.0 43.7
2008...................................... 46.2 44.9
2009...................................... 47.6 46.2
2010...................................... 49.1 47.7
2011...................................... 50.7 49.0
2012...................................... 52.3 50.7
2013...................................... 35.0 34.0
</TABLE>
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<PAGE> 38
---------------
(1) Determined from February 1 to January 31 of the following year.
(2) Determined from February 16 to February 15 of the following year.
(3) Includes an initial deposit of $2,396,509 to the collections account from
the proceeds of the offering of the Series A bonds.
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<PAGE> 39
REGULATION OF THE ELECTRIC INDUSTRY
The following is a summary overview of the industry and regulation and
shall not be considered a full statement of all issues pertaining thereto.
Historically, the electric utility industry in the United States was
composed primarily of investor-owned utilities, municipal utilities, rural
electric cooperatives and various federal power agencies, including the
Tennessee Valley Authority. These entities have traditionally been the only
significant providers of electric power to retail and wholesale customers.
Further, traditional electric utilities in the United States were
vertically-integrated businesses that owned generation, transmission and
distribution facilities and whose operations were comprehensively regulated by
federal and state governments using a cost-of-service framework. For many
investor-owned utilities, the generation of electricity has traditionally been
dominant in terms of assets employed, capital invested and revenue generated.
However, the structure and operation of the electric industry is changing as a
result of increasing competition and changing regulation.
TRADITIONAL ELECTRIC UTILITY INDUSTRY REGULATION
Electric utilities have historically been highly regulated by both state
public utility commissions and the Federal Energy Regulatory Commission. State
regulatory authorities exercise their jurisdiction over almost all aspects of
utility operation. The Federal Energy Regulatory Commission regulates wholesale
sales of electric power and the transmission of electricity in interstate
commerce pursuant to the Federal Power Act and regulations promulgated under the
Federal Power Act. Pursuant to its authority under the Federal Power Act, the
Federal Energy Regulatory Commission subjects public utilities to rate and
tariff regulation and accounting and reporting requirements, as well as
oversight of mergers and acquisitions, securities issuances and dispositions of
facilities.
Under the Public Utility Holding Company Act of 1935 ("PUHCA"), any company
that directly or indirectly owns, controls or holds with the power to vote ten
percent (10%) or more of the outstanding voting securities of a "public utility
company," or is a company that is a "holding company" of a public utility
company, must register with the SEC unless it is eligible for an exemption or
unless an appropriate application is filed with, and an order is granted by, the
SEC declaring it not to be a holding company. PUHCA requires registered public
utility holding companies to limit their operations to single integrated utility
systems and to divest any other operations not functionally related to the
operation of the utility system. A registered holding company and its
subsidiaries under PUHCA are subject to financial and organizational regulation,
including SEC approval of their financing transactions.
PURPA reduced regulatory constraints and encouraged entities other than
utilities to enter the electric power generation business. Independent power
producers and cogenerators satisfying the Federal Energy Regulatory Commission's
standards as qualifying facilities became exempt from PUHCA, most provisions of
the Federal Power Act and certain state laws relating to rate, organizational
and financial regulation. PURPA also required electric utilities to purchase
electricity generated by qualifying facilities at a price based on the utility's
avoided cost of purchasing electricity or generating electricity itself, and to
sell supplementary, back-up, maintenance and interruptible power to qualifying
facilities on a just and reasonable and non-discriminatory basis. The
implementation of PURPA created a new class of non-utility generating companies
and a significant market for electric power produced by non-utilities.
ELECTRIC INDUSTRY DEREGULATION AND RESTRUCTURING
The Energy Policy Act of 1992 (the "EP Act") engendered more competition in
the electric industry. The EP Act permitted independent generation companies
that met certain requirements to sell wholesale power to utilities without
becoming subject to PUHCA. As a result, the competition increased among
companies selling power to utilities. The EP Act also expanded the Federal
Energy Regulatory Commission's authority to increase competition at the
wholesale level by granting the Federal Energy Regulatory Commission the
authority to require utilities to provide access to their transmission lines,
upon request, to certain entities seeking to transmit power to wholesale
purchasers.
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<PAGE> 40
Legislation to restructure the electric industry is under active
consideration at the federal level, and several states have passed, or are
actively considering, restructuring legislation. Congress is considering
legislation that would modify federal laws affecting the electric industry.
Bills have been introduced in the Senate and the House of Representatives that
would, among other things, provide retail electric customers with the right to
choose their electricity providers. Modifications to PURPA and PUHCA have also
been proposed. Although the legislative and regulatory proposals vary, several
common themes have developed. These themes include the availability of market
pricing, retail customer choice of electric supplier, recovery of stranded
costs, deregulation of generation and separation of generation assets from
transmission, distribution and other assets.
As a result of these initiatives, it is now widely believed that the
generation of electricity will be deregulated and opened up to competition.
Electricity is expected to be traded as a commodity, and generators are expected
to compete primarily in terms of price. Participants in the commodity market are
expected to include electric utilities, power marketers, independent power
producers and commodity trading firms.
Many utilities have functionally separated their generation, transmission
and distribution operations (often called "disaggregation" or "unbundling") to
prepare for possible deregulation of generation. A number of electric utilities
have announced or completed plans to divest their generation assets. As a
result, the participants in the electricity generation market for the
foreseeable future are expected to include captive subsidiaries of
vertically-integrated utilities, non-utility generators with contracts to sell
power to utilities and merchant plants not subject to cost-of-service
regulation, as well as marketers of generation services.
The transmission and distribution of electricity, viewed to be natural
monopoly functions, are expected to remain regulated. In general, it is expected
that the utility regulators in each state will remain responsible for regulating
the distribution of electricity, while the Federal Energy Regulatory Commission
is expected to supervise the transmission of electricity.
In light of recent legislative and regulatory initiatives, power marketers
have emerged as intermediaries that buy electric energy and/or capacity,
transmission, ancillary services and other commodities and services from
traditional utilities and others and resell these commodities and services on a
wholesale basis. Unlike traditional utilities, power marketers often own neither
generation nor transmission facilities and have no franchised service area.
Wholesale power marketers, such as EPM, are subject to Federal Energy Regulatory
Commission jurisdiction under the Federal Power Act regarding rates, terms and
conditions of service and certain reporting requirements. Because the Federal
Power Act grants the Federal Energy Regulatory Commission jurisdiction over
wholesale electric sales, a power marketer that desires to sell electricity on a
wholesale basis must have its rates accepted for filing by the Federal Energy
Regulatory Commission. Wholesale power marketers with rates on file at the
Federal Energy Regulatory Commission are considered public utilities for the
purpose of the Federal Power Act. A power marketer may receive Federal Energy
Regulatory Commission authorization to make interstate wholesale power sales at
market-based rates if it does not own or control generation or transmission
facilities that could provide it with market power. Power marketers are subject
to other regulatory requirements, such as the filing of quarterly and annual
reports with the Federal Energy Regulatory Commission and notifying the Federal
Energy Regulatory Commission of any significant change in operations or applying
for Federal Energy Regulatory Commission approval of a change in corporate
structure.
A major additional development in the move to a more competitive electric
power industry occurred when the Federal Energy Regulatory Commission issued its
Order Nos. 888 and 889, which contained final rules that introduced competitive
reforms into the wholesale power market and reduced regulatory constraints. At
the core of the new rules is a price-regulated transmission sector that provides
service completely separated or "unbundled" from generation and supply. Under
the new rules, all wholesale buyers and sellers of power, including the
utilities themselves, are required to take transmission service pursuant to the
same pro-forma tariff on the same terms and conditions and at the same prices.
Order
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<PAGE> 41
No. 888 required utilities subject to the Federal Energy Regulatory Commission's
jurisdiction to provide access across their transmission systems to third
parties and allowed them to seek recovery as "stranded costs" from departing
wholesale customers, the revenues that the utilities expected to receive from
those customers. The Federal Energy Regulatory Commission also imposed
reciprocity requirements that compel non-jurisdictional utilities (e.g., public
power, government-owned power marketing administrations or members of the
Electric Reliability Council of Texas) to offer the same quality of service as a
condition to their eligibility to take advantage of open-access transmission by
Federal Energy Regulatory Commission-regulated utilities. Order No. 888 also
required power pools, or associations of interconnected electric transmission
and distribution systems that have an agreement for integrated and coordinated
operations, to provide open-access transmission. Under Order No. 889, public
utilities must provide the public with an electronic system for buying and
selling transmission service in transactions with the utilities and abide by
certain standards of conduct when using their transmission system to make
wholesale sales of power. The Federal Energy Regulatory Commission has acted on
rehearing of Order Nos. 888 and 889, and they are currently the subject of a
federal appeal. In addition, the Federal Energy Regulatory Commission has
recently issued Order No. 2000, affirmed by Order 2000-A, which encourages the
creation of regional transmission groups throughout the country.
STATE REGULATION
The New Jersey Board of Public Utilities exercises regulatory jurisdiction
over New Jersey's "public utilities." A "public utility" is defined as including
every individual, corporation, partnership or association and their lessees,
trustees or receivers that own, operate, manage or control within New Jersey any
electricity distribution system for public use.
The New Jersey Board of Public Utilities has jurisdiction over a public
utility to regulate its rates and service, the assumption by it of liabilities
and obligations and the issuance and sale of certain of its securities. This
regulatory jurisdiction includes the power to regulate a public utility's
earnings, fix its rates, and authorize it to recover certain costs from its
ratepayers. The New Jersey Board of Public Utilities' jurisdiction over an
electric public utility is limited to prescribing uniform systems of accounts,
conservation and reliability measures, service territory, filing of periodic
reports and, with respect to retail sales, rate structure. The New Jersey Board
of Public Utilities does not have jurisdiction to regulate the earnings or fix
the rates of an electric public utility that is not a public utility.
A New Jersey investor-owned electric utility serving the public at retail,
such as PSE&G, is subject to broad New Jersey Board of Public Utilities
regulatory jurisdiction, both as a public utility and as an electric public
utility. By comparison, an entity that supplies electricity on a wholesale basis
only is not subject to New Jersey Board of Public Utilities regulation as a
public utility. These entities, however, may be subject to the New Jersey Board
of Public Utilities' limited regulatory jurisdiction if they supply electricity
on the retail level and fall within the statutory definition of "electric power
supplier."
Since we will not make retail sales of electricity in New Jersey, we will
not be subject to New Jersey Board of Public Utilities regulation as an
"electric power supplier." Since we do not anticipate that we will own, maintain
or operate an electric generation, transmission or distribution system in New
Jersey, we do not believe that we will be subject to New Jersey Board of Public
Utilities regulation as an "electric public utility."
THE FEDERAL ENERGY REGULATORY COMMISSION ORDERS
The Federal Energy Regulatory Commission approved our request to sell
electricity at negotiated rates on July 12, 2000, and that approval order also
granted pre-approval for us to issue bonds and assume liabilities. The Federal
Energy Regulatory Commission order became final and nonappealable on August 12,
2000.
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THE NEW JERSEY BOARD OF PUBLIC UTILITIES ORDER
The Amended and Restated PPA amends and restates a purchase agreement that
PSE&G entered into with NBCP pursuant to PURPA. See "Summary of Certain
Transaction Documents -- Amended and Restated PPA." The New Jersey Board of
Public Utilities previously authorized PSE&G to recover the costs of this
qualifying facility agreement from its ratepayers. Since the Amended and
Restated PPA amends and restates the qualifying facility agreement under which
the New Jersey Board of Public Utilities previously authorized PSE&G's recovery
of costs, PSE&G filed with the New Jersey Board of Public Utilities a petition
seeking confirmation that the Amended and Restated PPA similarly qualifies for
cost recovery under New Jersey law. The Amended and Restated PPA, as a wholesale
power sales agreement, itself is not subject to New Jersey Board of Public
Utilities jurisdiction and PSE&G did not seek New Jersey Board of Public
Utilities approval of the agreement for any purpose other than to confirm cost
recovery. On July 7, 2000, the New Jersey Board of Public Utilities issued its
order approving the Amended and Restated PPA for cost recovery purposes. This
order became final and non-appealable on September 26, 2000.
THE TRANSACTION
GENERAL
Our company was established by El Paso Energy and its affiliates solely to:
- acquire the right, title, and interest to the Original PPA;
- sell electric energy and capacity under the Amended and Restated PPA;
- enter into other material agreements, the indenture and the related
financing documents and undertaking the transactions contemplated
thereunder;
- engage in other activities that are related to or incidental to the
foregoing, and
- issue the bonds.
We purchased the Original PPA from NBCP pursuant to a purchase and sale
agreement. The Original PPA was amended and restated immediately upon its
transfer to us. The proceeds of the offering of the Series A bonds were used to
pay the purchase price for the Original PPA and certain transaction costs and to
fund the liquidity account. See "Use of Proceeds."
NBCP owns the Newark Bay Facility. NBCP is an affiliate of ours. Pursuant
to the Original PPA, NBCP sold generating capacity and associated energy from
the Newark Bay Facility to PSE&G. Under the Original PPA, the Newark Bay
Facility was required to be a qualifying facility under PURPA. The managers of
NBCP and of PSE&G sought to amend the Original PPA in order to achieve a number
of benefits, including the elimination of this requirement that we must maintain
the status of the Newark Bay Facility as a qualifying facility under PURPA. The
benefits of the Amended and Restated PPA also include the right to meet our
capacity and energy obligations from any available source, not only from the
Newark Bay Facility, significantly more flexibility in scheduling energy
deliveries, including a greater degree of daily delivery flexibility and the
substantial reduction of the energy and capacity rates under the Amended and
Restated PPA from those under the Original PPA.
NBCP agreed to sell the Original PPA to us and we paid NBCP the purchase
price out of the proceeds of the offering of the Series A bonds. The amendment
of the Original PPA became effective on September 26, 2000.
We expect that interest and principal on the bonds will be paid solely from
capacity and energy payments from PSE&G to us under the Amended and Restated PPA
(as supplemented, under certain circumstances, by funds in the liquidity
account. All scheduled payments of principal and interest on the bonds have been
calculated so as to be paid from the total amount of payments that we expect to
receive
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each year from PSE&G. We have entered into the Power Services Agreement and the
Administrative Services Agreement with EPM in order to have EPM perform all of
our obligations and exercise all of our rights in accordance with all of our
material agreements and the indenture and the related financing documents under
which the Series A bonds were issued and the Series B bonds will be issued. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
AMENDED AND RESTATED PPA
Under the Amended and Restated PPA, which has a term expiring August 31,
2013, we are required to deliver the minimum energy deliveries. Further, under
the Amended and Restated PPA, we have the right to schedule and deliver at any
time during the year (subject to certain notification provisions and delivery
rate requirements) additional energy deliveries. If we deliver energy at the
rate of 150MW/hour (the maximum permitted under ordinary circumstances), the
minimum energy deliveries will only require us to deliver during 77% of the
on-peak hours during the summer months and 56% of the on-peak hours of the other
months. Although we are not required to schedule any additional energy
deliveries under the Amended and Restated PPA, in order for us to have
sufficient funds to pay principal and interest on the bonds, we must deliver the
full amount of the annual energy deliveries each year. In addition to the
minimum energy deliveries, under the Amended and Restated PPA we are required to
make available to PSE&G the reserved capacity so as to enable PSE&G's account
with PJM to reflect this reserved capacity. We are allowed to provide PSE&G with
reserved capacity and energy deliveries from any source of supply connected to
the PJM market, including, but not limited to, the Newark Bay Facility.
The Amended and Restated PPA requires PSE&G to pay us each month a combined
payment for the capacity and energy provided by us. The amount of the payment is
based, in part, on the amount of energy we actually deliver. The monthly
payments are deposited by PSE&G directly into a collections account established
by the trustee under the indenture under which the Series A bonds were issued
and the Series B bonds will be issued. Amounts in the collections account must
be used in the order of priority specified under "Description of the
Bonds -- Withdrawals from the Collections Account." Payments of interest and
principal on the bonds will be made solely from amounts in the collections
account (and in some limited circumstances, from funds in the liquidity account;
see "Description of the Bonds -- The Accounts"). The amount payable to us by
PSE&G in any month will be reduced by a credit to PSE&G if we fail to deliver
all or part of the energy scheduled for delivery or we fail to schedule and
deliver the minimum energy deliveries. The amount payable by PSE&G in any month
will also be reduced by a credit to PSE&G if we do not deliver energy at the
Newark Bay Facility or at other certain specified locations or if we fail to
provide all or part of the reserved capacity to PSE&G. Any such failure would
reduce the funds available to make payments on the bonds during the relevant
period in the event that EPM and El Paso Energy fail to perform their
obligations under the Power Services Agreement or the El Paso Energy Performance
Guaranty, respectively. See "Summary of Certain Transaction Documents -- Power
Services Agreement" and "Summary of Certain Transaction Documents -- El Paso
Energy Performance Guaranty."
POWER SERVICES AGREEMENT
In order to meet our obligations to provide reserved capacity and to
deliver energy under the Amended and Restated PPA, we have entered into the
Power Services Agreement with EPM, which became effective on September 26, 2000.
Under the Power Services Agreement, EPM must make available to us capacity
credits equal to the reserved capacity and must schedule and deliver the full
amount of the annual energy deliveries during each year. As is the case with us
under the Amended and Restated PPA, EPM may deliver energy to us at any point
within the PJM market.
In consideration for the reservation of capacity and delivery of energy by
EPM, we must make combined monthly energy and capacity payments to EPM. Our
monthly payments to EPM under the Power Services Agreement will be reduced by a
credit to us in the event that EPM fails to schedule and deliver the minimum
energy deliveries or to deliver energy as scheduled, EPM does not deliver energy
at the Newark Bay Facility or at other certain specified locations or if EPM
fails to provide all or part of the
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reserved capacity to us. These credits will be calculated in the same manner and
applied in the same months in which the corresponding credits are applied to
PSE&G under the Amended and Restated PPA. If at the end of any month, the amount
of the credits due to us is greater than the total amount that we owe to EPM for
that month, EPM will be obligated to pay us in cash these excess amounts.
If EPM does not schedule and deliver the annual energy deliveries to us in
any year, EPM will be required to pay to us by February 10th of the following
year the shortfall payments. In addition to the shortfall payments, EPM will
also be required to pay into a damages and indemnity account certain other
damages and indemnity payments and distribution surcharges that we may be liable
for under the Amended and Restated PPA. We or EPM have the right to terminate
the Power Services Agreement upon 10 days written notice if we do not pay
amounts that we owe to EPM within 30 days of EPM's notice to us that our payment
is overdue. We or EPM may also terminate the Power Services Agreement upon 10
days written notice if the Amended & Restated PPA terminates as the result of a
bankruptcy or other default of PSE&G. The other provisions of the Amended and
Restated PPA and the Power Services Agreement, including the terms during which
they are effective, are substantially similar to each other. See "Summary of
Certain Transaction Documents -- Power Services Agreement." For more information
about the provisions of the Amended and Restated PPA and the Power Services
Agreement, see "Summary of Certain Transaction Documents" below.
EPM expects to reserve capacity and procure energy to be delivered on our
behalf under the Power Services Agreement from energy procured from the PJM
market. For more information about the PJM market, see "Independent Energy
Consultant" and Annex A.
ADMINISTRATIVE SERVICES AGREEMENT
We have also entered into an Administrative Services Agreement with EPM
pursuant to which EPM has agreed:
- to perform all of our administrative and management obligations under the
Amended and Restated PPA, exercise all of our rights under the Power
Services Agreement and coordinate our operations under both agreements;
- to perform all of our administrative and managerial functions under our
material agreements, the indenture and the related financing documents;
and
- to notify EPM and El Paso Energy of their payment obligations under the
Power Services Agreement and the El Paso Energy Performance Guaranty,
respectively.
For more detailed information about the Administrative Services Agreement, see
"Summary of Certain Transaction Documents -- Administrative Services Agreement."
EL PASO ENERGY PERFORMANCE GUARANTY
El Paso Energy has entered into a performance guaranty pursuant to which El
Paso Energy has agreed to unconditionally guarantee all obligations (including
payment obligations) of EPM under the Power Services Agreement and the
Administrative Services Agreement.
For more detailed information about the El Paso Energy Performance Guaranty, see
"Summary of Certain Transaction Documents -- El Paso Energy Performance
Guaranty."
ACCOUNTS
Payments by PSE&G under the Amended and Restated PPA, shortfall payments
and excess amounts paid by EPM pursuant to the Power Services Agreement or by El
Paso Energy pursuant to the El Paso Energy Performance Guaranty and transfer
payments from the liquidity account must be deposited directly into the
collections account. A portion of the proceeds of the offering of the Series A
bonds was deposited into the collections account. The trustee must disburse
funds from the collections account to pay our
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expenses (including capacity and energy payments to EPM and principal and
interest on the bonds) in a specific order of priority. See "Description of the
Bonds -- Withdrawals from the Collections Account."
In order to offset any timing difference between our cash flows from the
additional energy deliveries, which we may receive on an irregular basis
throughout the year, and our interest payments on the bonds, which we must make
semi-annually, we have provided for the setting up and funding of the liquidity
account with the trustee in an amount equal to the liquidity reserve required
balance. Amounts on deposit in the liquidity account may also be used to pay
principal if we do not have sufficient funds in the collections account to pay
these amounts. Under certain circumstances, El Paso Energy may substitute
acceptable credit support for amounts deposited in the liquidity account. See
"Description of the Bonds -- The Accounts."
Under certain circumstances, EPM may be required to pay us certain amounts
for damages or indemnity payments that we will have to make to PSE&G. Those
amounts will be paid into, and the corresponding payment to PSE&G will be
disbursed from, the damages and indemnity account. See "Description of the
Bonds -- The Accounts."
SECURITY OWNERSHIP OF CERTAIN OWNERS
CEDAR BRAKES I, L.L.C.
The following table sets forth information concerning our owners.
<TABLE>
<CAPTION>
PERCENT OF
NATURE OF PERCENT OF TOTAL VOTING
NAME AND ADDRESS OWNERSHIP INTEREST OWNERSHIP POWER
---------------- ------------------ ---------- ------------
<S> <C> <C> <C>
Mesquite Investors, L.L.C. ................... Member 100 100
c/o El Paso Energy Corporation
1001 Louisiana Street
Houston, Texas 77002
</TABLE>
MESQUITE
Mesquite is an indirect wholly owned subsidiary of El Paso Energy and
Limestone.
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SUMMARY OF CERTAIN TRANSACTION DOCUMENTS
The following is a summary of selected provisions of certain principal
documents related to our transaction and should not be considered to be a full
statement of the terms and provisions of those agreements. Accordingly, the
following summaries are qualified by reference to each agreement and are subject
to the terms of the full text of each agreement. Unless otherwise stated, any
reference in this prospectus to any agreement will mean the agreement described
and all schedules, exhibits and attachments thereto as amended, restated,
supplemented or otherwise modified (including by any consent and agreement
required in connection with the financing contemplated in this prospectus) and
to be in effect as of the date of this prospectus. We encourage you to read
these agreements, copies of which will be available for inspection at our
principal executive offices or upon written request of any potential investor.
AMENDED AND RESTATED PPA
We entered into the Amended and Restated PPA with PSE&G on March 21, 2000.
The Amended and Restated PPA amends and restates a power purchase agreement
between NBCP and PSE&G, and provides that we must sell capacity and energy to
PSE&G.
TERM
The Amended and Restated PPA became effective on September 26, 2000 and
remains in effect through and including August 31, 2013 unless terminated
earlier as provided in the Amended and Restated PPA.
PURCHASE AND SALE OF CAPACITY AND ENERGY
General Condition of Delivery and Acceptance of Energy and Capacity
We may provide energy and capacity to PSE&G at our option from any source
of supply, including the Newark Bay Facility or other sources.
Qualifying Facility Status
Our obligations and PSE&G's obligations under the Amended and Restated PPA
to buy and sell capacity and energy is not conditioned in the Amended and
Restated PPA upon our maintenance of qualifying facility status of the Newark
Bay Facility or any other facility under PURPA.
Sale of Capacity and Energy
We are required to arrange for capacity credits to be made available to
PSE&G so that PSE&G will be credited by PJM with at least 123 MW of capacity per
day. We must take all necessary steps for PSE&G's account with PJM to reflect
these 123 MW of capacity credits per day, including utilizing PJM's "eCapacity"
mechanism, throughout the term of the Amended and Restated PPA. If we are
required to provide a different quantity of capacity credits to PSE&G because of
a change in the measurement methodology used by PJM, the new minimum quantity of
capacity credits will be based on the operation of the Newark Bay Facility
during the 12 months period from September 1, 1998 to August 31, 1999 or a
shorter period ending August 31, 1999. If PSE&G's agreement with the PJM market
no longer requires PSE&G to obtain capacity credits, we must provide the
capacity to PSE&G in an amount equal to the amount specified in the measurement
methodology in effect immediately before the cancellation of this requirement.
We will sell and deliver energy to PSE&G at any point on the PJM system,
and PSE&G must purchase this energy. The annual energy deliveries cannot exceed
788,954 MWh for the years 2000 through 2002, 811,229 MWh for year 2003, 855,779
MWh for years 2004 through 2012 and 570,519 MWh for year 2013. The number of MWh
that we may schedule in the initial year of the agreement must be
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reduced by a pro rata amount if the Amended and Restated PPA is not in effect
for the entire calendar year of the initial year.
Purchase Price and Payment Conditions
We will receive the payment for energy and capacity based on its delivery
of energy at the contract rate of $70.74/MWh in 2000. The contract rate will
increase on an annual basis as follows:
<TABLE>
<CAPTION>
CONTRACT
YEAR RATE ($)
---- --------
<S> <C>
2001....................................................... 72.17
2002....................................................... 73.53
2003....................................................... 74.64
2004....................................................... 75.44
2005....................................................... 76.96
2006....................................................... 78.74
2007....................................................... 80.34
2008....................................................... 82.13
2009....................................................... 83.88
2010....................................................... 85.76
2011....................................................... 87.67
2012....................................................... 89.63
2013....................................................... 92.43
</TABLE>
DELIVERY OF CAPACITY AND ENERGY
By no later than 3 business days prior to each calendar month, we must
provide PSE&G with a non-binding schedule of proposed energy deliveries for each
hour of the upcoming month. Subsequently, on the business day preceding the day
of delivery of the energy, we must provide PSE&G with a final schedule for
deliveries of energy by no later than one hour prior to the time that PJM
requires submission of final schedules. The amounts set forth in the daily
schedules may vary from each other and may vary from the amounts set forth in
the monthly schedule. If we fail to provide a daily or monthly schedule to
PSE&G, the amount of energy scheduled for delivery will be deemed to be the
amount that we set in the most recent monthly schedule that we delivered to
PSE&G.
We may deliver energy at a rate of up to 150 MWh per hour unless we are
also scheduling "make-up energy" (described below), in which case, we can
deliver up to 200 MWh per hour. We must schedule and deliver energy at the same
rate during all on-peak hours in any day and at the same rate during all
off-peak hours in any day. However, the delivery rate for on-peak hours in a
given day may differ from the delivery rate for off-peak hours in the same day
and the delivery rate for on-peak hours can vary from day to day.
Minimum On-Peak Deliveries
During the months of June, July, August and September, we must deliver to
PSE&G at least 40,000 MWh per month during the on-peak hours, which requirement
we refer to in this prospectus as the summer delivery requirement. For all other
months of the year, we must deliver an aggregate of 234,000 MWh during the
on-peak hours, which requirement we refer to in this prospectus as the yearly
delivery requirement. The summer delivery requirement and the yearly delivery
requirement, together, are called the minimum energy deliveries.
Make-up Energy Deliveries
If a force majeure event or a system emergency prevents us from delivering,
or prevents PSE&G from accepting, the scheduled amount of energy, we have the
right to reschedule deliveries of make-up quantities during comparable periods
during the remainder of the month in which the inability occurred. If
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we are unable to reschedule deliveries of make-up energy due to a force majeure
event or a system emergency, we have the right to reschedule the delivery of
make-up energy during comparable periods in the next month. If we (1) fail to
deliver scheduled quantities of energy or (2) fail to reschedule and deliver in
the immediately following month any make-up quantities, PSE&G may permit us to
reschedule any such quantities of energy in any subsequent month.
Our Failure to Deliver Energy and Capacity
If we fail, for reasons other than a force majeure event or a system
emergency, to deliver all or part of the scheduled energy, PSE&G may permit us
to reschedule delivery of the energy. In the event we fail to deliver all or
part of the scheduled energy or fail to schedule sufficient deliveries to meet
the minimum energy deliveries, the payment to us with respect to the
corresponding billing period shall be reduced by a credit against the amount
payable by PSE&G for the next succeeding month. If the credit amount is greater
than the amount payable by PSE&G for a single month, the excess portion of the
credit will be applied to reduce the amount otherwise payable by PSE&G for
subsequent months. PSE&G's credit will be calculated as follows:
- if we fail to deliver any scheduled quantities of energy, the credit will
be determined by multiplying the shortfall by the excess, if any, in the
rate that PSE&G had to pay to third parties to procure energy to replace
the energy that we failed to deliver over the rates payable to us under
the Amended and Restated PPA;
- if we fail to schedule the summer delivery requirement for any month, the
credit will be determined by multiplying the shortfall by the excess, if
any, of the average on-peak locational marginal prices at the Newark Bay
Facility for those on-peak hours in which we failed to schedule at least
120 MW for delivery, over the rates payable to us under the Amended and
Restated PPA; or
- if we fail to schedule the yearly delivery requirement, the credit will
be determined by multiplying the shortfall by the excess, if any, of the
average on-peak locational marginal prices at the Newark Bay Facility for
those on-peak hours during the non-summer months in which we failed to
schedule at least 90 MW for delivery over the rate payable to us under
the Amended and Restated PPA.
If we fail for reasons other than a force majeure or a system emergency,
during any month, to provide all or part of the capacity required to be provided
to PSE&G, PSE&G must use reasonable commercial efforts to purchase replacement
capacity in the amount of the shortfall. We must reimburse PSE&G for all costs
associated with the replacement. If PSE&G is unable to replace this capacity
shortfall, then the payments owed by PSE&G for that month will be reduced by a
credit against the amount payable by PSE&G for the next succeeding month in an
amount equal to the deficiency charge, if any, or other charges, as applicable,
payable by PSE&G as a direct result of our failure to provide this capacity.
These credits are the only damages that PSE&G can claim as a result of any
failure by us to deliver energy or provide capacity as required by the Amended
and Restated PPA. (However, the Amended and Restated PPA does not limit PSE&G's
remedies to liquidated damages if there is an Event of Default by us.)
Damages for Failure to Accept Delivery of Energy
If PSE&G fails to accept deliveries of energy scheduled by us for reasons
other than a force majeure event or a system emergency, PSE&G must pay us an
amount equal to the positive difference between the amount payable by PSE&G to
us under the Amended and Restated PPA for the scheduled energy which PSE&G
failed to accept and the amount that we, using commercially reasonable efforts
under the circumstances, realize through remarketing that energy to persons
other than PSE&G.
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Transmission
We are responsible for arranging transmission of all energy and capacity to
PSE&G and paying for all related transmission charges and congestion costs to
any delivery point. We may choose any delivery point on the PJM system, but if
we deliver energy and capacity to a delivery point other than the Newark Bay
Facility or certain alternate specified delivery points, the delivery price for
the energy must be reduced by an amount equal to the positive difference between
the locational marginal price at the Newark Bay Facility interconnection point
or such other specified location and the locational marginal price at the actual
delivery point.
System Emergency Exception
PSE&G is excused from accepting all or a portion of our energy and capacity
in the event of a system emergency if accepting our energy and capacity would
contribute to the system emergency. A "system emergency" is defined as the
existence of a physical or operational condition and/or the occurrence of an
event on PSE&G's system (or the PJM system) which in PSE&G's judgment is
imminently likely to endanger life or property, or impairs and/or imminently
will impair PSE&G's ability to discharge its statutory obligation to provide
safe, adequate and proper service to its customers and/or the safety and/or
reliability of PSE&G's system (or PJM's system).
FORCE MAJEURE
An event of force majeure is an event beyond the reasonable control of the
party claiming force majeure. These events include, without limitation, acts of
God; strikes, lockouts or other similar industrial disturbances; acts of the
public enemy, wars, civil disturbances, blockades, military actions,
insurrections or riots; landslides, floods, washouts, lightning, earthquakes,
tornadoes, hurricanes, blizzards or other storms or storm warnings; explosions,
fires, sabotage or vandalism; mandates, directives, orders or restraints of any
governmental, regulatory or judicial body or agency (other than mandates,
directives, orders or restraints either sought, approved or not contested by the
party asserting force majeure or issued in any bankruptcy or insolvency
proceeding for the relief of the party asserting force majeure); any
catastrophic physical failures or disruptions of the PJM transmission system;
breakage, defects, malfunctioning, or accident to machinery, equipment,
materials or lines of pipe or wires; freezing of machinery, equipment, materials
or lines of pipe or wires; inability or delay in the obtaining of materials or
equipment; inability to obtain or utilize any permit, approval, easement,
license or right-of-way.
Force majeure events do not include failures of the equipment of the party
claiming force majeure which are due to wear and tear or defects in manufacture,
design or construction; any increase in the cost of electricity supplies or
costs associated with transmission system operation, maintenance or congestion;
unavailability of capacity and/or energy from any source, regardless of price,
for delivery to a delivery point (except in the event of a system emergency);
interruption in service by a transmission provider unless the party contracting
with the transmission provider shall have made arrangements with the
transmission provider for the firm transmission, as defined under the
transmission provider's tariff, of the energy to be delivered hereunder, and the
interruption is due to an emergency or to an event of force majeure as defined
under the transmission provider's tariff; and any change in economic conditions
not caused by a force majeure event.
If either party is rendered unable, wholly or in part, by an event of force
majeure, to perform any obligation it has under the Amended and Restated PPA,
that party's obligations will be suspended to the extent those obligations are
affected by the event of force majeure for the duration of the event of force
majeure. Neither party is relieved from any obligation to make any payment to
the other during an event of force majeure. The affected party must use its best
efforts to remedy the cause of the force majeure with all reasonable dispatch.
Neither party will be liable to the other for any claim(s), loss(es),
damage(s), liability(ies) or expense(s) sustained or incurred, arising out of,
relating to, or resulting from our or PSE&G's inability or incapacity to perform
its obligations under the Amended and Restated PPA due to any event of force
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majeure. The requirement that any event of force majeure be remedied with all
reasonable dispatch will not require the settlement of strikes, lockouts or
other similar industrial disturbances when this course is, in the opinion of the
party directly affected, inadvisable.
LIABILITY
Neither PSE&G nor we (including each party's officers, directors, partners,
agents, servants, employees, affiliates, parent, subsidiaries or successors or
assigns) will be liable to the other for claims of incidental, special, direct,
indirect or consequential damages, whether the claim is based on warranty,
negligence, strict liability, contract, operation of law or otherwise, except
where the claim arises out of the gross negligence of a party or the willful
disregard by a party of its obligations under the Amended and Restated PPA.
However, PSE&G and we each have the right to seek to recover from the other
party direct damages upon the occurrence of an Event of Default under the
Amended and Restated PPA.
INDEMNIFICATION & WARRANTIES
We and PSE&G have each agreed to indemnify and hold harmless the other
(including officers, agents, servants and employees, successors and assigns)
from and against any and all claims, demands and suits, actions, and
liabilities, losses, damages, and/or judgments which may arise therefrom as well
as against any fees, costs, charges or expenses which PSE&G or we, our
respective officers, agents, servants and employees, successors and assigns,
incur in the defense of any such claims, suits, actions or similar such demands
made or filed by any third-party, which in any matter arise out of, relate to,
or result from negligence, or strict liability of, or breach of the Amended and
Restated PPA by, the other party.
We are obligated to supply to the delivery points energy and capacity free
and clear of any liens and/or adverse claims which might attach to this energy
and capacity prior to supply and receipt by PSE&G except with respect to any
lien possessed by a lender. We agree to indemnify and hold harmless PSE&G
against any and all claims, demands, suits, actions, costs, and liabilities,
damages, losses and/or judgments arising out of, relating to or resulting from
any such adverse claim or lien, as well as against any fees, costs, charges or
expenses which PSE&G might incur in the defense of any such claim, suit, action
or similar demand made or filed by the claimant, or its successors or assigns,
asserting the adverse claim.
DEFAULTS
Each of the following would constitute an "Event of Default" for us:
- We breach or fail to observe or perform, any of the material obligations,
covenants, conditions, services or responsibilities under the Amended and
Restated PPA, unless, within 30 days after written notice from PSE&G
specifying the nature of the breach or failure, we either cure the breach
or failure or, if the cure cannot be completed within 30 days, provide
PSE&G with a plan reasonably acceptable to PSE&G to cure the breach or
failure and commence and diligently pursue the plan.
