As filed with the Securities and Exchange Commission on May 12, 1998
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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ESI TRACTEBEL ACQUISITION CORP.
(Exact Name of Co-Registrant as Specified in its Charter)
Delaware 6799 65-0827005
- ------------------------ ---------------------------- ----------------------
(State of Incorporation) (Primary Standard Industrial (I.R.S. Employer
Classification Code Number) Identification Number)
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NORTHEAST ENERGY, LP
(Exact Name of Co-Registrant as Specified in its Charter)
Delaware 4911 65-0811248
- ---------------------------- ---------------------------- ----------------------
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation Classification Code Number) Identification Number)
or organization)
11760 US Highway One
Suite 600
North Palm Beach, Florida 33408
(561) 691-3500
(Address, Including Zip Code, and Telephone Number, Including Area Code,
of Registrant's Principal Executive Offices)
Glenn E. Smith, Vice President
c/o FPL Energy , Inc.
11760 US Highway One
Suite 600
North Palm Beach, Florida 33408
(561) 691-3500
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code,
of Agent For Service)
------------------------
Please send a copy of all communications to:
Daniel A. Mathews, Esq.
Orrick, Herrington & Sutcliffe LLP
666 Fifth Avenue
New York, New York 10103
(212) 506-5000
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Approximate date of commencement of proposed sale to the public: As
soon as practicable after the effective date of this Registration Statement.
If the securities being registered on this form are being offered in
connection with the formation of 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
registrations 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 Aggregate Offering Amount of
to be Registered Registered Per Unit Price Registration Fee
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7.99% Series B Secured
Bonds Due 2011 $220,000,000 100% $220,000,000 $64,900
==================================================================================================
The Co-Registrants hereby amend this Registration Statement on such
date or dates as may be necessary to delay its effective date until the
Co-Registrants shall file a further amendment which specifically states that
this Registration Statement shall thereafter become effective in accordance with
Section 8(a) of the Securities Act of 1933 or until the Registration Statement
shall become effective on such date as the Commission, acting pursuant to said
Section 8(a), may determine.
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Information contained herein is subject to completion or amendment. A
registration statement relating to these securities has been filed with the
Securities and Exchange Commission. These securities may not be sold nor may
offers to buy be accepted prior to the time the registration statement becomes
effective. This prospectus shall not constitute an offer to sell or the
solicitation of an offer to buy nor shall there be any sale of these securities
in any State in which such offer, solicitation or sale would be unlawful prior
to registration or qualification under the securities laws of any such State.
SUBJECT TO COMPLETION, DATED MAY 12, 1998
PROSPECTUS
Offer to Exchange
7.99% Series B Secured Bonds Due 2011 for all outstanding
7.99% Series A Secured Bonds Due 2011
of
ESI Tractebel Acquisition Corp.
Payment of principal and interest unconditionally guaranteed by Northeast
Energy, LP, a Delaware limited partnership ("NE LP").
The exchange offer will expire at 5:00 P.M. New York City time, on _______, 1998
(as such date may be extended, the "Expiration Date").
ESI Tractebel Acquisition Corp. ("ESI Tractebel Acquisition"), a
Delaware corporation, hereby offers upon the terms and subject to the conditions
set forth in this Prospectus and the accompanying Letter of Transmittal (which
together constitute the "Exchange Offer"), to exchange its 7.99% Series B
Secured Bonds Due 2011 (the "New Securities") which have been registered under
the Securities Act of 1933, as amended (the "1933 Act"), pursuant to a
Registration Statement of which this Prospectus is a part, for each of the
outstanding 7.99% Series A Secured Bonds Due 2011 (the "Old Securities" and
together with the New Securities, the "Securities") of which $220,000,000
principal amount is outstanding. The form and terms of the New Securities are
identical in all material respects to the form and terms of the Old Securities
except that the New Securities have been registered under the 1933 Act and
therefore are not subject to Registration Default Damages (as defined herein)
and will not bear legends restricting the transfer thereof. The New Securities
will evidence the same debt as the Old Securities and will be entitled to the
benefits under the indenture governing the Old Securities (the "Indenture").
The Securities are general, secured obligations of ESI Tractebel
Acquisition and rank senior in right of payment to all subordinated
indebtedness, if any, of ESI Tractebel Acquisition incurred in the future and
will rank pari passu in right of payment with all senior indebtedness, if any,
of ESI Tractebel Acquisition incurred in the future. ESI Tractebel Acquisition's
obligations to make payment on the Securities are unconditionally guaranteed by
NE LP.
ESI Tractebel Acquisition will accept for exchange any and all Old
Securities that are validly tendered on or prior to 5:00 p.m., New York City
time, on the date the Exchange Offer expires, which will be _______, 1998,
unless the Exchange Offer is extended. Tenders of Old Securities may be
withdrawn at any time prior to 5:00 p.m., New York City time, on the business
day prior to the Expiration Date unless previously accepted for exchange. The
Exchange Offer is not conditioned upon any minimum principal amount of Old
Securities being tendered for exchange. However, the Exchange Offer is subject
to certain conditions which may be waived by ESI Tractebel Acquisition.
ESI Tractebel Acquisition is making the Exchange Offer in reliance on
the position of the staff of the Securities and Exchange Commission (the "SEC")
set forth in certain no-action letters addressed to other parties in other
transactions. However, ESI Tractebel Acquisition has not sought its own
no-action letter and there can be no assurance that the staff of the SEC would
make a similar determination with respect to the Exchange Offer as in such other
circumstances. Based on these interpretations by the staff of the SEC, New
i
Securities issued pursuant to the Exchange Offer in exchange for Old Securities
may be offered for resale, resold, and otherwise transferred by a holder thereof
(other than (i) a broker-dealer who purchases such New Securities directly from
the Company to resell pursuant to Rule 144A or any other available exemption
under the 1933 Act or (ii) any other such holder which is an "affiliate" of ESI
Tractebel Acquisition or NE LP within the meaning of Rule 405 under the 1933
Act), without compliance with the registration and prospectus delivery
provisions of the 1933 Act provided that the New Securities are acquired in the
ordinary course of such holder's business and such holder has no arrangement
with any person to participate in the distribution of the New Securities. Any
holder who participates in the Exchange Offer for the purpose of participating
in a distribution of the New Securities may not rely on the position of the
staff of the SEC as set forth in these no-action letters and would have to
comply with the registration and prospectus delivery requirements of the 1933
Act in connection with any secondary resale transaction. In addition, any
broker-dealer that receives New Securities for its own account pursuant to the
Exchange Offer must acknowledge that it will deliver a prospectus in connection
with any resale of such New Securities. This Prospectus, as it may be amended or
supplemented from time to time, may be used by broker-dealers in connection with
the resale of New Securities received in exchange for Old Securities where such
Old Securities were acquired by such broker-dealer as a result of market-making
activities or other trading activities. ESI Tractebel Acquisition has agreed
that for a period of up to one year after the date of the consummation of the
Exchange Offer, it will use its best efforts to keep the Registration Statement,
of which this Prospectus is a part, continuously effective. See "Plan of
Distribution," The New Securities will bear interest from the last interest
payment date of the Old Securities to occur prior to the issue date of the New
Securities. Holders of the Old Securities whose Old Securities are accepted for
exchange will not receive interest on such Old Securities for any period
subsequent to the last interest payment date of the Old Securities to occur
prior to the issue date of the New Securities, and will be deemed to have waived
the right to receive any payment in respect of interest on the Old Securities
accrued from and after such interest payment date.
ESI Tractebel Acquisition will not receive any proceeds from the
Exchange Offer. ESI Tractebel Acquisition and NE LP will pay all expenses
incident to their performance of or compliance with the Registration Rights
Agreement. Tenders of Old Securities pursuant to the Exchange Offer may be
withdrawn at any time prior to the Expiration Date. In the event ESI Tractebel
Acquisition terminates the Exchange Offer and does not accept for exchange any
Old Securities, the Old Securities will be returned promptly to the holders
thereof. See "The Exchange Offer."
Goldman has made a market in the Old Securities and intends, but is not
obligated, to continue to make a market in the Old Securities and to make a
market in the New Securities. ESI Tractebel Acquisition does not currently
intend to list the New Securities on any securities exchange. There can be no
assurance that an active public market for the New Securities will develop.