- There is an assignment for the benefit of our creditors, or we are
adjudged a bankrupt, or a petition is filed by or against us under the
provisions of any state insolvency law or under the provisions of the
federal bankruptcy laws, or our business or principal assets are placed
in the hands of a receiver, assignee or trustee, or we are dissolved, or
our existence is terminated, or our business is discontinued. However,
these events will not constitute an Event of Default or otherwise affect
the validity of the Amended and Restated PPA, so long as the terms,
covenants and conditions of the Amended and Restated PPA on our part are
performed.
- We take any actions which prevent PSE&G from performing any of its
material obligations, covenants, conditions, responsibilities or services
under the Amended and Restated PPA, unless, within 30 days after written
notice from PSE&G specifying the nature of the action or failure to act,
we either cure the action or failure to act, or, if the cure cannot be
completed within 30 days,
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provide PSE&G with a plan reasonably acceptable to PSE&G to cure the
breach or failure and commence and diligently pursue the cure.
- We fail to deliver energy and capacity to PSE&G for 240 out of 365 days
for any reason other than force majeure or a system emergency and fail to
pay the liquidated damages associated with the failure when due or other
liquidated damages payments required to be paid under the Amended and
Restated PPA.
Each of the following would constitute an "Event of Default" for PSE&G:
- PSE&G breaches or fails to observe or perform any of the material
obligations, covenants, conditions, services or responsibilities under
the Amended and Restated PPA, unless, within 30 days after written notice
from us specifying the nature of the breach or failure, PSE&G either
cures the breach or failure, or, if the cure cannot be completed within
30 days, provides us with a plan reasonably acceptable to us to cure the
breach or failure and commences and diligently pursues the cure.
- PSE&G fails to accept deliveries of energy and capacity for any reason
other than a force majeure event or a system emergency, and the failure
continues for a period of 30 days following receipt of notice of the
failure and fails to pay the liquidated damages associated with the
failure as set forth in the Amended and Restated PPA.
- There is an assignment for the benefit of PSE&G's creditors, or PSE&G is
adjudged bankrupt, or a petition is filed by or against PSE&G under the
provisions of any state insolvency law or under the provisions of the
federal bankruptcy law, or the business or principal assets of PSE&G are
placed in the hands of a receiver, assignee or trustee, or PSE&G is
dissolved, or its existence is terminated, or its business is
discontinued. However, these events will not constitute an Event of
Default or otherwise affect the validity of the Amended and Restated PPA,
so long as the payment for energy and capacity delivered by us to PSE&G
as provided under the Amended and Restated PPA continues to be paid and
the other terms, covenants and conditions of the Amended and Restated PPA
on the part of PSE&G are performed.
- PSE&G takes any actions which prevent us from performing any of our
material obligations, covenants, conditions, responsibilities or services
under the Amended and Restated PPA, unless within 30 days after written
notice from us specifying the nature of the action or failure to act,
PSE&G either cures the action or failure to act, or, if such cure cannot
be completed within 30 days, provides us with a plan reasonably
acceptable to us to cure the breach or failure and commences and
diligently pursues the cure.
- PSE&G fails to pay, when due, the payment under the Amended and Restated
PPA, and the failure continues for a period of 30 days following the
receipt by PSE&G of notice of the failure; provided, however, PSE&G shall
not be considered in default if (1) it has paid the undisputed portion of
any payment due under the Amended and Restated PPA and (2) the parties
are in the process of resolving expeditiously any disputed portion in
accordance with the terms set forth in the Amended and Restated PPA.
REMEDIES
If either party claims that an Event of Default has occurred, that party
must provide the other party with a written notice of breach. The parties have
30 days from the date of notice to negotiate a resolution. If the parties are
unable to resolve the dispute by negotiation, each party has the right to submit
the dispute to arbitration or any regulatory body having jurisdiction.
Both parties have the obligation to act in a commercially reasonable manner
to mitigate damages as a result of any Event of Default. Neither party may
refuse to make, suspend or delay any payment otherwise required under the
Amended and Restated PPA or refuse to carry out any of its obligation under the
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Amended and Restated PPA on account of an alleged breach of the Amended and
Restated PPA or Event of Default.
ARBITRATION AND GOVERNING LAW
Any controversy, dispute or claim between PSE&G and us which is not
resolved by negotiation and over which no regulatory body has jurisdiction, or
for which the regulatory body with jurisdiction declines to initiate
proceedings, shall be settled by arbitration in accordance with the Commercial
Arbitration Rules of the American Arbitration Association. Any controversy,
dispute or claim submitted to arbitration shall be settled by arbitration in
Newark, New Jersey in accordance with the laws of the State of New Jersey.
ASSIGNMENT
We may assign our rights and obligations under the Amended and Restated PPA
to EPM or any entity controlling, controlled by or under common control with EPM
or which has a credit rating at least equal to Baa3 from Moody's or BBB -- from
Standard & Poor's or a similar rating from any other similar independent rating
agency. We may not assign our rights and obligations under the Amended and
Restated PPA in any other situation without the prior written consent of PSE&G,
which consent will not be unreasonably withheld.
PSE&G may, on notice to us, assign and transfer its rights and obligations
to any entity controlling, controlled by or under common control with PSE&G and
which has a credit rating by Moody's and Standard & Poor's at least equivalent
to that of PSE&G. PSE&G may not assign its rights and/or obligations under the
Amended and Restated PPA in any other situation, without our prior written
consent, which consent may not be unreasonably withheld.
POWER SERVICES AGREEMENT
We entered into the Power Services Agreement with EPM on September 20,
2000. Under the Power Services Agreement, EPM agrees to sell us capacity and
energy.
TERM
The term of the Power Services Agreement runs from September 26, 2000 until
August 31, 2013. We or EPM have the right to terminate the Power Services
Agreement upon 10 days written notice if any amount due to EPM is not paid
within 30 days after EPM has given us notice of the payment default; provided
that EPM will not have the right to terminate if the reason for the non-payment
results directly or indirectly from EPM's failure to perform under the Power
Services Agreement. We and EPM also have the right to terminate the Power
Services Agreement if we terminate the Amended and Restated PPA because of a
default by PSE&G.
PURCHASE AND SALE OF CAPACITY AND ENERGY
General Condition of Delivery and Acceptance of Energy and Capacity
EPM may provide energy and capacity to us at its option from any source of
supply in the PJM market, including, but not limited to, the Newark Bay
Facility.
Qualifying Facility Status
Our obligations and EPM's obligations under the Power Services Agreement to
buy and sell capacity and energy are not conditioned in the Power Services
Agreement upon EPM's maintenance of qualifying facility status of the Newark Bay
Facility or any other facility.
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Distribution Surcharges
EPM will pay to us the amount of any distribution surcharges claimed by
PSE&G pursuant to Article II(E) of the Amended and Restated PPA within 2 days of
receipt of written notice from us stating the amount of these distribution
surcharges.
Sale of Capacity and Energy
EPM must take all necessary steps for our account with PJM to reflect 123
MW of capacity credits per day, including utilizing PJM's "eCapacity" mechanism
throughout the term of the Power Services Agreement. If we require a different
quantity of capacity credits because of a change in the measurement methodology
used by PJM, EPM will be required to provide to us a new minimum quantity of
capacity credits which will be based on the operation of the Newark Bay Facility
during the 12 months period from September 1, 1998 to August 31, 1999 or any
shorter period ending as of August 31, 1999, as may be appropriate under the
circumstances. If the Amended and Restated PPA no longer requires us to obtain
capacity credits, EPM shall provide capacity to us in an amount equal to the
amount specified in the measurement methodology in effect immediately prior to
the cancellation of this requirement.
EPM must sell and deliver energy to us that is scheduled and delivered by
EPM at any delivery point selected by us, and we must purchase the energy at
that point. The amount of the annual energy deliveries which EPM must schedule
and deliver is 788,954 MWh for years 2000 through 2002, 811,229 MWh for year
2003, 855,779 MWh for years 2004 through 2012 and 570,519 MWh for year 2013. The
number of MWh that EPM may schedule in the initial year of the agreement must be
reduced on a pro rata basis if the Power Services Agreement is not in effect for
the entire calendar year.
EPM is obligated to perform all of our obligations under the Amended and
Restated PPA (including without limitation, our obligations to provide capacity
and energy) in accordance with the terms of the Amended and Restated PPA.
Purchase Price and Payment Conditions
EPM is entitled to be paid for energy and capacity based on its delivery of
energy at the contract rate of $23.03/MWh in 2000. The contract rate will change
on an annual basis as follows:
<TABLE>
<CAPTION>
CONTRACT
YEAR RATE($)
---- --------
<S> <C>
2001........................................................ 29.71
2002........................................................ 29.30
2003........................................................ 28.56
2004........................................................ 27.94
2005........................................................ 28.07
2006........................................................ 28.26
2007........................................................ 28.26
2008........................................................ 28.80
2009........................................................ 29.08
2010........................................................ 29.36
2011........................................................ 29.64
2012........................................................ 29.64
2013........................................................ 33.75
</TABLE>
DELIVERY OF CAPACITY AND ENERGY
By no later than 7 business days prior to each calendar month, EPM must
provide us with a non-binding schedule of proposed energy deliveries for each
hour of the upcoming month. Subsequently, on the business day preceding the day
of delivery of energy, EPM must provide us with a final schedule for deliveries
of energy by no later than 2 hours prior to the time that PJM requires
submission of final
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schedules. The volumes set forth in the daily schedules may vary from each other
and may vary from the volumes set forth in the monthly schedule. If EPM fails to
provide a daily or monthly schedule to us, the amount of energy scheduled for
delivery will be deemed to be the amount that was set forth in the most recent
monthly schedule delivered by EPM to us.
EPM may deliver energy at a rate of up to 150 MWh per hour, unless it is
also scheduling make-up energy (as provided below), in which case, up to 200 MWh
per hour may be scheduled for delivery to us. EPM must schedule and deliver
energy at the same delivery rate during all on-peak hours in any day and at the
same delivery rate during all off-peak hours in any day. However, the delivery
rate for on-peak hours in a given day may differ from the delivery rate for
off-peak hours in that day and, further, the delivery rate for on-peak hours can
vary from day to day.
We have designated EPM to be our agent in order to perform the scheduling
obligations under the Power Services Agreement. As our agent for these
scheduling obligations, EPM is authorized to act in its own name or in our name,
as EPM deems necessary or advisable.
Minimum On-Peak Deliveries
During the months of June, July, August and September, EPM must schedule
and deliver to us a minimum of 40,000 MWh per month during the on-peak hours.
For all other months of the year, EPM must schedule and deliver to us an
aggregate of 234,000 MWh during the on-peak hours.
Make-up Energy Deliveries
If EPM is unable to deliver energy or if we are unable to accept a
scheduled delivery of energy due to a force majeure event or a system emergency,
EPM must reschedule deliveries of make-up quantities of energy during comparable
periods during the remainder of the month in which the event or emergency
occurred and EPM must deliver the make-up energy as rescheduled. If EPM is
unable to deliver energy or we are unable to accept delivery as rescheduled, EPM
must reschedule deliveries of make-up quantities of such undelivered energy
during the remainder of the month in which such inability occurred. If EPM is
unable to reschedule such energy due to a force majeure event or a system
emergency, EPM shall be obligated to reschedule the make-up quantities during
comparable periods in the following month. To the extent EPM (1) fails to
deliver scheduled quantities of energy or (2) fails to deliver in the
immediately following month any such rescheduled make-up quantities, if we are
permitted under the Amended and Restated PPA to reschedule and deliver these
make-up quantities in any subsequent month, then EPM must reschedule and deliver
these make-up energy quantities in that subsequent month.
Seller's Failure to Schedule and Deliver Energy and Capacity
If EPM fails, for reasons other than a force majeure event or a system
emergency, to deliver all or part of the scheduled energy to the delivery point,
and PSE&G permits us to reschedule delivery of that energy, EPM must reschedule
the delivery of that energy at comparable times during subsequent months. If EPM
fails to deliver all or part of the energy scheduled for delivery, the payment
to EPM with respect to the corresponding billing period shall be reduced by a
credit against the amount payable by us. If the credit amount is greater than
the amount payable by us for a single month, EPM will pay us the excess portion
of the credit. That credit shall be calculated in the same manner as the credit
due to PSE&G under the Amended and Restated PPA and shall be applied under the
Power Services Agreement in the same months in which the credit is applied under
the Amended and Restated PPA.
If EPM fails, for reasons other than a force majeure event or a system
emergency, during any month to provide all or part of the capacity, and we must
consequently reimburse PSE&G for any costs it incurred in obtaining replacement
capacity, the payments owed by us for that month shall be reduced by a credit
against the amount payable by us for the next succeeding month in an amount
equal to the deficiency charge, if any, or other charges, as applicable, payable
by PSE&G as a direct result of our failure to provide such capacity under the
Amended and Restated PPA. If the credit amount is greater than the amount
payable by us for a single month, EPM will pay us the excess portion of the
credit.
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Shortfall Payments
If EPM does not deliver the annual energy deliveries in any year, EPM must
pay us an amount equal to (1) the difference between the annual energy
deliveries for the relevant year and the energy actually delivered by EPM during
that year multiplied by (2) the difference between the liquidated damages rate
for that calendar year and the contract rate, as set forth in the Power Services
Agreement, for that calendar year. The liquidated damages rate under the Power
Services Agreement for each year beginning with 2000 is set forth below. EPM
must pay these shortfall payments within five days after receipt of the invoice
from us. We must provide this invoice on or before the fifth day of February of
the succeeding calendar year.
<TABLE>
<CAPTION>
LIQUIDATED
YEAR DAMAGES RATE
---- ------------
<S> <C>
2000..................................................... $70.74
2001..................................................... 72.17
2002..................................................... 73.53
2003..................................................... 74.64
2004..................................................... 75.44
2005..................................................... 76.96
2006..................................................... 78.74
2007..................................................... 80.34
2008..................................................... 82.13
2009..................................................... 83.88
2010..................................................... 85.76
2011..................................................... 87.67
2012..................................................... 89.63
2013..................................................... 92.43
</TABLE>
Transmission
EPM is responsible for arranging transmission of all energy and capacity to
us and paying for all related transmission charges and congestion costs to the
delivery point. If EPM elects to deliver energy and capacity to a delivery point
other than the Newark Bay Facility or two alternate specified delivery points,
the delivery price for the energy must be reduced by a credit in an amount equal
to the positive difference between the locational marginal price at the Newark
Bay Facility interconnection point and the locational marginal price at the
actual point of delivery; provided that, if the amount of the credit is greater
than the amount payable by us for a single month, EPM will pay to us an amount
equal to this excess portion of the credit.
System Emergency Exception
We are excused from accepting all or a portion of EPM's energy and capacity
in the event of a system emergency if the purchases would contribute to the
system emergency. A system emergency is the existence of a physical or
operational condition and/or the occurrence of an event on PSE&G's system or the
PJM system which in PSE&G's judgment is imminently likely to endanger life or
property, or impairs and/or imminently will impair PSE&G's ability to discharge
its statutory obligation to provide safe, adequate and proper service to its
customers and/or the safety and/or reliability of PSE&G's system or PJM's
system.
FORCE MAJEURE
An event of "force majeure" is an event beyond the reasonable control of
the party claiming force majeure so long as the event is deemed to be a force
majeure event under the Amended and Restated PPA (whether or not the Amended and
Restated PPA is in full force and effect). These events include, without
limitation, acts of God; strikes, lockouts or other similar industrial
disturbances; acts of the public
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enemy, wars, civil disturbances, blockades, military actions, insurrections or
riots; landslides, floods, washouts, lightning, earthquakes, tornadoes,
hurricanes, blizzards or other storms or storm warnings; explosions, fires,
sabotage or vandalism; mandates, directives, orders or restraints of any
governmental, regulatory or judicial body or agency (other than mandates,
directives, orders or restraints either sought, approved or not contested by the
party asserting force majeure or issued in any bankruptcy or insolvency
proceeding for the relief of the party asserting force majeure); any
catastrophic physical failures or disruptions of the PJM transmission system;
breakage, defects, malfunctioning, or accident to machinery, equipment,
materials or lines of pipe or wires; freezing of machinery, equipment, materials
or lines of pipe or wires; inability or delay in the obtaining of materials or
equipment; inability to obtain or utilize any permit, approval, easement,
license or right-of-way; and events of force majeure as defined under and
declared by either party to the Amended and Restated PPA.
Force majeure events do not include failures of the equipment of the party
claiming force majeure which are due to wear and tear or defects in manufacture,
design or construction; any increase in the cost of electricity supplies or
costs associated with transmission system operation, maintenance or congestion;
unavailability of capacity and/or energy from any source, regardless of price,
for delivery to a delivery point (except in the event of a system emergency);
interruption in service by a transmission provider (unless the party claiming
force majeure has contracted with the transmission provider for firm
transmission of the energy, and the interruption is due to an emergency or to an
event of force majeure as defined under the transmission provider's tariff); and
any change in economic conditions not caused by a force majeure event.
If either EPM or we are rendered unable, wholly or in part, by an event of
force majeure, to perform any obligation either of us has under the Power
Services Agreement, when the party affected by the event of force gives notice
describing the event to the other party, the affected party's obligations will
be suspended during the continuance of the event of force majeure, but for no
longer period. These obligations will be suspended for no longer period than the
event of force majeure has suspended the parties' obligations under the Amended
and Restated PPA or in the event that the Amended and Restated PPA is no longer
in full force and effect, would have suspended the parties' obligations under
the Amended and Restated PPA. Neither party will be relieved of any obligation
to make any payment to the other required under the Power Services Agreement.
The affected party will use its best efforts to remedy the cause of the force
majeure with all reasonable dispatch. The obligations of EPM under the Power
Services Agreement to schedule and deliver the annual energy deliveries (other
than the minimum energy deliveries) will not be excused or suspended by an event
of force majeure.
Neither party will be liable to the other for any claims, losses, damages,
liabilities or expenses sustained or incurred, arising out of, relating to, or
resulting from EPM's or our inability or incapacity to perform its obligations
under the Power Services Agreement due to any event of force majeure. The
requirement that any event of force majeure will be remedied with all reasonable
dispatch will not require the settlement of strikes, lockouts or other similar
industrial disturbances when this course is, in the opinion of the party
directly affected, inadvisable.
LIABILITY
Neither of EPM nor we (including our respective officers, directors,
partners, agents, servants, employees, affiliates, parent, subsidiaries or
successors or assigns) will be liable to the other for claims of incidental,
special, direct, indirect or consequential damages, whether the claim is based
on warranty, negligence, strict liability, contract, operation of law or
otherwise, except where the claim arises out of the gross negligence of the
claimant or the willful disregard by the claimant of its obligations under the
Power Services Agreement. However, we have the right to seek to recover from EPM
direct damages upon the occurrence of an Event of Default under the Amended and
Restated PPA, and to seek indemnification payments required to be paid by us to
PSE&G under the Amended and Restated PPA. In the event of the termination of the
Amended and Restated PPA prior to the termination of the Power Services
Agreement, EPM will not be liable to us under the Power Services Agreement
unless EPM would have been liable under the Power Services Agreement if the
Amended and Restated PPA were in full force and effect.
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INDEMNIFICATION AND WARRANTIES
EPM has agreed to indemnify and hold harmless us and our officers, agents,
servants and employees, our successors and assigns from and against any and all
claims, demands and suits, actions, and liabilities, losses, damages, and/or
judgments which may arise therefrom as well as against any fees, costs, charges
or expenses which we, our officers, agents, servants and employees, our
successors and assigns, incur in the defense of any such claims, suits, actions
or similar demands made or filed by any third-party, which in any matter arise
out of, relate to, or result from negligence, strict liability or a breach of
the Power Services Agreement by EPM and against claims, suits, actions or
similar demands made or filed by PSE&G against us pursuant to the Amended and
Restated PPA.
EPM is obligated to supply to the delivery points energy and capacity free
and clear of any liens and/or adverse claims which might attach to the energy
and capacity prior to its supply and receipt by us except with respect to any
lien possessed by a lender to us. EPM agreed to indemnify us and hold us
harmless against any and all claims, demands, suits, actions, costs, and
liabilities, damages, losses and/or judgments arising out of, relating to or
resulting from any such adverse claim or lien, as well as against any fees,
costs, charges or expenses which we might incur in the defense of any such
claim, suit, action or similar demand made or filed by the claimant, or its
successors or assigns, asserting the adverse claim.
DEFAULTS
Each of the following constitutes an "Event of Default" by EPM:
- EPM breaches or fails to observe or perform, any of the material
obligations, covenants, conditions, services or responsibilities under
the Power Services Agreement, unless, within 25 days after written notice
from us specifying the nature of the breach or failure, EPM either cures
the breach or failure or, if the cure cannot be completed within 25 days,
provides us with a plan reasonably acceptable to us to cure the breach or
failure and commences and diligently pursues the plan.
- There is an assignment for the benefit of EPM's creditors, or EPM is
adjudged a bankrupt, or a petition is filed by or against EPM under the
provisions of any state insolvency law or under the provisions of the
federal bankruptcy laws, or EPM's business or principal assets are placed
in the hands of a receiver, assignee or trustee, or EPM is dissolved, or
EPM's existence is terminated, or EPM's business is discontinued.
However, these events will not constitute an Event of Default or
otherwise affect the validity of the Power Services Agreement, so long as
the terms, covenants and conditions of the Power Services Agreement on
EPM's part are performed.
- EPM takes any action which prevents us from performing any of our
material obligations, covenants, conditions, responsibilities or services
under the Power Services Agreement, unless, within 25 days after written
notice from us specifying the nature of the action or failure to act, EPM
either cures the action or failure to act, or, if the cure cannot be
completed within 30 days, provides us with a plan reasonably acceptable
to us to cure the breach or failure and commences and diligently pursues
the cure.
- EPM fails to deliver energy and capacity to us for 240 out of 365 days
for any reason other than force majeure or a system emergency and fails
to pay the liquidated damages associated with the failure when due or
other liquidated damages payments required to be paid under the Power
Services Agreement.
REMEDIES
If we claim that an Event of Default has occurred, we must provide EPM with
a written notice of breach. The parties have 25 days from the date of notice to
negotiate a resolution. If the parties are unable to resolve the dispute by
negotiation, each party will have the right to submit the dispute to arbitration
or any regulatory body having jurisdiction, such arbitration proceeding to be
joined with any arbitration proceeding initiated under the Amended and Restated
PPA with respect to substantially the same dispute or with respect to another
dispute involving substantially the same facts.
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We have the obligation to act in a commercially reasonable manner to
mitigate damages as a result of any Event of Default. Neither party shall refuse
to make, suspend or delay any payment otherwise required under the Power
Services Agreement or refuse to carry out any of its obligation under the Power
Services Agreement on account of an alleged breach of the Power Services
Agreement or Event of Default.
ARBITRATION AND GOVERNING LAW
Any controversy, dispute or claim between the parties to the Power Services
Agreement which is not resolved by negotiation and over which no regulatory body
has jurisdiction or, having jurisdiction, declines to initiate proceedings will
be settled by arbitration in accordance with the Commercial Arbitration Rules of
the American Arbitration Association. Any controversy, dispute or claim
submitted to arbitration will be settled by arbitration in Newark, New Jersey in
accordance with the laws of the State of New Jersey. We and EPM have agreed
that, in the event a dispute arises under the Power Services Agreement and
arbitration proceedings are initiated under the Power Services Agreement and
arbitration proceedings are initiated under Article XV of the Amended and
Restated PPA with respect to substantially the same dispute or with respect to
another dispute involving substantially the same facts, these disputes will be
resolved jointly in a single proceeding by the arbitration proceedings initiated
under Article XV of the Amended and Restated PPA.
ASSIGNMENT
We may assign our rights in the Power Services Agreement to any lender
(including a trustee on behalf of the holders) in connection with any financing
or other financial arrangement or to any person succeeding to all or
substantially all of our assets without EPM's consent. For any other reasons, we
may not assign our rights and obligations under the Power Services Agreement to
any person without EPM's prior written consent, which shall not be unreasonably
delayed or withheld so long as the assignee agrees to be bound by, subject to
and to comply with the terms and conditions of the Power Services Agreement. EPM
may not assign its rights and obligations under the Power Services Agreement
without our prior written consent.
ADMINISTRATIVE SERVICES AGREEMENT
We entered into the Administrative Services Agreement with EPM on September
20, 2000. Under the Administrative Services Agreement, EPM has agreed to perform
all administrative and managerial functions to be performed by us pursuant to
our material agreements, the indenture and the related financing documents.
TERM
The term of the Administrative Services Agreement commenced upon execution
and runs until the expiration or earlier termination of the Power Services
Agreement. Neither our nor EPM's rights and obligations under the Administrative
Services Agreement commence, however, until the effective date of the Amended
and Restated PPA. We have the right to terminate the Administrative Services
Agreement (i) at any time on 60 days written notice to EPM and the payment to
EPM of any amounts owed EPM under the Administrative Services Agreement or (ii)
upon EPM's bankruptcy, insolvency or liquidation.
SUPPORT OBLIGATIONS
Management and Administrative Services
EPM must perform the following management and administrative services:
accounting, auditing, financial reporting, budgeting and forecasting, tax, cash
management, review of significant operating and financial matters, contract
administrative services, invoicing, setting off amounts as permitted under the
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Power Services Agreement, computer and information services, and such other
management, administrative, and regulatory filing services as directed by us.
Specifically, EPM must provide the following services:
- maintaining our books and records in accordance with good business
practice, Internal Revenue Service regulations, applicable law and
generally accepted accounting principles and the retention and oversight
of independent auditors to review these books and records on an annual
basis;
- providing services regarding our cash, including (1) establishing bank
accounts and (2) investing funds in accordance with the financing
documents;
- providing accounting services related to the development and
implementation of our financial controls and systems and the
administering of the financing proceeds;
- exercising all of our rights and performing all of our administrative and
management obligations under the financing documents, including taking
all actions necessary to perfect and maintain the perfection and priority
of any security interests granted by us to any lender or creditor of ours
over any of our assets;
- administering the Amended and Restated PPA, the Power Services Agreement
and the other material agreements, and exercising all of our rights and
performing all of our obligations thereunder;
- to the extent that amounts are available from us, paying all of our fees,
debts and obligations;
- providing tax related services, including, without limitation, paying
from EPM's accounts directly to any third party payees, upon demand, any
taxes or other administrative fees and expenses due and payable by us;
- making and prosecuting, or causing to be made and prosecuted, such
filings and reports, keeping such records, and taking or causing to be
taken such other actions as may be necessary and lawful to maintain our
existence and good standing and to ensure our compliance with all
applicable laws, regulations, authorizations and orders of any government
agencies (including, without limitation, the Federal Energy Regulatory
Commission); and
- doing and performing such other acts as may be mutually agreed to by EPM
and us from time to time.
ASSIGNMENT
We may assign our rights in the Administrative Services Agreement to any
lender (including a trustee on behalf of the holders) in connection with any
financing or other financial arrangement or to any person succeeding to all or
substantially all of our assets without EPM's consent. For any other reasons, we
may not assign our rights and obligations under the Administrative Services
Agreement to any person without EPM's prior written consent, which shall not be
unreasonably delayed or withheld so long as the assignee agrees to be bound by,
subject to and to comply with the terms and conditions of the Administrative
Services Agreement. EPM may not assign its rights and obligations under the
Administrative Services Agreement without our prior written consent.
FEE
We will pay EPM $50,000 on February 15 and August 15 of each year under the
Administrative Services Agreement. This amount will cover all of EPM's internal
and overhead costs. We will reimburse EPM for all expenses other than internal
and overhead costs EPM incurs in performing its obligations under the
Administrative Services Agreement on February 15 and August 15 of each year
following EPM's delivery of an invoice not less than 30 days prior to each of
these dates. The fees and expenses to EPM under the Administrative Services
Agreement will be due and payable only to the extent that there are amounts on
deposit in the collections account after payment in accordance with the
indenture of all current and past due amounts ranking prior to the payment of
these fees and expenses.
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DEFAULTS
Each of the following constitutes an "Event of Default" with respect to
either EPM or us under the Administrative Services Agreement:
- failure to make, when due, any payment under the Administrative Services
Agreement if the failure is not remedied within 10 business days of
written notice of the failure by the non-defaulting party;
- any representation or warranty made by a party is false or misleading in
any material respect when made; or
- failure by a party to perform any material covenant set forth in the
Administrative Services Agreement.
Upon an Event of Default, the non-defaulting party has the right to
terminate the Administrative Services Agreement.
EL PASO ENERGY PERFORMANCE GUARANTY
We entered into the El Paso Energy Performance Guaranty with El Paso Energy
on September 20, 2000. Under the El Paso Energy Performance Guaranty, El Paso
Energy guarantees to us the punctual performance of all of EPM's obligations
under the Power Services Agreement and the Administrative Services Agreement.
TERM
The term of the El Paso Energy Performance Guaranty runs from the date of
execution until all of EPM's obligations under the Power Services Agreement and
the Administrative Services Agreement have been performed. The El Paso Energy
Performance Guaranty will remain in full force and effect or be reinstated if at
any time any payment by EPM in whole or in part is rescinded or must otherwise
be returned by us upon EPM's insolvency, bankruptcy or reorganization.
GUARANTY
El Paso Energy irrevocably and unconditionally guarantees to us the
punctual performance and payment of all of EPM's obligations under the Power
Services Agreement and the Administrative Services Agreement.
El Paso Energy will perform its guaranty in full irrespective of any claim,
set-off, or other right it may have at any time against us, EPM or any other
entity. The guaranty is a primary obligation of El Paso Energy and El Paso
Energy will perform its guaranty regardless of the validity or enforceability of
the Power Services Agreement or the Administrative Services Agreement, any
changes to the Power Services Agreement or the Administrative Services
Agreement, or any other circumstances constituting a legal or equitable
discharge or defense of a guarantor.
All payments that El Paso Energy is required to make under the El Paso
Energy Performance Guaranty are without any set-off, counterclaim or condition.
The guaranty is not affected by EPM's change of ownership, insolvency,
bankruptcy or any other change in EPM's legal status. If EPM's obligations are
stayed or performance is delayed upon insolvency, bankruptcy or reorganization,
El Paso Energy's guaranty will remain in full force and effect and will be
immediately due to the extent required absent the stay or delay.
WAIVERS
El Paso Energy irrevocably waives diligence, promptness, presentment,
demand for payment or performance, protest, and notice of any kind with respect
to all of its obligations. El Paso Energy also
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waives any legal or equitable defenses arising out of EPM's insolvency,
bankruptcy or similar legal disability.
COVENANTS
El Paso Energy will not exercise any right of subrogation or indemnity, or
similar right or remedy, against EPM or any of EPM's assets or property in
respect of any amount it paid under the El Paso Energy Performance Guaranty or
file a proof of claim in competition with us for any amount owed by EPM to El
Paso Energy on any account whatsoever in the event of insolvency or bankruptcy,
until all of EPM's obligations under the Administrative Services Agreement and
Power Services Agreement are performed. El Paso Energy covenants that the El
Paso Energy Performance Guaranty will not be discharged except by complete and
final payment and performance of EPM's obligations under the Power Services
Agreement and Administrative Services Agreement and by El Paso Energy under the
El Paso Energy Performance Guaranty.
DEFAULTS
Each of the following would constitute an "Event of Default" for El Paso
Energy:
- El Paso Energy's failure to make or perform, when due, any payment or
performance required to be made under the El Paso Energy Performance
Guaranty;
- any representation or warranty made by El Paso Energy proves to be false
or misleading in any material respect when made; and
- bankruptcy, insolvency or liquidation of El Paso Energy.
REMEDY
The rights and remedies set forth in the El Paso Energy Performance
Guaranty are in addition to and not exclusive of any rights and remedies
available to us. If any amount payable by El Paso Energy is not paid to us under
the El Paso Energy Performance Guaranty when due, we may without notice or
demand of any kind set-off and apply the unpaid amount against any amounts then
due and payable by us to El Paso Energy or EPM.
EXPENSES
El Paso Energy will reimburse us on demand for all reasonable costs and
expenses including attorney fees we incur in connection with the enforcement of
our rights under the El Paso Energy Performance Guaranty.
ASSIGNMENT
The El Paso Energy Performance Guaranty is binding on El Paso Energy and
its successors and assigns. El Paso Energy may not transfer any of its
obligations under the El Paso Energy Performance Guaranty without the prior
written consent by us.
We may transfer, pledge, encumber or assign the El Paso Energy Performance
Guaranty or the accounts, revenues or proceeds under the El Paso Energy
Performance Guaranty without El Paso Energy's consent in connection with any
financing and may transfer or assign the El Paso Energy Performance Guaranty to
any entity succeeding to all or substantially all of our assets.
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
EPM and El Paso Energy are affiliates of each other and an affiliate of
each of them manages us. All of the individuals who perform the day-to-day
financial, administrative, accounting and operational functions for us, as well
as those who are responsible for our direction, are currently employed by EPM.
Under the Administrative Services Agreement, EPM is paid a fee of $50,000
semi-annually. See "Summary of Certain Transaction Documents -- Administrative
Services Agreement." Pursuant to the Power Services Agreement, EPM provides
reserved capacity and delivers energy on the terms and at the rates set forth in
that agreement. See "Summary of Certain Transaction Documents -- Power Services
Agreement."
THE EXCHANGE OFFER
EXCHANGE TERMS
$310,600,000 principal amount of Series A bonds are currently issued and
outstanding. The maximum principal amount of Series B bonds that will be issued
in exchange for Series A bonds is $310,600,000. The terms of the Series B bonds
and the Series A bonds are substantially the same in all material respects,
except that the Series B bonds will be freely transferable by the holders except
as provided in this prospectus.
The Series B bonds will bear interest at a rate of 8 1/2% per year, payable
semi-annually on February 15 and August 15 of each year, beginning on February
15, 2001. Holders of Series B bonds will receive interest from the date of the
original issuance of the Series A bonds or from the date of the last payment of
interest on the Series A bonds, whichever is later. Holders of Series B bonds
will not receive any interest on Series A bonds tendered and accepted for
exchange. In order to exchange your Series A bonds for transferable Series B
bonds in the exchange offer, you will be required to make the following
representations:
- any Series B bonds will be acquired in the ordinary course of your
business;
- you have no arrangement with any person to participate in the
distribution of the Series B bonds; and
- you are not our "affiliate," as defined in Rule 405 of the Securities
Act, or, if you are our affiliate, you will comply with the applicable
registration and prospectus delivery requirements of the Securities Act.
Upon the terms and subject to the conditions set forth in this prospectus
and in the letter of transmittal, we will accept for exchange any Series A bonds
properly tendered in the exchange offer, and the exchange agent will deliver the
Series B bonds promptly after the expiration date (as defined below) of the
exchange offer. We expressly reserve the right to delay acceptance of any of the
tendered Series A bonds or terminate the exchange offer and not accept for
exchange any tendered Series A bonds not already accepted if any conditions set
forth under "Conditions of the Exchange Offer" beginning on page 63 have not
been satisfied or waived by us or do not comply, in whole or in part, with any
applicable law.
If you tender your Series A bonds, 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 the Series A bonds
in connection with the exchange offer. We will pay all charges, expenses and
transfer taxes in connection with the exchange offer, other than certain taxes
described below under "Transfer Taxes."
WE MAKE NO RECOMMENDATION TO YOU AS TO WHETHER YOU SHOULD TENDER OR REFRAIN
FROM TENDERING ALL OR ANY PORTION OF YOUR EXISTING SERIES A BONDS INTO THIS
EXCHANGE OFFER. IN ADDITION, NO ONE HAS BEEN AUTHORIZED TO MAKE THIS
RECOMMENDATION. YOU MUST MAKE YOUR OWN DECISION WHETHER TO TENDER INTO THIS
EXCHANGE OFFER AND, IF SO, THE AGGREGATE AMOUNT OF SERIES A 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.
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EXPIRATION DATE; EXTENSIONS; TERMINATION; AMENDMENTS
The term "expiration date" means 5:00 p.m., New York City time, on
[ ], 2000, 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 to extend the exchange offer on a
daily basis or for such period or periods as we may determine in our sole
discretion from time to time by giving oral, confirmed in writing, or written
notice to the exchange agent and by making a public announcement by press
release to the Dow Jones News Service prior to 9:00 a.m., New York City time, on
the first business day following the previously scheduled expiration date.
During any extension of the exchange offer, all Series A bonds previously
tendered, not validly withdrawn and not accepted for exchange will remain
subject to the exchange offer and may be accepted for exchange by us.
We expressly reserve the right, so long as applicable law allows:
- to waive any condition to the exchange offer; and
- to amend any of the terms of the exchange offer.
Any waiver or amendment to the exchange offer will apply to all Series A
bonds tendered, regardless of when or in what order the Series A bonds were
tendered. If we make a material change in the terms of the exchange offer or if
we waive a material condition of the exchange offer, we will disseminate
additional exchange offer materials, and we will extend the exchange offer to
the extent required by law.