SEE "RISK FACTORS" ON PAGE 16 FOR A DESCRIPTION OF CERTAIN RISKS THAT
SHOULD BE CONSIDERED BY PURCHASERS OF THE NEW SECURITIES.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
The date of this Prospectus is _____________, 1998
ii
AVAILABLE INFORMATION
ESI Tractebel Acquisition and NE LP have filed with the Securities and
Exchange Commission (the "SEC") a Registration Statement on Form S-4 (together
with all amendments, exhibits, schedules and supplements thereto, the
"Registration Statement") under the Securities Act of 1933, as amended (the
"1933 Act"), with respect to the New Securities. This Prospectus, which forms a
part of the Registration Statement, does not contain all the information set
forth in the Registration Statement, certain parts of which have been omitted in
accordance with the rules and regulations of the SEC. For further information
with respect to ESI Tractebel Acquisition, NE LP and the New Securities,
reference is made to the Registration Statement. Statements contained in this
Prospectus as to the contents of any contract, agreement or other document are
not necessarily complete and, in each instance, reference is made to the copy of
the document filed as an exhibit to the Registration Statement, and each such
statement shall be deemed qualified in its entirety by such reference. ESI
Funding and the Partnerships are subject to the information requirements of the
Securities Exchange Act of 1934, as amended (the "Exchange Act") and in
accordance therewith files reports and other information with the SEC. Reports
and other information filed by ESI Funding and the Partnerships and the
Registration Statement filed by ESI Tractebel Acquisition and NE LP can be
inspected and copied at the public reference facilities maintained by the SEC at
Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549; and at the SEC's
regional offices at Citicorp Center, Suite 1400, 500 West Madison Street,
Chicago, Illinois 60661, and Seven World Trade Center, New York, New York 10048.
Copies of such material can also be obtained from the SEC at prescribed rates
through its Public Reference Section at 450 Fifth Street, N.W., Washington, D.C.
20549. The SEC maintains a world wide web site (http://www.sec.gov) that
contains reports, proxy and information statements and other information
regarding registrants that file electronically with the SEC.
EST Tractebel Acquisition and NE LP are not currently subject to the
information requirements of the Exchange Act. ESI Tractebel Acquisition and NE
LP have agreed that, whether or not they are required to do so by the rules and
regulations of the SEC, for so long as any of the Securities remain outstanding,
they will furnish to the holders of the Securities and to any beneficial owner
of the Securities who so request ESI Tractebel Acquisition in writing and will
file with the SEC (unless the SEC will not accept such filings) (i) all
quarterly and annual financial information that would be required to be
contained in a filing with the SEC on Forms 10-Q and 10-K if ESI Tractebel
Acquisition and NE LP were required to file such forms, including a
"Management's Discussion and Analysis of Results of Operations and Financial
Condition" and, with respect to the annual information only, a report thereon by
ESI Tractebel Acquisition's and NE LP's certified independent accountants and
(ii) all reports that would be required to be filed with the SEC on Form 8-K if
ESI Tractebel Acquisition and NE LP were required to file such reports. In
addition, for so long as any of the Securities remain outstanding, ESI Tractebel
Acquisition and NE LP have agreed to make available to any prospective purchaser
of the Securities or beneficial owner of the Securities in connection with any
sale thereof the information required by Rule 144(d)(4) under the 1933 Act.
DEFINED TERMS
Unless otherwise specified, all capitalized terms used in this
Prospectus and not otherwise defined herein have the meanings assigned in
Appendix A hereto, beginning on page A-1 of this Prospectus.
iii
SAFE HARBOR STATEMENT UNDER THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 (Reform Act), ESI Tractebel Acquisition and the
Partnerships are hereby filing cautionary statements identifying important
factors that could cause the Partnerships' actual results to differ materially
from those projected in forward-looking statements (as such term is defined in
the Reform Act) of the Partnerships made by or on behalf of the Partnerships
which are made in this Prospectus, in presentations, in response to questions or
otherwise. Any statements that express, or involve discussions as to,
expectations, beliefs, plans, objectives, assumptions or future events or
performance (often, but not always, through the use of words or phrases such as
will likely result, are expected to, will continue, is anticipated, estimated,
projection, outlook) are not statements of historical facts and may be
forward-looking. Forward-looking statements involve estimates, assumptions, and
uncertainties that could cause actual results to differ materially from those
expressed in the forward-looking statements. Accordingly, any such statements
are qualified in their entirety by reference to, and are accompanied by, the
following important factors that could cause the Partnerships' actual results to
differ materially from those contained in forward-looking statements of the
Partnerships made by or on behalf of the Partnerships.
-iv-
Any forward-looking statement speaks only as of the date on which such
statement is made, and the Partnerships undertake no obligation to update any
forward-looking statement or statements to reflect events or circumstances after
the date on which such statement is made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time and it is not
possible for management to predict all of such factors, nor can it assess the
impact of each such factor on the business or the extent to which any factor, or
combination of factors, may cause actual results to differ materially from those
contained in any forward-looking statements.
Some important factors that could cause actual results or outcomes to
differ materially from those discussed in the forward-looking statements include
prevailing governmental policies and regulatory actions, with respect to allowed
rates of return, industry and rate structure, acquisition and disposal of assets
and facilities, operation and construction of plant facilities, recovery of fuel
and purchase power costs, recovery of fuel and purchase power costs, and present
or prospective competition.
The business and profitability of the Partnerships are also influenced
by economic and geographic factors including political and economic risks,
changes in and compliance with environmental and safety laws and policies,
weather conditions, population growth rates and demographic patterns,
competition for retail and wholesale customers, pricing and transportation of
commodities, market demand for energy from plants or facilities, changes in tax
rates or policies or in rates of inflation, unanticipated development project
delays or changes in project costs, unanticipated changes in operating expenses
and capital expenditures, capital market conditions, competition for new energy
development opportunities, and legal and administrative proceedings (whether
civil, such as environmental, or criminal) and settlements.
All such factors are difficult to predict, contain uncertainties which
may materially affect actual results, and are beyond the control of the
Partnerships.
-v-
SUMMARY
The following summary is qualified in its entirety by, and should be
read in conjunction with, the more detailed information and financial
statements, including the notes thereto, appearing elsewhere in this Prospectus.
Potential purchasers should carefully consider the information set forth under
the caption "Risk Factors" prior to making any decision to invest in the
Securities.
The Issuer
ESI Tractebel Acquisition is a Delaware corporation that has been
established as a special purpose funding corporation for the purpose of issuing
the Securities. Each of ESI Northeast Energy Acquisition Funding, Inc. ("ESI
Acquisition Funding") and Tractebel Power owns fifty percent (50%) of the
outstanding capital stock of ESI Tractebel Acquisition. The Note (as defined
below) and any rights of ESI Tractebel Acquisition in the collateral pledged as
security for the payment of the Note are the only material assets of ESI
Tractebel Acquisition.
The Securities and the Use of Proceeds
Neither ESI Tractebel Acquisition nor NE LP will receive any proceeds
from the issuance of the New Securities in the Exchange Offer. In consideration
for the New Securities issued by ESI Tractebel Acquisition, as contemplated in
this Prospectus, ESI Tractebel Acquisition will receive in exchange a like
principal amount of Old Securities. The Old Securities surrendered in exchange
for the New Securities will be retired. Accordingly, the issuance of the New
Securities will not result in any change in the indebtedness of ESI Tractebel
Acquisition.
The proceeds received by ESI Tractebel Acquisition from the sale of the
Old Securities pursuant to the purchase agreement on February 12, 1998 by and
among ESI Tractebel Acquisition, NE LP, ESI Energy, Tractebel Power and Goldman
(the "Offering") were loaned (the "Bond Loan") by ESI Tractebel Acquisition to
NE LP. NE LP used the net proceeds received from the sale of the Old Securities,
after deducting fees and expenses, to reimburse certain of ESI Energy's and
Tractebel Power's subsidiaries for a portion of the original $534 million equity
contribution that was used to finance the cost of the Acquisitions described
below.
NE LP's obligation to repay the Bond Loan is evidenced by a promissory
note (the "Note") executed and delivered to ESI Tractebel Acquisition by NE LP
and assigned by ESI Tractebel Acquisition to the Trustee as security for the
payment of the Securities. The Note has terms that are substantially identical
to the terms of the Securities. As described below, ESI Tractebel Acquisition
has pledged to the Trustee all of ESI Tractebel Acquisition's rights to the
payments to be made by NE LP under the Note, and NE LP has guaranteed to the
Trustee the payment of the principal of and premium, if any, and interest and
Registration Default Damages, if any, on the Securities.