We expressly reserve the right to terminate the exchange offer if any of
the conditions set forth under "Conditions of the Exchange Offer" beginning on
page 63 exist. Any such termination will be followed promptly by a public
announcement. In the event we terminate the exchange offer, we will give
immediate notice to the exchange agent, and all Series A bonds previously
tendered and not accepted for payment will be returned promptly to the tendering
holders.
In the event that the exchange offer is withdrawn or otherwise not
completed, Series B bonds will not be given to holders of Series A bonds who
have validly tendered their Series A bonds.
RESALE OF SERIES B BONDS
Based on interpretations of the SEC staff set forth in no action letters
issued to third parties, we believe that Series B bonds issued under the
exchange offer in exchange for Series A 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, if:
- you are not our "affiliate" within the meaning of Rule 405 under the
Securities Act;
- you are not a broker-dealer who purchased Series A bonds directly from us
for resale pursuant to Rule 144A or any other available exception under
the Securities Act;
- you are acquiring Series B bonds in the ordinary course of your business;
and
- you do not intend to participate in the distribution of the Series B
bonds.
If you tender Series A bonds in the exchange offer with the intention of
participating in any manner in a distribution of the Series B bonds:
- you cannot rely on those interpretations by the SEC staff, and
- you must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a secondary resale
transaction and that such a secondary resale transaction must be covered
by an effective registration statement containing the selling security
holder information required by Item 507 or 508, as applicable, of
Regulation S-K.
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Only broker-dealers that acquired the Series A bonds as a result of
market-making activities or other trading activities may participate in the
exchange offer. Each broker-dealer that receives Series B bonds for its own
account in exchange for Series A bonds, where such Series A bonds were acquired
by such broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of the Series B bonds. Please read the section captioned "Plan
of Distribution" beginning on page 90 for more details regarding the transfer of
Series B bonds.
ACCEPTANCE OF SERIES A BONDS FOR EXCHANGE
We will accept for exchange Series A bonds validly tendered pursuant to the
exchange offer, or defectively tendered, if such defect has been waived by us,
after the later of: (1) the expiration date of the exchange offer and (2) the
satisfaction or waiver of the conditions specified below under "Conditions of
the Exchange Offer." We will not accept Series A bonds for exchange subsequent
to the expiration date of the exchange offer. Tenders of Series A bonds will be
accepted only in minimum denominations equal to $100,000 or integral multiples
of $1,000 in excess thereof.
We expressly reserve the right, in our sole discretion, to:
- delay acceptance for exchange of Series A bonds tendered under the
exchange offer, subject to Rule 14e-1 under the Exchange Act, which
requires that an offeror pay the consideration offered or return the
securities deposited by or on behalf of the holders promptly after the
termination or withdrawal of a tender offer, or
- terminate the exchange offer and not accept for exchange any Series A
bonds not theretofore accepted for exchange, if any of the conditions set
forth below under "Conditions of the Exchange Offer" have not been
satisfied or waived by us or in order to comply in whole or in part with
any applicable law. In all cases, Series B bonds will be issued only
after timely receipt by the exchange agent of certificates representing
Series A bonds, or confirmation of book-entry transfer, a properly
completed and duly executed letter of transmittal, or a manually signed
facsimile thereof, and any other required documents. For purposes of the
exchange offer, we will be deemed to have accepted for exchange validly
tendered Series A bonds, or defectively tendered Series A bonds with
respect to which we have waived such defect, if, as and when we give
oral, confirmed in writing, or written notice to the exchange agent.
Promptly after the expiration date, we will deposit the Series B bonds
with the exchange agent, who will act as agent for the tendering holders
for the purpose of receiving the Series B bonds and transmitting them to
the holders. The exchange agent will deliver the Series B bonds to
holders of Series A bonds accepted for exchange after the exchange agent
receives the Series B bonds.
If, for any reason, we delay acceptance for exchange of validly tendered
Series A bonds or we are unable to accept for exchange validly tendered Series A
bonds, then the exchange agent may, nevertheless, on our behalf, retain tendered
Series A bonds, without prejudice to our rights described under "Expiration
Date; Extensions; Termination; Amendments" beginning on page 58, "Conditions of
the Exchange Offer" beginning on page 63 and "Withdrawal of Tenders" beginning
on page 63, subject to Rule 14e-1 under the Exchange Act, which requires that an
offeror pay the consideration offered or return the securities deposited by or
on behalf of the holders thereof promptly after the termination or withdrawal of
a tender offer.
If any tendered Series A bonds are not accepted for exchange for any
reason, or if certificates are submitted evidencing more Series A bonds than
those that are tendered, certificates evidencing Series A bonds that are not
exchanged will be returned, without expense, to the tendering holder, or, in the
case of Series A bonds tendered by book-entry transfer into the exchange agent's
account at a book-entry transfer facility under the procedure set forth under
"Procedures for Tendering Series A Bonds -- Book-Entry Transfer" beginning on
page 60, such Series A bonds will be credited to the account maintained at such
book-entry transfer facility from which such Series A bonds were delivered,
unless otherwise requested by
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such holder under "Special Delivery Instructions" in the letter of transmittal,
promptly following the exchange date or the termination of the exchange offer.
Tendering holders of Series A bonds exchanged in the exchange offer will
not be obligated to pay brokerage commissions or transfer taxes with respect to
the exchange of their Series A bonds other than as described in "Transfer Taxes"
beginning on page 64 or in Instruction 7 to the letter of transmittal. We will
pay all other charges and expenses in connection with the exchange offer.
PROCEDURES FOR TENDERING SERIES A BONDS
Any beneficial owner whose Series A bonds are registered in the name of a
broker, dealer, commercial bank, trust company or other nominee or held through
a book-entry transfer facility and who wishes to tender Series A bonds should
contact such registered holder promptly and instruct such registered holder to
tender Series A bonds on such beneficial owner's behalf.
Tender of Series A Bonds Held Through DTC.
The exchange agent and DTC have confirmed that the exchange offer is
eligible for the DTC automated tender offer program. Accordingly, DTC
participants may electronically transmit their acceptance of the exchange offer
by causing DTC to transfer Series A bonds to the exchange agent in accordance
with DTC's automated tender offer program procedures for transfer. DTC will then
send an agent's message to the exchange agent.
The term "agent's message" means a message transmitted by DTC, received by
the exchange agent and forming part of the book-entry confirmation, which states
that DTC has received an express acknowledgment from the participant in DTC
tendering Series A bonds that are the subject of that book-entry confirmation
that the participant has received and agrees to be bound by the terms of the
letter of transmittal, and that we may enforce such agreement against such
participant. In the case of an agent's message relating to guaranteed delivery,
the term means a message transmitted by DTC and received by the exchange agent
which states that DTC has received an express acknowledgment from the
participant in DTC tendering Series A bonds that they have received and agree to
be bound by the notice of guaranteed delivery.
Tender of Series A Bonds Held in Certificated Form.
For a holder to validly tender Series A bonds held in certificated form:
- the exchange agent must receive at its address set forth in this
prospectus a properly completed and validly executed letter of
transmittal, or a manually signed facsimile thereof, together with any
signature guarantees and any other documents required by the instructions
to the letter of transmittal, and
- the exchange agent must receive certificates for tendered Series A bonds
at such address, or such Series A bonds must be transferred pursuant to
the procedures for book-entry transfer described above. A confirmation of
such book-entry transfer must be received by the exchange agent prior to
the expiration date of the exchange offer. A holder who desires to tender
Series A bonds and who cannot comply with the procedures set forth herein
for tender on a timely basis or whose Series A bonds are not immediately
available must comply with the procedures for guaranteed delivery set
forth below.
LETTERS OF TRANSMITTAL AND SERIES A BONDS SHOULD BE SENT ONLY TO THE
EXCHANGE AGENT, AND NOT TO US OR TO ANY BOOK-ENTRY TRANSFER FACILITY.
THE METHOD OF DELIVERY OF SERIES A BONDS, LETTERS OF TRANSMITTAL AND ALL
OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE ELECTION AND RISK OF
THE HOLDER TENDERING SERIES A BONDS. DELIVERY OF SUCH
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DOCUMENTS WILL BE DEEMED MADE ONLY WHEN ACTUALLY RECEIVED BY THE EXCHANGE AGENT.
IF SUCH DELIVERY IS BY MAIL, WE SUGGEST THAT THE HOLDER USE PROPERLY INSURED,
REGISTERED MAIL WITH RETURN RECEIPT REQUESTED, AND THAT THE MAILING BE MADE
SUFFICIENTLY IN ADVANCE OF THE EXPIRATION DATE OF THE EXCHANGE OFFER TO PERMIT
DELIVERY TO THE EXCHANGE AGENT PRIOR TO SUCH DATE. NO ALTERNATIVE, CONDITIONAL
OR CONTINGENT TENDERS OF SERIES A BONDS WILL BE ACCEPTED.
Signature Guarantees.
Signatures on the letter of transmittal must be guaranteed by an eligible
institution unless:
- the letter of transmittal is signed by the registered holder of the
Series A bonds tendered therewith, or by a participant in one of the
book-entry transfer facilities whose name appears on a security position
listing it as the owner of those Series A bonds, or if any Series A bonds
for principal amounts not tendered are to be issued directly to the
holder, or, if tendered by a participant in one of the book-entry
transfer facilities, any Series A bonds for principal amounts not
tendered or not accepted for exchange are to be credited to the
participant's account at the book-entry transfer facility, and neither
the "Special Issuance Instructions" nor the "Special Delivery
Instructions" box on the letter of transmittal has been completed, or
- the Series A bonds are tendered for the account of an eligible
institution.
An eligible institution is a firm that is a participant in the Security
Transfer Agents Medallion program or the Stock Exchange Medallion program, which
is generally a member of a registered national securities exchange, a member of
the National Association of Securities Dealers, Inc., or a commercial bank or
trust company having an office in the United States.
Book-Entry Transfer.
The exchange agent will seek to establish a new account or utilize an
existing account with respect to the Series A bonds at DTC promptly after the
date of this prospectus. Any financial institution that is a participant in the
book-entry transfer facility system and whose name appears on a security
position listing it as the owner of the Series A bonds may make book-entry
delivery of Series A bonds by causing the book-entry transfer facility to
transfer such Series A bonds into the exchange agent's account. HOWEVER,
ALTHOUGH DELIVERY OF SERIES A BONDS MAY BE EFFECTED THROUGH BOOK-ENTRY TRANSFER
INTO THE EXCHANGE AGENT'S ACCOUNT AT A BOOK-ENTRY TRANSFER FACILITY, A PROPERLY
COMPLETED AND VALIDLY EXECUTED LETTER OF TRANSMITTAL, OR A MANUALLY SIGNED
FACSIMILE THEREOF, MUST BE RECEIVED BY THE EXCHANGE AGENT AT ONE OF ITS
ADDRESSES SET FORTH IN THIS PROSPECTUS ON OR PRIOR TO THE EXPIRATION DATE OF THE
EXCHANGE OFFER, OR ELSE THE GUARANTEED DELIVERY PROCEDURES DESCRIBED BELOW MUST
BE COMPLIED WITH. The confirmation of a book-entry transfer of Series A bonds
into the exchange agent's account at a book-entry transfer facility is referred
to in this prospectus as a "book-entry confirmation." Delivery of documents to
the book-entry transfer facility in accordance with that book-entry transfer
facility's procedures does not constitute delivery to the exchange agent.
Guaranteed Delivery.
If you wish to tender your Series A bonds and:
(1) certificates representing your Series A bonds are not lost but are
not immediately available,
(2) time will not permit your letter of transmittal, certificates
representing your Series A bonds and all other required documents to reach
the exchange agent on or prior to the expiration date of the exchange
offer, or
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(3) the procedures for book-entry transfer cannot be completed on or
prior to the expiration date of the exchange offer, you may nevertheless
tender if all of the following are complied with:
- your tender is made by or through an eligible institution;
- on or prior to the expiration date of the exchange offer, the
exchange agent has received from the eligible institution a
properly completed and validly executed notice of guaranteed
delivery, by manually signed facsimile transmission, mail or hand
delivery, in substantially the form provided with this prospectus.
The notice of guaranteed delivery must:
(a) set forth your name and address, the registered number(s) of
your Series A bonds and the principal amount of Series A bonds
tendered;
(b) state that the tender is being made thereby ;
(c) guarantee that, within three New York Stock Exchange trading
days after the date of the notice of guaranteed delivery, the
letter of transmittal or facsimile thereof properly completed
and validly executed, together with certificates representing
the Series A bonds, or a book-entry confirmation, and any other
documents required by the letter of transmittal and the
instructions thereto, will be deposited by the eligible
institution with the exchange agent; and
(d) the exchange agent receives the properly completed and validly
executed letter of transmittal or facsimile thereof with any
required signature guarantees, together with certificates for
all Series A bonds in proper form for transfer, or a book-entry
confirmation, and any other required documents, within three New
York Stock Exchange trading days after the date of the notice of
guaranteed delivery.
Other Matters
Series B bonds will be issued in exchange for Series A bonds accepted for
exchange only after timely receipt by the exchange agent of:
- certificates for (or a timely book-entry confirmation with respect to)
your Series A bonds,
- a properly completed and duly executed letter of transmittal or facsimile
thereof with any required signature guarantees, or, in the case of a
book-entry transfer, an agent's message, and
- any other documents required by the letter of transmittal.
We will determine, in our sole discretion, all questions as to the form of
all documents, validity, eligibility, including time of receipt, and acceptance
of all tenders of Series A bonds. Our determination will be final and binding on
all parties. ALTERNATIVE, CONDITIONAL OR CONTINGENT TENDERS OF SERIES A BONDS
WILL NOT BE CONSIDERED VALID. We reserve the absolute right to reject any or all
tenders of Series A bonds that are not in proper form or the acceptance of
which, in our opinion, would be unlawful. We also reserve the right to waive any
defects, irregularities or conditions of tender as to particular Series A bonds.
Our interpretation of the terms and conditions of the exchange offer,
including the instructions in the letter of transmittal, will be final and
binding.
Any defect or irregularity in connection with tenders of Series A bonds
must be cured within the time we determine, unless waived by us. We will not
consider the tender of Series A bonds to have been validly made until all
defects and irregularities have been waived by us or cured. Neither we, the
exchange agent, or any other person will be under any duty to give notice of any
defects or irregularities in tenders of Series A bonds, or will incur any
liability to holders for failure to give any such notice.
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By signing or agreeing to be bound by the letter of transmittal, you will
represent to us that, among other things:
- any Series B bonds that you receive will be acquired in the ordinary
course of your business;
- you have no arrangement or understanding with any person or entity to
participate in the distribution of the Series B bonds;
- if you are not a broker-dealer, that you are not engaged in and do not
intend to engage in the distribution of the Series B bonds;
- if you are a broker-dealer that will receive Series B bonds for your own
account in exchange for Series A bonds that were acquired as a result of
market-making activities, you will deliver a prospectus, as required by
law, in connection with any resale of those Series B bonds; and
- you are not our "affiliate," as defined in Rule 405 of the Securities
Act, or, if you are an affiliate, you will comply with any applicable
registration and prospectus delivery requirements of the Securities Act.
WITHDRAWAL OF TENDERS
Except as otherwise provided in this prospectus, you may withdraw your
tender of Series A bonds at any time prior to the expiration date.
For a withdrawal to be effective:
- the exchange agent must receive a written notice of withdrawal at one of
the addresses set forth below under "-- Exchange Agent" on page 65, or
- you must comply with the appropriate procedures of DTC's automated tender
offer program system.
Any notice of withdrawal must:
- specify the name of the person who tendered the Series A bonds to be
withdrawn and
- identify the Series A bonds to be withdrawn, including the principal
amount of the Series A bonds.
If Series A bonds have been tendered pursuant to the procedure for
book-entry transfer described above, any notice of withdrawal must specify the
name and number of the account at DTC to be credited with the withdrawn Series A
bonds and otherwise comply with the procedures of DTC.
We will determine all questions as to validity, form, eligibility and time
of receipt of any withdrawal notices. Our determination will be final and
binding on all parties. We will deem any Series A bonds so withdrawn not to have
been validly tendered for exchange for purposes of the exchange offer.
Any Series A bonds that have been tendered for exchange but that are not
exchanged for any reason will be returned to their holder without cost to the
holder or, in the case of Series A bonds tendered by book-entry transfer into
the exchange agent's account at DTC according to the procedures described above,
such Series A bonds will be credited to an account maintained with DTC for the
Series A bonds. This return or crediting will take place as soon as practicable
after withdrawal, rejection of tender or termination of the exchange offer. You
may retender properly withdrawn Series A bonds by following one of the
procedures described under "-- Procedures for Tendering Series A Bonds"
beginning on page 60 at any time on or prior to the expiration date.
CONDITIONS OF THE EXCHANGE OFFER
We will not be required to accept for exchange, or exchange any Series B
bonds for, any Series A bonds tendered, and we may terminate, extend or amend
the exchange offer and may, subject to Rule 14e-1 under the Exchange Act, which
requires that an offeror pay the consideration offered or return the securities
deposited by or on behalf of the holders thereof promptly after the termination
or withdrawal
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of a tender offer, postpone the acceptance for exchange of Series A bonds so
tendered if, on or prior to the expiration date of the exchange offer, the
following shall have occurred:
- we have determined that the offering and sales under the registration
statement, the filing of such registration statement or the maintenance
of its effectiveness would require disclosure of or would interfere in
any material respect with any material financing, merger, offering or
other transaction involving the issuer of the bonds or would otherwise
require disclosure of nonpublic information that could materially and
adversely affect the issuer or the subsidiary guarantors.
The conditions to the exchange offer are for our sole benefit and may be
asserted by us in our sole discretion or may be waived by us, in whole or in
part, in our sole discretion, whether or not any other condition of the exchange
offer also is waived. We have not made a decision as to what circumstances would
lead us to waive any condition, and any waiver would depend on circumstances
prevailing at the time of that waiver. Any determination by us concerning the
events described in this section shall be final and binding upon all persons.
ALTHOUGH WE HAVE NO PRESENT PLANS OR ARRANGEMENTS TO DO SO, WE RESERVE THE
RIGHT TO AMEND, AT ANY TIME, THE TERMS OF THE EXCHANGE OFFER. WE WILL GIVE
HOLDERS NOTICE OF ANY AMENDMENTS IF REQUIRED BY APPLICABLE LAW.
TRANSFER TAXES
We will pay all transfer taxes applicable to the transfer and exchange of
Series A bonds pursuant to the exchange offer. If, however:
- delivery of the Series B bonds and/or certificates for Series A bonds for
principal amounts not exchanged, are to be made to any person other than
the recordholder of the Series A bonds tendered;
- tendered certificates for Series A bonds are recorded in the name of any
person other than the person signing any letter of transmittal; or
- a transfer tax is imposed for any reason other than the transfer and
exchange of Series A bonds to us or our order,
the amount of any such transfer taxes, whether imposed on the recordholder or
any other person, will be payable by the tendering holder prior to the issuance
of the Series B bonds.
CONSEQUENCES OF FAILURE TO EXCHANGE
If you do not exchange your Series A bonds for Series B bonds in the
exchange offer, you will remain subject to the restrictions on transfer of the
Series A bonds:
- as set forth in the legend printed on the bonds as a consequence of the
issuance of the Series A bonds pursuant to the exemptions from, or in
transactions not subject to, the registration requirements of the
Securities Act and applicable state securities laws; and
- otherwise set forth in the memorandum distributed in connection with the
private offering of the Series A bonds.
In general, you may not offer or sell the Series A bonds unless they are
registered under the Securities Act, or if the offer or sale is exempt from
registration under the Securities Act and applicable state securities laws.
Except as required by the registration rights agreement, we do not intend to
register resales of the Series A bonds under the Securities Act. Based on
interpretations of the SEC staff, you may offer for resale, resell or otherwise
transfer Series B bonds issued in the exchange offer without compliance with the
registration and prospectus delivery provisions of the Securities Act, provided
that (1) you are not
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our "affiliate" within the meaning of Rule 405 under the Securities Act, (2) you
acquired the Series B bonds in the ordinary course of your business and (3) you
have no arrangement or understanding with respect to the distribution of the
Series B bonds to be acquired in the exchange offer. If you tender Series A
bonds in the exchange offer for the purpose of participating in a distribution
of the Series B bonds:
- you cannot rely on the applicable interpretations of the SEC; and
- you must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a secondary resale
transaction and such a secondary resale transaction must be covered by an
effective registration statement containing the selling security holder
information required by Item 507 or 508, as applicable, of Regulation
S-K.
EXCHANGE AGENT
Bankers Trust Company has been appointed as exchange agent for the exchange
offer. You should direct questions and requests for assistance, requests for
additional copies of this prospectus, the letter of transmittal or any other
documents to the exchange agent. You should send certificates for Series A
bonds, letters of transmittal and any other required documents to the exchange
agent addressed as follows:
BANKERS TRUST COMPANY
<TABLE>
<S> <C> <C>
By Overnight, By Mail: By Hand in New York:
Registered or Certified Mail Bankers Trust Company
or Overnight Courier: BT Services Tennessee, Inc. Corporate Trust and Agency Group
BT Services Tennessee, Inc. Reorganization Unit Attn: Reorganization Department
Corporate Trust & Agency Group P.O. Box 292737 Receipt and Delivery Window
Reorganization Unit Nashville, Tennessee 37229-2737 123 Washington Street-1st Floor
648 Grassmere Park Road New York, New York 10006
Nashville, Tennessee 37211
</TABLE>
By Facsimile:
(for eligible institutions only)
(615) 835-3701
Confirm by telephone:
(615) 835-3572
DESCRIPTION OF THE BONDS
The following summaries of certain provisions of the indenture and the
bonds do not purport to be complete and are subject to, and are qualified in
their entirety by reference to, all of the provisions of the indenture, and the
bonds, including the definitions therein. Copies of the indenture are available
for inspection at the corporate trust office of the trustee. We urge you to read
the bonds and the indenture because they, and not this description, define your
rights as holder of the bonds. Capitalized terms used herein and not otherwise
defined in this prospectus have the meanings ascribed to them under "Defined
Terms."
We issued the Series A bonds under an indenture dated September 26, 2000,
as amended by a supplemental indenture dated November 20, 2000, between us and
Bankers Trust Company, as trustee, in a private transaction that was not subject
to the registration requirements of the Securities Act. The Series B bonds will
be issued under the same indenture. The terms of the bonds include those stated
in the indenture and those made part of the indenture by reference to the Trust
Indenture Act.
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GENERAL
The Series A bonds and the Series B bonds will constitute a single class of
debt securities under the indenture, as amended. If the exchange offer is
completed, holders of Series A bonds who do not exchange their Series A bonds
for Series B bonds will vote together with holders of the Series B bonds for all
relevant purposes under the indenture. In that regard, the indenture requires
that certain actions by holders, including the acceleration following an event
of default, must be taken, and certain rights must be exercised, by specified
minimum percentages of the aggregate principal amount of the outstanding
securities issued under the indenture. In determining whether the required
holders have given any notice, consent or waiver or taken any other action
permitted under the indenture, any Series A bonds that remain outstanding after
the exchange offer will be aggregated with the Series B bonds, and the holders
of the Series A bonds and the Series B bonds will vote together as a single
series. All references in this prospectus to specified percentages in aggregate
principal amount of the notes means, at any time after the exchange offer is
completed, the percentages in aggregate principal amount of the Series A bonds
and the Series B bonds collectively then outstanding.
The term "bonds" as used in this prospectus refers collectively to the
Series A bonds and the Series B bonds.
PRINCIPAL AMOUNT, INTEREST RATE AND STATED MATURITY
The bonds will have an aggregate principal amount of $310,600,000 and will
bear interest at the rate of 8 1/2% per year. The bonds will mature on February
15, 2014.
Interest on the bonds will accrue at an annual rate of 8 1/2%. We will pay
interest on the bonds semi-annually on February 15 and August 15 or, if that day
is not a business day in New York City, then on the next succeeding business day
commencing February 15, 2001 (each, an "Interest Payment Date"), to the
registered owners thereof at the close of business on the February 1 or August 1
preceding the relevant Interest or Principal Payment Date. Interest will be
computed on the basis of a 360-day year consisting of twelve 30-day months.
We will repay principal on the bonds annually on February 15 or, if that
day is not a business day in New York City, the next succeeding business day,
commencing February 15, 2002 (each a "Principal Payment Date").
PAYMENT OF PRINCIPAL AND INTEREST
We will make all payments (including principal, Make-Whole Premium and
interest) on the bonds at the corporate trust office of the trustee or, at our
option, by check mailed to the address of the person entitled thereto, except
for the payment of the final installment of principal payable with respect to a
bond, which we will make upon presentation and surrender of that bond at the
corporate trust office of the trustee or such other place of payment as is
designated pursuant to the indenture. We will make these payments to the person
in whose name the bond (or one or more predecessor bonds) is registered at the
close of business on the regular record date (the fifteenth day next preceding
the relevant Interest or Principal Payment Date) for the payment.
Notwithstanding the foregoing, upon written request, we will make a payment on
the bonds (other than a final payment of principal) by wire transfer to holders
of $1 million or more aggregate principal amount of bonds. In the case of the
global bonds, these payments will be made to DTC or to any nominee thereof,
which will be the holder of record of the global bonds. See "-- Form and
Denomination."
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INSTALLMENT PAYMENTS OF PRINCIPAL
Installments of principal on the bonds are payable as follows:
<TABLE>
<CAPTION>
PERCENTAGE OF PRINCIPAL
PAYMENT DATE AMOUNT PAYABLE
------------ -----------------------
<S> <C>
February 15, 2002................................. 1.9
February 15, 2003................................. 2.5
February 15, 2004................................. 3.5
February 15, 2005................................. 4.9
February 15, 2006................................. 5.8
February 15, 2007................................. 6.7
February 15, 2008................................. 7.7
February 15, 2009................................. 8.8
February 15, 2010................................. 9.9
February 15, 2011................................. 11.3
February 15, 2012................................. 12.6
February 15, 2013................................. 14.3
February 15, 2014................................. 10.1
</TABLE>
REDEMPTION AT OUR OPTION
We may at any time redeem all or any portion of the outstanding bonds, in
whole or in part, at a redemption price equal to the principal amount thereof to
be redeemed plus accrued and unpaid interest thereon to the redemption date,
plus the Make-Whole Premium, if any, on a redemption date that we will
establish.
We will mail a notice of any such redemption to each holder of a bond which
is to be redeemed (in whole or in part) at that holder's address of record not
less than 30 days nor more than 60 days before the applicable redemption date.
In addition, we will provide a notice of redemption of bonds to be redeemed to
the trustee in accordance with the terms of the indenture. On and after any such
redemption date, interest will cease to accrue on the bonds (or portion of the
principal amount thereof) called for redemption.
LIMITATION ON LIABILITY
There is no recourse for the payment of principal of or Make-Whole Premium,
if any, or interest on any bond, or for any claim based thereon or otherwise in
respect thereof, or of the Indebtedness represented thereby, or upon any
obligation, covenant or agreement under the indenture or any bond, against any
of our affiliates or any incorporator, stockholder, member, officer, employee or
director of us or any such affiliate or any predecessor or successor thereof and
any such liability is expressly waived and released. Nothing, however, limits
the liability of any of the foregoing for fraud, gross negligence or willful
misconduct.
FORM AND DENOMINATION
All bonds will be issued in registered form without coupons. The bonds may
be issued in minimum denominations of $100,000 and integral multiples of $1,000
in excess thereof. The bonds, and transfers thereof, will be registered as
provided in the indenture. Any person in whose name a bond is registered may to
the fullest extent permitted by applicable law be treated as the absolute owner
of that bond. The person in whose name a bond is registered is referred to in
this prospectus as the "holder" of a bond.
Except in the limited circumstances described under "-- Certificated Bonds"
below, beneficial interests in the global bonds will only be recorded by
book-entry and owners of beneficial interests in the global bonds will not be
entitled to receive physical delivery of certificates representing the bonds.
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Except as set forth below, the Series B bonds will be represented by one
permanent global registered bond in global form without interest coupons, which
we refer to in this prospectus as the "global bonds." The global bonds will be
deposited with, or on behalf of, DTC and registered in the name of Cede & Co.
Global Bonds
Upon the issuance of the global bonds it is expected that, DTC or its
nominee will credit, on its internal system, the respective principal amounts of
the individual beneficial interests represented by those global bonds to the
accounts of persons who have accounts with DTC. These accounts initially will be
designated by or on behalf of the initial purchaser. Ownership of beneficial
interests in a global bond will be limited to persons who have accounts with DTC
("participants") or persons who hold interests through participants. Ownership
of beneficial interests in the global bonds will be shown on, and the transfer
of that ownership will be effected only through, records maintained by DTC or
its nominee (with respect to interests of participants) and the records of agent
members (with respect to interests of persons other than participants).
So long as DTC or its nominee is the holder of a global bond, DTC or its
nominee, as the case may be, will be considered the holder of the bonds
represented by that global bond for all purposes under the indenture and the
bonds. No beneficial owner of an interest in a global bond will be able to
transfer that interest except in accordance with DTC's applicable procedures (in
addition to those under the indenture referred to herein and, if applicable,
those of Euroclear and Clearstream Luxembourg) unless we issue certificates for
the bonds in definitive registered form as described under "-- Certificated
Bonds" below.
Payments of the principal of, and interest and Make-Whole Premium, if any,
on the global bonds will be made to DTC or its nominee, as the holder thereof.
Neither we, the initial purchaser 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 those beneficial
ownership interests or the transfer thereof.
We expect that DTC or its nominee, upon receipt of any payment of principal
of, or interest on, or Make-Whole Premium, if any, in respect of a global bond
held by it or its nominee, will immediately credit participants' accounts with
payments in amounts proportionate to their respective beneficial interests in
the principal amount of the global bond as shown on the records of DTC or its
nominee. We also expect that payments by participants to owners of beneficial
interests in that global bond held through the participants will be governed by
standing instructions and customary practices. These payments will be the
responsibility of the participants.
Transfers between participants in DTC will be effected in the ordinary way
in accordance with DTC rules and will be settled in same-day funds. The laws of
some jurisdictions may require that certain persons take physical delivery of
bonds in definitive form. Consequently, the ability to transfer beneficial
interests in a global bond to these persons may be limited. Because DTC can only
act on behalf of participants, who in turn act on behalf of indirect
participants and certain banks, the ability of a person having a beneficial
interest in a global bond to pledge that interest to persons or entities that do
not participate in the DTC system, or otherwise take actions in respect of that
interest, may be affected by the lack of a physical certificate representing
that interest. Transfers between participants in Euroclear and Clearstream
Luxembourg will be effected in the ordinary way in accordance with their
respective rules and operating procedures.
Subject to compliance with the transfer restrictions applicable to the
bonds described above and under "Transfer Restrictions," cross-market transfers
between DTC, on the one hand, and directly or indirectly through Euroclear or
Clearstream Luxembourg participants, on the other, will be effected in DTC in
accordance with DTC rules on behalf of Euroclear or Clearstream Luxembourg, as
the case may be, by its respective depositories; however, these cross-market
transactions will require delivery of instructions to Euroclear or Clearstream
Luxembourg, as the case may be, by the counterparty in such system in accordance
with its rules and procedures and within its established deadlines. Euroclear or
Clearstream Luxembourg, as the case may be, will, if the transaction meets its
settlement requirements, deliver
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instructions to its respective depositories to take action to effect final
settlement on its behalf by delivering or receiving interests in the global bond
in DTC, and making or receiving payment in accordance with normal procedures for
same-day funds settlement applicable to DTC. Euroclear and Clearstream
Luxembourg participants may not deliver instructions directly to the
depositories for DTC.
Because of time zone differences, the bond account of a Euroclear or
Clearstream Luxembourg participant purchasing an interest in a global bond from
a DTC participant will be credited during the bonds settlement processing day
(which must be a business day for Euroclear or Clearstream Luxembourg, as the
case may be) immediately following the DTC settlement date, and the credit of
any transactions in interests in a global bond settled during a processing day
will be reported to the relevant DTC participant on that day. Cash received in
Euroclear or Clearstream Luxembourg as a result of sales of interests in a
global bond by or through a Euroclear or Clearstream Luxembourg participant to a
DTC participant will be received on the DTC settlement date, but will be
available in the relevant Euroclear or Clearstream Luxembourg cash account only
as of the business day following settlement in DTC.
We expect that DTC will take any action permitted to be taken by a holder
of bonds (including the presentation of bonds for exchange as described below)
only at the direction of one or more participants to whose DTC account interests
in the global bond are credited, and only in respect of that portion of the
aggregate principal amount of the bonds as to which that participant or those
participants has or have given such direction.
DTC is a limited purpose trust company organized under the laws of the
State of New York; 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 pursuant to the provisions of Section 17A of the
Securities Exchange Act. DTC was created to hold bonds for its participants and
facilitate the clearance and settlement of bond transactions between
participants through electronic book-entry changes in accounts of its
participants, thereby eliminating the need for physical movement of
certificates. Participants include bonds brokers and dealers, banks, trust
companies and clearing corporations and may include certain other organizations.
Indirect access to the DTC system is available to others such as banks, brokers,
dealers and trust companies that clear through or maintain a custodial
relationship with a DTC participant, either directly or indirectly.
Although DTC, Euroclear and Clearstream Luxembourg have agreed to the
foregoing procedures in order to facilitate transfers of interest in the global
bonds among participants of DTC, Euroclear and Clearstream Luxembourg, they are
under no obligation to continue to perform such procedures, and such procedures
may be discontinued at any time. Neither we, the initial purchaser nor the
trustee will have any responsibility for the performance by DTC, Euroclear or
Clearstream Luxembourg or their respective participants or indirect participants
of their respective obligations under the rules and procedures governing their
operations.
The information herein concerning DTC, Euroclear and Clearstream Luxembourg
and their respective procedures has been obtained from sources (including DTC,
Euroclear and Clearstream Luxembourg) that we believe to be reliable, but we do
not take any responsibility for the accuracy thereof.
Certificated Bonds
The bonds will be issued in certificated fully registered form (which we
refer to as the individual bonds) to holders or their nominees, rather than as
global bonds if:
- we notify the trustee in writing that DTC or any successor depositary, as
the case may be, is unwilling or unable to continue as a depositary for a
global bond or ceases to be a depositary and we are unable to locate a
qualified successor depositary within 90 days of this notice;
- we elect to terminate the book-entry system through DTC with respect to
the bonds; or
- after the occurrence of an Event of Default, the beneficial owners
holding interests representing an aggregate principal amount of bonds of
not less than a majority of the bonds represented by the global bonds
advise the trustee through DTC in writing that the continuation of a
book-entry system through DTC is no longer in their best interest.
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The holder of an individual bond may transfer the bond by surrendering it
at the corporate trust office or agency maintained by us for such purpose in the
Borough of Manhattan, The City of New York, which initially will be the office
of the trustee.
THE ACCOUNTS
Establishment of Accounts
Pursuant to the indenture, the trustee established and maintains the
following accounts and subaccounts in its own name for the benefit of the
holders (collectively, the "accounts"):
- the collections account;
- the liquidity account; and
- the damages and indemnity account.
Collections Account
We have instructed each person from whom we receive or are entitled to
receive collections to pay those collections (identifying them as such) directly
to the trustee for deposit in the collections account. On the closing date of
the offering of the Series A bonds, the collections account was funded by an
amount equal to $2,396,509 from the proceeds of the offering of the Series A
bonds. The trustee must deposit into the collections account all transfer
payments from the liquidity account as described in the third paragraph of the
section entitled "-- Liquidity Account" and amounts on deposit in the
collections account will be withdrawn as described in "-- Withdrawals from the
Collections Account."
Liquidity Account
The liquidity account was funded on the closing date of the offering of the
Series A bonds by the transfer to the trustee and the deposit into the liquidity
account of an amount equal to the maximum amount of interest that will be due on
any subsequent Interest Payment Date from the net proceeds of the offering of
the Series A bonds. The Liquidity Account will also be funded by the transfer by
the trustee on each Interest Payment Date of funds from the collections accounts
to the liquidity account as described under priority fifth of "-- Withdrawals
from the Collections Account."