The Project Partnerships
NE LP, a limited partnership jointly owned by subsidiaries of ESI
Energy and Tractebel Power, owns a one percent (1%) general partner interest and
a ninety-eight percent (98%) limited partner interest in each of Northeast
Energy Associates, A Limited Partnership ("NEA") and North Jersey Energy
Associates, A Limited Partnership ("NJEA" and together with NEA, the
"Partnerships"). Northeast Energy, LLC ("NE LLC" and together with NE LP, the
"Partners"), a limited liability company directly and wholly owned by NE LP,
owns a one percent (1%) limited partner interest in each of the Partnerships.
The Partners purchased their interests in the Partnerships on January 14, 1998
from Intercontinental Energy Corporation ("IEC") and from certain individuals
(collectively, with IEC, the "Sellers"), as described below under the caption
"The Acquisitions."
Each of the Partnerships was formed in 1986 to develop, construct, own,
operate and manage a nominal 300 MW gas-fired combined-cycle cogeneration
facility. NEA's facility is located in Bellingham, Massachusetts (the "NEA
Project") and NJEA's facility is located in Sayreville, New Jersey (the "NJEA
Project" and, together with the NEA Project, the "Projects"). The NEA Project
commenced commercial operation in September 1991, and the NJEA Project commenced
commercial operation in August 1991. NE LP is the sole general partner of each
of the Partnerships and NE LP and its wholly-owned subsidiary NE LLC are the
only limited partners of each of the Partnerships. NE LP is dedicated solely to
the ownership, operation and management of the Projects. NE LLC is dedicated
solely to the ownership of its limited partner interest in each of the
Partnerships.
The Projects
Each of the Projects is a nominal 300 MW combined-cycle cogeneration
facility. The Projects use natural gas to produce electrical energy and thermal
energy in the form of steam. The Projects were constructed by Westinghouse
Electric Corporation ("Westinghouse Electric") and pursuant to contracts with
Westinghouse Electric that expire in 2001 (collectively, the "O&M Agreements"),
are operated and maintained by Westinghouse Operating Services Company
("Westinghouse Services" or the "Operator"), a subsidiary of Westinghouse
Electric. On November 15, 1997, Westinghouse Electric announced that it intended
to sell all of its industrial businesses, including the business of Westinghouse
Services, to Siemens AG. Each of the Partnerships is also party to an operation
and maintenance agreement (collectively, the "New O&M Agreements") with ESI
Operating Services, Inc. (the "New Operator"), a direct and wholly-owned
subsidiary of ESI Energy, pursuant to which the New Operator has agreed to
operate and maintain the Projects following the expiration or early termination
of the O&M Agreements and, prior to such date, to provide certain other
services.
NEA currently sells 100% of the net electrical energy produced by the
NEA Project to three regulated utilities, Boston Edison Company ("Boston
Edison"), Commonwealth Electric Company ("Commonwealth") and Montaup Electric
Company ("Montaup"). Boston Edison purchases approximately 75% of such energy
under two contracts, Commonwealth purchases approximately 16% under two
contracts and Montaup purchases approximately 9%. NJEA currently sells the
electricity produced at the NJEA Project to one regulated utility, Jersey
Central Power & Light Company ("JCP&L"). Such sales are made pursuant to power
purchase agreements, all of which provide substantially for the continuous
delivery of base load power (collectively, the "Power Purchase Agreements"). Two
of the six Power Purchase Agreements are scheduled to expire in September 2011
and August 2011, three months and four months, respectively, prior to the final
maturity date of the Securities. Three of the six Power Purchase Agreements are
scheduled to expire in September 2016 and the sixth is scheduled to expire in
September 2021.
The Projects were developed and are operated as Qualifying Facilities
("QFs") under the Public Utility Regulatory Policies Act of 1978 and the
regulations promulgated thereunder ("PURPA") by the Federal Energy Regulatory
Commission ("FERC"). The Projects must satisfy certain annual operating and
efficiency standards, as well as ownership requirements, to maintain QF status,
which exempts the Projects from certain federal and state regulations. To date,
both Projects have satisfied these standards, and NE LP expects that they will
continue to do so.
Steam generated by the NEA Project is sold to NECO-Bellingham, Inc.
("NECO"), a special-purpose subsidiary of a privately held company based in
Texas, for use by a carbon dioxide plant located adjacent to the NEA Project
(the "Carbon Dioxide Plant"). The Carbon Dioxide Plant is owned by NEA and
leased to NECO. The steam generated by the NJEA Project is sold to Hercules,
Incorporated ("Hercules") for use by Hercules' Parlin, New Jersey plant.
Approximately 80% of the natural gas that fuels the Projects is
supplied to the Projects pursuant to long-term gas supply agreements with ProGas
Limited of Alberta, Canada ("ProGas") and, in the case of the NJEA Project, also
2
pursuant to a long-term gas supply agreement with Public Service Electric and
Gas of Newark, New Jersey ("PSE&G"). The gas supply agreements with ProGas and
the gas supply agreement with PSE&G are referred to collectively as the
"Long-term Gas Supply Agreements." Gas is transported to, or stored for later
use by, the Projects pursuant to long-term gas transportation agreements (the
"Long-term Gas Transportation Agreements") and long-term gas storage agreements
(the "Long-term Gas Storage Agreements"). The Long-term Gas Supply Agreements
between NEA and ProGas (the "NEA ProGas Agreement") and between NJEA and ProGas
(the "NJEA ProGas Agreement" and, together with the NEA ProGas Agreement, the
"ProGas Agreements"), expire in November 2013. The Long-term Gas Supply
Agreement between NJEA and PSE&G (the "PSE&G Contract") for the supply, delivery
and transportation of natural gas expires in August 2011. There are several
Long-term Gas Transportation Agreements for transportation on a firm basis by
various transporters of gas purchased under the gas supply and storage
contracts, which expire in March 1999, October 2006, November 2011, March 2012
and November 2016. The Long-term Gas Storage Agreements expire in March 2012.
The remainder of the daily fuel requirements of the Projects are met by
open-market purchases delivered on an interruptible basis both into storage and
directly to the Projects. The price escalators under the Long-term Gas
Agreements are intended to substantially correlate to the price escalators under
the Power Purchase Agreements. The NEA Project may also be run on Number 2 fuel
oil in certain limited circumstances. See "The Projects -- Gas Supply
Arrangements" and "The Projects -- The NEA Project -- Project Description."
Each of the Partnerships is party to a fuel management agreement
(collectively, the "Fuel Management Agreements") with ESI Northeast Fuel
Management, Inc. (the "Fuel Manager"), an indirect wholly-owned subsidiary of
FPL Energy, pursuant to which the Fuel Manager has agreed to provide certain
fuel management and administrative services.
For more detailed information regarding the Projects, including the
various contracts referred to above and regulatory matters that affect the
Projects, see "The Projects," "Business," "Regulation" and "Summary of Principal
Project Agreements."
The Partners
All of the interests in the Partnerships are held by NE LP and NE LLC,
which in turn are owned by ESI GP and ESI LP (as defined herein), wholly-owned
subsidiaries of ESI Energy; and by Tractebel GP and Tractebel LP, wholly-owned
subsidiaries of Tractebel Power.
Each of ESI GP and Tractebel GP owns a one percent (1%) general partner
interest in NE LP, and each of ESI LP and Tractebel LP owns a forty-nine percent
(49%) limited partner interest in NE LP. ESI GP and ESI LP are wholly-owned,
direct subsidiaries of ESI Energy, and Tractebel GP and Tractebel LP are
wholly-owned subsidiaries of Tractebel Power.
On January 15, 1998, FPL Energy, Inc., ("FPL Energy"), an indirect,
wholly-owned subsidiary of FPL Group, Inc. ("FPL Group"), received as capital
contribution from FPL Group Capital Inc. ("FPL Group Capital") all of the
outstanding shares of stock of ESI Energy and of FPL Group International. FPL
Group is a holding company whose stock is traded on the New York Stock Exchange.
FPL Group is also the parent company of Florida Power & Light Company ("FPL"),
one of the largest investor-owned utilities in the United States. FPL Group
Capital, a wholly-owned subsidiary of FPL Group, holds the capital stock of FPL
Energy and provides most of the funding for the operating subsidiaries of FPL
Group other than FPL. The business activities of these companies primarily
consist of investments in non-utility energy projects and agricultural
operations.
Tractebel Power is a direct, wholly-owned subsidiary of Tractebel Inc.
("Tractebel"), which in turn is a direct, wholly-owned subsidiary of Tractebel,
S.A. ("Tractebel Belgium"), a global energy and environmental services business
3
founded in 1895 and based in Brussels, Belgium. Services include engineering,
installations and communications. Tractebel Belgium's two primary U.S. operating
subsidiaries are Tractebel Power and Tractebel Energy Marketing, Inc.
The Acquisitions
The Partners acquired all of the partnership interests in each of the
Partnerships on January 14, 1998, pursuant to a Purchase Agreement, dated as of
November 21, 1997, by and among the Partners, the Sellers, ESI Northeast Energy
Funding, Inc. ("ESI Funding") and Tractebel Power. In connection with the
acquisition of all of the partnership interests in the Partnerships, ESI Funding
and Tractebel Power each acquired a thirty-seven and one-half percent (37.5%)
interest in ESI Tractebel Funding Corp. ("ESI Tractebel Funding"), a Delaware
special purpose corporation formerly known as "IEC Funding Corp." and the issuer
of the Project Securities described below. The Partners paid the purchase price
for all of the partnership interests in the Partnerships and for seventy-five
percent (75%) of the outstanding shares of capital stock in ESI Tractebel
Funding (collectively, the "Acquisitions") from contributions made by each of
ESI GP, Tractebel GP, ESI LP and Tractebel LP, the partners of NE LP. Broad
Street Contract Services, Inc. ("Broad Street"), a nominee for State Street Bank
and Trust Company, owns the remaining twenty-five percent (25%) of the
outstanding shares of capital stock in ESI Tractebel Funding for the purpose of
providing an independent director. Broad Street has no economic interest in
Partnership distributions.
Outstanding Project Indebtedness
Pursuant to a Trust Indenture, dated as of November 15, 1994, among
each of the Partnerships, IEC Funding Corp. (now ESI Tractebel Funding), and
State Street Bank and Trust Company, as trustee (the "Project Trustee"), as
supplemented by the First Supplemental Trust Indenture, dated as of November 15,
1994 (the "Original Project Indenture"), IEC Funding Corp. issued notes and
bonds in an aggregate principal amount of $560,000,000 (the "Project
Securities"). IEC Funding Corp. and the Partnerships applied the proceeds from
the sale of the Project Securities to refinance the costs of construction of the
Projects, among other things. As of December 31, 1997, the principal amount of
outstanding Project Securities was $490,286,720.
The Original Project Indenture requires the Partnerships to arrange for
the delivery of letters of credit in an aggregate amount of up to $82,000,000 to
secure the Partnerships' obligations to certain of the Projects' power
purchasers and for certain other purposes and permits the Partnerships to borrow
up to $20,000,000 for working capital purposes (the "Working Capital Facility").
At the time the original Project Securities were issued, the Partnerships
entered into a Credit Agreement (the "Sanwa Credit Agreement") with The Sanwa
Bank, Limited, New York Branch ("Sanwa Bank"), pursuant to which (i) Sanwa Bank
agreed to issue the project letters of credit (the "Sanwa Letters of Credit")
and (ii) Sanwa Bank and the other banks named in the Sanwa Credit Agreement
agreed to provide working capital loans under a working capital facility (the
"Sanwa Working Capital Facility"). The aggregate outstanding principal amount of
the Sanwa Letters of Credit as of December 31, 1997 was $67,656,000.
In February 1998, NE LP terminated the Sanwa Credit Agreement, the
Sanwa Letters of Credit and the Sanwa Working Capital Facility and arranged for
the delivery of new project letters of credit to satisfy requirements in certain
of the Power Purchase Agreements (the "Energy Bank Letters of Credit"). The new
Energy Bank Letters of Credit were issued in face amounts of $12,656,000 and
$54,000,000 by BankBoston, N.A. ("BankBoston") and NationsBank of Texas
("NationsBank"), respectively. Following the issuance of the Energy Bank Letters
of Credit and the FPL Group Capital Guaranty to BankBoston and NationsBank, cash
in the amount of approximately $69,156,000, plus interest receivable,
constituting the Cash Collateral Proceeds, was released and distributed to the
Partners. In January 1998 NE LP arranged for the issuance to the Project Trustee
by BankBoston and Bank Brussels Lambert of two letters of credit (the
"Substitute Letters of Credit") in substitution for the cash on deposit in the
Debt Service Reserve Fund under the Project Indenture. Following the issuance of
4
the Substitute Letters of Credit, cash in the amount of approximately
$33,270,000 was released from the Debt Service Reserve Fund and distributed to
the Partners.
On January 14, 1998, in connection with the Acquisitions, and with the
consent of the holders of a majority in aggregate principal amount of the
Project Securities then outstanding, the Original Project Indenture was amended
by the Second Supplemental Trust Indenture, dated as of January 14, 1998 (the
"Second Supplemental Indenture"). The Original Project Indenture, as amended by
the Second Supplemental Indenture is referred to herein as the "Project
Indenture." The amendments contained in the Second Supplemental Indenture permit
(i) the Acquisitions, (ii) substitution of a guaranty (the "FPL Group Capital
Guaranty") to be issued by FPL Group Capital, a wholly-owned subsidiary of FPL
Group, for the cash collateral (the "Cash Collateral Proceeds") that secured the
Partnerships' reimbursement obligations related to the Sanwa Letters of Credit,
(iii) at the time of substitution of the FPL Group Capital Guaranty, the release
of such Cash Collateral Proceeds directly to the Partners without first
depositing such amounts to the Revenue Fund described below and (iv) upon the
substitution of Substitute Letters of Credit described above, the release
directly to the Partners of amounts held in the Debt Service Reserve Fund for
the Project Securities, without first depositing such amounts to the Revenue
Fund. Under the Reimbursement Agreement, dated as of November 21, 1997, NE LP's
obligation to reimburse FPL Group Capital for any of the amount paid by FPL
Group Capital Guaranty is subject to the prior payment of any amounts payable
under the Indenture in respect of the Securities.
The Partnerships' obligations under the Project Indenture, the Working
Capital Facility and certain interest rate swap agreements described below
(collectively, the "Project Indebtedness"), for which the Partnerships are
jointly and severally liable, are secured by mortgages of and security interests
in substantially all of the property of the Partnerships. Pursuant to the
Project Indenture, the Partnerships are required to pay debt service in respect
of the Project Indebtedness, to pay certain other expenses (including the costs
of operating and maintaining the Projects) and to fund certain reserves prior to
making any distributions to the Partners. In addition, distributions from the
Partnerships to the Partners are subject to satisfaction of a number of other
requirements, including satisfaction of financial ratio tests and the absence of
any default or event of default under the Project Indenture. NE LP will have no
source of income to make payments under the Note other than the distributions it
receives from the Partnerships, and ESI Tractebel Acquisition will have no
source of income other than the loan payments it receives from NE LP under the
Note. The Partnerships' debt and other obligations are required in all events to
be paid prior to the payment of debt service in respect of the Securities. See
"Risk Factors -- Holding Company Structure; Dependence upon Operations of
Partnerships."
5
Ownership Structure
Flow Chart of the ownership structure
showing the relationship among ESI Tractebel
Acquisition, NE LP and the Partnerships.
6
The Exchange Offer
Securities Offered............................ $220,000,000 principal amount of 7.99% Series B Secured Bonds Due
December 30, 2011 of ESI Tractebel Acquisition (the "New Securities").
Issuance of Old Securities;
Registration Rights...................... The Old Securities were issued on February 12, 1998 to Goldman which
placed the Old Securities with "qualified institutional buyers" (as
such term is defined in Rule 144A promulgated under the 1933 Act). In
connection therewith, ESI Tractebel Acquisition and NE LP executed and
delivered the Registration Rights Agreement pursuant to which ESI
Tractebel Acquisition and NE LP agreed (i) to file a registration
statement (the "Registration Statement") on or prior to 90 days after
February 19, 1998 with respect to the Exchange Offer and (ii) use their
best efforts to cause the Registration Statement to be declared
effective by the Commission on or prior to 180 days after February 19,
1998. In certain circumstances, ESI Tractebel Acquisition and NE LP
will be required to provide a shelf registration statement (the "Shelf
Registration Statement") to cover resales of the Old Securities by the
holders thereof. If ESI Tractebel Acquisition and NE LP do not comply
with their obligations under the Registration Rights Agreement, ESI
Tractebel Acquisition and NE LP will be required to pay Registration
Default Damages to holders of the Old Securities. See "The Exchange
Offer -- Registration Rights; Registration Default Damages."