At any time El Paso Energy may withdraw amounts on deposit in the liquidity
account if El Paso Energy delivers to the trustee for allocation to the
liquidity account to replace the amount withdrawn, either (1) a guaranty issued
by El Paso Energy in the amount withdrawn, in favor of the trustee for the
benefit of the holders or (2) one or more letters of credit in an aggregate face
amount equal to all or a portion of the then current liquidity reserve required
balance. In order for El Paso Energy to be able to use the guaranty described in
(1) El Paso Energy must have and maintain at least the following ratings: P-1
(or its equivalent) from Moody's and A-1 (or its equivalent) from Standard &
Poor's. Each such letter of credit described in (2) must (A) be from a financial
institution rated at least Aa3 (or its equivalent) by Moody's and AA- (or its
equivalent) by Standard & Poor's; (B) name the trustee as its sole beneficiary;
and (C) provide that the trustee may unconditionally draw, upon presentation of
the documentation required by such letter of credit, under any circumstances
that would otherwise permit withdrawals from the liquidity account or at any
time within 30 days before the expiration of that letter of credit (unless the
validity of the letter of credit is extended or the letter of credit is replaced
with another letter of credit that meets the requirements of the indenture).
If on any Interest Payment Date or Principal Payment Date, as applicable,
the aggregate amount of funds on deposit in and available to be withdrawn from
the collections account is insufficient for the payment of principal or interest
then due and payable on the bonds (any such deficiency, a "Liquidity
Deficiency"), the trustee will transfer from the liquidity account to the
collections account an amount equal to the Liquidity Deficiency. If on any
Interest Payment Date the aggregate amount of funds on deposit in and available
to be withdrawn from the liquidity account exceeds the then current liquidity
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reserve required balance, the excess funds will be transferred on the next
Principal Payment Date (but no earlier than February 15, 2003) to the
collections account. If the cash in the liquidity account has been replaced by a
letter of credit, the trustee will not draw on the letter of credit for the
amount of such excess, but will take such action on the next Principal Payment
Date (but no earlier than February 15, 2003) as El Paso Energy will reasonably
direct in writing to the trustee to reduce the amount available to be drawn
under the letter of credit by the amount of the excess.
Damages and Indemnity Account
We will instruct EPM and El Paso Energy to pay to the trustee for deposit
into the damages and indemnity account all amounts to be paid by EPM under the
Power Services Agreement and all amounts to be paid by El Paso Energy under the
El Paso Energy Performance Guaranty to cover:
- damages payable by us to PSE&G pursuant to Article XIV of the Amended and
Restated PPA;
- indemnity payments payable by us to PSE&G pursuant to Article XII of the
Amended and Restated PPA; and
- distribution charges payable by us to PSE&G pursuant to Article II(E) of
the Amended and Restated PPA.
Funds will be withdrawn from the damages and indemnity account from time to
time as needed to pay:
- damages payable by us to PSE&G pursuant to Article XIV of the Amended and
Restated PPA;
- indemnity payments payable by us to PSE&G pursuant to Article XII of the
Amended and Restated PPA; and
- distribution charges payable by us to PSE&G pursuant to Article II(E) of
the Amended and Restated PPA.
WITHDRAWALS FROM THE COLLECTIONS ACCOUNT
Unless a holder has given notice of an Event of Default or notice that a
Bankruptcy Event of Default has occurred and is continuing, the trustee will
apply amounts in the collections account on the following dates and in the
following order of priority (if a date is specified and that date is not a
business day in New York, the payment will be made on the next business day in
New York):
(1) first, on the fifteenth day of each month, to pay to the trustee
the amount of trustee fees due and payable at such time in connection with
the bonds;
(2) second, on the fifteenth day of each month, to pay to EPM, for
energy and capacity provided under the Power Services Agreement for the
month prior to the most recently ended month (as specified in our officer's
certificate);
(3) third, on each Interest Payment Date, to pay, pro rata, to the
holders of the bonds an amount equal to the interest due and payable at
that time on the bonds;
(4) fourth, on each Principal Payment Date, to pay, pro rata, to the
holders of the bonds an amount equal to the principal and Make-Whole
Premium (if any) due and payable at that time on the bonds;
(5) fifth, on each Interest Payment Date, to transfer to the liquidity
account an amount, if any, necessary to cause the amount on deposit in the
liquidity account to be equal to the liquidity reserve required balance;
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(6) sixth, on each Interest Payment Date, to pay to EPM an amount
equal to the accrued and unpaid fees and expenses owed EPM under the
Administrative Services Agreement; and
(7) seventh, on each Principal Payment Date or on February 15, 2001,
provided that (as specified in our officer's certificate) (A) no Event of
Default or Default has occurred and is continuing on such date and (B) the
Debt Service Reserve Coverage Ratio calculated as of that date for the most
recently ended six-month period equals or exceeds 1.03 to 1.00, to us for
distribution to our members.
INVESTMENT OF FUNDS
The trustee will invest the moneys on deposit in the accounts in Permitted
Investments as directed by us. Profits from Permitted Investments will be
deposited into the collections account. Losses on Permitted Investments will be
charged to the applicable account. The trustee has the right to sell or
otherwise liquidate any Permitted Investments to the extent necessary to make
any payment or transfer under the indenture and will have no liability for any
losses incurred in connection with the sale or liquidation.
CERTAIN COVENANTS
The indenture contains the following covenants, among others:
Material Agreements
We will enforce our rights under each of our material agreements unless the
failure to enforce those rights could not reasonably be expected to result in a
Material Adverse Effect.
Performance of Obligations
We may contract with other persons to assist us in performing our
obligations, and, if we do, the performance by that person or those persons will
be treated the same as if we had performed the obligation ourselves. As of the
closing date of the offering of the Series A bonds, we contracted with EPM to
perform our obligations under the indenture and the other financing documents,
so any action taken by EPM in performing our duties will be treated as an action
taken by us.
Liens
We will not create or permit to exist any lien on any of the collateral,
other than the liens created by the indenture, unless the existence of the lien
could not reasonably be expected to result in a Material Adverse Effect.
Indebtedness
We will not create or permit to remain outstanding, any Indebtedness,
except for Indebtedness represented by the bonds issued on the closing date.
Guaranties
We will not at any time be or become obligated, contingently or otherwise,
with respect to any guaranty.
Transactions with Affiliates
We will not effect any transaction with any of our affiliates on a basis
more favorable to this affiliate than would be at the time be obtainable for a
comparable transaction on an arm's-length dealing with an unrelated third party,
except for (1) our material agreements entered into on or before the closing
date or (2) in connection with any restructuring of the assets of Mesquite.
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Investments, Loans and Advances
Except for Permitted Investments, we will not acquire any capital stock,
debt securities or other securities of any other person and we will not make
investments in any other person.
Material Agreements; Additional Contracts
We will not assign any of our rights or obligations under any of our
material agreements nor terminate or suffer any termination of, or agree to the
assignment of the rights or obligations of any party to, any of our material
agreements.
We will not amend or grant any waiver of timely performance under any of
our material agreements or financing documents, unless the amendment or waiver
could not reasonably be expected to result in a Material Adverse Effect.
We will not become a party to any contract, lease, agreement or instrument
other than the agreements expressly identified in the definition of our material
agreements and financing documents to the extent the action could reasonably be
expected to result in a Material Adverse Effect.
Fundamental Change
We will undertake not to do any of the following:
- sell, lease, transfer or otherwise dispose of any of our right, title or
interest in or to the collateral, unless doing so could not reasonably be
expected to result in a Material Adverse Effect;
- conduct any business or own any assets other than the business and assets
conducted and owned by us as of the closing date of the offering of the
Series A bonds;
- directly or indirectly merge or consolidate with any other person,
liquidate, wind up, terminate, reorganize or dissolve ourselves, or
otherwise wind up;
- change our legal form; or
- establish any subsidiary.
Maintenance of Market-Based Rate Authority
We will take all actions, if required, necessary to maintain our Federal
Energy Regulatory Commission market-based rate authority and will maintain in
effect all governmental approvals required to conduct our business under our
material agreements.
Restricted Payments
Except in accordance with the conditions set forth in clause seventh of
"-- Withdrawals from the Collections Account," we will not, directly or
indirectly,
- make any distribution (by reduction of capital or otherwise), whether in
cash, property, securities or a combination thereof, to our members or
any owner of a beneficial interest in us or otherwise with respect to any
ownership or equity interest or security in or of us;
- redeem, purchase, retire or otherwise acquire for value any such
ownership or equity interest or security; or
- set aside or otherwise segregate any amounts for any such purpose.
We will not, directly or indirectly, make payments to or distributions from
the collections account except in accordance with the indenture and the
financing documents. See "-- Withdrawals from the Collections Account."
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ADDITIONAL COVENANTS
In addition to the covenants described above, the indenture also contains
covenants regarding:
- payment of principal, Make-Whole Premium and interest;
- maintenance of office or agency;
- maintenance of existence and properties;
- payment of taxes and other claims;
- delivery to the trustee of notice, compliance certificates and certain
other information;
- taking of all actions to preserve liens in favor of the trustee under the
financing documents;
- complying with all applicable laws and all of our obligations under the
indenture, the other financing documents, our material agreements and
each of our other agreements, unless, in each case, the failure to comply
could not reasonably be expected to result in a Material Adverse Effect;
- maintenance of books and records;
- maintenance of and compliance with Governmental Approvals;
- schedule and deliver the annual energy deliveries; and
- further assurances.
EVENTS OF DEFAULT
An Event of Default will occur under the indenture (an "Event of Default")
if:
(1) we default in the payment of any principal of or Make-Whole
Premium, if any, on any of the bonds when the same becomes due and payable,
whether by scheduled maturity or acceleration or otherwise, and such
default continues for a period of at least five days;
(2) we default in the payment of interest on, or any other amount
required to be paid with respect to, any of the bonds (other than principal
or Make-Whole Premium) in each case when the same becomes due and payable,
and the default continues for a period of at least 15 days;
(3) El Paso Energy or PSE&G or we fail to observe or perform any
covenant or provision of any of our material agreements or financing
document to which El Paso Energy or PSE&G or we, as the case may be, are a
party, and the failure (a) could reasonably be expected to result in a
Material Adverse Effect and (b) continues for a period of at least 30 days
after the date notice thereof has been given to us by the trustee or the
Majority Holders;
(4) any of our material agreements or financing documents ceases at
any time to be valid and binding and in full force and effect and the
invalidity and unenforceability could reasonably be expected to result in a
Material Adverse Effect;
(5) (A) any grant of a lien contained in the indenture or in any
financing document ceases or otherwise fails to be effective to grant a
lien to the trustee on any material portion of the collateral described
therein, or ceases to be perfected or to be a first priority security
interest, or (B) any creditor of ours (other than the trustee or any bond
holder) asserts any right or interest with respect to the collateral and
the assertion could reasonably be expected to result in a Material Adverse
Effect or (C) certain other events occur which could impair our right to
receive payments with respect to the collateral and which events could
reasonably be expected to result in a Material Adverse Effect;
(6) certain events occur involving our bankruptcy, insolvency or
receivership;
(7) it becomes unlawful for us to perform any of our obligations under
the indenture or any bond, or any of our obligations thereunder ceases to
be valid, binding and enforceable, unless such event or occurrence could
not reasonably be expected to result in a Material Adverse Effect;
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(8) for any reason the Amended and Restated PPA or the El Paso Energy
Performance Guaranty are terminated or abrogated at any time (prior to
their scheduled expiration);
(9) a final and non-appealable judgment or judgments for the payment
of money in excess of $15 million in the aggregate, which is not adequately
covered by insurance or a payment or performance bond, is entered against
us and the judgment or judgments have not been vacated, discharged, stayed
or bonded pending appeal within 60 days from the entry thereof; or
(10) we fail to observe or perform any covenant or provision of
Section 3(b) of the registration rights agreement (pursuant to which we are
obligated to use commercially reasonable efforts to continue the
effectiveness of a registration statement) and such failure continues for a
period of at least 30 days after the date notice has been given to us by
the trustee or the Majority Holders.
REMEDIES
If an Event of Default (other than Events of Default specified in
subparagraph (6) of the section "-- Events of Default" above (a "Bankruptcy
Event of Default")) occurs and is continuing, then the trustee upon the
direction of no less than 25% (for an Event of Default with respect to failure
to make payments on the bonds) or the Majority Holders (for any other Event of
Default) must declare the principal amount of all the bonds to be due and
payable immediately, and upon any such declaration the principal amount, any
accrued and unpaid interest, any Make-Whole Premium and all other amounts
payable under the bonds will become immediately due and payable.
If a Bankruptcy Event of Default occurs, the principal amount of, any
accrued interest on, any Make-Whole Premium and all other amounts payable under
the outstanding bonds will become immediately due and payable.
In addition, if one or more of the Events of Default (other than a
Bankruptcy Event of Default) occurs and is continuing, the trustee may
accelerate the maturity of the bonds notwithstanding the absence of direction
from the holders, if in the judgment of the trustee this action is necessary to
protect the interests of the holders.
At any time after the principal of the bonds becomes due and payable upon a
declared acceleration, and before any judgment or decree for the payment of the
money so due, or any portion thereof, is entered, the Majority Holders, by
written notice to us and the trustee, may rescind and annul the declaration and
its consequences if all Events of Default giving rise to the acceleration have
been cured or waived.
At any time after a declaration of acceleration under the indenture, but
before a judgment or decree for payment of the principal amount of the bonds
then due has been obtained by the trustee, we may, by written notice to a
responsible officer of the trustee, rescind and annul such declaration and its
consequences if we have paid or deposited with the trustee a sum sufficient to
pay:
- all overdue interest on the bonds;
- all unpaid principal of and premium, if any, on any outstanding bonds
that have become due otherwise then by the declaration of acceleration
and interest thereon at the rate borne by the bonds;
- to the extent that payment of interest is lawful, interest upon overdue
interest and overdue principal at the rate borne by the bonds;
- all sums paid or advanced by the trustee under the indenture and the
reasonable compensation, expenses, disbursements and advances of the
trustee, its agents and counsel; and
- all Defaults and Events of Default, other than the non-payment of amounts
of principal of, premium, if any, or interest on the bonds that have
become due solely by such declaration of acceleration and have been cured
or waived as provided in the indenture.
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Subject to the provisions of the indenture relating to the duties of the
trustee, in case an Event of Default occurs and is continuing, the trustee is
under no obligation to exercise any of the rights or powers vested in it under
the indenture at the request or direction of any of the holders unless it is
offered security or indemnity reasonably satisfactory to it against costs,
expenses and liabilities.
If any Event of Default occurs and is continuing, the trustee may and, at
the written instruction of the Majority Holders, shall, exercise any or all of
the following rights and remedies:
- collect, receive and appropriate any or all of the collateral and
exercise any of our rights, remedies, powers or privileges under any of
our material agreements;
- set off against all amounts due and payable under the indenture funds on
deposit in the accounts;
- proceed by suit at law or in equity to seek specific performance of any
obligation of ours;
- take possession of the collateral, in which case we will deliver the
collateral to the trustee or its designee at the time or times and the
place or places as the trustee may reasonably specify;
- sell, lease, assign, give an option or options to purchase or otherwise
dispose of and deliver all or any part of the collateral (or contract to
do so) at one or more public or private sales, at any exchange, broker's
board or at any of the trustee's offices or elsewhere at the prices as it
may deem best, for cash or on credit or for future delivery without
assumption of any credit risk; provided that, if the proceeds of such
sale or sales are not sufficient to satisfy all of the outstanding
principal, accrued and unpaid interest, any Make-Whole Premium and other
amounts due under the bonds, all of the Holders shall have consented to
such sale or sales;
- proceed by suit at law or in equity to foreclose upon, or appoint a
receiver with respect to, the collateral or exercise any other right or
remedy (including specific performance of our obligations under the
financing documents) available under applicable law.
APPLICATION OF MONEY COLLECTED
Any money collected by the trustee pursuant to its exercise of remedies
under the indenture will be applied in the following order of priority:
- first, to the payment of all amounts due to the trustee and each
predecessor trustee, if any, under the indenture;
- second, to the payment of the amounts when due and unpaid for principal
of (and Make-Whole Premium, if any) and any interest on the bonds in
respect of which or for the benefit of which the money has been
collected, ratably, without preference or priority of any kind, according
to the amounts due and payable on the bonds for principal (and Make-Whole
Premium, if any) and any interest, respectively;
- third, to the payment of all amounts due and payable to EPM under the
Administrative Services and the Power Services Agreement, as set forth in
our officer's certificate or as determined by a court of competent
jurisdiction; and
- fourth, to us.
AMENDMENTS AND SUPPLEMENTS
Without the consent of the holders of the bonds, we and the trustee may
enter into one or more supplemental indentures for any of the following
purposes:
- to evidence the succession of another person to us and the assumption by
any such successor of our covenants contained in the indenture and in the
bonds;
- to add to our covenants for the benefit of the holders of the bonds or to
surrender any right or power conferred upon us in the indenture;
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- to add any additional Events of Default;
- to secure the bonds;
- to evidence and provide for the acceptance of appointment by a successor
trustee with respect to the bonds and to add to or change any of the
provisions of the indenture as shall be necessary to provide for or
facilitate the administration of the trusts thereunder by more than one
trustee;
- to cure any ambiguity, to correct or supplement any provision of the
indenture which may be inconsistent with any other provision therein, or
to make any other provisions with respect to matters or questions arising
under the indenture; provided that action shall not adversely affect the
interests of the holders of bonds in any material respect; or
- to supplement any of the provisions of the indenture to the extent as
shall be necessary to permit or facilitate the defeasance and discharge
of the bonds; provided that any such action does not adversely affect the
interests of the holders of the bonds in any material respect.
With the consent of the holders of a majority of all outstanding bonds, we
and the trustee may enter into an indenture or indentures supplemental to the
indenture for the purpose of adding any provisions to or changing in any manner
or eliminating any of the provisions of the indenture or of modifying in any
manner the rights of the holders of bonds under the indenture; provided,
however, that no such supplemental indenture will, without the consent of the
holder of each outstanding bond affected thereby:
- change the stated maturity of the principal of, or any installment of
interest on, any bond;
- reduce the principal amount or interest on or any Make-Whole Premium
payable upon the redemption of any bond including discharge of repayment
of principal of or interest on any bond;
- reduce the percentage in principal amount of outstanding bonds, the
consent of the holders of which is required for the adoption of a
resolution or the quorum required at any meeting of holders at which a
resolution is adopted or the percentage in principal amount of
outstanding bonds the holders of which are entitled to request the
calling of a holder's meeting;
- change the percentage rules established for adopting resolutions at
meetings of holders or regarding the quorum necessary to constitute a
meeting;
- modify any of the provisions of the indenture regarding the approval of
supplemental indentures or waiver of past default, except to increase the
percentage of required holders for those approvals;
- change the place or coin or currency for payment of principal of,
Make-Whole Premium or interest on, any bond;
- impair the right to institute suit for the enforcement of any payment on
or after the stated maturity thereof or any redemption date therefor;
- permit the creation of any lien with respect to all or any substantial
portion of the collateral, or terminate the lien of the security
documents on all or any substantial portion of the collateral or deprive
any holder of the security afforded by the lien of the security
documents, except to the extent expressly permitted by the indenture or
any of the financing documents;
- modify the ranking or priority of the bonds; or
- waive a default in the payment of principal of, Make-Whole Premium, if
any, or interest on the bonds.
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SATISFACTION AND DISCHARGE OF THE INDENTURE
The indenture will cease to be of further effect (except as to any
surviving rights of registration of transfer or exchange of bonds expressly
provided for and except as otherwise specifically provided in the indenture)
when:
(1) either
(A) all bonds previously authenticated and delivered (other than (i)
bonds which have been destroyed, lost or stolen and which have been
replaced or paid and (ii) bonds for whose payment money has previously been
deposited in trust with the trustee) have been delivered to the trustee for
cancellation; or
(B) all bonds not previously delivered to the trustee for cancellation
(i) have become due and payable, or
(ii) will become due and payable at their stated maturity within
one year, or
(iii) if redeemable at our option, are to be called for redemption
within one year under arrangements satisfactory to the trustee for the
giving of notice of redemption by the trustee in our name and at our
expense;
and we, in the case of (B) (i), (ii) or (iii) above, have irrevocably
deposited or caused to be deposited with the trustee as trust funds in
trust for the purpose an amount sufficient to pay and discharge the entire
indebtedness on those bonds not previously delivered to the trustee for
cancellation, for principal, Make-Whole Premium, if any, and interest to
the date of the deposit (in the case of bonds which have become due and
payable) or to the stated maturity or redemption date, as the case may be;
(2) we have paid or caused to be paid all other sums payable under the
indenture by us; and
(3) we have delivered to the trustee an officer's certificate and an
opinion of counsel, each stating that all conditions precedent relating to the
satisfaction and discharge of the indenture as to the bonds have been complied
with.
DEFEASANCE OR COVENANT DEFEASANCE
We may, at our option, elect to be discharged from our obligations with
respect to the outstanding bonds ("defeasance"). This defeasance means that we
will be deemed to have paid and discharged the entire indebtedness represented
by such outstanding bonds and to have satisfied all our other obligations under
those bonds and the indenture insofar as those bonds are concerned, except for
the following which shall survive until otherwise terminated or discharged:
- the rights of holders of the outstanding bonds to receive, solely from
the trust funds, payments in respect of the principal of and interest and
Make-Whole Premium on those bonds when those payments are due;
- certain ministerial obligations with respect to registration, payment and
transfer of the bonds and similar matters;
- the rights, powers, trusts, duties and immunities of the trustee under
the indenture; and
- the defeasance provisions of the indenture.
In addition, we may also elect to have covenant defeasance apply. In the
event covenant defeasance occurs, (1) we will be released from our covenants
contained in the indenture, except for the covenants concerning the payment of
principal, interest and Make-Whole Premium, maintenance of office or agency and
maintenance of existence and properties; and (2) thereafter, failure to comply
with all covenants except those listed in clause (i) above will not be deemed to
be an Event of Default.
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In order to exercise either defeasance or covenant defeasance with respect
to any outstanding bonds a number of conditions must be satisfied, including the
following:
- we must irrevocably deposit or cause to be deposited with the trustee an
amount sufficient to pay and discharge the outstanding principal of and
unpaid installments of interest (and Make-Whole Premium, if any) on the
outstanding bonds on the date when those payments become due;
- we must deliver opinions of counsel and an officer's certificate as to
certain specified matters;
- we must certify that the bonds, if then listed on any securities
exchange, will not be delisted as a result of such deposit;
- no Default or Event of Default with respect to the outstanding bonds will
have occurred and be continuing on the date of the deposit or, insofar as
paragraph (6) under "-- Events of Default" is concerned, at any time
during the period ending on the 121st day after the date of the deposit;
- the defeasance or covenant defeasance will not result in a breach or
violation of, or constitute a default under, the indenture or any other
material agreement or instrument to which we are a party or by which we
are bound; and
- the defeasance or covenant defeasance will not result in the trust
arising from the deposit constituting an investment company as defined in
the Investment Company Act of 1940, as amended, or the trust will be
qualified under the act or exempt from regulation thereunder.
THE TRUSTEE
Bankers Trust Company is the trustee under the indenture. The trustee's
current address is 4 Albany Street, New York, New York 10006, Attention:
Corporate Trust Office.
COLLATERAL SECURITY
We will grant to the trustee at the closing date, on behalf of and for the
benefit of the holders, all of our right, title and interest in and to:
- the Amended and Restated PPA;
- the Power Services Agreement;
- the Administrative Services Agreement;
- our other material agreements;
- the collections and all amounts payable to us arising out of,
attributable to, in respect of or otherwise in connection with the
collections;
- all other amounts payable to us pursuant to our material agreements;
- the collections account, the liquidity account and the damages and
indemnity account and all funds and all investments and proceeds on
deposit therein from time to time;
- all our governmental approvals and general intangibles;
- all damages and other amounts payable to us in respect of the foregoing;
- all of our rights, claims, powers, privileges and remedies (whether
mandatory, discretionary or judgmental), whether arising by contract, at
law, in equity or otherwise with respect to the foregoing; and
- all present and future claims and demands in respect of any or all of the
foregoing, insurance proceeds, condemnation awards and all payments and
all proceeds of every kind and nature whatsoever in respect of any or all
of the foregoing (collectively, the "collateral").
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REPORTS TO HOLDERS
The trustee will transmit to holders such information, documents and
reports, and such summaries thereof, concerning the trustee and its actions
under the indenture as may be required pursuant to the Trust Indenture Act at
the times and in the manner provided pursuant thereto. We will notify the
trustee when any bonds are listed on any stock exchange.
MEETINGS OF HOLDERS
The trustee will call, upon the request of the holders of at least 10% in
aggregate principal amount of the outstanding bonds or our request, or, in the
event the trustee fails to call such a meeting, we or the holders of at least
10% in aggregate principal amount of the outstanding bonds may call, or the
trustee at its discretion, may call, a meeting of the holders at any time and
from time to time, to:
- give any notice to us or to the trustee, or to give any directions to the
trustee, or to waive or to consent to the waiving of any default under
the indenture and its consequences, or to take any other action
authorized to be taken by holders in connection with the occurrence of an
Event of Default;
- remove the trustee pursuant to the indenture;
- consent to the execution of a supplemental indenture; or
- take any other action authorized to be taken by or on behalf of the
holders of any specified aggregate principal amount of the bonds under
any other provision of the indenture or under applicable law.
Meetings will be held at such time and at such place in the Borough of
Manhattan, the City of New York as the trustee or we or the holders of not less
than 10% in aggregate principal amount of the outstanding bonds at the time
determine. Notice of any meeting of holders setting forth the time and the place
of that meeting and in general terms the action proposed to be taken at that
meeting will be given by the trustee not less than 20 days nor more than 120
days prior to the date fixed for the meeting.
Any holder may attend the meeting in person or by proxy.
At any meeting, the presence of persons holding or representing bonds with
respect to which the meeting is being held in an aggregate principal amount
sufficient to take action upon the business for the transaction of which the
meeting was called will be necessary to constitute a quorum; but, if less than a
quorum is present, the persons holding or representing a majority of the bonds
represented at the meeting may adjourn the meeting with the same effect, for all
intents and purposes, as though a quorum had been present. At any meeting, each
holder of a bond or a proxy will be entitled to one vote for each $1,000
principal amount of bonds held or represented by it.
GOVERNING LAW AND ENFORCEABILITY
The indenture and the bonds are governed by, and construed in accordance
with, the laws of the State of New York.
We have consented to the non-exclusive jurisdiction of any court of the
State of New York or any United States federal court sitting in The Borough of
Manhattan, New York City, New York, United States, and any appellate court from
any thereof, and have waived any immunity from the jurisdiction of these courts
over any suit, action or proceeding that may be brought in connection with the
indenture or the bonds.
We irrevocably appointed CT Corporation System as our authorized agent upon
which all writs, process and summonses may be served in any suit, action or
proceeding brought in connection with the indenture or the bonds against us in
any court of the State of New York or any United States federal court sitting in
the Borough of Manhattan, New York City and will agree that this appointment
will be irrevocable so long as any of the bonds remain outstanding or until the
irrevocable appointment by us of a
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successor in New York City as our authorized agent for such purpose and the
acceptance of this appointment by the successor.
DEFINED TERMS
"Debt Service Reserve Coverage Ratio" means, for any period, the ratio
which is equal to (a) Net Collections for that period divided by (b) Mandatory
Debt Service for that period. For the purposes of this definition, "Net
Collections" means for any period, the excess, if any, of (a) the sum of the
collections and the transfer payments from the liquidity account to the
collections account over (b) any amount payable during that period pursuant to
clauses (i)-(ii) of the Section "-- Withdrawals from the Collections Account"
and "Mandatory Debt Service" means, for any period, all scheduled interest and
principal payments and fees payable during that period in respect of the bonds.
"Default" means any event which is, or after notice or passage of time or
both would be, an Event of Default.
"Fitch" means Fitch, Inc.
"Government Approval" means any authorization, approval, consent, waiver,
exception, license, filing, registration, ruling, permit, tariff, certification,
exemption and other action or requirement by or with any governmental agency.
Without limiting the generality of the foregoing, with respect to us,
Governmental Approvals shall include approval from the Federal Energy Regulatory
Commission pursuant to Section 205 of the Federal Power Act for the rates to be
charged by us under the Amended and Restated PPA.
"Indebtedness" means with respect to any person, (a) any liability of that
person (1) for borrowed money, or under any reimbursement obligation relating to
a letter of credit, or (2) evidenced by a bond, note, debenture or similar
instrument (including a purchase money obligation) given in connection with the
acquisition of any businesses, properties or assets of any kind (other than a
trade payable or a current liability arising in the ordinary course of
business), or (3) for the payment of money relating to any obligations under any
capital lease of real or personal property which has been recorded as a
capitalized lease obligation; (b) all redeemable stock issued by that person
(the amount of Indebtedness represented by any involuntary liquidation
preference plus accrued and unpaid dividends); (c) any liability of others
described in the preceding clause (a) that the person has guaranteed or that is
otherwise its legal liability; and (d) (without duplication) any amendment,
supplement, modification, deferral, renewal, extension or refunding of any
liability of the types referred to in clauses (a), (b) and (c) above. For
purposes of determining any particular amount of Indebtedness under this
definition, guarantees of (or obligation with respect to letters of credit
supporting) Indebtedness otherwise included in the determination of that amount
shall not also be included.
"Independent Investment Banker" means Credit Suisse First Boston
Corporation or its successor.
"lien" means any security interest, mortgage, pledge, hypothecation,
assignment, assignment in trust, deposit arrangement, encumbrance, lien
(statutory or other), or preference, priority or other security agreement
(including, without limitation, any conditional sale or other title retention
agreement, any financing lease having substantially the same economic effect as
any of the foregoing, and the filing of any financing statement under the
Uniform Commercial Code of any state of the United States or comparable law of
any jurisdiction).
"Majority Holders" means the holders of not less than 51% in aggregate
principal amount of the outstanding bonds.
"Make-Whole Premium" means an amount equal to the Discounted Present Value
calculated for any bond subject to redemption less the unpaid principal amount
of that bond; provided that the Make-Whole Premium shall not be less than zero.
For purposes of this definition, the "Discounted Present Value" of any bond
subject to redemption shall be equal to the discounted present value of all
principal and interest payments scheduled to become due in respect of that bond
after the date of this redemption, calculated by the Independent Investment
Banker using a discount rate equal to the sum of (1) the yield to maturity on
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the United States treasury security having an average life equal to the
remaining average life of that bond and trading in the secondary market at the
price closest to par and (2) 50 basis points; provided, however, that, if there
is no United States treasury security having an average life equal to the
remaining average life of that bond, this 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 that bond and trading in the
secondary market at the price closest to par.
"Material Adverse Effect" means an event, occurrence or condition which has
or could reasonably be expected to have a material adverse effect on (i) the
business, operations, property, condition (financial or otherwise) of us, El
Paso Energy or PSE&G, (ii) the rights or remedies of the trustee or holders
under the financing documents, (iii) our ability or the ability of El Paso
Energy or PSE&G to perform our or their obligations under the financing
documents or our material agreements, or (iv) the validity, enforceability or
priority of the liens on the collateral.
"Moody's" means Moody's Investors Service, Inc.
"Permitted Investments" means the following investments maturing in each
case, not less than one business day before the Interest Payment Date next
following the date such investment is made; provided, however, that in the case
of any investment pursuant to clause (b) of this definition which is made with
the trustee, such investment may mature on such Interest Payment Date:
(a) any direct obligations of, or obligations fully guaranteed by, the
United States of America, or any agency or instrumentality of the United
States of America, the obligations of which are fully backed by the full
faith and credit of the United States of America;
(b) demand and time deposits in, certificates of deposit of, bankers'
acceptances issued by, or federal funds sold by any depository institution
or trust company incorporated under the laws of the United States of
America or any State thereof and subject to supervision and examination by
federal and/or state authorities, or incorporated under the laws of any
other jurisdiction, so long as at the time of such investment or
contractual commitment providing for such investment the unsecured
commercial paper or other unsecured short-term debt obligations of such
depository institution or trust company have at least the Required Credit
Rating from Moody's and Standard & Poor's;
(c) repurchase obligations with respect to any security described in
clauses (a) or (b) above, in each case entered into with either (i) a
depository institution or trust company (acting as principal) which in
respect of its short-term unsecured debt has at least the Required Credit
Rating from Moody's and Standard & Poor's; or (ii) a money market fund
maintained by a broker which in respect of its short-term unsecured debt
has at least the Required Credit Rating from Moody's and Standard & Poor's;
(d) unsecured debt securities bearing interest or sold at a discount
issued by any corporation incorporated under the laws of the United States
of America, or any State thereof, which have at the time of such investment
at least the Required Credit Rating from Moody's and Standard & Poor's;
(e) unsecured commercial paper which has at the time of such
investment at least the Required Credit Rating from Moody's and Standard &
Poor's; and
(f) investments in money market funds or money market mutual funds
which have at the time of such investment at least the Required Credit
Rating from Moody's and Standard & Poor's (including such funds for which
the trustee or any of its affiliates is investment manager or advisor and
for which the trustee or any of its affiliates may receive a fee).
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"Rating Agency" means, individually, each of Moody's and Standard & Poor's,
so long as such persons maintain a rating on the bonds; and if either Moody's or
Standard & Poor's no longer maintains a rating on the bonds, such other
nationally recognized statistical rating organization selected by the trustee;
collectively, the "Rating Agencies."
"Required Credit Rating" means P-l (or its equivalent) from Moody's and A-l
(or its equivalent) from Standard & Poor's.
"Standard & Poor's" means Standard & Poor's Rating Services.
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DESCRIPTION OF OUR PRINCIPAL FINANCING DOCUMENTS
The following summaries of certain provisions of the financing documents
(other than the indenture and the bonds which are described in "Description of
the Bonds") do not purport to be complete and are subject to, and are qualified
in their entirety by reference to, all of the provisions of such financing
documents, including the definitions therein. Copies of such financing documents
are available for inspection at the corporate trust office of the trustee. We
urge you to read such financing documents because they, and not this
description, define your rights as holder of the bonds.
SECURITY DOCUMENTS
Consents
Each of EPM, PSE&G and El Paso Energy entered into a consent and agreement
with the trustee and us whereby such party among other things, consented to the
assignment to the trustee of all of its right, title, interest and obligations
under our material agreements to which it is a party and agreed:
- to provide certain notifications to the trustee; and
- to not suspend (in the case of EPM and El Paso Energy) or terminate the
applicable agreement without providing the trustee or its designee the
opportunity to cure any default within 60 days (or within 30 days in the
case of the Amended and Restated PPA) after the last day of the cure
period in the applicable agreement. Assignment by PSE&G of its rights
under the Amended and Restated PPA is prohibited without our consent
unless the assignee is an entity with a credit rating at least equivalent
to PSE&G's rating from both Moody's and Standard & Poor's. In addition,
pursuant to the consent and agreement with PSE&G, in the event that the
trustee or any designee or assignee succeeds to our interests under the
Amended & Restated PPA, this successor will assume liability for our
obligations under the Amended & Restated PPA, including those obligations
arising prior to succession.
Account Control Agreement
We entered into an Account Control Agreement with the trustee and Bankers
Trust Company as security intermediary in order to perfect the trustee's
security interest in the security entitlements credited to the accounts and
pursuant to which Bankers Trust Company agrees to act as securities
intermediary.
PERFECTION OF SECURITY INTERESTS
The security interests granted under the financing documents will be
perfected to the extent that perfection may be obtained by filing financing
statements under the UCC and in the case of the securities entitlements credited
to the accounts, through the Account Control Agreement.
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CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES
UNITED STATES FEDERAL INCOME TAX
The summary of federal income tax consequences, prepared by Chadbourne &
Parke LLP, is for general information only. We urge you to consult your own tax
advisors as to the precise federal, state, local and other tax consequences of
the exchange offer.
The following discussion summarizes certain material United States federal
income tax consequences to beneficial owners arising from the exchange offer.
The remainder of this discussion generally refers to the Series A bonds and the
Series B bonds as the "bonds." The discussion which follows is based on the U.S.
Internal Revenue Code of 1986, as amended, the Treasury regulations promulgated
thereunder, and judicial and administrative interpretations thereof, all as in
effect on the date hereof, and is subject to any changes in these or other laws
occurring after such date, possibly with retroactive effect.
For purposes of this summary, the term "U.S. Holder" means a beneficial
owner of a bond that is, for U.S. federal income tax purposes, (a) an individual
who is a U.S. citizen or resident, (b) a corporation or partnership (other than
a partnership that is not treated as a U.S. person under any applicable Treasury
regulations) created or organized under the laws of the United States or any
political subdivision thereof, or (c) an estate or trust that is otherwise
subject to U.S. federal income tax on a net basis with respect to its worldwide
income. The term "Non-U.S. Holder" means the beneficial owner of a bond who is
not, for U.S. federal income tax purposes, a U.S. Holder.
The discussion which follows is intended as a descriptive summary only and
is not intended as tax advice to any particular investor. This summary is not a
complete analysis or listing of all potential U.S. federal income tax
consequences to U.S. Holders and Non-U.S. Holders relating to the bonds, and
does not address the effect of any United States gift, estate, state or local
tax law or foreign tax law on a potential investor in the bonds.
This summary is generally limited to investors who will hold the bonds as
"capital assets" within the meaning of Section 1221 of the Internal Revenue Code
and whose functional currency is the United States dollar. This summary does not
address the tax treatment of U.S. Holders and Non-U.S. Holders that may be
subject to special income tax rules such as insurance companies, tax-exempt
organizations, banks, U.S. Holders subject to the alternative minimum tax,
United States expatriates, holders that are broker-dealers in securities,
holders that own (directly, indirectly or by attribution) 10 percent or more of
our equity interests, or that hold the bonds as a hedge against currency risks,
as a position in a "straddle" for tax purposes, or as part of a conversion or
other integrated transaction.
Exchange Offer
The exchange of Series A bonds for Series B bonds pursuant to the exchange
offer should not constitute a taxable exchange for U.S. federal income tax
purposes. Accordingly, a U.S. Holder should not recognize gain or loss upon the
receipt of Series B bonds pursuant to the exchange offer, and a U.S. Holder
should be required to include interest on the Series B bonds in gross income in
the manner and to the extent interest income was includable under the Series A
bonds. A U.S. Holder's holding period for the Series B bonds should include the
holding period of the Series A bonds exchanged therefor, and such U.S. Holders'
adjusted basis in the Series B bonds should be the same as the basis of the
Series A bonds exchanged therefor immediately before the exchange.
U.S. Holders
Interest on the Bonds. Interest on a bond will be includable in the gross
income of a U.S. Holder as ordinary interest income at the time such interest is
treated as received or accrued, in accordance with the U.S. Holder's method of
accounting for U.S. federal income tax purposes. We expect that the bonds will
not be considered to be issued with original issue discount for U.S. federal
income tax purposes.
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<PAGE> 91
Make-Whole Premium. The bonds provide for the payment of additional
amounts under the circumstances described above under "Description of the
Bonds -- Payment of Principal and Interest," and, therefore, are subject to the
Treasury regulations that apply to debt instruments that provide for one or more
contingent payments. We believe that the possible payment of such additional
amounts would not cause the bonds to be treated as having been issued with
original issue discount under those Treasury regulations, because, as of the
issue date, the possibility of such payment is "remote," and would therefore be
ignored. In such circumstances, the rules described above under "-- Interest on
the Bonds" would apply. Our determination that such payments are a remote
contingency for these purposes is binding on a U.S. Holder, unless such U.S.
Holder discloses in the proper manner to the Internal Revenue Service that it is
taking a different position.
Market Discount. A U.S. Holder that purchases a bond at a market discount
(as described below) generally will be required to treat any principal payments
on, or any gain on the disposition or maturity of, such bond as ordinary income
to the extent of the accrued market discount (not previously included in income)
at the time of such payment or disposition. In general, market discount is the
amount by which the bond's stated redemption price at maturity exceeds the U.S.
Holder's basis in the bond immediately after the bond is acquired. A bond is not
treated as purchased at a market discount, however, if the market discount is
less than 0.25% of the stated redemption price at maturity of the bond
multiplied by the number of complete years to maturity from the date when the
U.S. Holder acquired the bond. Market discount on a bond will accrue on a
straight-line basis, unless the U.S. Holder elects to accrue such discount on a
constant yield to maturity basis. This election is irrevocable and applies only
to the bond for which it is made. The U.S. Holder may also elect to include
market discount in income currently as it accrues. This election, once made,
applies to all market discount obligations acquired on or after the first day of
the first taxable year to which the election applies and may not be revoked
without the consent of the IRS. Generally, if a bond with market discount is
transferred in specified non-taxable transactions (other than a non-recognition
transaction described in Section 1276(c) of the Code), accrued market discount
will be includable as ordinary income to the U.S. Holder as if such U.S. Holder
sold the bond at its fair market value. A U.S. Holder may be required to defer
until the maturity of the bond or, in certain circumstances, its earlier
disposition, the deduction for all or a portion of the interest expense
attributable to debt incurred or continued to purchase or carry a bond with
market discount, unless an election to include the market discount on a current
basis is made.
Amortizable Bond Premium. A U.S. Holder that purchases a bond for an
amount in excess of its stated principal amount at maturity will generally be
considered to have purchased the bond with "amortizable bond premium." A U.S.
Holder generally may elect to amortize such premium using the constant yield to
maturity method. The amount amortized in any year will generally be treated as a
reduction of the U.S. Holder's interest income on the bond. The premium on a
bond held by a U.S. Holder that does not make such an election will decrease the
gain or increase the loss otherwise recognized on the sale, redemption,
retirement or other disposition of the bond. The election to amortize the
premium on a constant yield to maturity method, once made, applies to all debt
obligations held or subsequently acquired by the electing U.S. Holder on or
after the first day of the first taxable year to which the election applies and
may not be revoked without the consent of the IRS.
Disposition of the Bonds. In general, a U.S. Holder's adjusted tax basis
in a bond will equal the cost of such bond to the U.S. Holder, increased by the
amount of any market discount previously included in the U.S. Holder's income
with respect to the bond, and reduced by (i) the amount of any principal
payments on the bond and (ii) the amortized amount of any amortizable bond
premium on the bond.
A U.S. Holder will generally recognize gain or loss on the sale, retirement
or other disposition of a bond in an amount equal to the difference between (i)
the amount of cash and the fair market value of property received by such U.S.
Holder on such sale, retirement or other disposition (less any amounts
attributable to accrued but unpaid interest which will be taxable as such) and
(ii) the U.S. Holder's adjusted tax basis in the bond (as described above). Gain
or loss upon the sale, retirement or other disposition of a bond will be capital
gain or loss if the bond is a capital asset in the hands of the U.S. Holder and,
in the case of an individual U.S. Holder, will be subject to U.S. federal income
tax at a
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<PAGE> 92
reduced rate if such bond was owned by such U.S. Holder for more than one year.
Gains on the sale of capital assets held for one year or less are subject to
U.S. federal income tax at ordinary income rates. Certain limitations exist on
the deductibility of capital losses by both corporations and individual
taxpayers.
Non-U.S. Holders
A Non-U.S. Holder of a bond generally will not be subject to U.S. federal
income tax by withholding or otherwise on the payment of interest (generally,
including stated interest and market discount, as adjusted by amortizable bond
premium) on a bond provided that the beneficial owner of the bond fulfills the
certification requirements set forth in applicable Treasury regulations unless
(A) such Non-U.S. Holder (i) actually or constructively owns 10% or more of the
total combined voting power of the equity of the Company entitled to vote, (ii)
is a controlled foreign corporation related, directly or indirectly, to the
Company through equity ownership or (iii) is a bank receiving interest described
in Section 881(c)(3)(A) of the Internal Revenue Code or (B) such interest is
effectively connected with the conduct of a trade or business by the Non-U.S.
Holder in the United States. Under these certification requirements, either (i)
the beneficial owner of the bond certifies to the Company or its agent, under
penalties of perjury, that it is not a U.S. Holder and provides its name and
address on the appropriate U.S. Treasury Form W-8 (or on a suitable substitute
form) or (ii) a securities clearing organization, bank or other financial
institution that holds customers' securities in the ordinary course of its trade
or business (a "financial institution") and that holds the bond certifies under
penalties or perjury that such Form W-8 (or suitable substitute form) has been
received from the beneficial owner by it or by a financial institution between
it and the beneficial owner and furnishes the payer with a copy thereof.
A Non-U.S. Holder generally will not be subject to United States federal
income tax by withholding or otherwise on gain realized on the sale, retirement
or other disposition of a bond, unless (i) such gain is effectively connected
with the conduct by such Non-U.S. Holder of a trade or business within the
United States, or (ii) such gain is realized by an individual Non-U.S. Holder
who is present in the United States for at least 183 days in the taxable year of
the sale, retirement or other disposition, and specified other conditions are
met.
UNITED STATES INFORMATION REPORTING AND BACKUP WITHHOLDING
Payments of principal, premium and interest and the proceeds from the
disposition by certain non-corporate holders of bonds may be subject to U.S.
information reporting and backup withholding. A U.S. Holder generally will be
subject to U.S. information reporting and backup withholding at a rate of 31%
unless the U.S. Holder supplies an accurate taxpayer identification number, as
well as certain other information, or otherwise establishes, in the manner
prescribed by law, an exemption. U.S. information reporting and backup
withholding may also apply to Non-U.S. Holders that are not "exempt recipients"
and that fail to provide specified information as may be required by U.S. law
and applicable regulations. The payment of principal, premium and interest on,
or the proceeds of the disposition of, bonds to a U.S. paying agent or through
the U.S. office of a broker will be subject to U.S. information reporting and
backup withholding unless the owner certifies its status as a Non-U.S. Holder
under penalties of perjury or otherwise establishes an exemption. The payment of
principal, premium or interest on and the proceeds of the disposition by a
Non-U.S. Holder of the bonds to or through a foreign office of a broker will
generally not be subject to backup withholding, unless such broker has specified
U.S. relationships. Any amount withheld under backup withholding is not an
additional tax and is generally allowable as a credit against the U.S. Holder's
federal income tax upon furnishing the required information to the IRS.
Treasury regulations, generally effective for payments made after December
31, 2000, subject to certain transition rules (the "New Withholding
Regulations"), will change some of the backup withholding and information
reporting rules discussed above. You should consult your own tax advisors
regarding the application of the U.S. information reporting and backup
withholding rules to your particular situation, including your qualification for
exemption therefrom, and the procedure for obtaining such an exemption, if
applicable, and the application of the New Withholding Regulations.
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<PAGE> 93
CERTAIN ERISA CONSIDERATIONS
If you intend to use plan assets to purchase any of the bonds offered for
sale in connection with this prospectus, you should consult with counsel on the
potential consequences of your investment under the fiduciary responsibility
provisions of the Employee Retirement Income Security Act of 1974, as amended,
and the prohibited transaction provisions of ERISA. If you intend to use
governmental or church plan assets to purchase any of the bonds, you should
consult with counsel on the potential consequences of your investment under
similar provisions applicable under laws governing governmental and church
plans.
The following summary is based on the provisions of ERISA and the Internal
Revenue Code and related guidance in effect as of the date of this prospectus.
This summary does not attempt to be a complete summary of these considerations.
Future legislation, court decisions, administrative regulations or other
guidance will change the requirements summarized in this section. Any of these
changes could be made retroactively and could apply to transactions entered into
before the change is enacted.
FIDUCIARY RESPONSIBILITIES
ERISA imposes certain requirements on (1) employee benefit plans subject to
ERISA, (2) entities whose underlying assets include employee benefit plan
assets, for example, collective investment funds and insurance company general
accounts, and (3) fiduciaries of employee benefit plans. Under ERISA,
fiduciaries generally include persons who exercise discretionary authority or
control over plan assets. Before investing any employee benefit plan assets in
any bond offered in connection with this prospectus, you should determine
whether the investment:
(1) is permitted under the plan document and other instruments
governing the plan; and
(2) is appropriate for the plan in view of its overall investment
policy and the composition and diversification of its portfolio, taking
into account the limited liquidity of the bonds.
You should consider all factors and circumstances of a particular
investment in the bonds, including for example the risk factors discussed in
"Risk Factors" and the fact that in the future there may not be a market in
which you will be able to sell or otherwise dispose of your interest in the
bonds.
We are not making any representation that the sale of any bonds to a plan
meets the fiduciary requirements for investment by plans generally or any
particular plan or that such an investment is appropriate for plans generally or
any particular plan.
PROHIBITED TRANSACTIONS
ERISA and the Internal Revenue Code prohibit a wide range of transactions
involving (1) employee benefit plans and arrangements subject to ERISA and/or
the Internal Revenue Code, and (2) persons who have certain relationships to the
plans. These persons are called "parties in interest" under ERISA and
"disqualified persons" under the Internal Revenue Code. The transactions
prohibited by ERISA and the Internal Revenue Code are called "prohibited
transactions." If you are a party in interest or disqualified person who engages
in a prohibited transaction, you may be subject to excise taxes and other
penalties and liabilities under ERISA and/or the Internal Revenue Code. As a
result, if you are considering using plan assets to invest in any of the bonds
offered for sale in connection with this prospectus, you should consider whether
the investment might be a prohibited transaction under ERISA and/or the Internal
Revenue Code.
Prohibited transactions may arise, for example, if the bonds are acquired
by a plan with respect to which we, or any of our affiliates, are a party in
interest or a disqualified person. Certain exemptions from the prohibited
transaction provisions of ERISA and the Internal Revenue Code may apply
depending in
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<PAGE> 94
part on the type of plan fiduciary making the decision to acquire a bond and the
circumstances under which such decision is made. Some of these exemptions
include:
(1) Prohibited transaction class exemption or "PTCE" exemptions 96-23,
(relating to certain transactions directed by in-house asset managers);
(2) PTCE 95-60 (relating to certain transactions involving insurance
company general accounts);
(3) PTCE 91-38 (relating to certain transactions by bank collective
investment funds);
(4) PTCE 90-1 (relating to certain transactions involving insurance
company pooled separate accounts);
(5) PTCE 84-14 (relating to certain transactions directed by
independent qualified professional asset managers); and
(6) PTCE 75-1 (relating to certain transactions involving employee
benefit plans and broker-dealers, reporting dealers and banks).
These exemptions, do not, however, provide relief from the self-dealing
prohibitions under ERISA and the Internal Revenue Code. In addition, there is no
assurance that any of these class exemptions or other exemption will be
available with respect to any particular transaction involving the bonds.
TREATMENT OF BONDS AS DEBT INSTRUMENTS
Certain transactions involving our operation could give rise to prohibited
transactions under ERISA and the Internal Revenue Code if our assets were deemed
to be plan assets. Pursuant to Department of Labor Regulations Section
2510.3-101 (which we refer to as the "plan assets regulations"), in general,
when a plan acquires an "equity interest" in an entity such as Cedar Brakes I,
L.L.C., the plan's assets include both the equity interest and an undivided
interest in each of the underlying assets of the entity unless certain
exceptions set forth in the plan assets regulations apply.
In general, an "equity interest" is defined under the plan assets
regulations as any interest in an entity other than an instrument which is
treated as indebtedness under applicable local law and which has no substantial
equity features. Although there is very little published authority concerning
the application of this definition, we believe that the bonds should be treated
as debt rather than equity interest under the plan assets regulations because
the bonds (1) should be treated as indebtedness under applicable local law and
debt, rather than equity, for United States tax purposes and (2) should not be
deemed to have any "substantial equity features." However, no assurance can be
given that the bonds will be treated as debt for purposes of ERISA. If the bonds
were to be treated as an equity interest under the plan assets regulations, the
purchase of the bonds using plan assets could cause our assets to become subject
to the fiduciary and prohibited transaction provisions of ERISA and the Internal
Revenue Code unless investment in the bonds by "benefit plan investors" is not
"significant," as determined under the plan assets regulations. We cannot assure
you that the criteria for this exception will be satisfied at any particular
time and no monitoring or other measures will be taken to determine whether such
criteria are met. This means that, if the bonds are treated as equity interests
under the plan asset regulations and investment in the bonds by benefit plan
investors is significant, our assets could be treated as the plan assets subject
to ERISA and a non-exempt prohibited transaction could arise in connection with
our operating activities.
Any insurance company proposing to invest assets of its general account in
the bonds should consider the implications of the U.S. Supreme Court's decision
in John Hancock Mutual Life Insurance Co. v. Harris Trust and Savings Bank, 501
U.S. 86, 114 S. Ct. 517 (1993), which, in certain circumstances, treats such
general account as including the assets of a plan that owns a policy or other
contract with such insurance company, as well as the effect of Section 401(c) of
ERISA, as interpreted by regulations proposed by the Department of Labor.
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<PAGE> 95
GOVERNMENT AND CHURCH PLANS
Governmental plans and certain church plans, while not subject to the
fiduciary responsibility provisions of ERISA or the prohibited transactions
provisions of ERISA or the Internal Revenue Code, may be subject to state or
other federal laws that are very similar to the provisions of ERISA and the
Internal Revenue Code. If you are a fiduciary of a governmental or church plan,
you should consult with counsel before purchasing any bonds offered for sale in
connection with this prospectus.
FOREIGN INDICIA OF OWNERSHIP
ERISA also prohibits plan fiduciaries from maintaining the indicia of
ownership of any plan assets outside the jurisdiction of the United States
district courts except in certain cases. Before investing in any bond offered
for sale in connection with this prospectus, you should consider whether the
acquisition, holding or disposition of a bond would satisfy such indicia of
ownership rules.
REPRESENTATIONS AND WARRANTIES
If you acquire or accept a bond offered in connection with this prospectus,
you will be deemed to have represented and warranted that either:
(1) you have not used plan assets to acquire such bond; or
(2) your acquisition and holding of a bond (A) is exempt from the
prohibited transaction restrictions of ERISA and the Internal Revenue Code
under one or more prohibited transaction class exemptions or does not
constitute a prohibited transaction under ERISA and the Internal Revenue
Code, and (B) meets the fiduciary requirements of ERISA.
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 you may transfer Series B bonds
issued under the exchange offer in exchange for Series A bonds unless you are:
- our "affiliate" within the meaning of Rule 405 under the Securities Act;
- a broker-dealer that acquired Series A bonds directly from us; or
- a broker-dealer that acquired Series A bonds as a result of market-making
or other trading activities without compliance with the registration and
prospectus delivery provisions of the Securities Act;
provided that you acquire the Series B bonds in the ordinary course of your
business and you are not engaged in, and do not intend to engage in, and have no
arrangement or understanding with any person to participate in, a distribution
of the Series B bonds. Broker-dealers receiving Series B bonds in the exchange
offer will be subject to a prospectus delivery requirement with respect to
resales of the Series B bonds.
To date, the staff of the SEC has taken the position that participating
broker-dealers may fulfill their prospectus delivery requirements with respect
to transactions involving an exchange of securities such as this exchange offer,
other than a resale of an unsold allotment from the original sale of the Series
A bonds, with the prospectus contained in the exchange offer registration
statement.
Pursuant to the Registration Agreement, each broker-dealer that receives
Series B bonds for its own account pursuant to the exchange offer must
acknowledge that it will deliver a prospectus in connection with any resale of
such Series B bonds. This prospectus, as it may be amended or supplemented from
time to time, may be used by a broker-dealer in connection with resales of
Series B bonds received in exchange for Series A bonds where such Series A bonds
were acquired as a result of market-making activities or other trading
activities. We have agreed that, for a period of 180 days after the expiration
date, we will
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make this prospectus, as amended or supplemented, available to any broker-dealer
for use in connection with any such resale. In addition, until [ ],
2000, all dealers effecting transactions in the Series B Bonds may be required
to deliver a prospectus.
We will not receive any proceeds from any sale of Series B bonds by
broker-dealers. Series B bonds received by broker-dealers for their own account
pursuant to the exchange offer may be sold from time to time in one or more
transactions in the over-the-counter market, in negotiated transactions, through
the writing of options on the Series B 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 Series B bonds. Any broker-dealer
that resells Series B bonds that were received by it for its own account
pursuant to the exchange offer and any broker or dealer that participates in a
distribution of such Series B bonds may be deemed to be an "underwriter" within
the meaning of the Securities Act and any profit on any such resale of Series B
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 180 days after the expiration date, we will promptly send
additional copies of this prospectus and any amendment or supplement to this
prospectus to any broker-dealer that requests such documents in the letter of
transmittal. We have agreed to pay all expenses incident to the 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.
LEGAL MATTERS
Our counsel, Chadbourne & Parke LLP, New York, New York, will issue an
opinion regarding the validity of the bonds and other specified legal matters.
EXPERTS
The financial statements as of September 30, 2000 and for the period from
inception (March 3, 2000) to September 20, 2000 included in this Prospectus have
been so included in reliance on the report of PricewaterhouseCoopers LLP,
independent accountants, given on the authority of said firm as experts in
auditing and accounting.
Pace prepared the Power Services Agreement Assessment included as Annex A
to this prospectus. We include this report in this prospectus in reliance upon
Pace's authority as a consultant in evaluation of power markets and related
matters. You should read this report in its entirety for information contained
therein with respect to the PJM power market and the related matters discussed
therein.
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<PAGE> 97
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Accountants........................... F-2
Financial Statements:
Statement of Income....................................... F-3
Balance Sheet............................................. F-4
Statement of Cash Flows................................... F-5
Statement of Member's Equity.............................. F-6
Notes to the Financial Statements........................... F-7
</TABLE>
F-1
<PAGE> 98
REPORT OF INDEPENDENT ACCOUNTANTS
To the Member of Cedar Brakes I, L.L.C.:
In our opinion, the accompanying balance sheet and the related statements
of income, of member's equity and of cash flows present fairly, in all material
respects, the financial position of Cedar Brakes I, L.L.C. (the "Company") at
September 30, 2000, and the results of its operations and its cash flows for the
period from inception (March 3, 2000) to September 30, 2000, in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audit. We conducted our audit of these statements in accordance with
auditing standards generally accepted in the United States of America, which
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, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
------------------------------------------
Houston, Texas
November 10, 2000
F-2
<PAGE> 99
CEDAR BRAKES I, L.L.C.
STATEMENT OF INCOME
FOR THE PERIOD FROM INCEPTION (MARCH 3, 2000) TO SEPTEMBER 30, 2000
(IN THOUSANDS)
<TABLE>
<S> <C>
Operating revenues
Electricity sales......................................... $849
----
Operating expenses
Electricity purchases..................................... 276
Administrative fees....................................... 1
Amortization of the power purchase agreement.............. 186
----
463
----
Operating income............................................ 386
----
Interest and debt expense................................... 298
----
Net income.................................................. $ 88
====
</TABLE>
See accompanying notes.
F-3
<PAGE> 100
CEDAR BRAKES I, L.L.C.
BALANCE SHEET
AS OF SEPTEMBER 30, 2000
(IN THOUSANDS)
<TABLE>
<S> <C>
ASSETS
Current assets
Cash and cash equivalents................................. $ 2,397
Accounts receivable
Trade.................................................. 849
Affiliate.............................................. 481
--------
Total current assets................................... 3,727
Power purchase agreement, net............................... 289,644
Restricted cash............................................. 13,201
Deferred financing costs, net............................... 5,119
--------
Total assets...................................... $311,691
========
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Accounts payable -- affiliate............................. $ 277
Accrued interest payable.................................. 294
Other accrued liabilities................................. 432
--------
Total current liabilities......................... 1,003
Long-term debt.............................................. 310,600
Commitments
Member's equity............................................. 88
--------
Total liabilities and member's equity............. $311,691
========
</TABLE>
See accompanying notes.
F-4
<PAGE> 101
CEDAR BRAKES I, L.L.C.
STATEMENT OF CASH FLOWS
FOR THE PERIOD FROM INCEPTION (MARCH 3, 2000) TO SEPTEMBER 30, 2000
(IN THOUSANDS)
<TABLE>
<S> <C>
OPERATING ACTIVITIES
Net income................................................ $ 88
Adjustments to reconcile net income to net cash used in
operating activities
Amortization of the power purchase agreement........... 186
Amortization of deferred financing costs............... 4
Working capital changes
Accounts receivable -- trade and affiliate........... (1,330)
Accounts payable -- affiliate........................ 277
Accrued interest payable............................. 294
Other accrued liabilities............................ 432
---------
Net cash used in operating activities............. (49)
---------
INVESTING ACTIVITIES
Purchase of power purchase agreement...................... (289,830)
---------
Net cash used in investing activities............. (289,830)
---------
FINANCING ACTIVITIES
Net proceeds from issuance of long-term debt.............. 305,477
Increase in restricted cash............................... (13,201)
---------
Net cash provided by financing activities......... 292,276
---------
NET CHANGE IN CASH AND CASH EQUIVALENTS..................... 2,397
CASH AND CASH EQUIVALENTS, beginning of period.............. --
---------
CASH AND CASH EQUIVALENTS, end of period.................... $ 2,397
=========
</TABLE>
See accompanying notes.
F-5
<PAGE> 102
CEDAR BRAKES I, L.L.C.
STATEMENT OF MEMBER'S EQUITY
FOR THE PERIOD FROM INCEPTION (MARCH 3, 2000) TO SEPTEMBER 30, 2000
(IN THOUSANDS)
<TABLE>
<S> <C>
Initial capital contribution on March 3, 2000............... $ 1
Contribution receivable from member......................... (1)
Net income.................................................. 88
---
Balance, September 30, 2000................................. $88
===
</TABLE>
See accompanying notes.
F-6
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CEDAR BRAKES I, L.L.C.
NOTES TO THE FINANCIAL STATEMENTS
1. ORGANIZATION AND NATURE OF OPERATIONS
We are a single member Delaware limited liability company organized in
March 2000, pursuant to the terms of a limited liability company agreement. We
are owned indirectly by Chaparral Investors, L.L.C. Chaparral is owned by
Limestone Electron Trust and El Paso Energy Corporation and was established to
own and manage investments in domestic power and natural gas assets within North
America. Chaparral indirectly owns interests in (i) twenty-two commercially
operating gas-fired power facilities in New Jersey, Rhode Island, Massachusetts,
Colorado, Nevada and California, and (ii) two gas-fired power facilities under
construction in Connecticut and Florida.
In September 2000, we acquired a long-term power purchase agreement to sell
electric capacity and electric energy to Public Service Electric & Gas Company
(PSE&G). We do not have any employees and our operations are carried out by El
Paso Merchant Energy, L.P. (EPM), a subsidiary of El Paso Energy, under a
long-term administrative services agreement (see Note 6). We purchase the
electric capacity and energy necessary to meet our obligations under our power
purchase agreement from EPM under a long-term power services agreement (see Note
5).
2. LIMITED LIABILITY COMPANY
Under Delaware law, no member of a limited liability company is obligated
personally for any debt, obligation, or liability of a limited liability company
simply because they are a member of that limited liability company. Such debts,
liabilities and obligations are solely those of the limited liability company.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our financial statements are prepared on the accrual basis of accounting in
conformity with accounting principles generally accepted in the United States.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates
and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses and disclosure of contingent assets and liabilities that
exist at the date of the financial statements. Actual results are likely to
differ from those estimates.
Cash and Cash Equivalents
We consider short-term investments purchased with an original maturity of
three months or less to be cash equivalents.
Restricted Cash
As required by our bond indenture (see Note 4), we established a restricted
cash fund from the proceeds of our bond issuance equal to the amount of a
semi-annual interest payment. We must maintain this fund through the maturity
date of the bonds. As of September 30, 2000, we had restricted cash of $13.2
million.
Allowance for Doubtful Accounts
We review collectibility of our accounts receivable on a regular basis,
primarily under the specific identification method. At September 30, 2000, no
allowance for doubtful accounts was recorded.
F-7
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CEDAR BRAKES I, L.L.C.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
Intangible Assets
Our intangible assets represent the fair value of a power purchase
agreement we acquired which we are amortizing on a straight-line basis over the
power purchase agreement's life, which is thirteen years. Amortization of
intangible assets was approximately $186 thousand for the period ended September
30, 2000.
We evaluate the impairment of our intangibles in accordance with Statement
of Financial Accounting Standards (SFAS) No. 121 Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. Under this
methodology, when an event occurs to suggest that impairment may have occurred,
we review the undiscounted net cash flows of the underlying asset. If these cash
flows are not sufficient to recover the amount of the underlying asset on our
books, these cash flows are discounted at a risk-adjusted rate with the
difference recorded as an impairment in the Statement of Income. No impairments
were recorded during the period ended September 30, 2000.
Deferred Financing Costs
Our deferred financing costs represent the cost to issue our bonds and are
being amortized using the straight-line method over the life of the bonds.
Amortization of deferred financing costs was approximately $4 thousand for the
period ended September 30, 2000.
Income Taxes
Since we are a limited liability company, income taxes accrue to our
members. As a result, we have not reflected a provision for income taxes in our
financial statements.
Revenue Recognition
We recognize revenue when we deliver electricity. Revenue is based on the
quantity of electricity delivered at rates specified under contractual terms.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities. In June of 1999,
the FASB extended the adoption date of SFAS No. 133 through the issuance of SFAS
No. 137, Deferral of the Effective Date of FASB Statement No. 133. In June 2000,
the FASB issued SFAS No. 138, Accounting for Certain Derivative Instruments and
Certain Hedging Activities, which also amended SFAS No. 133. SFAS No. 133, and
its amendments and interpretations, establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. It will require that we
measure all derivative instruments at their fair value, and classify them as
either assets or liabilities on our balance sheet, with a corresponding offset
to income or other comprehensive income depending on their designation, their
intended use, or their ability to qualify as hedges under the standards. We will
adopt SFAS No. 133 beginning January 1, 2001, and will apply the standard to all
derivative instruments that exist on that date.
Our power purchase agreement and power services agreement (see Note 5) will
meet the criteria of a derivative instrument under SFAS No. 133. We anticipate
the impact of adopting SFAS No. 133 will result in an increase to our assets
ranging between $95 to $105 million and our liabilities ranging between $10 to
$20 million, with an increase to net income ranging between $85 to $95 million
based on anticipated future prices of power as of September 30, 2000, which will
be classified as a cumulative effect of a change in accounting principle.
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CEDAR BRAKES I, L.L.C.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
The amounts we will actually record upon adoption of SFAS No. 133 may
materially differ from these estimates since the amounts recorded will be based
on the fair value of the contracts at the adoption date. In addition, further
interpretation and guidance from the standard setting groups on the proper
application of SFAS No. 133's provisions may also substantially alter our
estimates.
4. LONG-TERM DEBT
In September 2000, we issued 8 1/2% Senior Secured Bonds with an aggregate
principal amount of $310.6 million. The bonds mature on February 15, 2014, with
principal paid annually on February 15 beginning in 2002. Interest payments are
due semiannually on February 15 and August 15 beginning in 2001. The bonds are
collateralized by our assets.
Obligations under our bonds are non-recourse to our members, other than the
payment of additional interest by El Paso Energy under its funding agreement
(see Note 6).
The following are aggregate maturities of the principal amounts of our
bonds for the next five years and in total thereafter:
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
2001................................................... $ --
2002................................................... 5,901
2003................................................... 7,765
2004................................................... 10,871
2005................................................... 15,219
Thereafter............................................. 270,844
--------
Total long-term debt, including current
maturities................................. $310,600
========
</TABLE>
5. COMMITMENTS
Power Purchase Agreement
In September 2000, we purchased a power purchase agreement (PPA) from
Newark Bay Cogeneration, L.P., an indirect wholly-owned subsidiary of Chaparral
for its fair market value of approximately $289.8 million. Once acquired, we
amended this agreement. Under the amended agreement, we sell electricity to
PSE&G at various fixed rates. PSE&G makes combined capacity and energy payments
to us based on actual energy delivered each month. The PPA has a term of
thirteen years and expires on August 31, 2013.
Power Services Agreement
In September 2000, we entered into a power services agreement to purchase
power from EPM at various fixed rates each year through August 2013. All power
purchased under this agreement will be supplied to PSE&G and only the amount
requested by PSE&G will be purchased. If EPM does not deliver power volumes to
us equal to the contracted amounts, they will be required to pay us liquidated
damages as defined in the agreement. EPM's performance under this agreement has
been guaranteed by El Paso Energy under a performance guaranty issued in
September 2000 (see Note 6).
6. RELATED PARTY TRANSACTIONS
Administrative Services Agreement
In September 2000, we entered into an administrative services agreement
with EPM to provide project management, finance and accounting services to us
for a fee of $100,000 per year through 2013. In
F-9
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CEDAR BRAKES I, L.L.C.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
addition to the base fee, we are obligated to reimburse EPM for certain direct
expenses other than project management, finance and accounting services that may
be incurred on our behalf. Fees and expenses under this agreement are due and
payable only to the extent that we have sufficient cash after paying obligations
under our bond indenture.
El Paso Energy Funding Agreement
We will be required to pay an additional 1/2% interest on our bonds if we
do not file a registration statement with the Securities and Exchange Commission
(SEC) within 90 days of September 26, 2000, and complete an exchange of our
current bonds for bonds registered under the rules of the SEC within 40 business
days from the date on which that registration statement has been declared
effective by the SEC. El Paso Energy is obligated under a funding agreement
entered into in September 2000 to contribute to us an amount equal to the
additional 1/2% interest on our bonds if, on the third business day prior to
any payment date, we do not have sufficient funds to pay the additional interest
due. This agreement terminates upon the consummation of the exchange of our
current bonds for bonds registered under the rules of the SEC.
El Paso Energy Performance Guaranty
El Paso Energy has entered into a performance guaranty pursuant to which El
Paso Energy has agreed to unconditionally guarantee all obligations (including
payment obligations) of EPM under the Power Services Agreement and the
Administrative Services Agreement.
Contribution Receivable
Our contribution receivable on the Statement of Member's Equity was
generated from our initial capitalization by Chaparral.
See Note 5 for additional discussion on commitments with related parties.
7. CONCENTRATION OF CREDIT RISKS
Our cash and accounts receivable potentially subject us to credit risk. Our
cash accounts are held by major financial institutions. Our trade accounts
receivable are concentrated with PSE&G which purchases electricity from us under
a long-term power purchase agreement.
8. FAIR VALUE OF FINANCIAL INSTRUMENTS
As of September 30, 2000, the carrying amounts of our financial instruments
including cash, cash equivalents, and trade receivables and payables are
representative of fair value because of their short-term maturity. The carrying
amount and fair value of our long-term debt was $310.6 million at September 30,
2000.
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[PACE LETTERHEAD]
ANNEX
A
CEDAR BRAKES I, L.L.C.
POWER SERVICES AGREEMENT ASSESSMENT
PREPARED FOR:
CREDIT SUISSE FIRST BOSTON
September 20, 2000
Legal Notice
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
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
express written permission.
This Report and information and statements herein are based in whole or in part
on information obtained from various sources. 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, 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 Cedar Brakes I, L.L.C. 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. Contract interpretation of these contracts
by legal counsel or a jurisdictional body could differ.
Finally, this Report was prepared in June 2000 and is based on 2nd Quarter Year
2000 data for fuel and electric power prices. To the best of Pace's knowledge,
since the date of preparation of the Report, no event affecting the Report or
the matters referred to herein has occurred which changes in any material
adverse respect, as of the date hereof, any finding or conclusion contained in
the Report.