The Exchange Offer............................ The New Securities are being offered in exchange for a like principal
amount of Old Securities. The issuance of the New Securities is
intended to satisfy certain obligations of ESI Tractebel Acquisition
and NE LP pursuant to certain registration rights granted under the
Registration Rights Agreement. See "The Exchange Offer -- Purpose of
the Exchange Offer". For procedures for tendering see "The Exchange
Offer -- Procedures for Tendering Old Securities". Based on an
interpretation of the staff of the SEC set forth in no-action letters
issued to third parties in circumstances substantially the same as
those applicable here, ESI Tractebel Acquisition believes that New
Securities issued pursuant to the Exchange Offer in exchange for Old
Securities may be offered for resale, resold and otherwise transferred
by a holder thereof (other than (i) a broker-dealer who purchases such
New Securities directly from the Company to resell pursuant to Rule
144A or any other available exemption under the 1933 Act or (ii) any
such holder which is an "affiliate" of ESI Tractebel Acquisition or NE
LP within the meaning of the Rule 405 under the 1933 Act) without
compliance with the registration and prospectus delivery provisions of
the 1933 Act, provided that such New Securities are acquired in the
ordinary course of such holder's business and such holder has no
arrangement or understanding with any person to participate in the
distribution of such New Securities. Any broker-dealer that receives
New Securities for its own account pursuant to the Exchange Offer must
acknowledge that it will deliver a prospectus in connection with any
resale of such New Securities. See "Plan of Distribution". Although
there has been no indication of any change in the staff's position,
there can be no assurance that the staff of the SEC would make a
similar determination with respect to the resale of the New Securities.
ESI Tractebel Acquisition believes that there are no other federal or
stateregulatory requirements to be complied with or approvals obtained to
effectuate the Exchange Offer.
Book-Entry Transfer........................... State Street Bank and Trust Company (the "Exchange Agent") will make a
request to establish an account with respect to the Old Securities at
The Depository Trust Company ("DTC") for purposes of the Exchange Offer
within two business days after the date of the Exchange Offer, and any
financial institution that is a participant in DTC's systems may make
book-entry delivery of Old Securities by causing DTC to transfer such
Old Securities into the Exchange Agent's account at DTC in accordance
with DTC's procedures. The Letter of Transmittal or facsimile thereof,
with any required signature guarantees and any other required
documents, must, in any case, be transmitted to and received by the
Exchange Agent at the address set forth under "'The Exchange Offer--
Procedures for Tendering Old Securities" on or prior to the Expiration
Date or the guaranteed delivery procedures described below must be
complied with.
Tenders' Expiration Date; Withdrawal.......... The Exchange Offer will expire at 5:00 p.m., New York City time, on
____________, 1998, or such later date and time to which it is
extended. If the Company elects to extend the Expiration Date, in no
event will the Expiration Date be extended beyond ____________, 1998.
The tender of the Old Securities pursuant to the Exchange Offer may be
withdrawn at any time prior to 5:00 p.m., New York City time, on the
Expiration Date by delivering a written notice of withdrawal to the
Exchange Agent. See "The Exchange Offer -- Withdrawal Rights". Any Old
7
Securities not accepted for exchange for any reason will be returned
without expense to the tendering holder thereof as promptly as
practicable after the expiration or termination of the Exchange Offer.
The registration rights granted pursuant to the Registration Rights
Agreement will expire upon completion of the Exchange Offer.
Therefore, any holder that fails to tender its Old Securities prior to
the completion of the Exchange Offer will be unable to obtain
registration under the 1933 Act for the Old Securities.
Guaranteed Delivery Procedures................ If a registered holder of Old Securities desires to tender such Old
Securities and the Old Securities are not immediately available, or
time will not permit such holder's Old Securities or other required
documents to reach the Exchange Agent before the Expiration Date, or
the procedure for book-entry transfer cannot be completed on a timely
basis, a tender may be effected according to the guaranteed delivery
procedures set forth in "The Exchange Offer -- Guaranteed Delivery
Procedures".
Consequences of Failure to Exchange........... There is currently no market for the New Securities, nor is there any
active market for the Old Securities. See "Risk Factors -- Absence of
Public Market". The liquidity of the market for a holder's Old
Securities could be adversely affected upon completion of the Exchange
Offer if such holder does not participate in the Exchange Offer or does
not validly tender such holder's Old Securities pursuant to the
Exchange Offer. See "Risk Factors -- Consequences of Failure to
Properly Tender" and "The Exchange Offer -- Consequences of Failure to
Exchange".
Procedures for Tendering Old Securities....... Each holder of Old Securities wishing to accept the Exchange Offer must
complete and sign the Letter of Transmittal, have the signature thereon
guaranteed if required by Instruction 4 of the Letter of Transmittal
and mail or deliver the Letter of Transmittal, together with the Old
Securities and any other required documents (such as appropriate bond
powers, if the Old Securities have not been endorsed, and evidence of
authority to act, if the Letter of Transmittal or any Old Securities or
bond powers are signed by someone acting in a fiduciary or
representative capacity), to the Exchange Agent, at the address set
forth herein and therein on or prior to the Expiration Date. Any
holder of Old Securities whose Old Securities are registered in the
name of brokers, dealers, commercial banks, trust companies or other
nominees should contact such entities or persons promptly to instruct
them to effect the Exchange Offer on such holder's behalf if such
holder wishes to accept the Exchange Offer. Letters of Transmittal and
certificates representing Old Securities should not be sent to ESI
Tractebel Acquisition. Such documents should only be sent to the
Exchange Agent. See "The Exchange Offer -- Procedures for Tendering Old
Securities".
Form of New Securities........................ The New Securities will be issued initially in the form of global
notes. See "Description of Securities -- Form, Denomination and
Title". Holders of beneficial interests in one or more of the global
notes representing the Old Securities desiring to exchange such
interests should follow the procedures described in "The Exchange Offer
-- Exchanging Book-Entry Old Securities" and in the Letter of
Transmittal.
Certain Federal Income Tax Considerations..... The exchange of New Securities for Old Securities will not be a taxable
event for federal income tax purposes. See "Certain Federal Tax
Considerations".
Rights of Dissenting Security Holders......... Holders of the Securities do not have any appraisal or dissenters'
rights under the Delaware General Corporation Law or the Indenture in
connection with the Exchange Offer.
Exchange Agent................................ State Street Bank and Trust Company is the Exchange Agent. The address
and phone number of the Exchange Agent is set forth in "The Exchange
Offer -- The Exchange Agent."
Summary of Terms of the New Securities
The terms of the Old Securities and the New Securities are identical in
all material respects, except (i) for certain transfer restrictions and
registration rights relating to the Old Securities and (ii) that, if the
Exchange Offer is not consummated by August 19, 1998 ("Registration Default"),
ESI Tractebel Acquisition and NE LP will be required to pay to each holder of
Old Securities liquidated damages ("Registration Default Damages") in an amount
equal to $.05 per week for each $1,000 principal amount of Old Securities, as
applicable, held by such holder for each week or portion thereof that the
Registration Default continues for the first 90-day period following the
occurrence of such Registration Default. The amount of the Registration Default
Damages will increase by an additional $.05 per week with respect to each 90-day
period until the Exchange Offer is consummated, up to a maximum of $.50 per week
for each $1,000 principal amount of Old Securities, as applicable.
Securities Offered........................ $220,000,000 principal amount of 7.99% Series B Secured Bonds Due 2011
Maturity Date............................. December 30, 2011
Interest Payment Dates.................... June 30 and December 30 of each year, commencing on the first such date
to occur after the exchange of the New Securities for Old Securities
Guaranty.................................. ESI Tractebel Acquisition's payment obligations under the New
8
Securities will be unconditionally guaranteed by NE LP pursuant to a
Guaranty (the "Bond Guaranty"). See "Description of Securities."