[CEDAR BRAKES LOGO]
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[PACE LOGO]
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TABLE OF CONTENTS
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<TABLE>
<S> <C>
Executive Summary........................................... A-1
Transaction Summary....................................... A-1
Scope of Work............................................. A-1
Summary of Analysis....................................... A-1
Findings and Conclusions.................................. A-3
Transaction Overview........................................ A-6
Transaction Overview...................................... A-6
Capacity and Energy Delivery Requirements................. A-7
Bid Strategy and Option Value Analysis...................... A-9
Introduction.............................................. A-9
Bid Strategy Analysis..................................... A-10
Option Value Analysis..................................... A-12
PJM Market Price Forecast................................... A-14
Market Clearing Price Forecast Approach................... A-14
Approach.................................................. A-14
Simulated Market Price Forecast For PJM................... A-15
CEMAS Simulated Market Prices.......................... A-15
Average System Annual Time of Day Prices............... A-16
Adjusted Average System Annual Time of Day Prices...... A-16
Wholesale Market Transactions............................. A-17
Existing Demand Profile................................... A-18
Base Case Assumptions..................................... A-20
Regional Market Definition and Transmission
Interchange.......................................... A-21
Regional Demand Forecast............................... A-22
Fuel Pricing........................................... A-27
Existing Generating Capacity Profiles.................. A-39
Expansion Generating Capacity.......................... A-41
Pace Global Energy Services, LLC............................ A-45
</TABLE>
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EXHIBITS
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<TABLE>
<S> <C> <C>
Exhibit 1: Relationship of EPM Contract Price to Market Price.......... A-3
Exhibit 2: Summary of the Average Hourly "All-In" Power Prices ($/MWh)
for the PSA Contract, Pace's Forward Price Curve Forecast,
Pace's Forecasted Option Value-Adjusted Price and Pace's
Forecasted Bid Strategy-Adjusted Price...................... A-4
Exhibit 3: Summary Overview of the Cedar Brakes Transaction............ A-7
Exhibit 4: PSE&G Contracted Annual Energy Delivery Requirements in
MWh......................................................... A-8
Exhibit 5: Average All Hour All-In Power Prices for the PJM Market for
the May 1, 1999 through April 30, 2000...................... A-10
Exhibit 6: Average All Hour All-In Power Price and its Standard
Deviation as a Function of The Total Available Days Per Year
in the PJM Market........................................... A-11
Exhibit 7: Relationship of EPM Contract Price to Market Price.......... A-12
Exhibit 8: Summary of the Average All Hour "All-In" Power Prices
($/MWh) for the EPM Contact and Forecasted Option Value
Adjusted Values............................................. A-13
Exhibit 9: Pace CEMAS Methodology...................................... A-15
Exhibit 10: PJM Northeast Annual System Time of Day Prices -- Base Case
(1998 $/MWh)................................................ A-16
Exhibit 11: PJM Average Annual EPM Contact and Bid Strategy Prices (1998
$/MWh)...................................................... A-17
Exhibit 12: Power Marketer Transactions by NERC Region.................. A-18
Exhibit 13: PJM Demand and Energy Requirements Forecast................. A-19
Exhibit 14: PJM Market Demand and Reserve Margin Forecast -- Summer..... A-20
Exhibit 15: PJM Market Demand and Reserve Margin Forecast -- Winter..... A-20
Exhibit 16: PJM Sub-Regional Designations............................... A-21
Exhibit 17: Assumed PJM Market Area Transmission Constraints............ A-22
Exhibit 18: Historic Inter-Regional Transactions........................ A-22
Exhibit 19: Pace Load Forecasting Methodology........................... A-23
Exhibit 20: Pace PJM Energy Forecast -- GWh............................. A-25
Exhibit 21: Pace PJM Energy Forecast -- GWh............................. A-25
Exhibit 22: Pace Sub-Regional Energy Forecast for PJM -- GWh............ A-26
Exhibit 23: Pace Sub-Regional Peak Demand Forecast for PJM -- MW........ A-27
Exhibit 24: Monthly Fuel Price Adjustment Factors....................... A-28
Exhibit 25: PJM Natural Gas Price Forecasts (1998 $/MMBtu).............. A-29
Exhibit 26: Pace Gas Price Sub-regions -- PJM........................... A-30
Exhibit 27: WTI Crude Oil Price Forecast (1998 $/MMBtu)................. A-32
Exhibit 28: Pace Oil Price Sub-Regions for PJM.......................... A-33
Exhibit 29: PJM Fuel Oil Location Basis (1998 $/MMBtu).................. A-33
Exhibit 30: Crude Oil to Refined Product Crack Spreads (1998 $/MMBtu)... A-34
Exhibit 31: Fuel Oil Price Forecast by PJM Sub-Region (1998 $/MMBtu).... A-34
Exhibit 32: Definition of Coal Quality Grades........................... A-35
Exhibit 33: Coal Consumption By Sulfur Grade -- PJM..................... A-37
Exhibit 34: Projected Real Commodity Escalation Rates by Sulfur Level... A-37
Exhibit 35: Projected Average Transportation Escalation Rates........... A-38
Exhibit 36: Avg. Delivered Coal Price Forecast For PJM by Sulfur Grade
(1998 $).................................................... A-39
Exhibit 37: PJM Nuclear Units........................................... A-40
Exhibit 38: Announced Power Projects in PJM............................. A-42
Exhibit 39: Expansion Unit Characteristics.............................. A-43
Exhibit 40: High Construction Cost Areas................................ A-44
</TABLE>
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EXECUTIVE SUMMARY
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TRANSACTION SUMMARY
Cedar Brakes I, L.L.C. ("Cedar Brakes" or the "Issuer") has entered into an
Amended and Restated Power Purchase Agreement ("Amended and Restated PPA") with
Public Service Electric and Gas Company ("PSE&G"), which resulted from a
restructuring of the power purchase agreement ("Original PPA") entered into on
June 15, 1998, between the Newark Bay Cogeneration Partnership L.P. ("NBCP") and
PSE&G. The Amended and Restated PPA resulted in, among other things,
significantly reduced capacity and energy rates payable by PSE&G and
significantly more flexibility for Cedar Brakes to meet its energy and capacity
delivery obligations to PSE&G from any reliable source, not just a single power
plant.
In order to meet the 13-year power supply obligations to PSE&G under the Amended
and Restated PPA, Cedar Brakes entered into a Power Services Agreement ("PSA")
with El Paso Merchant Energy L.P. ("EPM") for the purchase of an equal amount of
capacity and energy, transferring its energy supply obligations under the
Amended and Restated PPA to EPM. El Paso Energy Corporation ("EPEC") has
ownership interests in Cedar Brakes, NBCP and EPM. Aside from energy rates, the
terms of the PSA mirror those of the Amended and Restated PPA, thus providing
EPM with the flexibility to supply energy and capacity from numerous sources
within the PJM market for delivery to Cedar Brakes, and from Cedar Brakes to
PSE&G. This flexibility in both the source and timing of energy delivery creates
significant option value to EPM. As such, the energy rates in the PSA, which
represent the option-value adjusted forecast of the PJM market, are
significantly lower than the energy rates in the Amended and Restated PPA. The
contract price differential represents the net revenue stream that is being
securitized in the bond offering.
SCOPE OF WORK
Pace Global Energy Services, LLC ("Pace"), an independent energy consulting
firm, was retained to review the PJM power market and certain provisions of the
PSA. Specifically, Pace was asked to provide an opinion as to whether (1) the
"all-in" energy and capacity prices under the PSA reasonably reflect market
pricing in the PJM region, adjusted for energy delivery flexibility ("option
value") that EPM has under the PSA, and whether (2) capacity resources within
the PJM market are sufficient to ensure that EPM can meet its contractual
obligations under the PSA. Our opinions assume that there will be no significant
changes to the PJM market with respect to the bidding process, the current cap
on bid prices and the market structure. Further, the analysis assumes there are
no adverse effects from EPM's other activities affecting its ability to perform
under the PSA with Cedar Brakes.
SUMMARY OF ANALYSIS
In order to provide an opinion as to the reasonableness of the annual PSA
contract prices, in conjunction with forecasting the PJM market clearing prices
over the term of the PSA, Pace performed two distinct analyses: a bid strategy
analysis and an option value analysis. The bid strategy analysis assesses the
potential value to EPM of selling power into the PJM market during hours when
EPM is not obligated to sell power to Cedar Brakes under the PSA. This analysis
includes a forecast of the market clearing prices during the hours in which EPM
would deliver energy under the PSA, assuming EPM fulfills its contractual
obligations during the lowest priced hours available. This forecast of PJM East
power prices is based on Pace's Capacity & Energy Market Analysis System
("CEMAS") 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
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energy under a defined set of assumptions. The option value analysis quantifies
the value to EPM derived from the delivery flexibility provided for in the PSA.
This analysis is a more conservative approach to valuing the energy delivery
flexibility contained in the PSA, as compared to the bid strategy analysis.
These analyses were performed in order to assess the value of the energy
delivery flexibility contained in the PSA.
THE BID STRATEGY ANALYSIS
The bid strategy analysis assessed the energy delivery flexibility in the PSA
that allows EPM to direct on a daily basis power deliveries, within contract
limits, to either the Cedar Brakes contract or to the PJM market. This analysis
was based on a strategy that would minimize the all-in cost to EPM of
electricity delivered under the PSA. By utilizing its contractual flexibility on
a daily basis EPM can, with fairly high certainty, sell power during the higher
priced days in the PJM market, while delivering the balance of its energy
delivery obligations to Cedar Brakes during lower priced periods. As such,
within certain limitations under the PSA, EPM can designate periods for selling
a substantial portion of its energy for its own account into the PJM market.
Although there are a limited number of days under the PSA for EPM to make sales
into the PJM market, the number of days available are sufficient to extract
substantial value from the PJM all-in annual average market price.
The PSA allows EPM to suspend energy deliveries to Cedar Brakes for
approximately five days per month or 23% of the time during the on-peak summer
period, assuming a 150 MWh delivery rate to PSE&G. EPM has a financial incentive
to suspend deliveries on days when power prices are highest in the PJM market,
which effectively lowers the cost of supplying energy under the PSA and supports
the below market contract price. Historical data have shown at least five days
per month when the market price rises considerably higher than the monthly
average. As EPM suspends delivery to Cedar Brakes during these days, the average
all-in cost to EPM of energy delivered during the month will correspondingly
decrease. In the off-peak and the non-summer on-peak periods, the number of days
when EPM can suspend delivery under the PSA increases significantly to 43% and
44%, respectively.
THE OPTION VALUE ANALYSIS
The option value analysis quantifies the value to EPM of the flexibility
embedded within the PSA by quantifying market priced option premiums via the use
of implied market volatility for options contracts traded in the PJM region. The
time-of-delivery flexibility provided in the PSA creates option value for EPM
that effectively depresses its all-in cost of energy relative to average market
prices in two ways. First, the potential for downward price movements in the
market will enable EPM to extract volatility value by selectively selling
(putting) energy to Cedar Brakes under the PSA at prices below forecasted market
levels. This "price-drop" value has been calculated by quantifying the monthly
put option premium in the PJM market. Second, as stated earlier, the potential
for price spikes in the summer peak periods will enable EPM to reduce the cost
of power delivered under the PSA by exercising its option to suspend energy
deliveries to Cedar Brakes for five days per month or approximately 23% of the
time during the on-peak summer period. This value has been quantified by summing
the value of the calculated premium derived from the sale of one-day power call
options that could be sold during approximately five days of each summer month.
These options effectively allow EPM to extract a portion of the highest energy
prices of the year for its own account (i.e., quantifying the value of not
supplying power when the market is hyper-inflated), thus, lowering the average
monthly all-in energy cost for energy sold under the PSA.
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Exhibit 1 illustrates the general relationship of PJM market prices to the
contract price under the PSA using the option value adjustment methodology. As
shown in Exhibit 1, contract price is equal to the average hourly annual market
price reduced by the value for the sale of on-peak call and put options and
off-peak put options.
EXHIBIT 1: RELATIONSHIP OF EPM CONTRACT PRICE TO MARKET PRICE
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[CHART]
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FINDINGS AND CONCLUSIONS
Certain statements in this report are forward-looking and are based on current
assumptions and forecasts, and consequently involve risks and uncertainties.
Accordingly, the EPM's actual results could differ materially from the
expectations expressed in the forward-looking statements. While Pace believes,
based on its present knowledge and expertise, that the assumptions and forecasts
relied upon in this report are reasonable, given the uncertainties of energy
pricing, investors' review should include consideration of alternate assumptions
and forecasts.(1)
Pace has reviewed the PJM market as well as the PSA contract prices provided by
EPM in conjunction with the analyses described above. Our analysis focuses on
whether or not the contract prices provided by EPM are reasonable in light of
the current market structure, future expectations for the PJM market and the
energy delivery flexibility in the PSA. With respect to the PJM market review
and the PSA contract prices provided by EPM, Pace makes the following findings
and conclusions:
1. PJM operates a competitive wholesale energy market and facilitates open
access to transmission. With over 170 members including every segment of the
electric power industry, the PJM market has become one of the most liquid and
active energy markets in the country.
2. As of 1998, there were 52,000 MW of existing capacity present in the PJM
power market. The contract capacity specified in the PSA of approximately 123
MW represents approximately 0.2%-0.3% of the total existing capacity in this
market. The low market share coupled with a well-developed and highly
reliable electrical transmission system, capable of transferring high
quantities of power between generators/sellers and buyers, will allow EPM to
access numerous power purchasers for capacity and energy sales and purchases.
EPM will therefore have many options to fulfill its on-peak and off-peak
obligations under the PSA and exploit the energy delivery flexibility of the
PSA. There may be times when the PJM electric transmission system may
experience disruptions due to system component failures or act-of-god events.
However, these events are highly unlikely to affect EPM's overall ability to
fulfill its on-peak and off-peak obligations under the PSA, given the design
and overall size of the PJM transmission system as well as the makeup energy
provisions in the PSA.
---------------
1 Please note that this Report was prepared in June 2000 and is based on 2nd
Quarter Year 2000 data for fuel and electric power prices. To the best of
Pace's knowledge, since the date of preparation of the Report, no event
affecting the Report or the matters referred to herein has occurred which
changes in any material adverse respect, as of the date hereof, any finding or
conclusion contained in the Report
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3. Incremental capacity is needed in the region to match energy demand growth,
which is estimated to average 1.64% per year over the term of the 13-year
contract based on PJM forecasts and similar forecasts conducted by Pace.
4. Given the structure of the PSA, EPM has the flexibility to sell to the market
during volatile peak periods and conversely put power to Cedar Brakes during
lower pricing periods. The implicit capacity factor based on contracted
energy delivery requirements of the PSA is 77% during summer peak hours and
56% during non-summer peak periods. The implicit capacity factor based on
contract delivery quantities during non-peak periods is 57%.
5. Based on the scheduling flexibility in the PSA and imputing the PJM market
price by eliminating the volatile peak periods, the average projected market
price is $22.09/MWh under the bid strategy analysis and $20.63/MWh under the
option value analysis, in East PJM for the September through December 2000
period.
6. As illustrated in Exhibit 2, for the 2001 through 2006 period, Pace believes
the PSA contract price is in-line with Pace's adjusted market price. For the
remainder of the forecast period (2007-2013), Pace estimates that the
contract prices under the PSA are slightly lower than Pace's adjusted market
price. However, given the increasing level of uncertainty as the time horizon
becomes more distant, Pace believes that the contract prices are not
significantly different from market expectations. Accordingly, on a net
present value ("NPV") basis, the value ascribed to the differential between
the Pace-adjusted market prices and the PSA contract prices is approximately
4%, assuming a discount rate of 10% and a 13-year term of the PSA.
EXHIBIT 2: SUMMARY OF THE AVERAGE HOURLY "ALL-IN" POWER PRICES ($/MWH) FOR
THE PSA CONTRACT, PACE'S FORWARD PRICE CURVE FORECAST, PACE'S FORECASTED OPTION
VALUE-ADJUSTED PRICE AND PACE'S FORECASTED BID STRATEGY-ADJUSTED PRICE
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------
PSA CONTRACT PACE'S FORWARD
PRICES PROVIDED PRICE CURVE OPTION VALUE BID STRATEGY
YEAR BY EPM FORECAST ADJUSTED PRICES ADJUSTED PRICES
-----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
2000(1) 23.03 23.37 20.63 22.09
2001 29.71 35.42 30.25 27.56
2002 29.30 33.84 29.19 26.40
2003 28.56 32.57 27.87 25.32
2004 27.94 33.94 28.47 26.46
2005 28.07 34.21 28.63 26.68
2006 28.26 34.93 29.37 27.26
2007 28.26 36.37 30.48 28.38
2008 28.80 37.03 31.21 28.94
2009 29.08 38.39 32.23 30.10
2010 29.36 39.61 33.26 31.06
2011 29.64 40.90 34.30 32.12
2012 29.94 42.29 35.26 33.25
2013(1) 33.75 50.99 41.83 34.21
-----------------------------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
(1) These prices have been adjusted to reflect the timing and term of the bond
offering.
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Based upon Pace's analysis of the PJM power market and a review of the relevant
portions of the Cedar Brakes transaction documents, we believe that the contract
rates stipulated in the PSA reasonably reflect market prices in the PJM market,
adjusted for the energy delivery flexibility ("option value") that EPM has under
the PSA. Moreover, we believe that the PJM market offers sufficient power
resources to enable EPM to meet its contractual obligations under the PSA.
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TRANSACTION OVERVIEW
--------------------------------------------------------------------------------
TRANSACTION OVERVIEW
NBCP owns a 147 megawatt ("MW") cogeneration facility located in Newark, New
Jersey ("the Facility"). Pursuant to the Original PPA with PSE&G, NBCP sold
generation capacity and the associated energy from the Facility to PSE&G. The
Original PPA was acquired and subsequently amended and restated in its entirety
by PSE&G and Cedar Brakes. Under the Amended and Restated PPA, the capacity and
energy rates paid by PSE&G have been significantly reduced from those under the
original PPA, while Cedar Brakes, as seller, has been given significantly more
flexibility in scheduling deliveries, including the right to select the source
of energy and capacity from which to meet its delivery obligations. This
scheduling and source flexibility significantly enhances the economic value of
the Amended and Restated PPA to Cedar Brakes.
Exhibit 3 below provides a summary of the Cedar Brakes transaction. The proceeds
of the bond offering will be used to purchase the Original PPA, cover certain
transaction costs and fund the liquidity account. The contract prices under the
PSA and the Amended and Restated PPA allow Cedar Brakes to realize a spread on
its energy sales in order to service the debt. As depicted, Cedar Brakes
supplies the energy and capacity requirements, as stipulated in the Amended and
Restated PPA, in return for energy and capacity payments from PSE&G. The
interest and principal on the bonds will be paid solely from capacity and energy
payments from PSE&G (as supplemented, under certain circumstances, by funds in a
liquidity account). Net of the costs of capacity and energy purchased from EPM
under the PSA, all scheduled payments of principal and interest on the bonds
have been calculated based on the net annual capacity and energy revenues.
In order to meet its obligations under the Amended and Restated PPA, Cedar
Brakes entered into the PSA with EPM. The PSA mirrors the terms and conditions
in the Amended and Restated PPA with the exception of the hourly price per
megawatt hour, which is significantly lower. Under the PSA, EPM will supply the
capacity and energy required by Cedar Brakes to meet its energy delivery
obligations under the Amended and Restated PPA. The PSA also provides payment of
liquidated damages and indemnification of Cedar Brakes in the event of energy
delivery shortfalls, i.e., failure to meet the capacity and energy delivery
requirements. Cedar Brakes has also entered into an Administrative Services
Agreement with EPM pursuant to which EPM carries out all of Cedar Brakes
administrative affairs and contractual obligations, including those under the
Amended and Restated PPA. Lastly, EPEC has provided an unconditional guarantee
of all payment and performance obligations of EPM under the PSA and
Administrative Services Agreement.
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EXHIBIT 3: SUMMARY OVERVIEW OF THE CEDAR BRAKES TRANSACTION
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
CAPACITY AND ENERGY DELIVERY REQUIREMENTS
Presented below are the terms and conditions of the PSA that were relevant to
Pace's analysis:
a) The PSA becomes effective on the later of (i) the last date upon which
certain conditions precedent are satisfied or waived and (ii) September
4, 2000, and remains in effect through and including August 31, 2013
unless terminated earlier as provided in the PSA.
b) EPM has the option to supply Cedar Brakes' capacity and energy
requirements from any source in the PJM market, including but not
limited to the NBCP Facility.
c) EPM is required to take all necessary steps for PSE&G to receive at
least 123 MW of capacity credits per day from the PJM market, including
utilizing PJM's "eCapacity" mechanism throughout the term of the PSA.
d) EPM is required to deliver energy to Cedar Brakes according to the
annual contracted levels presented in Exhibit 4.
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EXHIBIT 4: PSE&G CONTRACTED ANNUAL ENERGY DELIVERY REQUIREMENTS IN MWH
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
GROSS ANNUAL ON-PEAK OFF-PEAK
YEAR ENERGY DELIVERIES DELIVERIES DELIVERIES
<C> <C> <C> <C> <S>
2000 788,954 394,000 394,954
2001 788,954 394,000 394,954
2002 788,954 394,000 394,954
2003 811,229 394,000 417,229
2004 855,779 394,000 461,779
2005 855,779 394,000 461,779
2006 855,779 394,000 461,779
2007 855,779 394,000 461,779
2008 855,779 394,000 461,779
2009 855,779 394,000 461,779
2010 855,779 394,000 461,779
2011 855,779 394,000 461,779
2012 855,779 394,000 461,779
2013 570,519 394,000 176,519
</TABLE>
--------------------------------------------------------------------------------
e) EPM may deliver energy at a rate of up to 150 MWh per hour unless EPM is
also scheduling "make-up energy", in which case EPM may deliver up to
200 MWh per hour.
f) EPM must schedule and deliver energy at the same rate during all on-peak
hours in any day and at the same rate during off-peak hours in any day.
However, the delivery rate for on-peak hours in a given day may differ
from the delivery rate for off-peak hours in the same day and the
delivery rate for on-peak and off-peak hours may vary from day to day.
g) During the on-peak summer period of June, July, August and September,
EPM must deliver to Cedar Brakes at least 40,000 MWh per month during
the on-peak hours. For the remaining eight months of the year (on-peak
non-summer period), EPM must deliver an aggregate of 234,000 MWh during
the on-peak hours.
h) EPM must deliver aggregate energy during the off-peak hours as noted in
Exhibit 4.
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--------------------------------------------------------------------------------
BID STRATEGY AND OPTION VALUE ANALYSIS
--------------------------------------------------------------------------------
INTRODUCTION
In order to determine whether the contract prices contained in the PSA are
reasonable, in conjunction with forecasting the PJM market clearing prices over
the term of the PSA, Pace performed two distinct analyses: a bid strategy
analysis and option value analysis. The bid strategy analysis assesses the
potential value to EPM of selling power into the PJM market during hours when
EPM is not obligated to sell power to Cedar Brakes under the PSA. This analysis
includes a forecast of the market clearing prices during the hours in which EPM
would deliver energy under the PSA, assuming EPM fulfills its contractual
obligations during the lowest priced hours available. This forecast of PJM East
power prices is based on Pace's Capacity & Energy Market Analysis System
("CEMAS") 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. The
option value analysis quantifies the value to EPM in the options market derived
from the delivery flexibility provided for in the PSA. This analysis is a more
conservative approach to valuing the energy delivery flexibility as compared to
the bid strategy analysis. These analyses were performed in order to assess the
value of the energy delivery flexibility contained in the PSA.
Exhibit 5 illustrates the PJM market price volatility associated with all-in
power prices for the May 1, 1999 through April 30, 2000 period. In general, the
summer months possess the greatest price volatility. This is apparent from the
price spike levels as compared to the annual average all-in power prices.
Although this is an historical perspective on the PJM energy market, we expect
similar behavior in the future, barring any major structural changes to the PJM
market. Therefore, we believe the conclusions based on the historical PJM market
data are relevant.
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EXHIBIT 5: AVERAGE ALL HOUR ALL-IN POWER PRICES FOR THE PJM MARKET FOR THE
MAY 1, 1999 THROUGH APRIL 30, 2000
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
BID STRATEGY ANALYSIS
The bid strategy analysis assessed the energy delivery flexibility in the PSA
that allows EPM to control the scheduling of certain power deliveries on a daily
basis. This analysis was based on a strategy that would minimize the all-in cost
to EPM of electricity delivered under the PSA. By utilizing the contractual
flexibility on a daily basis, EPM can, with fairly high certainty, select days
to sell its power in the higher priced PJM market, while delivering the balance
of its energy to Cedar Brakes to meet its contractual obligations under the PSA.
As such, within certain limitations under the PSA, EPM can designate periods for
selling a substantial portion of its energy into the PJM market. Although there
are a limited number of days under the PSA for EPM to make sales into the PJM
market, the number of days available are sufficient to extract substantial value
from the PJM all-in annual average market price.
Based on historical data, we would expect at least five days per month when
the average peak power price rises considerably higher than the average monthly
peak price. This market feature will afford EPM opportunities to lower its total
cost of energy deliveries under the PSA by selectively omitting these days for
delivery. The amount of delivery flexibility in the PSA is the highest in the
off-peak and non-summer peak periods, during which time EPM can choose to
suspend energy deliveries for approximately 45% of the total hours. During the
summer on-peak period, EPM can suspend energy deliveries for about 23% of the
total available peak hours.
It would be unreasonable to assume that EPM would be able to designate all of
the high price days available in any one month. However, it is reasonable to
assume that EPM would be fairly successful given the number of
--------------------------------------------------------------------------------
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[PACE LOGO]
days of energy delivery flexibility and the nature of the PJM power market.
Accordingly, a max-min volatility valuation was structured to reflect the power
market trading risk and the embedded optionality contained in the PSA.
Exhibit 6 illustrates the average annual all-in power price and its standard
deviation as a function of the total number of the highest priced days per year
excluded in the calculation. The X-axis measures the number of days excluded as
a percentage of the total number of days per year. The Y-axis measures the
average annual all-in power prices in dollars per MWh. One hundred percent
represents the average based on 365 days and 80% represents 292 days and so on.
Based on our analysis, eliminating approximately 7% of the high price days will
result in a significant reduction in the average all-in power price from
approximately $31 per MWh to approximately $22 per MWh, or an approximate 30%
reduction. Moreover, the average all-in power price standard deviation, which is
a measure of price volatility, falls from approximately $50 per MWh to
approximately $10 per MWh, or an approximate 80% reduction. Based on this
analysis, it is apparent how EPM can offer contract power prices below the
forecasted annual average all-in market power prices; namely by effectively
selecting out those price periods in which to dedicate its sales to the PJM
market.
EXHIBIT 6: AVERAGE ALL HOUR ALL-IN POWER PRICE AND ITS STANDARD DEVIATION
AS A FUNCTION OF THE TOTAL AVAILABLE DAYS PER YEAR IN THE PJM MARKET
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
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OPTION VALUE ANALYSIS
The option value analysis quantifies the value to EPM of the energy delivery
flexibility embedded within the PSA by quantifying market priced option premiums
via the implied market volatility for power options traded in the PJM region.
The time-of-delivery flexibility provided in the PSA creates option value for
EPM, which essentially lowers its all-in cost of energy relative to average
market prices in two ways. First, the potential for downward price movements in
the market allows EPM to extract volatility value by selectively selling
(putting) energy to Cedar Brakes under the PSA at prices below forecasted market
levels. This "price-drop" value has been calculated by quantifying the monthly
put option premium in the PJM market. Second, as stated earlier, the potential
for price spikes in the summer peak periods allows EPM to extract value by
exercising its option to suspend energy deliveries to Cedar Brakes for five days
per month or approximately 23% of the time during the on-peak summer period.
This value is quantified by summing the value of the premiums earned on the sale
of one-day power call options that could be sold during approximately five days
of each summer month. These options effectively allow EPM to extract a portion
of the highest energy prices of the year for its own account (i.e., quantifying
the value of not supplying power to Cedar Brakes when the market is
hyper-inflated) and thus lower the average monthly all-in energy cost to EPM of
selling energy to Cedar Brakes under the PSA.
EXHIBIT 7: RELATIONSHIP OF EPM CONTRACT PRICE TO MARKET PRICE
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
Exhibit 7 illustrates the general relationship of market price to EPM's contract
price under the PSA using the option value adjustment methodology. The contract
price is equal to the average annual market price reduced by the value for the
sale of on-peak call and put options and off-peak put options. Deriving market
implied volatility for the PJM market and utilizing options pricing models, we
calculated the value of the on-peak and off-peak put options and the on-peak
call options for the term of the contract (i.e., 2000 through 2013). We
subtracted option premia from our power price forecast for the PJM market to
arrive at adjusted market power prices or comparative contract prices. The
results are presented below in Exhibit 8.
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EXHIBIT 8: SUMMARY OF THE AVERAGE ALL HOUR "ALL-IN" POWER PRICES ($/MWH)
FOR THE EPM CONTACT AND FORECASTED OPTION VALUE ADJUSTED VALUES
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
EPM PACE'S FORWARD PRICE OPTION VALUE
CONTRACT PRICE CURVE FORECAST ADJUSTED PRICE FORECAST
YEAR ($/MWH) ($/MWH) ($/MWH)
-------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
2000 $23.03 23.37 20.63
2001 $29.71 35.42 30.25
2002 $29.30 33.84 29.19
2003 $28.56 32.57 27.87
2004 $27.94 33.94 28.47
2005 $28.07 34.21 28.63
2006 $28.26 34.93 29.37
2007 $28.26 36.37 30.48
2008 $28.80 37.03 31.21
2009 $29.08 38.39 32.23
2010 $29.36 39.61 33.26
2011 $29.64 40.90 34.30
2012 $29.94 42.29 35.26
2013 $33.75 50.99 41.83
-------------------------------------------------------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
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--------------------------------------------------------------------------------
PJM MARKET PRICE FORECAST
--------------------------------------------------------------------------------
The following section details the market price forecasting methodology used
to perform the bid strategy assessment of the PSA. This forecast provides the
expected level and distribution (time of day and season) of PJM East power
prices, based on Pace's CEMAS model. This section includes Pace's Base Case
forecast of market clearing prices for the period 2000-2013, an assessment of
the capacity availability resources within the PJM region, a key assumptions
description and methodology underlying the development of the forecast.
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.
APPROACH
Pace conducted a detailed analysis of the PJM market clearing prices. This
analysis provides in-depth insight into the fundamentals of the PJM and the
emerging competitive market within the region. The analysis is based on Pace's
competitive market vision of a "one-price" market for 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 forecast market clearing prices for both capacity and energy. As
illustrated in Exhibit 9, CEMAS consists of five modules. These modules are:
1. REVENUE REQUIREMENT MODULE: This module compares fixed and variable
costs for all generating units with all-in revenues generated from a
given bidding strategy. It then reports information regarding over or
under-recovery (stranded costs) to the Bid Analysis Module.
2. UNIT FUEL PRICING MODULE: This module calculates fuel prices for each
unit and transfers the data to the Revenue Requirement Module. These
fuel pricing calculations take into account escalation schedules,
transportation costs, fuel quality, and fuel procurement and contractual
constraints.
3. BIDDING ANALYSIS MODULE: Based on the fixed and variable costs of
generating units and over and under-recovery data generated by the
Revenue Requirement Module, this module generates bids for each unit on
the system and transfers those bids to the Market Clearing Price Module
for production simulation.
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 bid prices generated by the
Bidding Analysis Module and the hourly load data generated by the Hourly
Load Module. For each hour in the study period, the module dispatches
generating units according to their bid prices and availabilities. The
Market Clearing Price Module uses a utility grade
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dispatch model to model the hourly system constraints of a regional
power pool, optimizing least cost generation choices to match demand
fluctuations. The module then produces hourly market clearing prices,
which are passed to the Revenue Requirement Module to evaluate system
operations and market price stability. Based on this analysis, CEMAS
will either produce a new iteration of optimized bids or, if the market
is deemed stable, summarize market-clearing prices for each study
period.
EXHIBIT 9: PAGE CEMAS METHODOLOGY
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
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.
SIMULATED MARKET PRICE FORECAST FOR PJM
CEMAS SIMULATED MARKET PRICES
Pace's Base Case market price forecast was founded on our expected assumptions
underlying a competitive market. Specifically, given the cost structure of
generating units, demand, fuel pricing, and other key factors, the CEMAS model
simulated the PJM system and optimized unit dispatch and bidding to identify the
market pricing and price distribution to allow the system to recover all fixed
and variable costs of generation units except those fixed costs that are
determined above market or "stranded". Additionally, as discussed previously,
bidding strategies are set to achieve a market price within +/- 5% of the levels
which expansion capacity would require to cover their minimum fixed and variable
costs.
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AVERAGE SYSTEM ANNUAL TIME OF DAY PRICES
Exhibit 10 shows Pace's forecast of time of day prices for the study period 2000
through 2013. The time of day designation consists of peak, off-peak, and
weekend. The peak period consists of 16 hour blocks during the 5 day work-week,
while the off-peak period represents the remaining 8 hours during these 5 days.
The weekend designation represents 24-hour blocks for Saturday and Sunday.
Pace's Base Case market price forecasts for the PJM Northeast sub-region are
between $33.99/MWh and $28.67/MWh (measured in 1998 real dollars) for the period
from 2000 to 2013. Pace expects that electricity prices will remain stable over
the period as sufficient capacity is constructed to meet demand and efficiency
improvements offset a modest natural gas real price increase.
EXHIBIT 10: PJM NORTHEAST ANNUAL SYSTEM TIME OF DAY PRICES -- BASE CASE
(1998 $/MWH)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
-------------------------------------------------
YEAR PEAK OFF-PEAK WEEKEND AVERAGE
-------------------------------------------------
<S> <C> <C> <C> <C>
2000 51.08 16.08 20.41 33.99
2001 48.71 16.30 20.35 32.89
2002 44.83 15.72 19.51 30.66
2003 41.78 15.42 18.26 28.79
2004 42.45 15.56 18.73 29.27
2005 41.43 15.74 18.56 28.78
2006 41.21 16.01 18.34 28.67
2007 41.66 16.22 18.97 29.12
2008 41.34 16.27 18.81 28.93
2009 41.46 16.52 19.53 29.26
2010 41.60 17.06 19.51 29.45
2011 41.51 17.32 20.23 29.67
2012 42.04 17.54 20.07 29.93
2013 41.86 17.71 20.42 29.98
-------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
ADJUSTED AVERAGE SYSTEM ANNUAL TIME OF DAY PRICES
Pace's annual time of day prices are used in the bid strategy analysis to assess
the potential for EPM to reasonably extract the higher price hours for its own
use (sales) in the PJM market, based on Pace's forward price curve forecast.
As shown in Exhibit 11, for the 2001 through 2006 period, Pace estimates the EPM
contract price to be in-line with Pace's adjusted market price forecast. For the
remainder of the forecast period, 2007-2013, Pace estimates the EPM contract
price to be slightly below Pace's adjusted market price. However, given the
increasing level of uncertainty as the time horizon grows more distant, we do
not believe that the contract price is significantly different from market
expectations. As such, on a net present value ("NPV") basis, the value ascribed
to the differential between the Pace-adjusted market prices and the EPM contract
prices is approximately 4%, assuming a discount rate of 10% and a 13-year term
of the contract.
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EXHIBIT 11: PJM AVERAGE ANNUAL EPM CONTACT AND BID STRATEGY PRICES (1998
$/MWH)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
--------------------------------------------
BID STRATEGY
YEAR CONTRACT ANALYSIS PRICES
--------------------------------------------
<S> <C> <C> <C>
2000* 23.03 22.09
2001 29.71 27.56
2002 29.30 26.40
2003 28.56 25.32
2004 27.94 26.46
2005 28.07 26.68
2006 28.26 27.26
2007 28.26 28.38
2008 28.80 28.94
2009 29.08 30.10
2010 29.36 31.06
2011 29.64 32.12
2012 29.94 33.25
2013* 33.75 34.21
--------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
* The market prices for the years 2000 and 2013 represent partial years, as the
contract term begins September 2000 and expires August 2013.
WHOLESALE MARKET TRANSACTIONS
The PJM power market is a highly competitive and maturing wholesale market. The
market's competitiveness is evidenced by the region's large volume of power
transactions. Wholesale market trading in the area offers additional
opportunities to EPM to fulfill its on peak and off peak obligations and
capitalize on the flexibility of the PSA. The PJM power market has experienced
high wholesale market volumes of over 163,682 GWh in 1998 and more than 121,946
GWh through 3rd quarter 1999. Accordingly, the PPA/PSA volumes represent only
0.001% of the entire PJM market. Due to these high trading volumes within the
PJM market, the region is typically considered a liquid market. Additionally,
since the PPA/PSA is such a small percentage of the market, Pace concludes that
EPM will be able to fulfill its contract obligations without impacting the
larger market.
The high volume of area electricity interchange and the region's proximity to
liquid trading hubs such as the Cinergy trading hub, indicate a strong market
for sales to PJM's neighboring regions. PJM is bordered by the NERC sub-regions
of NYPP, VACAR, and ECAR. Within these areas, power market trading occurs within
three additional spot markets: ComEd, TVA, and Southern. ECAROT, on the northern
border of PJM, is host to Cinergy, the most active power trading market to date.
The high volume of area electricity interchange and the liquidity of these
markets indicate a strong market for sales/purchases for EPM. Exhibit 12 shows
quantities of electricity trades in all NERC regions.
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EXHIBIT 12: POWER MARKETER TRANSACTIONS BY NERC REGION(2)
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
EXISTING DEMAND PROFILE
For each utility's respective demand forecast, Pace reviewed published data from
the Regional Electricity Supply & Demand Projections (EIA-411) report submitted
by the NERC sub-regions to the U.S. Energy Information Administration (EIA). The
EIA-411 report provides historical and projected peak and energy demands shown
in Exhibit 13 for the combined sub-regions of Entergy-North, Entergy-Gulf, TVA,
and Southern.
Exhibit 13 indicates that PJM utilities expect summer peak demand and energy to
increase at an average rate of 1.71% and 1.68% per year over the next 10 years,
respectively. Specifically, peak demand is projected to grow from 48,445 MW to
50,576 MW between 1998 and 2000. Thereafter, peak demand is expected to rise to
approximately 57,381 MW by the year 2008. Net energy is expected to escalate
from a base of approximately 248,806 GWh in 1998 to nearly 293,958 GWh by the
year 2008.
---------------
2 Reflects power marketer transactions occurring during 1998. Transaction
volumes represent both interstate and intrastate trades.
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EXHIBIT 13: PJM DEMAND AND ENERGY REQUIREMENTS FORECAST
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
*1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
-------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Peak Demand Summer (MW) 48,445 49,807 50,576 51,426 52,238 53,048 53,892 54,769 55,634 56,516
Peak Demand Winter (MW) 36,532 43,009 43,628 44,264 44,917 45,575 46,247 46,947 47,631 48,321
Net Energy for Load (MWh) 248,806 254,967 258,859 263,326 267,951 271,635 276,230 280,506 284,900 289,339
System Load Factor 59.28% 61.85% 62.29% 61.71% 61.62% 61.51% 61.61% 62.04% 61.89% 61.63%
Summer Change (MW) 1,362 769 850 812 810 844 877 865 882
Winter Change (MW) 6,477 619 636 653 658 672 700 684 690
Energy Change (MWh) 6,161 3,892 4,467 4,625 3,684 4,595 4,276 4,394 4,439
Summer Change (%) 2.81% 1.54% 1.68% 1.58% 1.55% 1.59% 1.63% 1.58% 1.59%
Winter Change (%) 17.73% 1.44% 1.46% 1.48% 1.46% 1.47% 1.51% 1.46% 1.45%
Energy Change (%) 2.48% 1.53% 1.73% 1.76% 1.37% 1.69% 1.55% 1.57% 1.56%
Annual Summer Peak Growth 1.71%
Annual Winter Peak Growth 2.98%
Annual Energy Growth 1.68%
<CAPTION>
---------------------------- -----------
2008
---------------------------- -----------
<S> <C> <C>
Peak Demand Summer (MW) 57,381
Peak Demand Winter (MW) 48,981
Net Energy for Load (MWh) 293,958
System Load Factor 61.50%
Summer Change (MW) 865
Winter Change (MW) 660
Energy Change (MWh) 4,619
Summer Change (%) 1.53%
Winter Change (%) 1.37%
Energy Change (%) 1.60%
Annual Summer Peak Growth
Annual Winter Peak Growth
Annual Energy Growth
</TABLE>
Source: EIA-411
*Actual
--------------------------------------------------------------------------------
Also shown in Exhibit 13, the PJM market has a relatively high load factor of
over 59%. Over the forecast period, utilities are expecting this load factor to
increase to approximately 62%. This increasing load factor is attributable to
energy demand growing at a faster rate than the system peak. If the system load
factor does not improve, this will increase the amount of capacity needed to
meet reserve and reliability requirements. However, to be conservative, Pace's
market study assumes that the customer mix, load shape, and consequently this
high load factor will be achieved throughout the study period, thereby slightly
minimizing the need for incremental expansion capacity.
Despite the aforementioned load factor improvement, as is shown in Exhibit 14,
PJM utilities are expecting a declining summer reserve margin varying between
5%-14%. This declining reserve margin is due to expectations that only
approximately 2,396 MW of net capacity additions can be achieved in the next 10
years. Therefore, the demand increases will outpace the capacity improvements.
As is shown in Exhibit 14, it is expected that there will be 55,470 MW of
capacity present in the PJM power market during the summer of 2000. The contract
capacity specified in the PSA of approximately 123 MW represents approximately
0.2% of the total existing capacity in this market. The low market share coupled
with a well-developed electrical transmission system, capable of transferring
high quantities will allow EPM to access numerous power purchasers for excess
capacity and energy sales/purchases. Therefore, EPM will have many physical
options to fulfill its on-peak and off-peak obligations and utilize the
flexibility of the PSA.
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-19
<PAGE> 129
[PACE LOGO]
EXHIBIT 14: PJM MARKET DEMAND AND RESERVE MARGIN FORECAST -- SUMMER
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
1999 2000 2001 2002 2003 2004 2005 2006 2007
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Internal Demand 49,807 50,576 51,426 52,238 53,048 53,892 54,769 55,634 56,516
Standby Demand 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Total Internal Demand 49,807 50,576 51,426 52,238 53,048 53,892 54,769 55,634 56,516
Direct Ctrl Load Mgt 800.00 800.00 799.00 799.00 800.00 800.00 800.00 801.00 800.00
Interruptible Demand 1,381 1,416 1,423 1,430 1,431 1,432 1,434 1,435 1,437
Net Internal Demand 47,626 48,360 49,204 50,009 50,817 51,660 52,535 53,398 54,279
Total Owned Capacity 52,037 52,061 52,385 52,955 53,211 53,327 53,715 54,419 54,735
Inoperable Capacity 0 0 0 0 0 0 0 0 0
Net Operable Capacity 52,037 52,061 52,385 52,955 53,211 53,327 53,715 54,419 54,735
IPPs 4,151.00 4,197.00 4,197.00 4,197.00 4,114.00 3,736.00 3,736.00 3,736.00 3,736.00
Capacity Purchases 649 518 518 518 518 518 518 518 68
Full Response Purchases 450 450 450 450 450 450 450 450 0
Capacity Sales 1,326 1,306 1,393 1,393 439 439 439 439 439
Full Response Sales 954 954 954 954 0 0 0 0 0
Planned Capacity Res 55,511 55,470 55,707 56,277 57,404 57,142 57,530 58,234 58,100
Reserve Margin (MW) 7,885 7,110 6,503 6,268 6,587 5,482 4,995 4,836 3,821
Reserve Margin (%) 14.20% 12.82% 11.67% 11.14% 11.47% 9.59% 8.68% 8.30% 6.58%
<CAPTION>
-------------------------------- ------------
2008
-------------------------------- ------------
<S> <C> <C>
Internal Demand 57,381
Standby Demand 0.00
Total Internal Demand 57,381
Direct Ctrl Load Mgt 802.00
Interruptible Demand 1,438
Net Internal Demand 55,141
Total Owned Capacity 54,558
Inoperable Capacity 0
Net Operable Capacity 54,558
IPPs 3,720.00
Capacity Purchases 68
Full Response Purchases 0
Capacity Sales 439
Full Response Sales 0
Planned Capacity Res 57,907
Reserve Margin (MW) 2,766
Reserve Margin (%) 4.78%
</TABLE>
Source: EIA-411
--------------------------------------------------------------------------------
EXHIBIT 15: PJM MARKET DEMAND AND RESERVE MARGIN FORECAST -- WINTER
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
1999 2000 2001 2002 2003 2004 2005 2006 2007
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Internal Demand 43,009 43,628 44,264 44,917 45,575 46,247 46,947 47,631 48,321
Standby Demand 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Total Internal Demand 43,009 43,628 44,264 44,917 45,575 46,247 46,947 47,631 48,321
Direct Ctrl Load Mgt 121.00 122.00 123.00 123.00 124.00 126.00 126.00 127.00 128.00
Interruptible Demand 1,029 1,029 1,029 1,029 1,029 1,029 1,029 1,029 1,029
Net Internal Demand 41,859 42,477 43,112 43,765 44,422 45,092 45,792 46,475 47,164
Total Owned Capacity 54,360 54,384 54,708 55,278 55,534 55,650 56,038 56,742 57,058
Inoperable Capacity 0 0 0 0 0 0 0 0 0
Net Operable Capacity 54,360 54,384 54,708 55,278 55,534 55,650 56,038 56,742 57,058
IPPs 4,279.00 4,325.00 4,325.00 4,325.00 4,242.00 3,870.00 3,870.00 3,870.00 3,870.00
Capacity Purchases 623 518 518 518 518 518 518 68 68
Full Response Purchases 450 450 450 450 450 450 450 0 0
Capacity Sales 1,306 1,306 1,393 1,393 439 439 439 439 439
Full Response Sales 954 954 954 954 0 0 0 0 0
Planned Capacity Res 57,956 57,921 58,158 58,728 59,855 59,599 59,987 60,241 60,557
Reserve Margin (MW) 16,097 15,444 15,046 14,963 15,433 14,507 14,195 13,766 13,393
Reserve Margin (%) 27.77% 26.66% 25.87% 25.48% 25.78% 24.34% 23.66% 22.85% 22.12%
<CAPTION>
-------------------------------- ------------
2008
-------------------------------- ------------
<S> <C> <C>
Internal Demand 48,981
Standby Demand 0.00
Total Internal Demand 48,981
Direct Ctrl Load Mgt 129.00
Interruptible Demand 1,029
Net Internal Demand 47,823
Total Owned Capacity 56,881
Inoperable Capacity 0
Net Operable Capacity 56,881
IPPs 3,854.00
Capacity Purchases 0
Full Response Purchases 0
Capacity Sales 0
Full Response Sales 0
Planned Capacity Res 60,735
Reserve Margin (MW) 12,912
Reserve Margin (%) 21.26%
</TABLE>
Source: EIA-411
--------------------------------------------------------------------------------
BASE CASE ASSUMPTIONS
The following presents Pace's major input assumptions used in the integrated
market pricing forecast of PJM. The input assumptions for the forecast are
presented in the following six categories:
- Regional Market Definition and Transmission Interchange
- Demand Forecast
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-20
<PAGE> 130
[PACE LOGO]
- Fuel Price Forecast
- Existing Generating Capacity Profiles
- Expansion Generating Capacity Profiles
REGIONAL MARKET DEFINITION AND TRANSMISSION INTERCHANGE
Based on the review of existing transmission transfer capabilities and recent
transmission assessment studies, Pace developed the major intra-regional market
areas of PJM as South, Southeast, Northeast, Central, and ACE. Exhibit 16
illustrates the PJM sub-regional designations to be employed in Pace's
simulation.
EXHIBIT 16: PJM SUB-REGIONAL DESIGNATIONS
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
Major PJM utility service territories were allocated to sub-regions as follows:
- PJM SOUTH -- Baltimore Gas & Electric, Potomac Electric Power Co
- PJM SOUTHEAST -- Delmarva Power & Light Co
- PJM CENTRAL -- Pennsylvania Power & Light Co, Pennsylvania Electric Co.,
Metropolitan Edison Co.
- PJM NORTHEAST -- PECO Energy Co, Jersey Central Power & Light Co, Public
Service Electric & Gas Co.
- PJM ACE -- Atlantic City Electric Company
Generally, power in PJM flows from West to East, from low cost, low demand areas
in the West to high cost, high demand areas in the East. Such power transfers
tax the system heavily, creating less flexibility for system
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-21
<PAGE> 131
[PACE LOGO]
balance and emergency response. To slow the region's increasing transmission
congestion, the PJM Interconnection has designed location-based market pricing
systems ("LBMP") to provide market-based incentives to site capacity resources
near load centers and thereby relieve system constraints. Pace's subdivisions
were created to reflect such locational pricing based on regional transmission
zones and inter-regional constraints. Exhibit 17 provides the intra-regional
transfer capability schematic for PJM employed in the simulation.
EXHIBIT 17: ASSUMED PJM MARKET AREA TRANSMISSION CONSTRAINTS
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
Pace simulates all resources in PJM including each transmission area's native
load and capacity. Additionally, inter-regional transfers with utilities that
are more than one wheel away from PJM are modeled on a net transaction basis
(i.e., net purchases or sales are simulated, but full resource optimization is
not conducted). Net transactions were developed utilizing historical wholesale
transactions as reported to the FERC for the years 1995 to 1998 and are outlined
in Exhibit 18. These transactions are modeled as available energy to the region
designated at the running system marginal cost.
EXHIBIT 18: HISTORIC INTER-REGIONAL TRANSACTIONS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
FROM TO MW
<S> <C> <C>
NYPP PJM 200
MAIN PJM 350
SERC PJM 300
ECAR PJM 800
</TABLE>
--------------------------------------------------------------------------------
REGIONAL DEMAND FORECAST
Pace developed an independent demand forecast for each of the five sub-regions
in PJM. The following summarizes Pace's demand forecast methodology and results.
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-22
<PAGE> 132
[PACE LOGO]
PACE'S INDEPENDENT LOAD FORECASTING METHODOLOGY
Pace's independent demand forecast was developed according to the methodology
illustrated in Exhibit 19. This methodology has two primary components. The
first is the use of econometric models to forecast annual energy and peak demand
levels based on changes in population, employment, income, and other relevant
economic indicators. The second component of the methodology is the translation
of historical hourly demand levels and forecasted peak demand to create
predicted hourly load for each forecast year.
Typically, the most accurate means of projecting future demand is not done
solely by analyzing past trends in peak and energy demand, but by analyzing the
underlying factors that drive the consumption of electricity. This approach is
often referred to as a "bottom-up" analytical approach. As shown in Exhibit 19,
the foundation of Pace's load forecasting methodology is a bottom-up analytical
approach.
EXHIBIT 19: PACE LOAD FORECASTING METHODOLOGY
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
Pace generated its demand forecast based on the historical relationships between
regional demand and multiple historic economic indicators (examples: population,
employment and income) between 1990-1999. To generate this demand forecast,
Pace:
- Established the historical relationship between net energy for load,
population, employment, and disposable income in PJM.
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-23
<PAGE> 133
[PACE LOGO]
- Forecast a Base demand case based on the historical trends in population,
employment, and personal income.
- Forecast a Low demand case based on a forecast of these same economic
indicators projected forward at a slowed economic growth rate equal to
3/4 the rate of historic trends.
- Forecast a High demand case based on a nominal increase in population
growth relative to the historical trend.
- 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:
- Normal weather conditions are assumed with no factors included to
simulate extreme weather conditions.
- 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 aggressive in future years and will likely
fall short of their stated goals.
For purposes of the Base Case, Pace will simulate our base case demand forecast,
which is consistent with future expectations. The low and high demand cases are
developed for comparison and, ultimately, for sensitivity analyses.
ENERGY DEMAND FORECAST RESULTS
Pace's analysis indicates that PJM's historical growth in retail electricity
sales correlated to changes in employment, personal income, and population with
a high degree of reliability. Pace's regression analysis resulted in a
correlation coefficient of 94%. The resulting forecast of PJM system load is
illustrated in Exhibit 20 and provided in tabular form in Exhibit 21. The
summary of the energy forecast results are outlined below:
- Pace expects that regional electricity demand growth will slow from
historic long-term trends. Historically, demand has grown at an average
rate of 1.80% per year in PJM. Pace forecasts annual demand growth
through 2013 for PJM at 1.64%.
- In the near-term (2000-2008), Pace forecasts a slightly higher energy
growth rate for PJM than the currently filed utility forecasts.
Specifically, Pace expects a 1.63% average annual growth rate over the
period versus the PJM utility forecast of 1.60%.
- In contrast to PJM's historical annual load growth rate of 1.80%, the
pool forecasts future growth rates to average 1.60% annually over the
next 10 years.
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-24
<PAGE> 134
[PACE LOGO]
EXHIBIT 20: PACE PJM ENERGY FORECAST -- GWH
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
EXHIBIT 21: PACE PJM ENERGY FORECAST -- GWH
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
PJM PACE PJM PACE PJM
UTILITIES' PACE PJM ENERGY ENERGY PACE PJM
ENERGY ENERGY FORECAST FORECAST ENERGY
DEMAND BACKCAST LOW CASE BASE CASE FORECAST HIGH
(GWH) (GWH) (GWH) (GWH) CASE (GWH)
------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
HISTORIC
------------------------------------------------------------------------------------
1990 221,099 220,691
1991 228,588 225,649
1992 226,154 230,377
1993 235,980 235,134
1994 238,379 238,557
1995 243,043 241,451
1996 243,328 243,977
1997 243,967 246,684
1998 248,806 251,095
1999 259,644 255,209
------------------------------------------------------------------------------------
FORECAST
------------------------------------------------------------------------------------
2000 258,859 257,284 259,371 260,728
2001 263,326 259,377 263,602 266,370
2002 267,951 261,488 267,904 272,135
2003 271,635 263,616 272,278 278,026
2004 276,230 265,761 276,726 284,048
2005 280,506 267,925 281,247 290,202
2006 284,900 270,107 285,844 296,492
2007 289,339 272,306 290,519 302,920
2008 293,958 274,525 295,271 309,490
2009 276,761 300,104 316,205
2010 279,017 305,017 323,068
2011 281,291 310,013 330,083
2012 283,584 315,093 337,252
2013 285,896 320,258 344,580
------------------------------------------------------------------------------------
Gr. Rate 1990-1999 1.80% 1.63%
------------------------------------------------------------------------------------
Gr. Rate 2000-2008 1.60% 0.81% 1.63% 2.17%
------------------------------------------------------------------------------------
Gr. Rate 2000-2013 0.81% 1.64% 2.17%
------------------------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-25
<PAGE> 135
[PACE LOGO]
The PJM energy forecast reflects an aggregation of Pace's development of a
sub-regional forecast for ACE, Central, Northeast, South and Southeast. As shown
in Exhibit 22, energy demand in the Southeast is expected to grow at the highest
annual average rate of 2.47% from 17,532 GWh in 1999 to 24,866 GWh in 2013.
Energy demand growth in the Southeast is followed by ACE at 2.01%, South at
1.60%, Northeast at 1.57%, and Central at 1.47%.
EXHIBIT 22: PACE SUB-REGIONAL ENERGY FORECAST FOR PJM -- GWH
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
PACE'S ENERGY FORECAST(GWH) UTILITIES'
ENERGY
FORECAST
-----------------------------------------------------------------------------------------------
ACE CENTRAL NORTHEAST SOUTH SOUTHEAST TOTAL
-----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
HISTORIC
-----------------------------------------------------------------------------------------------
1990 8,686 58,124 88,500 51,674 14,115 221,099
1991 9,030 60,057 91,424 53,344 14,734 228,588
1992 8,982 59,382 90,379 52,697 14,715 226,154
1993 9,424 61,924 94,230 54,904 15,498 235,980
1994 9,572 62,516 95,112 55,379 15,800 238,379
1995 9,812 63,701 96,895 56,377 16,257 243,043
1996 9,878 63,738 96,931 56,359 16,423 243,328
1997 9,958 63,867 97,108 56,422 16,612 243,967
1998 10,155 64,534 99,034 57,541 17,541 248,806
1999 10,459 67,027 104,063 60,563 17,532 259,644
-----------------------------------------------------------------------------------------------
FORECAST
-----------------------------------------------------------------------------------------------
2000 10,598 67,169 103,225 60,282 18,096 259,371 258,859
2001 10,811 68,158 104,841 61,247 18,544 263,602 263,326
2002 11,029 69,162 106,483 62,228 19,003 267,904 267,951
2003 11,251 70,180 108,150 63,224 19,473 272,278 271,635
2004 11,477 71,214 109,843 64,236 19,955 276,726 276,230
2005 11,708 72,263 111,563 65,264 20,449 281,247 280,506
2006 11,943 73,327 113,310 66,309 20,955 285,844 284,900
2007 12,184 74,407 115,084 67,370 21,474 290,519 289,339
2008 12,429 75,502 116,886 68,449 22,005 295,271 293,958
2009 12,679 76,614 118,717 69,545 22,550 300,104
2010 12,934 77,742 120,575 70,658 23,108 305,017
2011 13,194 78,887 122,463 71,789 23,680 310,013
2012 13,459 80,049 124,381 72,938 24,266 315,093
2013 13,730 81,227 126,328 74,106 24,866 320,258
-----------------------------------------------------------------------------------------------
Gr. Rate 1990-1999 2.08% 1.60% 1.82% 1.78% 2.44% 1.80%
-----------------------------------------------------------------------------------------------
Gr. Rate 2000-2008 2.01% 1.47% 1.57% 1.60% 2.47% 1.63% 1.60%
-----------------------------------------------------------------------------------------------
Gr. Rate 2000-2020 2.01% 1.47% 1.57% 1.60% 2.47% 1.64%
-----------------------------------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
Pace also developed the summer and winter peak demand for each sub-region based
on each subregional energy forecast reflecting historical load factors. Pace's
forecast for winter and summer peak demand for each PJM sub-region along with
utility filed peak forecasts are detailed in Exhibit 23.
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-26
<PAGE> 136
[PACE LOGO]
EXHIBIT 23: PACE SUB-REGIONAL PEAK DEMAND FORECAST FOR PJM -- MW
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
PACE NON-
ACE CENTRAL NORTHEAST SOUTH SOUTHEAST COINCIDENT PEAK
-----------------------------------------------------------------------------------------------------------------------
SUMMER WINTER SUMMER WINTER SUMMER WINTER SUMMER WINTER SUMMER WINTER SUMMER WINTER
-----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
HISTORIC
------------------------------------------------------------------------------------------------------------------
1993
1994
1995
1996
1997
1998
1999
------------------------------------------------------------------------------------------------------------------
FORECAST
------------------------------------------------------------------------------------------------------------------
2000 2,326 1,663 12,106 11,519 20,923 16,345 12,295 10,741 3,658 3,275 51,309 43,543
2001 2,361 1,688 12,240 11,646 21,168 16,536 12,443 10,870 3,726 3,336 51,938 44,076
2002 2,397 1,713 12,376 11,775 21,416 16,730 12,592 11,000 3,796 3,397 52,576 44,617
2003 2,433 1,739 12,513 11,906 21,667 16,927 12,743 11,133 3,866 3,461 53,222 45,165
2004 2,470 1,765 12,651 12,038 21,922 17,125 12,896 11,266 3,938 3,525 53,877 45,720
2005 2,507 1,792 12,792 12,171 22,179 17,326 13,051 11,402 4,011 3,591 54,540 46,282
2006 2,544 1,819 12,934 12,306 22,439 17,530 13,208 11,539 4,086 3,658 55,212 46,852
2007 2,583 1,846 13,077 12,443 22,703 17,735 13,367 11,678 4,162 3,726 55,893 47,429
2008 2,622 1,874 13,223 12,581 22,969 17,944 13,529 11,819 4,240 3,795 56,582 48,013
2009 2,661 1,902 13,370 12,722 23,239 18,154 13,692 11,961 4,319 3,866 57,281 48,606
2010 2,701 1,931 13,519 12,863 23,512 18,368 13,857 12,105 4,400 3,939 57,989 49,206
2011 2,742 1,960 13,670 13,007 23,788 18,584 14,024 12,251 4,483 4,013 58,707 49,814
2012 2,783 1,989 13,822 13,152 24,068 18,802 14,193 12,399 4,567 4,088 59,433 50,431
2013 2,825 2,019 13,977 13,299 24,351 19,023 14,365 12,549 4,652 4,165 60,170 51,055
---------------------------------------------------------------------------------------------------------------------
<CAPTION>
---------- -----------------
PJM UTILITIES
COINCIDENT PEAK
---------- -----------------
SUMMER WINTER
---------- -----------------
<S> <C> <C>
HISTORIC
------------------------------------------------------------------
1993 46,494 41,406
1994 46,019 40,653
1995 48,577 40,790
1996 44,302 40,468
1997 49,464 37,217
1998 48,445 36,532
1999 51,600 38,123
---------------------------------------------------------------------------------------------
FORECAST
------------------------------------------------------------------------------------------------------------------------
2000 50,576 43,628
2001 51,426 44,264
2002 52,238 44,917
2003 53,048 45,575
2004 53,892 46,247
2005 54,769 46,947
2006 55,634 47,631
2007 56,516 48,321
2008 57,381 48,981
2009
2010
2011
2012
2013
---------------------------------------------------------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
Pace used an hourly load module tool to translate annual peak and energy demand
growth factors into future hourly demand for the study period. The translation
process is a two step process:
1) The first step involves aggregating actual utility hourly loads as
reported to the FERC (for each utility under consideration in this study). This
aggregation creates integrated hourly system load profiles, or base system
hourly load files, for each transmission area in the PJM market.
2) The second step involves applying annual growth factors and seasonal
peak demand forecasts to the base system hourly load file, to create hourly
demand files for each year in the study.
Pace assumed that the basic historic system load shape as represented by 1998
values would be maintained throughout the study. However, system load factors do
change slightly as the result of applying annual peak and energy growth factors.
As the relationship of peak demand and energy change, the system load factor and
shape will shift.
FUEL PRICING
Pace developed fuel price forecasts for each major fuel (natural gas, No. 2
distillate fuel oil, No. 6 residual fuel oil, coal, and uranium) in the PJM
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.(3)
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.
---------------
3 Gas-fired expansion plants are assigned the natural gas regional benchmark
price.
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-27
<PAGE> 137
[PACE LOGO]
Pace applies monthly fuel adjustment factors as shown in Exhibit 24 to reflect
monthly fluctuations in fuel prices.
EXHIBIT 24: MONTHLY FUEL PRICE ADJUSTMENT FACTORS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
----------------------------------------------------------
MONTH GAS COAL NO. 2 NO. 6 JET
----------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Jan 126% 102% 102% 108% 106%
Feb 122% 101% 103% 103% 103%
Mar 110% 99% 99% 97% 97%
Apr 94% 95% 102% 99% 101%
May 85% 101% 100% 98% 97%
Jun 85% 102% 95% 97% 95%
Jul 85% 102% 94% 98% 95%
Aug 85% 102% 96% 94% 98%
Sep 86% 102% 102% 96% 101%
Oct 94% 94% 104% 102% 104%
Nov 109% 100% 102% 103% 103%
Dec 119% 98% 101% 106% 102%
----------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
The remainder of this section reviews Pace's major conclusions and base case
assumptions regarding fuel pricing.
NATURAL GAS
Pace's independent forecast of delivered natural gas prices in PJM is comprised
of commodity prices, 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 PJM
delivered price sub-regions.
Commodity Prices
In general, Pace expects Henry Hub commodity prices to decline from expected
year 2000 price levels through 2003. Thereafter, Pace expects a 0.5% annual real
price increase throughout the forecast period. Fundamental factors driving
Pace's Henry Hub commodity forecast are:
- Short-term production reductions over mid-1998 to mid-1999 were in
response to low prices and high inventory levels, which resulted from low
domestic demand brought about by warmer than normal weather over the past
two years. This decrease in supply, and expectations for more normal
weather and gas demand this winter, caused prices to increase in the
later half of 1999 and in the NYMEX futures strip for 2000.
- Stronger than normal activity, from 2000 to 2002, will occur in the
expansion of the North American pipeline grid and production capacity,
particularly from the Western Canadian Sedimentary Basin and Sable
Island. The expansions will increase gas on gas competition in the
Midwest and Northeast U.S. and displace some Gulf Coast supply, causing
Henry Hub prices to decline from current levels.
- Gulf Coast production levels will remain flat as declines are offset by
increases in deep water offshore drilling.
- Canadian imports and associated infrastructure development will level off
after 2003.
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-28
<PAGE> 138
[PACE LOGO]
- Shifting preferences in energy consumption and power generation spurred
by environmental regulations for cleaner, more efficient natural gas will
support a slightly higher long-term real price escalation relative to
other fuels.
- A continued decline in finding and production costs, brought about by
technological advancements, will allow for lower inventories and a more
economically driven and responsive E&P sector. These fundamentals will
keep real price escalation from rising too high relative to other fuels.
Exhibit 25 provides an annual summary of Pace's independent forecast of the
Henry Hub and the delivered prices to each respective PJM fuel sub-region.
EXHIBIT 25: PJM NATURAL GAS PRICE FORECASTS (1998 $/MMBTU)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
------------------------------------------------------
HENRY PJM NORTHERN
YEAR HUB PJM EAST DELMARVA WEST NJ
------------------------------------------------------
<S> <C> <C> <C> <C> <C>
2000 2.88 3.37 3.35 3.60 3.27
2001 2.75 3.22 3.20 3.45 3.12
2002 2.47 2.98 2.94 3.19 2.86
2003 2.33 2.86 2.82 3.07 2.74
2004.. 2.34 2.89 2.85 3.10 2.77
2005.. 2.35 2.92 2.88 3.13 2.80
2006.. 2.36 2.93 2.89 3.14 2.81
2007.. 2.37 2.94 2.90 3.15 2.82
2008.. 2.39 2.96 2.92 3.17 2.84
2009.. 2.40 2.97 2.93 3.18 2.85
2010.. 2.41 2.98 2.94 3.19 2.86
2011.. 2.42 2.99 2.95 3.20 2.87
2012.. 2.43 3.00 2.96 3.21 2.88
2013.. 2.45 3.02 2.98 3.23 2.90
------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
Regional Basis
The delivered gas price forecast incorporates general price differentials and
the cost of transportation to the PJM gas price sub-regions as depicted in
Exhibit 26.
--------------------------------------------------------------------------------
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[PACE LOGO]
EXHIBIT 26: PACE GAS PRICE SUBREGIONS -- PJM
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
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:
- Transportation rates in PJM will experience some incremental competition
during the early part of the mid-term as projects, such as Millennium,
are built to bring excess Midwestern supply to markets in the Northeast.
- Eastern PJM receives supply primarily off of Texas Eastern Transmission
(TETCO) and Transcontinental Gas Pipeline (Transco). These pipelines
terminate in the New York City (NYC) market area, which sets the price
for deliveries in this area. Eastern PJM markets can receive supply just
upstream of constraint points heading into NYC and therefore are priced
at a $0.04/MMBtu discount to delivered prices in the NY City region. On
an annual average basis, prices in Western PJM are approximately
$0.10/MMBtu less than prices in Eastern PJM. This price discrepancy is
attributed to the region's proximity to Appalachian supply and access to
more available pipeline capacity on Columbia Transmission (TCO) and CNG
Transmission (CNG). Markets in Northern New Jersey receive supply
primarily from Transco and TETCO. These deliveries are downstream of
seasonal constraint points that cause delivered supply to average
approximately $0.04/MMBtu over PJM East deliveries on an annual average
basis. Markets located in the DelMarVa Peninsula do not have direct
access to interstate pipeline systems and, therefore, must use the local
distribution companies to obtain delivery of supply. Pace assumes a
transportation charge of $0.25/MMBtu in addition to PJM East delivered
prices.
--------------------------------------------------------------------------------
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[PACE LOGO]
FUEL OIL
Pace forecasts prices for No. 2 distillate oil and No. 6 residual oil for PJM
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:
- Commodity prices as represented by the price for West Texas Intermediate
("WTI") crude oil on the NYMEX in Cushing, Oklahoma,
- Location basis, and
- Crack spreads.
Commodity Prices
Following extremely depressed market conditions in 1997-98, when prices for some
crude grades slipped into single digits, there has been a significant rally in
crude oil prices since late 1999. Recent price strength is attributed to low
inventory levels brought about by effective compliance by OPEC members with
reduced output quotas and demand growth stemming from a continued strong US
economy and gradual economic recovery in Asia. Prices are currently at levels
that will stimulate non-OPEC production and encourage OPEC members to either
exceed current production quotas or revise the quotas to sanction higher output
levels. Therefore, it is Pace's view that average world prices (as measured by
the IRAC) will settle at levels that are comparable to the average real price
for the five-year period prior to the 1998 price collapse. Pace's WTI commodity
forecast is based on the following key fundamentals:
OPEC Production
- Compliance by OPEC members to production cuts will continue through the
first quarter of 2000. The continued reduction in supply will prop prices
up through mid 2000 when signs of increased production activity from
non-OPEC members and the potential elimination of cuts by OPEC members
should become visible causing prices to gravitate toward a more
sustainable long term equilibrium price of approximately $20.88.
- Continued expansion of Iraqi production to 2.8 MMBD is expected by the
end of year 2000, consistent with UN Security Council resolutions. Iraq
has signaled its intent to expand production aggressively when UN
sanctions are lifted.
- OPEC will undertake relatively ambitious capacity expansion programs in
order to accommodate the projected rise in worldwide petroleum demand.
Much of the expansion will occur in the Persian Gulf where the
reserves-to-production ratio already exceeds 80 years.
- OPEC will refrain from further attempts to boost prices by curtailing
output, targeting a price range near recent historical averages prior to
the 1997-98 glut.
- OPEC's relative market share will grow from its current level of
approximately 40%, but will not surpass the historic high of 53% reached
in 1973.
Non-OPEC Production
- Non-OPEC production has been 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 prices in the range forecast by Pace are sufficient to sustain, and
in some regions
--------------------------------------------------------------------------------
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expand, output by non-OPEC producers, the relative share of non-OPEC
output will fall due to expected strong growth in OPEC production.
- US 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% annually. The impact of sharply lower
Alaskan oil output, which has historically represented about 25% of total
US crude oil production, is tempered somewhat by technological
innovations that improve success rates and lower costs for deepwater
exploration and production in the Gulf of Mexico.(4)
- 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 delays in startup of many Caspian Basin projects
as well as a generally pessimistic outlook for investment in Russia.
- North Sea production, the largest supply component in the European Union,
is expected to grow for the next several years before peaking and
entering a decline phase.
Oil Demand
- Flat to modest projected petroleum demand growth in industrialized
countries is projected due to lower expected GDP growth and a gradual
shift away from oil for non-transportation uses such as power generation
and space heating.
- Dramatic increases in demand 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.
- FSU and Eastern Europe are projected to have relatively rapid GDP growth,
but the impact on petroleum demand is modest because the transition to a
market system will lead to offsetting improvements in energy efficiency.
Exhibit 27 shows Pace's crude oil price forecast for WTI for the period of
2000-2020.
EXHIBIT 27: WTI CRUDE OIL PRICE FORECAST (1998 $/MMBTU)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
--------------------------------------
WTI PRICE
YEAR FORECAST
--------------------------------------
<S> <C>
2000 4.31
2001 4.19
2002 4.07
2003 3.95
2004 3.83
2005 3.71
2006-2013 3.60
--------------------------------------
</TABLE>
--------------------------------------------------------------------------------
---------------
4 Combined with the expected growth in US oil demand, the decline in US
production implies an increase in US oil imports.
--------------------------------------------------------------------------------
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[PACE LOGO]
Location Basis
An adjustment for WTI crude oil prices must be made to reflect the price
differentials between Cushing, OK and the oil regions presented in Exhibit 28.
The location adjustment for each region is calculated by reviewing the
differential between prices for oil product in Oklahoma and each oil sub-region.
EXHIBIT 28: PACE OIL PRICE SUB-REGIONS FOR PJM
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
A local delivery charge is also applied to local rack pricing to reflect
transport charges to the plant sites. The final regional Location Basis are
presented in Exhibit 29.
EXHIBIT 29: PJM FUEL OIL LOCATION BASIS (1998 $/MMBTU)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
----------------------------------------------------
CUSHING, OK TO: LOCATION BASIS
----------------------------------------------------
<S> <C>
PJM East (0.03)
PJM South (0.03)
PJM West 0.14
New York City &
Vicinity (0.12)
----------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
Refined Product Crack Spreads
Ten years of historical US Gulf Coast spot prices were used to determine the
average crack spreads between crude oil and No. 2 distillate and No. 6 residual.
The average crack spreads shown in Exhibit 30 are forecasted to determine the
refined product prices in each region.
--------------------------------------------------------------------------------
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[PACE LOGO]
EXHIBIT 30: CRUDE OIL TO REFINED PRODUCT CRACK SPREADS (1998 $/MMBTU)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
----------------------------------------------------------------------------
YEAR LS NO. 2 OIL NO. 2 OIL NO. 6-0.3% OIL NO. 6-1% OIL
----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1998 0.69 0.59 0.07 (0.38)
1999 0.65 0.50 (0.12) (0.39)
2000 0.63 0.50 (0.13) (0.44)
2001 0.62 0.49 (0.15) (0.49)
2002 0.61 0.49 (0.16) (0.54)
2003 0.60 0.49 (0.18) (0.59)
2004 0.59 0.48 (0.19) (0.64)
2005 0.59 0.48 (0.19) (0.64)
2006-13 0.59 0.48 (0.19) (0.64)
----------------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
Delivered Oil Price Forecasts
By summing each of the oil price components detailed above, Pace's forecast of
annual delivered oil prices are provided in Exhibit 31.
EXHIBIT 31: FUEL OIL PRICE FORECAST BY PJM SUB-REGION (1998 $/MMBTU)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
PJM WEST (W PA, W M) PJM SOUTH (E MD) PJM EAST (E PA, NJ) NEW YORK CITY & VICINITY
----------------------------------------------------------------------------------------------------------------------
LS NO.6 NO.6 LS NO.6 NO.6 LS NO.6 NO.6 LS NO.6 NO.6
YEAR NO.2 NO.2 .3% 1% NO.2 NO.2 .3% 1% NO.2 NO.2 .3% 1% NO.2 NO.2 .3% 1%
----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000 5.08 4.94 4.31 4.01 4.91 4.77 4.14 3.84 4.91 4.77 4.14 3.84 4.82 4.68 4.05 3.75
2001 4.95 4.82 4.18 3.84 4.78 4.65 4.01 3.67 4.78 4.65 4.01 3.67 4.69 4.56 3.92 3.58
2002 4.82 4.70 4.05 3.67 4.65 4.53 3.88 3.50 4.65 4.53 3.88 3.50 4.56 4.44 3.79 3.41
2003 4.69 4.58 3.91 3.50 4.52 4.41 3.74 3.33 4.52 4.41 3.74 3.33 4.43 4.32 3.65 3.24
2004 4.56 4.46 3.78 3.33 4.39 4.29 3.61 3.16 4.39 4.29 3.61 3.16 4.30 4.20 3.52 3.07
2005 4.44 4.34 3.66 3.21 4.27 4.17 3.49 3.04 4.27 4.17 3.49 3.04 4.18 4.08 3.40 2.95
2006 4.32 4.22 3.54 3.10 4.15 4.05 3.37 2.93 4.15 4.05 3.37 2.93 4.06 3.96 3.28 2.84
2007 4.32 4.22 3.54 3.10 4.15 4.05 3.37 2.93 4.15 4.05 3.37 2.93 4.06 3.96 3.28 2.84
2008 4.32 4.22 3.54 3.10 4.15 4.05 3.37 2.93 4.15 4.05 3.37 2.93 4.06 3.96 3.28 2.84
2009 4.32 4.22 3.54 3.10 4.15 4.05 3.37 2.93 4.15 4.05 3.37 2.93 4.06 3.96 3.28 2.84
2010 4.32 4.22 3.54 3.10 4.15 4.05 3.37 2.93 4.15 4.05 3.37 2.93 4.06 3.96 3.28 2.84
2011 4.32 4.22 3.54 3.10 4.15 4.05 3.37 2.93 4.15 4.05 3.37 2.93 4.06 3.96 3.28 2.84
2012 4.32 4.22 3.54 3.10 4.15 4.05 3.37 2.93 4.15 4.05 3.37 2.93 4.06 3.96 3.28 2.84
2013 4.32 4.22 3.54 3.10 4.15 4.05 3.37 2.93 4.15 4.05 3.37 2.93 4.06 3.96 3.28 2.84
----------------------------------------------------------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
COAL FORECAST
Pace's coal price 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, expectations
for the timing of "over-market" coal contract expiration, and anticipated
changes in consumption profiles required to satisfy Phase II SO(2) emission
limits. Pace employs the following process to generate plant specific coal price
forecasts:
1. National trends in coal supply and demand were surveyed to forecast
escalation rates for coal commodity prices as a function of sulfur
grade.