Scheduled Principal Payments.............. The principal of the New Securities will be payable in semi-annual
installments to the holders thereof as follows:
Scheduled Payment Date Principal Amount
---------------------- ----------------
June 30, 1998 $ 0
December 30, 1998 0
June 30, 1999 0
December 30, 1999 0
June 30, 2000 0
December 30, 2000 0
June 30, 2001 0
December 30, 2001 0
June 30, 2002 4,400,000
December 30, 2002 4,400,000
June 30, 2003 4,400,000
December 30, 2003 4,400,000
June 30, 2004 4,400,000
December 30, 2004 4,400,000
June 30, 2005 4,400,000
December 30, 2005 4,400,000
June 30, 2006 6,600,000
December 30, 2006 6,600,000
June 30, 2007 11,000,000
December 30, 2007 11,000,000
June 30, 2008 11,000,000
December 30, 2008 11,000,000
June 30, 2009 13,200,000
December 30, 2009 13,200,000
June 30, 2010 17,600,000
December 30, 2010 17,600,000
June 30, 2011 33,000,000
December 30, 2011 33,000,000
Security...................................... Payment of the New Securities will be secured by: (a) a perfected,
first priority pledge of (i) 100% of the partner interests of NE LP,
(ii) 100% of the member interests in NE LLC and (iii) NE LP's 98%
limited partner interest in each of the Partnerships and NE LLC's one
percent limited partner interest in each of the Partnerships; (b) a
second priority pledge of NE LP's one percent general partner interest
in each of the Partnerships (subordinate to the first priority pledge
of such general partner interest that secures the payments of and the
Partnerships' obligations under the Project Indebtedness); (c) a
perfected, first priority pledge of the Note evidencing NE LP's
obligation to repay the Bond Loan made by ESI Tractebel Acquisition to
NE LP; (d) a perfected, first priority lien on the funds in the
Accounts under the Indenture; and (e) a perfected, first priority
pledge of all of the outstanding capital stock of ESI Tractebel
Acquisition. See "Description of Securities."
Source of Payment for the New Securities...... The New Securities are payable solely from payments to be made by NE LP
under the Note and the Bond Guaranty and from other monies that may be
available from time to time in the Accounts held by the Trustee and are
not obligations of the Partnership's. NE LP's obligations to make
payments under the Note and the Bond Guaranty are general obligations
of NE LP, although NE LP's only source of funds to make such payments
are the distributions from the Partnerships to NE LP and NE LLC, which
are pledged by NE LP and NE LLC to the Trustee. So long as the Project
Indebtedness is outstanding, distributions from the Partnerships
constitute "Restricted Payments" under the Project Indenture and may be
released by the Project Trustee only upon satisfaction of the
conditions set forth in the Project Indenture. See "Outstanding
Project Indebtedness-Flow of Funds" for a more detailed description of
the flow of funds under the Project Indenture and of the conditions
that must be satisfied prior to any distributions to NE LP and NE LLC.
Optional Redemption........................... The New Securities will not be redeemable at ESI Tractebel
Acquisition's option prior to June 30, 2008. Thereafter, the New
Securities will be subject to redemption at any time at the option of
ESI Tractebel Acquisition, in whole or in part, at the redemption
prices set forth herein, together with accrued and unpaid interest and
Registration Default Damages, if any, to the date fixed for redemption.
9
Extraordinary Mandatory Redemption............ The New Securities will be subject to mandatory redemption pro rata, at
a redemption price equal to 100% of the principal amount of the New
Securities being redeemed plus accrued and unpaid interest and
Registration Default Damages, if any, to the date fixed for redemption
if (1) (a) any event occurs that triggers the mandatory redemption or
repurchase of any or all of the outstanding Project Securities and (b)
any funds so required to be applied to such redemption or repurchase
remain after giving effect to such redemption or repurchase and such
excess funds equal at least $2,000,000 and are distributed to NE LP or
NE LLC or (2) a buyout or similar payment is made to a Partnership
under any Power Purchase Agreement and any such funds are distributed
to NE LP or NE LLC in accordance with the terms of the Project
Indenture and of the Indenture, provided that, in each case, only such
funds so distributed must be applied to the extraordinary mandatory
redemption. See "Description of Securities -- Extraordinary Mandatory
Redemption."
Change of Control............................. Upon the occurrence of a Change of Control (as defined herein), ESI
Tractebel Acquisition will be required to offer to each Holder to
repurchase in cash all or any part of such Holder's New Securities, at
a purchase price equal to 101% of the aggregate principal amount
thereof, plus accrued and unpaid interest, if any, to the date of
purchase. A Change of Control will not occur, however, if Moody's and
S&P confirm that the then existing ratings of the New Securities will
not be lowered as a result of any of the events that, in the absence of
such confirmed rating, would have triggered ESI Tractebel Acquisition's
obligations with respect to a Change of Control. See "Description of
Securities -- Repurchase At the Option of the Holders Upon a Change of
Control."
Ranking....................................... The New Securities will rank senior in right of payment to any
subordinated indebtedness of ESI Tractebel Acquisition incurred in the
future and will rank pari passu in right of payment with any senior
indebtedness of ESI Tractebel Acquisition incurred in the future. The
Old Securities are and the New Securities will be unconditionally
guaranteed by NE LP. The claims of the Holders of the New Securities
and the claims of the Trustee as holder of the Note will be effectively
subordinated to all present and future indebtedness and other
liabilities and commitments of NEA and NJEA, including the guarantee by
NEA and NJEA of the Project Indebtedness. See "Risk Factors -- Holding
Company Structure; Dependence upon Operations of Projects" and
"Description of Securities -- General."
Certain Covenants............................. The Indenture governing the New Securities is the same Indenture which
governs the Old Securities and contains certain covenants that, among
other things, require ESI Tractebel Acquisition, NE LP and NE LLC to
comply with, and requires NE LP, as general partner of NEA and NJEA, to
cause NEA and NJEA to comply with, certain covenants contained in the
Project Indenture, as if such covenants were still in full force and
effect notwithstanding the termination or expiration of the Project
Indenture (including, among others, covenants to maintain existence,
insurance, rights necessary to conduct the business, government
approvals and QF status by NEA and NJEA, to comply with the formation
documents and applicable laws and to pay taxes), to limit the ability
of ESI Tractebel Acquisition, NE LP and NE LLC and their Subsidiaries
(including NEA and NJEA) to incur Additional Indebtedness (as defined
herein), issue Disqualified Stock (as defined herein), incur liens, pay
dividends or distributions or make investments or certain other
Restricted Payments (as defined herein), engage in mergers,
consolidations, or sales of assets, enter into certain transactions
with affiliates or assume any suretyship obligations. All of these
restrictions, however, are subject to a number of important exceptions
and qualifications. See "Description of Securities" and "Appendix D --
Summary of Project Indenture."
Ratings....................................... "Ba1" by Moody's Investors Service, Inc. ("Moody's") and "BB" by
Standard & Poor's Ratings Services, a division of the McGraw-Hill
Companies, Inc. ("S&P").
10
Risk Factors
See "Risk Factors" for a discussion of certain factors including, among
other things, (i) substantial leverage, (ii) holding company structure;
dependence upon operations of projects and (iii) regulatory and financial
pressures on power purchasers, that should be considered in evaluating an
investment in the New Securities.
Experts' Reports
The Independent Engineer's Report and the Fuel Consultant's Report,
each summarized below, are included in this Prospectus as Appendices B and C.
Each of Sargent & Lundy LLC and Benjamin Schlesinger and Associates, Inc. were
selected by NE LP based on their reputation in the field. Neither entity has any
affiliation with ESI Tractebel Acquisition, the Partners or the Partnerships.
None of ESI Tractebel Acquisition, the Partners or the Partnerships imposed any
limitation on the scope of investigation conducted by either entity.