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[PACE LOGO]
2. The current coal commodity price is established for each plant based on
historical data and a specific coal consumption profile is developed for
each plant relating to sulfur grade and contracting status (i.e., spot
vs. long-term contract).
3. Each plant's purchasing profile was reviewed to determine the transition
from above-market contract deliveries to market-based purchases.
4. Information from the preceding steps was combined with estimated
transportation rates from relevant producing regions to each plant to
obtain plant-specific forecasts of delivered coal costs.
To reflect variations in coal quality, Pace divides coal consumption by power
generators in PJM into three categories. The categories are based on three
sulfur grade ranges as defined in Exhibit 32.
EXHIBIT 32: DEFINITION OF COAL QUALITY GRADES
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
LBS S LBS SO(2) APPROX.
PER MMBTU PER MMBTU % S
------------------------------------------------------------------------------------
<S> <C> <C> <C>
Low Sulfur* <0.60 <1.20 < 0.72
Medium Sulfur 0.6-1.67 1.20-3.34 0.72-2.00
High Sulfur >1.67 >3.34 >2.00
------------------------------------------------------------------------------------
</TABLE>
* Represents average emission rate utilities are required to meet by January 1,
2000 under CAAA, or compliance coal.
--------------------------------------------------------------------------------
The following discussion profiles historic and expected trends in the market
fundamentals underlying the demand, supply, and cost of coal delivered to
utilities in the PJM market. Ultimately, this information along with historic
delivered prices serves to develop the plant level delivered coal cost Pace
employs in the simulation of the PJM market.
Trends in Coal Supply
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.
- Coal demand is expected to increase only slightly in the aggregate, with
modest growth in domestic electric generation consumption partially
offset by declining exports.
- Coal consumption for power generation will increase slightly as a result
of higher utilization rates at existing plants, and there may also be
additions to coal-fired generating capacity in later years.
- Composition of demand will shift in favor of lower sulfur grades that
facilitate compliance with CAAA90 Phase II SO(2) emissions limits.
- Mine productivity will continue to be the key supply side price driver.
There is a long-term trend of increasing mine productivity that will
continue to exert downward pressure on coal prices in the U.S.
- Productivity growth is unlikely to continue at historical rates for the
following reasons:
- Many of the less efficient mines have already been shut down and the
first waves of industry consolidation have already passed.
- Mining companies have dramatically reduced their investment in new
capacity and are currently idling (reducing production) capacity at
existing mines in response to the soft coal market.
--------------------------------------------------------------------------------
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[PACE LOGO]
- Historically, U.S. utilities have purchased coal under long-term coal
supply contracts. In the short to medium term, significant numbers of
such contracts that are priced above market will expire and/or be
renegotiated, which will tend to lower the fuel cost for plants in the
region. These contract expirations will continue to release substantial
amounts of coal to the spot market as has been the case over the last
five years. Pace expects that the vast majority of the contracts priced
over-market specific to PJM will have expired around 2001, earlier than
similar such contracts in other NERC regions.
- Intensified competition among coal producers and shippers will stimulate
innovation and tighten operating margins to further reduce both
extraction and transportation costs.
- 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.
While these factors will tend to depress overall coal prices, albeit not at
historical rates, it is likely that there will be a divergence in the relative
rates of price decline across coal grades. Factors affecting the price of
specific sulfur grades include:
- Compliance with stricter air quality standards under Phase II of the CAAA
is expected to increase demand, and thereby mitigate expected price
declines, for lower sulfur coal grades. The impact on demand for
low-sulfur coal will be determined by the market value of emission
allowances, capital cost of scrubbers, and the amount of emission
allowances banked by an individual generator. However, most electric
generation facilities have found the use of low sulfur coal to be the
most cost-effective option for complying with CAAA mandates.
- Demand for higher sulfur coal is expected to decline faster than other
grades as utilities and IPPs move to comply with stricter sulfur emission
standards, particularly until 2005 when additional scrubbers are
scheduled to be installed.
- Real price declines for medium sulfur coal will be bounded by the
economics of burning lower sulfur coal without scrubbing compared with
purchasing higher sulfur coals in conjunction with scrubbing or utilizing
emission allowances.
Commodity Profile and Forecast
Coal consumption in PJM is dominated by medium sulfur coal from Pennsylvania and
West Virginia, with the remainder split between high sulfur coal from Northern
Appalachia and low sulfur coal from Central Appalachia. Exhibit 33 depicts the %
allocation of coal quality by sulfur grade used by utilities in PJM.
--------------------------------------------------------------------------------
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[PACE LOGO]
EXHIBIT 33: COAL CONSUMPTION BY SULFUR GRADE -- PJM
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
Based on a review of historical prices of coal delivered to utilities in the
study area, Pace established individual plant base year (1998) delivered prices
ranging from $0.94/MMBtu to $1.97/MMBtu in PJM. The base year prices were
derived using current full year of price data available from FERC Form 423 (June
1998 to May 1999). The range in delivered price is due to differences in each
plant's consumption profile with respect to sulfur level, varying transportation
rates and possible price discounts for large volume consumers. The varying base
year prices are also affected by the amount of coal under contract versus spot
purchases.
The accuracy of the FERC data was verified by comparing it to independent
estimates of delivered costs developed from mine-mouth price data published in
Coal Week and estimated transportation costs to plants in the study region.
The escalation rate for each plant's market-based coal price is weighted by its
past and projected consumption profile. Pace's forecasted coal price escalators
for each sulfur grade are provided in Exhibit 34.
EXHIBIT 34: PROJECTED REAL COMMODITY ESCALATION RATES BY SULFUR LEVEL
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
---------------------------------------------------------------------
CUM. AVG.
1998-
1998-05 2005-13 2013
---------------------------------------------------------------------
<S> <C> <C> <C>
Low Sulfur -1.4% -0.7% -1.03%
Medium Sulfur -2.2% -1.7% -1.93%
High Sulfur -3.6% -2.4% -2.96%
---------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
Pace's forecast is consistent with recent trends in Central Appalachia, but
implies that real prices at times will decline at a rate slower than the recent
historical trends for both Northern Appalachia and the Northern/ Central
Appalachia weighted average. In addition to slower productivity growth,
consolidation, and a recovery in export sales, this trend change is also due to
the expiration of long-term, above market contracts, as discussed previously.
--------------------------------------------------------------------------------
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[PACE LOGO]
Transportation Profile and Forecast
The transportation component of PJM delivered coal prices was determined using
data and projections from Hill & Associates, Inc.'s ("Hill") Coal Demand and
Price Projections: Volume 1 and 2, prepared for the Gas Research Institute
("GRI") and data obtained from the Fieldston Coal Transportation Manual. The
Hill data includes detail on transportation costs trends by sulfur grade for
deliveries into various sub-regions of the study area.
As with coal commodity prices, the key driver of future coal transport costs is
productivity. Productivity gains through consolidation and the application of
new technology in the rail transportation industry will keep transportation
costs low or declining. Use of aluminum rail cars, improved scheduling and fleet
management, utilization of electronic control mechanisms, and better locomotive
engineering are factors contributing to decreased cycle times, increased
carrying capacity, and enhanced rail productivity. Barge rates are expected to
continue to be more volatile than rail rates, but 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 in real terms.
The transportation component, both base year and projected, was calculated using
a weighted average depending on the source region for each plant's coal. In
general, Pace applied the average transportation rates projected by Hill for the
relevant supply and consumption regions. In the case of plants with a
significant component of mine-mouth coal, the transportation rate was adjusted
to reflect those plants' relatively lower transportation costs. Average
transportation escalation rates applied by Pace are provided in Exhibit 35.
EXHIBIT 35: PROJECTED AVERAGE TRANSPORTATION ESCALATION RATES
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
---------------------------------------------------------------------
CUM. AVG.
1998-
1998-05 2005-13 2013
---------------------------------------------------------------------
<S> <C> <C> <C>
Low/Medium Sulfur -1.6% -1.0% -1.28%
High Sulfur -1.7% -1.0% -1.33%
---------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
Plant Delivered Coal Costs
Pace developed delivered coal price forecasts for each coal-fired plant in the
study area utilizing each plant's coal consumption profile, base year price,
Pace's coal price escalators and the Hill transportation rate forecasts. The
resulting delivered coal price forecast on a regional level for each sulfur
grade is depicted in Exhibit 36.(5)
---------------
5 The regional level delivered coal price forecast was derived applying the
delivered escalation rates, weighted by commodity and transportation, to 1998
weighted average base year prices by sulfur level.
--------------------------------------------------------------------------------
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[PACE LOGO]
EXHIBIT 36 AVG. DELIVERED COAL PRICE FORECAST FOR PJM BY SULFUR GRADE (1998 $)
--------------------------------------------------------------------------------
[CHART]
--------------------------------------------------------------------------------
URANIUM
Pace expects uranium prices to remain constant in real terms over the next 13
years. Therefore, Pace assumed utility uranium prices would be equal to their
1998 average value (0.00 % annual real rate of escalation).
EXISTING GENERATING CAPACITY PROFILES
Pace reviewed and assessed the existing and expected power generation resource
mix, the operational characteristics of capacity in PJM, and the cost profile of
existing units.
EXISTING UNIT COST PROFILE
For characterization of existing capacity, Pace utilized plant and unit specific
data for 1998 as reported to FERC and the EIA detailing variable O&M, fixed O&M,
fuel costs (adjusted for market delivered prices), capital expenditures, heat
rate efficiency, and summer and winter capacity. Given that capital costs are
not reported at the plant level, Pace has developed a methodology for allocating
utility-level embedded costs to each major power plant in the region.
Pace expects that variable and fixed O&M will remain constant over the 20 year
forecast period. Further, in order to maintain a level of conservativeness
underlying the Base Case Pace did not retire any existing units except for
nuclear capacity as detailed in the next section.
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[PACE LOGO]
NUCLEAR UNIT ASSESSMENT
Accounting for approximately 21% of installed capacity in PJM nuclear capacity
has a significant impact on the regional electric power markets and the expected
need for additional capacity into the future.
The nuclear industry has been subject to much uncertainty regarding future plant
operations. Specifically, the nuclear fleet must address issues associated with
design, cost, and re-licensing in order to establish future availability. While
license renewal remains an uncertainty for several plants in this and other
regions nationwide, the Calvert Cliffs nuclear facility in PJM is the first
nuclear facility in the US to receive license renewal. A final ruling on the
license application was issued by the Nuclear Regulatory Commission (NRC) on
March 23, 2000 and provides for license extension through 2034 and 2036 for
Units 1 and 2, respectively.
In addition, nuclear asset purchases have enjoyed significant attention from
market participants. Groups particularly active in nuclear tenders include
Entergy, AmerGen (a joint venture of PECO Energy and British Energy), and more
recently, Dominion Resources. Calling upon core competencies in nuclear asset
operations, these firms hope to decrease operating costs, increase plant margins
through pooling multiple nuclear assets, and ultimately, reduce costs associated
with decommissioning. However, it is currently unclear whether these and other
nuclear operators intend to expend significant capital to refurbish and maintain
these units past their license expiration or if they intend to decommission
these units when major investment is required.
Given the uncertainty surrounding the future of nuclear generation, Pace assumes
that all nuclear units in PJM will retire at their license expiration date.
Exhibit 37 provides a list of existing nuclear capacity located in PJM and the
current NRC license expiration date.
EXHIBIT 37: PJM NUCLEAR UNITS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------
SUMMER YEAR LICENSE
SUB- CAPACITY ORIGINALLY EXPIRATION/
REGION REGION PLANT NAME UNIT # OWNER (MW) CONSTRUCTED RETIREMENT
---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
MAAC South Calvert Cliffs 1 BG&E 835 1975 2034
MAAC South Calvert Cliffs 2 BG&E 840 1977 2036
MAAC ACE Hope Creek 1 PSE&G and ACE 1,031 1987 2026
MAAC Northeast Limerick 1 PECO Energy Co. 1,155 1986 2024
MAAC Northeast Limerick 2 PECO Energy Co. 1,155 1990 2029
AmerGen Energy (PECO and British 619
MAAC Northeast Oyster Creek 1 Energy) 1969 2009
PECO Energy Co/PSE&G/ACE/ 1,093
MAAC Northeast Peach Bottom 2 Delmarva 1974 2013
PECO Energy Co/PSE&G/ACE/ 1,093
MAAC Northeast Peach Bottom 3 Delmarva 1974 2014
PECO Energy Co/PSE&G/ACE/ 1,106
MAAC Northeast Salem 1 Delmarva 1977 2016
PECO Energy Co/PSE&G/ACE/ 1,124
MAAC Northeast Salem 2 Delmarva 1981 2020
PP&L, Inc. and Allegheny Electric 1,090
MAAC Central Susquehanna 1 Coop, Inc. 1983 2022
PP&L, Inc. and Allegheny Electric 1,094
MAAC Central Susquehanna 2 Coop, Inc. 1985 2024
AmerGen Energy (PECO and British 786
MAAC Central Three Mile Island 1 Energy) 1974 2014
</TABLE>
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
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EXPANSION GENERATING CAPACITY
NEW PLANT ANNOUNCEMENT ASSUMPTIONS
Developers have announced intentions to construct approximately 10,000 MW of
merchant capacity in PJM. Pace assessed each project's development status (i.e.,
permitting, financing, construction) through a review of trade press, regulatory
agency queuing, discussions with market participants, and information attained
through our activities in energy markets. Pace believes just over 4,600 MW of
this announced capacity has a strong potential of reaching commercial operation
in PJM. As detailed in Exhibit 38, Pace included those projects determined to
have a strong potential of reaching commercial operation in the Base Case.
--------------------------------------------------------------------------------
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[PACE LOGO]
EXHIBIT 38: ANNOUNCED POWER PROJECTS IN PJM
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
PJM PROJECTS INCLUDED IN BASE CASE
PROJECT SUB- CAPACITY UNIT
COMPANY NAME REGION LOCATION STATE MW FUEL TYPE IN SERVICE COMMENTS
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
AES Corp. Red Oak Northeast Sayerville NJ 800 NG CC 2002 Permitting and finance
closing expected by
year-end 2000
AES Corp. Ironwood Central South Lebanon PA 700 NG CC 2001 Financing complete,
Township under construction
Enron Capital Linden Cogen Northeast Linden NJ 250 NG CC 2002 Under Development
and Trade
Resources
PG&E Generating Linden Northeast Linden NJ 1,100 NG CC 2003 Under Development;
Dupont Brownfield Site
with prelim siting
approvals in place
PG&E GENERATING MANTUA Northeast West Depford NJ 800 NG CC 2003 Under Development; has
CREEK received final Township
planning board siting
approval
PEI Power Corp. Archbald Central Archbald PA 70 Methane CT 2001 Under Construction;
broke ground in
November 1998
PECO Energy Muddy Run Northeast Muddy Run PA 104 Water Hydro 2001 Expansion to existing
hydro unit presently
under construction.
Commonwealth Accomack Southeast Accomack VA 312 Oil CT 2002 First phase of
Chesapeake Corp County construction commenced
of Norfolk August 1999.
Virginia
Calpine Ontelaunee Northeast Ontelaunee PA 545 NG CC 2003 Permitting application
Corporation Township filed June 1999 and
expect to break ground
in early 2000.
Purchased Westinghouse
501 F-D Turbines.
SUBTOTAL: 4,681
PJM PROJECTS NOT INCLUDED IN BASE CASE
Columbia Kelson Ridge Waldorf MD 550 NG CC 2001 County hearings on
Electric environmental impact
began 11/99.
Colombia Liberty Delaware PA 500 NG CC 2001 50/50 ownership split
Electric County
Westcoast Power
Panda Energy Hanover Hanover PA 1,000 NG CC 2002 Air permitting under
International Township process. EPC contractor
to be selected by April
2000.
Old Dominion Cecil County Cecil County MD 1,020 NG CT 2002 Filed permit
Electric application with
Cooperative Maryland PUC in August
1999
FPL Energy Marcus Hook Marcus Hook PA 725 NG CC 2002 Received community
Cogen council approval 1/2000
PP&L Global Martins Martins Creek PA 550 NG CC 2002
Creek
Williams Energy Hazleton Hazleton PA 250 NG CC 2000 Under Development,
Group Williams will act as
power marketer,
Repowering
SUBTOTAL: 4,595
GRAND TOTAL 9,276
</TABLE>
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-42
<PAGE> 152
[PACE LOGO]
EXPANSION UNIT CHARACTERISTICS AND COSTS
In evaluating potential generation technologies for meeting future demand
requirements in the region, Pace assessed each technology's maturity level,
operating history, and duty cycle. The region's existing power supply system is
comprised of an abundance of base-load power plants (e.g., coal, nuclear, and
hydro) and abundant intermediate and peaking capabilities.
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:
- Pulverized Coal-Fired Capacity -- to meet base load requirements.
- Gas-Fired Combined Cycle -- to meet base load through intermediate
requirements.
- Gas-Fired Combustion Turbine -- to meet peak load requirements.
The characteristics of these standard units are detailed in Exhibit 39. These
expansion unit costs drive the expansion planning module to determine the
necessary capacity additions to meet projected demand and provide reserves with
the optimum mix of gas-fired combustion turbine, gas-fired combined cycle, and
coal-fired steam turbine capacity.
EXHIBIT 39: EXPANSION UNIT CHARACTERISTICS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------
ITEM UNIT GAS CT GAS CC GAS CC COAL ST
---------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Model or Technology F G
---------------------------------------------------------------------------------
ASSUMPTIONS
Available Year Year 1999 1999 2005
Capacity MW 170 520 520 500
Installed Cost $/kW 325 525 536 1,050
Variable O&M $/MWh 3.50 1.75 1.75 1.75
Fixed O&M $/kW-yr 8.25 14.00 14.00 29.00
Heat Rate Btu/kWh 10,400 7,050 6,850 9,600
Percent Equity % 30 30 30 30
Interest Rate % 8.50 8.50 8.50 8.50
After Tax Return on
Equity % 15.00 15.00 15.00 15.00
Debt Term Years 15 15 15 15
Forced Outage % 2.5 2.5 2.5 2.5
Annual Maintenance Weeks 2.0 3.0 3.0 4.5
---------------------------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
The expansion unit characteristics are assumed for standard construction
conditions. In areas where there are higher land values, labor costs, and other
potential cost adders, Pace increased the standard unit costs accordingly.
Pace's assumption of the high construction cost areas and their associated
adders are shown in Exhibit 40.
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-43
<PAGE> 153
[PACE LOGO]
EXHIBIT 40: HIGH CONSTRUCTION COST AREAS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
-------------------------------------------------------------
RESULTING INSTALLED COST ($/KW)
MULTIPLE OF --------------------------------
MODEL STANDARD COST CC CC
ZONE ASSUMPTION CT F G COAL
-------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Central 1.00 325 525 536 1,050
South 1.10 358 578 590 1,155
PJM-SE 1.10 358 578 590 1,155
ACE 1.15 374 604 616 1,208
PJM-NE 1.15 374 604 616 1,208
-------------------------------------------------------------
</TABLE>
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-44
<PAGE> 154
[PACE LOGO]
--------------------------------------------------------------------------------
PACE GLOBAL ENERGY SERVICES, LLC
--------------------------------------------------------------------------------
Pace Global Energy Services, LLC is an integrated energy consulting and
management company providing both strategic and transactional services to the
energy industry since 1979. Pace has extensive experience with the fuel and
power market evaluations both domestically and internationally. Pace provides a
unique level of experience and expertise in both the power and fuels markets.
Specifically, Pace provides our clients the following:
- Detailed and fundamental analysis of integrated power and fuel markets;
- A proven track record for comprehensive market price assessments for the
Northeast and other regions throughout the U.S. and internationally;
- Experience in power project financing and project due diligence support
of over 15,000 MW of projects;
- Real world gas and power transaction management experience nationwide and
specifically in the Northeast market area;
- Experience and perspective of working on behalf of developments,
industrials, and financial institutions during the development and
construction of energy projects;
- Multi-area market assessments considering transmission constrained power
trading;
- Risk management and market price volatility assessment and valuation;
- Optimization modeling and forecasts of energy and capacity markets.
--------------------------------------------------------------------------------
PROPRIETARY & CONFIDENTIAL
A-45
<PAGE> 155
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
WE HAVE NOT AUTHORIZED ANY DEALER, SALESPERSON OR OTHER PERSON TO GIVE YOU
WRITTEN INFORMATION OTHER THAN THIS PROSPECTUS OR TO MAKE REPRESENTATIONS AS TO
MATTERS NOT STATED IN THIS PROSPECTUS. YOU MUST NOT RELY ON UNAUTHORIZED
INFORMATION. THIS PROSPECTUS IS NOT AN OFFER TO SELL THE BONDS OR OUR
SOLICITATION OF YOUR OFFER TO BUY THE BONDS IN ANY JURISDICTION WHERE THAT WOULD
NOT BE PERMITTED OR LEGAL. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALES
MADE HEREUNDER AFTER THE DATE OF THIS PROSPECTUS SHALL CREATE AN IMPLICATION
THAT THE INFORMATION CONTAINED HEREIN OR THE AFFAIRS OF THE COMPANY HAVE NOT
CHANGED SINCE THE DATE OF THIS PROSPECTUS.
UNTIL , ALL DEALERS THAT EFFECT TRANSACTIONS IN THESE SECURITIES,
WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DELIVER A
PROSPECTUS. THIS IS IN ADDITION TO THE DEALERS' OBLIGATION TO DELIVER A
PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNUSED
ALLOTMENTS OR SUBSCRIPTIONS.
CEDAR BRAKES I, L.L.C.
$310,600,000
OFFER TO EXCHANGE ALL OUTSTANDING
8 1/2% SENIOR SECURED BONDS DUE 2014
FOR
8 1/2% SERIES B SENIOR SECURED BONDS DUE 2014
--------------------
PROSPECTUS
--------------------
NOVEMBER 28, 2000
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE> 156
PART II
INFORMATION REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF MANAGERS AND OFFICERS
Our limited liability company agreement provides that, except to the extent
expressly prohibited by the Delaware Limited Liability Company Act, we must
indemnify each person made or threatened to be made a party to any action or
proceeding, whether civil or criminal, by reason of the fact that the person or
the person's testator or intestate is or was our member or officer, against
judgments, fines (including excise taxes assessed on a person with respect to an
employee benefit plan), penalties, amounts paid in settlement and reasonable
expenses, including attorneys' fees, actually and necessarily incurred in
connection with such action or proceeding, or any appeal from such actions or
proceedings; provided that no indemnification will be made if a judgment or
other final adjudication adverse to the person establishes that his conduct did
not meet the then applicable minimum statutory standards of conduct; and
provided, further, that no indemnification will be required to any settlement or
other non-adjudicated disposition of any threatened or pending action or
proceeding unless we have given our prior consent to such settlement or such
other disposition, which consent will not be unreasonably withheld.
Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to managers, officers or persons controlling us pursuant to the
foregoing, we have been informed that, in the opinion of the Securities and
Exchange Commission, such indemnification is against public policy as expressed
in the Securities Act and is, therefore, unenforceable.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
----------- -----------
<C> <S>
1.1 -- Purchase Agreement dated as of September 20, 2000 between
Cedar Brakes I, L.L.C. and Credit Suisse First Boston
Corporation, as Initial Purchaser.
3.1 -- Certificate of Formation of Cedar Brakes I, L.L.C. dated
as of March 3, 2000.
3.2 -- Amended and Restated Limited Liability Company Agreement
of Cedar Brakes I, L.L.C. dated September 11, 2000.
3.3 -- Amendment No. 1, dated October 19, 2000, to Amended &
Restated Limited Liability Company Agreement of Cedar
Brakes I, L.L.C. dated September 11, 2000.
4.1 -- Indenture dated as of September 26, 2000 between Cedar
Brakes I, L.L.C. and Bankers Trust Company, as Trustee.
4.2 -- First Supplemental Indenture dated as of November 20,
2000 between Cedar Brakes I, L.L.C. and Bankers Trust
Company, as Trustee.
4.3 -- Form of 8 1/2% Senior Secured Bonds due February 15,
2014.
4.4 -- Assignment and Security Agreement dated as of September
26, 2000 between Cedar Brakes I, L.L.C. and Bankers Trust
Company, as Trustee.
4.5 -- Accounts Control Agreement dated as of September 26, 2000
among Cedar Brakes I, L.L.C., Bankers Trust Company, as
Trustee, and Bankers Trust Company, as Securities
Intermediary.
4.6 -- Consent and Acknowledgment dated September 26, 2000 among
Cedar Brakes I, L.L.C., El Paso Energy Corporation and
Bankers Trust Company, as Trustee.
</TABLE>
II-1
<PAGE> 157
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
----------- -----------
<C> <S>
4.7 -- Consent and Acknowledgment dated September 26, 2000 among
Cedar Brakes I, L.L.C., El Paso Merchant Energy, L.P. and
Bankers Trust Company, as Trustee.
4.8 -- Consent and Acknowledgment dated September 26, 2000 among
the Company, Public Service Electric and Gas Company and
Bankers Trust Company, as Trustee.
4.9 -- Registration Rights Agreement dated as of September 20,
2000 between Cedar Brakes I, L.L.C. and Credit Suisse
First Boston, as Initial Purchaser.
5.1 -- Opinion of Chadbourne & Parke LLP as to the legality of
the bonds being registered hereby.
8.1 -- Opinion of Chadbourne & Parke LLP regarding tax matters.
10.1 -- Amended and Restated Power Purchase Agreement dated as of
March 21, 2000 between Cedar Brakes I, L.L.C. and Public
Service Electric and Gas Company.
10.2 -- Power Services Agreement dated September 20, 2000 between
Cedar Brakes I, L.L.C. and El Paso Merchant Energy, L.P.
10.3 -- Administrative Services Agreement dated as of September
20, 2000 between Cedar Brakes I, L.L.C. and El Paso
Merchant Energy, L.P.
10.4 -- Guaranty dated as of September 20, 2000 from El Paso
Energy Corporation of the performance of El Paso Merchant
Energy, L.P. under the Power Services Agreement (included
as Exhibit 10.2 hereto) and the Administrative Services
Agreement (included as Exhibit 10.3 hereto).
12.1 -- Statement Regarding Computation of Ratios
23.1 -- Consent of PricewaterhouseCoopers LLP.
23.2 -- Consent of Pace Global Energy Services LLC
23.3 -- Consent of Chadbourne & Parke LLP (included in Exhibit
8.1 hereto)
24.1 -- Power of Attorney (included on the signature pages of
this Registration Statement)
25.1 -- Statement of Eligibility of Trustee dated as of [ ]
by Bankers Trust Company.
27.1 -- Financial Data Schedule.
99.1 -- Form of Letter of Transmittal for the 8 1/2% Senior
Secured Bonds Due 2014.
99.2 -- Form of Notice of Guaranteed Delivery for the 8 1/2%
Senior Secured Bonds Due 2014.
99.3 -- Form of Letter to Holders.
99.4 -- Form of Letter to Clients.
99.5 -- Form of Letter to Registered Holders and Depositary Trust
Company Participants.
99.6 -- Guidelines for Certification of Taxpayer Identification
Number on Substitute Form W-9.
99.7 -- Form of Exchange Agent Agreement
</TABLE>
ITEM 22. UNDERTAKINGS
(a) Insofar as indemnification for liabilities arising under the Securities
Act of 1933, as amended (the "Securities Act"), may be permitted to directors,
officers and controlling persons of the registrant pursuant to the foregoing
provisions, or otherwise, the registrant has been advised that, in the opinion
of the Securities and Exchange Commission, such indemnification is against
public policy as expressed in the
II-2
<PAGE> 158
Securities Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or controlling
person of the registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant will, unless, in
the opinion of its counsel, the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the
Securities Act and will be governed by the final adjudication of such issue.
(b) The undersigned registrant hereby undertakes:
(1) that prior to any public reoffering of the securities registered
hereunder through use of a prospectus which is a part of this registration
statement, by any person or party who is deemed to be an underwriter within
the meaning of Rule 145(c), the issuer undertakes that such reoffering
prospectus will contain the information called for by the applicable
registration form with respect to reofferings by persons who may be deemed
underwriters, in addition to the information called for by the other Items
of the applicable form.
(2) that every prospectus (i) that is filed pursuant to paragraph (1)
immediately preceding, or (ii) that purports to meet the requirements of
Section 10(a)(3) of the Securities Act and is used in connection with an
offering of securities subject to Rule 415 (section 230.415 of this
chapter), will be filed as a part of an amendment to the registration
statement and will not be used until such amendment is effective, and that,
for purposes of determining any liability under the Securities Act, each
such post-effective amendment shall be deemed to be a new registration
statement relating to the securities offered therein, and the offering of
such securities at that time shall be deemed to be the initial bona fide
offering thereof.
(3) that, for purposes of determining any liability under the
Securities Act of 1933, each filing of the registrant's annual report
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(and, where applicable, each filing of an employee benefit plan's annual
report pursuant to Section 15(d) of the Securities Exchange Act of 1934)
that is incorporated by reference in the registration statement shall be
deemed to be a new registration statement relating to the securities
offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.
(d) to respond to requests for information that is incorporated by
reference into this prospectus pursuant to Items 4, 10(b), 11 or 13 of this
Form, within one business day of receipt of such request, and to send the
incorporated documents by first class mail or other equally prompt means.
This includes information contained in documents filed subsequent to the
effective date of the registration statement through the date of responding
to the request.
(e) to supply by means of a post-effective amendment all information
concerning a transaction, and the company being acquired involved therein,
that was not the subject of and included in the registration statement when
it became effective.
II-3
<PAGE> 159
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant has duly caused this Registration Statement to be signed on their
behalf by the undersigned, thereunto duly authorized, in the City of Houston,
Texas, on November 28, 2000.
CEDAR BRAKES I, L.L.C.
By: /s/ JOHN L. HARRISON
----------------------------------
Name: John L. Harrison
Title: Vice President, Senior
Managing
Director and Class A
Manager
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature
appears below hereby, effective November 8, 2000, constitutes and appoints,
jointly and severally, H. Brent Austin and Britton White Jr., and each of them
acting individually, as his attorney-in-fact, each with full power of
substitution, for him in any and all capacities, including as an individual or
as an officer or manager authorized to act on behalf of Cedar Brakes I, L.L.C.
(the "Company"), to sign any and all amendments to the Registration Statement
with respect to the $310,600,000 8.50% Senior Secured Bonds issued by the
Company (the "Registration Statement"), and to file the same, with exhibits
thereto and other documents in connection therewith, with the Securities and
Exchange Commission, hereby ratifying and confirming our signatures as they may
be signed by our said attorney to any and all amendments to said Registration
Statement.
Pursuant to the requirements of the Securities Act of 1933, as amended,
this Registration Statement has been signed by the following persons in the
capacities and on the dates indicated:
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ CLARK C. SMITH
----------------------------------------------------- President (principal
Clark C. Smith executive officer) November 28, 2000
/s/ CECILIA T. HEILMANN
----------------------------------------------------- Vice President, Managing
Cecilia T. Heilmann Director and Controller
(principal accounting
officer) November 28, 2000
/s/ JOHN L. HARRISON
----------------------------------------------------- Vice President, Senior
John L. Harrison Managing Director and Class
A Manager (principal
financial officer) November 28, 2000
/s/ TIMOTHY SULLIVAN
-----------------------------------------------------
Timothy Sullivan Class A Manager November 28, 2000
/s/ KURT REGULSKI
-----------------------------------------------------
Kurt Regulski Class A Manager November 28, 2000
</TABLE>
II-4
<PAGE> 160
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
----------- -----------
<C> <S>
1.1 -- Purchase Agreement dated as of September 20, 2000 between
Cedar Brakes I, L.L.C. and Credit Suisse First Boston
Corporation, as Initial Purchaser.
3.1 -- Certificate of Formation of Cedar Brakes I, L.L.C. dated
as of March 3, 2000.
3.2 -- Amended and Restated Limited Liability Company Agreement
of Cedar Brakes I, L.L.C. dated September 11, 2000.
3.3 -- Amendment No. 1, dated October 19, 2000, to Amended and
Restated Limited Liability Company Agreement of Cedar
Brakes I, L.L.C. dated September 11, 2000.
4.1 -- Indenture dated as of September 26, 2000 between Cedar
Brakes I, L.L.C. and Bankers Trust Company, as Trustee.
4.2 -- First Supplemental Indenture dated as of November 20,
2000 between Cedar Brakes I, L.L.C. and Bankers Trust
Company, as Trustee.
4.3 -- Form of 8 1/2% Senior Secured Bonds due February 15,
2014.
4.4 -- Assignment and Security Agreement dated as of September
26, 2000 between Cedar Brakes I, L.L.C. and Bankers Trust
Company, as Trustee.
4.5 -- Accounts Control Agreement dated as of September 26, 2000
among Cedar Brakes I, L.L.C., Bankers Trust Company, as
Trustee, and Bankers Trust Company, as Securities
Intermediary.
4.6 -- Consent and Acknowledgment dated September 26, 2000 among
Cedar Brakes I, L.L.C., El Paso Energy Corporation and
Bankers Trust Company, as Trustee.
4.7 -- Consent and Acknowledgment dated September 26, 2000 among
Cedar Brakes I, L.L.C., El Paso Merchant Energy, L.P. and
Bankers Trust Company, as Trustee.
4.8 -- Consent and Acknowledgment dated September 26, 2000 among
the Company, Public Service Electric and Gas Company and
Bankers Trust Company, as Trustee.
4.9 -- Registration Rights Agreement dated as of September 20,
2000 between Cedar Brakes I, L.L.C. and Credit Suisse
First Boston, as Initial Purchaser.
5.1 -- Opinion of Chadbourne & Parke LLP as to the legality of
the bonds being registered hereby.
8.1 -- Opinion of Chadbourne & Parke LLP regarding tax matters.
10.1 -- Amended and Restated Power Purchase Agreement dated as of
March 21, 2000 between Cedar Brakes I, L.L.C. and Public
Service Electric and Gas Company.
10.2 -- Power Services Agreement dated September 20, 2000 between
Cedar Brakes I, L.L.C. and El Paso Merchant Energy, L.P.
10.3 -- Administrative Services Agreement dated as of September
20, 2000 between Cedar Brakes I, L.L.C. and El Paso
Merchant Energy, L.P.
10.4 -- Guaranty dated as of September 20, 2000 from El Paso
Energy Corporation of the performance of El Paso Merchant
Energy, L.P. under the Power Services Agreement (included
as Exhibit 10.2 hereto) and the Administrative Services
Agreement (included as Exhibit 10.3 hereto).
12.1 -- Statement Regarding Computation of Ratios.
</TABLE>
<PAGE> 161
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
----------- -----------
<C> <S>
23.1 -- Consent of PricewaterhouseCoopers LLP.
23.2 -- Consent of Pace Global Energy Services LLC.
23.3 -- Consent of Chadbourne & Parke LLP (included in Exhibit
8.1 hereto).
24.1 -- Power of Attorney (included on the signature pages of
this Registration Statement).
25.1 -- Statement of Eligibility of Trustee dated as of [ ]
by Bankers Trust Company.
27.1 -- Financial Data Schedule.
99.1 -- Form of Letter of Transmittal for the 8 1/2% Senior
Secured Bonds Due 2014.
99.2 -- Form of Notice of Guaranteed Delivery for the 8 1/2%
Senior Secured Bonds Due 2014.
99.3 -- Form of Letter to Holders.
99.4 -- Form of Letter to Clients.
99.5 -- Form of Letter to Registered Holders and Depositary Trust
Company Participants.
99.6 -- Guidelines for Certificate of Taxpayer Identification
Number on Substitute Form W-9.
99.7 -- Form of Exchange Agent Agreement.
</TABLE>