Independent Engineer's Report
Sargent & Lundy LLC ("Sargent & Lundy") has prepared a report dated
February 12, 1998 (the "Independent Engineer's Report"), a copy of which is
included as Appendix B in this Prospectus, to assist prospective investors in
understanding and evaluating the Projects and the Carbon Dioxide Plant. The
Independent Engineer's Report assesses certain technical, environmental and
economic aspects of the Projects and of the Carbon Dioxide Plant including,
among other things, certain financial and operations estimates and projections
prepared by, and which are the responsibility of, NE LP. Price Waterhouse LLP
has neither examined nor compiled the Projections contained in Appendix B, and
accordingly, Price Waterhouse LLP does not express an opinion or any other form
of assurance with respect thereto. The Price Waterhouse LLP report included in
this Prospectus relates solely to the Partnerships' historical financial
information. It does not extend to the Projections and should not be read to do
so. For purposes of preparing these projections and estimates, NE LP relied upon
certain assumptions regarding material contingencies and other matters that are
not within the control of ESI Tractebel Acquisition, the Partners, the
Partnerships, the Independent Engineer or any other person. These assumptions
are inherently subject to significant uncertainties and actual results will
differ, perhaps materially, from those projected. None of ESI Tractebel
Acquisition, the Partners, the Partnerships or the Independent Engineer can give
any assurance that these assumptions are correct or that these projections and
estimates will reflect actual results of operations. Therefore, no
representations are made or intended, nor should any be inferred, with respect
to the likely existence of a particular future set of facts or circumstances. If
actual results are materially less favorable than those shown or if the
assumptions used in formulating these projections and estimates prove to be
incorrect, ESI Tractebel Acquisition's ability to make payments of principal of
and interest on the Securities may be materially adversely affected. For certain
additional information relating to the projections and estimates contained in
the Independent Engineer's Report, see "Risk Factors -- Uncertainties of
Projections and Assumptions."
Subject to the information contained, and assumptions made, in the
Independent Engineer's Report, the Independent Engineer has expressed the
following opinions:
o The facilities have been well constructed in accordance with generally
accepted engineering practices and are fully capable of performing in
accordance with the operating and financial projections.
o The technology used for the Projects is sound, commercially proven and
should provide an additional 20 years of service or longer with proper
operations and maintenance practices.
o An acceptable operation and maintenance program, including provisions
for planned major maintenance, has been established.
o The plants are clean, well maintained and well operated. After the
current O&M Agreements with Westinghouse expire, the facilities will be
operated and maintained by ESI Operating Services, Inc. ESI Operating
11
Services, Inc. is fully capable of operating and maintaining these
combined-cycle power plant facilities.
o Both plants have been operating for over six years, with higher than
guaranteed net capacities and lower than guaranteed plant heat rates.
The availabilities of the plants have exceeded guaranteed levels and are
higher than industry averages.
o The plants have in the past and are capable in the future of meeting the
requirements of the existing power purchase agreements.
o The pro forma projections reflect demonstrated plant performance and
include conservative estimates of future performance of the facilities.
The estimates of technical performance and of the expenses for
operations and maintenance of the facilities and other similar operating
assumptions used in the projections represent conservative estimates and
assumptions in light of the circumstances of the Projects. The budgets
provide sufficient funds for routine and major maintenance practices
used in the industry to minimize degradation of power output and heat
rate. The Independent Engineer expects that maintenance expenses will be
within the limits anticipated in the budgets.
o Under the base-case assumptions, the pro forma financial projections
show a minimum debt service coverage ratio for the New Securities of
2.25 times and an average debt service coverage ratio of 2.88 times over
the life of the New Securities. The debt service coverage ratios remain
relatively stable over a broad range of sensitivities.
o The facilities meet the requirements of all regulatory agencies,
including those for QFs and those required by the environmental permits,
and the Independent Engineer expects that they will continue to do so in
the future.
For a more complete discussion of the methodology employed by the
Independent Engineer and the assumptions underlying the foregoing opinions, see
"Appendix B -- The Independent Engineer's Report."
Fuel Consultant's Report
Benjamin Schlesinger and Associates, Inc. (the "Fuel Consultant") has
prepared a report (the "Fuel Consultant's Report") dated February 12, 1998, a
copy of which is included as Appendix C in this Prospectus. The Fuel
Consultant's Report was prepared to provide a due diligence analysis and
evaluation of the fuel supply, transportation and storage arrangements for the
Projects. The Fuel Consultant's Report summarizes and evaluates NE LP's
projections regarding future costs for gas, the Partnerships' overall fuel
supply plan, the linkage of fuel costs and certain Project Revenues and the
Partnerships' gas supply and transportation arrangements. The assumptions
contained in the Projections and evaluated in the Fuel Consultant's Report
concern material contingencies and other matters that are not within the control
of ESI Tractebel Acquisition, the Partnerships, the Partners, the Fuel
Consultant or any other person. These assumptions are inherently subject to
significant uncertainties, and actual results will differ, perhaps
substantially, from those projected. None of ESI Tractebel Acquisition, the
Partnerships, the Partners, the Fuel Consultant or any other person can give any
assurance that these assumptions are correct or that the Projections will
reflect actual results of operations. No representation is made therefore, or
intended, nor should any representation be inferred, with respect to the likely
existence of a particular future set of facts or circumstances. If actual
results are materially less favorable than those shown or if the assumptions
evaluated in the Fuel Consultant's Report and utilized in preparing the
Projections prove to be incorrect, ESI Tractebel Acquisition's ability to pay
principal of and interest on the Securities may be materially and adversely
affected. See "Risk Factors -- Uncertainties of Projections and Assumptions."
Subject to the information contained, and assumptions made, in the Fuel
Consultant's Report, the Fuel Consultant has expressed the following
conclusions:
12
o The assumptions contained in NE LP's pro forma financial model for the
Projects as they relate to the current and projected prices of natural
gas are reasonable, and the expected cash flows for NE LP are robust
enough to withstand alternative fuel price scenarios.
o The Partnerships have secured contract gas at the Projects on a highly
reliable basis. Moreover, since the Projects entered commercial
operations in 1991, neither has ever had to shut down due to lack of
availability of non-contract gas supplies.
o Taken together, NEA's and NJEA's delivered fuel costs and power revenues
are naturally hedged; i.e., the degree to which NJEA's and NEA's gas
purchases are tied to their energy payments equals 95% and 91%,
respectively.
o NEA's and NJEA's contracted gas supply, storage and transportation
services are adequate to satisfy 80% of the plants' daily fuel
requirements at full operations.
o NEA and NJEA are well positioned to continue to obtain competitive and
reliable spot supplies because of (a) the significant liquidity of spot
gas markets as an ongoing feature of the Northeast natural gas industry
and (b) their individual and combined purchasing power.
o Early expiration of the Projects' interstate pipeline contracts poses no
risk to bondholders due to the protections inherent in federal
regulation and market realities.
o No material adverse economic impact upon NJEA's financial projections
associated with the termination of the PSE&G contract as scheduled in
2011 is foreseen.
o NEA and NJEA have executed exceptionally strong fuel supply and
transportation strategies and will be able to continue fulfilling all of
their gas requirements reliably and in a way that will protect
bondholders at least over the next 15 years.
For a more complete discussion of the methodology employed by the Fuel
Consultant and the assumptions underlying the foregoing conclusions, see
"Appendix C -- The Fuel Consultant's Report."
SUMMARY HISTORICAL AND PRO FORMA COMBINED FINANCIAL DATA
Historical
Presented below is the summary historical combined financial data of
the Partnerships at the dates and for the periods indicated. The summary
historical combined statement of operations data and statement of cash flows
data for the years ended December 31, 1995, 1996 and 1997 are derived from the
Partnerships' combined financial statements included elsewhere in this
Prospectus. The summary historical combined statement of operations data and
statement of cash flows data for the years ended December 31, 1993 and 1994 are
derived from the Partnerships' audited combined financial statements not
included in this Prospectus. The summary historical combined financial data set
forth below should be read in conjunction with, and is qualified by reference
to, "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the audited combined financial statements of the Partnerships
and related notes thereto included elsewhere in this Prospectus.
Pro Forma
Because NE LP was formed November 21, 1997, it had no activity as of
and for the year ended December 31, 1997. As a result, the summary NE LP pro
forma financial information gives effect to the Acquisitions based on the
historical combined financial statements of the Partnerships, under the
assumptions and adjustments set forth in the notes accompanying the unaudited
13
pro forma financial statements contained in "Unaudited Pro Forma Financial
Statements." NE LP has accounted for the Acquisitions as a purchase for
financial reporting purposes. The summary pro forma statement of operations data
for the year ended December 31, 1997 assumes that the Acquisitions and the
Offering were consummated on January 1, 1997. The summary pro forma balance
sheet as of December 31, 1997 assumes the Acquisitions and the Offering were
consummated on December 31, 1997.
The summary NE LP pro forma financial information should be read in
conjunction with the notes accompanying the unaudited pro forma financial
statements contained in "Unaudited Pro Forma Financial Statements" and with the
historical combined financial statements of the Partnerships and related notes
thereto included elsewhere in this Prospectus. The summary pro forma combined
financial information has been prepared for informational purposes only and is
not necessarily indicative of the actual or future results of operations or
financial condition that would have been achieved had the Acquisitions occurred
at the dates assumed.
14
SUMMARY HISTORICAL AND PRO FORMA COMBINED FINANCIAL DATA
(In Thousands of Dollars)
NE LP
Partnerships Combined Pro Forma
- ------------------------------------------------------------------------------------------------------------ --------------------
Year Ended December 31, Year Ended
- ------------------------------------------------------------------------------------------------------------ --------------------
1993 1994 1995 1996 1997 December 31, 1997(1)
STATEMENT OF OPERATIONS DATA:
Total revenues.......................... $ 238,826 $ 238,712 $ 280,549 $ 272,262 $ 312,154 $ 312,154
Operating income........................ $ 46,882 $ 54,176 $ 86,097 $ 71,279 $ 94,013 $ 73,532
Net income (loss)....................... $ (1,261) $ (16,916)(2) $ 26,857 $ 9,924 $ 36,673 $ (7,224)
BALANCE SHEET DATA:
Total assets............................ $ 546,484 $ 650,027 $ 617,034 $ 566,392 $ 541,431 $1,478,746
========= ========= ========= ========= ========== ==========
Loans payable and other liabilities..... $ 483,626 $ 587,459 $ 559,558 $ 532,949 $508,052 $1,080,345
Energy Bank liabilities................. 111,398 155,496 188,053 220,922 230,565 171,581
--------- --------- --------- --------- ---------- ----------
Total liabilities................ 595,024 742,955 747,611 753,871 738,617 1,251,926
Partners' equity (deficit).............. (48,540) (92,928) (130,577) (187,479) (197,186) 226,820
--------- --------- --------- --------- ---------- ----------
Total liabilities and partners'
equity (deficit)................ $ 546,484 $ 650,027 $ 617,034 $ 566,392 $ 541,431 $1,478,746
========= ========= ========= ========= ========== ==========
STATEMENT OF CASH FLOWS DATA:
Non-cash charges and Energy Bank
accruals(3)............................ $ 69,955 $ 70,745 $ 59,766 $ 60,220 $ 36,798
Extraordinary loss on extinguishment of
debt................................... -- 13,937 -- -- --
Change in future obligations under
interest rate swap agreements.......... -- 6,425 (2,771) (1,632) (1,133)
Change in working capital............... 455 (5,828) (12,622) 6,514 9,837
Net income (loss)....................... (1,261) (16,916) 26,857 9,924 36,673
--------- --------- --------- --------- ----------
Net cash provided by operating
activities(4).......................... $ 69,149 $ 68,363 $ 71,230 $ 75,026 $ 82,175
========= ========= ========= ========= ==========
Principal payments on debt.............. $ 48,742 $ 34,290 $ 20,434 $ 25,204 $ 24,075
Interest paid........................... $ 38,090 $ 37,743 $ 53,869 $ 51,435 $ 48,794
Distributions to partners............... $ 10,878 $ 27,472 $ 64,506 $ 66,826 $ 46,380
Ratio of earnings to fixed charges(5)... -- -- 1.38 1.18 1.70 --
- ----------
(1) See "Unaudited Pro Forma Financial Statements."
(2) Includes extraordinary loss on extinguishment of debt of $13.9 million and
expense of $6.7 million related to future obligations under interest rate
swap agreements.
(3) Includes depreciation of property, plant and equipment, amortization of
financing costs, and annual increases in Energy Bank balances.
(4) Net cash provided by operating activities is net of interest paid during
the period.
(5) The ratio of earnings to fixed charges is determined by dividing the sum of
pre-tax income (net income) and fixed charges (consisting of interest
expense, amortization of debt issue costs, the estimated interest component
of rent expense and equipment rentals) by fixed charges. The earnings
for 1993, 1994 and pro forma 1997 were inadequate to cover fixed charges.
The coverage deficiencies during 1993, 1994 and pro forma 1997 are $1.261
million, $2.979 million and $7.224 million, respectively.
15
RISK FACTORS
Holders of the Old Securities should consider carefully the risk
factors set forth below, as well as other information contained herein, before
tendering their Old Securities in the Exchange Offer.
Substantial Leverage
As of the date of this Prospectus, ESI Tractebel Acquisition and NE LP
are substantially leveraged. On December 31, 1997, after giving pro forma effect
to the Offering, ESI Tractebel Acquisition would have had total indebtedness of
approximately $220 million, representing the aggregate principal amount of the
Securities. On December 31, 1997, after giving pro forma effect to the
Acquisitions, the Offering, and the uses of proceeds therefrom, NE LP would have
had total long-term indebtedness of $860,305,000 (of which $220,000,000 would
have consisted of the non-current portion of its Note relating to the
Securities, $468,724,000 would have consisted of the Partnerships' loan payable
to a related party and $171,581,000 would have consisted of Energy Bank
balances) and Partners' equity of $226,820,000. Subject to the limitations set
forth in the Indenture, ESI Tractebel Acquisition, NE LP and NE LLC and their
subsidiaries will be permitted to incur additional indebtedness in the future.
See "Capitalization" and "Summary Historical and Pro Forma Combined Financial
Data" and "Description of Securities."
ESI Tractebel Acquisition's ability to make scheduled payments of the
principal of, or to pay the interest on and Registration Default Damages, if
any, or to refinance, its indebtedness (including the Securities), will depend
upon NE LP's ability to make scheduled payments under the Note. NE LP's ability
to make such payments and the Partnerships' ability to make payments on the
Project Indebtedness and to fund planned capital expenditures for the Projects
will depend, in turn, on the future performance of the Partnerships, which, to a
certain extent, is subject to general economic, financial, competitive,
legislative, regulatory and other factors that are beyond ESI Tractebel
Acquisition's, NE LP's or the Partnerships' control. Based upon the current
level of operations of the Partnerships, management of NE LP believes that cash
flow from operations and available cash will be adequate to meet the
Partnerships', NE LP's and ESI Tractebel Acquisition's future liquidity needs.
There can be no assurance, however, that the Partnerships' business will
generate sufficient cash flow from operations or that future borrowings will be
available in an amount sufficient to enable the Partnerships to service the
Project Indebtedness and to enable NE LP and ESI Tractebel Acquisition to
service their respective indebtedness, including the Securities, or to fund
their other liquidity needs. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
The degree to which the Partnerships and NE LP are leveraged could have
important consequences to holders of the Securities, including, but not limited
to: (i) making it more difficult for ESI Tractebel Acquisition to satisfy its
obligations with respect to the Securities, (ii) increasing the Partnerships'
vulnerability to general adverse economic and industry conditions, (iii)
limiting NE LP's and the Partnerships' ability to obtain additional financing to
fund future working capital, capital expenditures and other general requirements
and (iv) limiting the Partnerships' flexibility in planning for, or reacting to,
changes in its business and in the industry. In addition, each of the Project
Indenture and the Indenture contain, certain restrictive covenants that limit
the ability of the Partnerships and ESI Tractebel Acquisition and NE LP,
respectively, to, among other things, borrow additional funds. Failure by the
Partnerships, NE LP or ESI Tractebel Acquisition to comply with such covenants
under the respective indentures could result in an event of default that, if not
cured or waived, could have a material adverse effect on the Partnerships and/or
ESI Tractebel Acquisition and NE LP. In addition, the degree to which ESI
Tractebel Acquisition is leveraged could prevent it from repurchasing all of the
Securities tendered to it upon the occurrence of a Change of Control. See "--
Holding Company Structure; Dependence upon Operations of Projects," "Description
16
of Securities -- Repurchase at the Option of Holders Upon a Change of Control"
and "-- Outstanding Project Indebtedness."
Holding Company Structure; Dependence Upon Operations of Projects
Payment of the principal and premium, if any, and interest and
Registration Default Damages, if any, on the Securities are not obligations of
the Partnerships but are payable from payments to be received by ESI Tractebel
Acquisition on the Note, which payments can be made solely from distributions to
be made by the Partnerships to NE LP and NE LLC, and from funds held by the
Trustee in the Accounts, including the Debt Service Reserve Account. So long as
the Project Indebtedness is outstanding, such distributions can be made only
after all of the payments and deposits required under the Project Indenture have
been made. In addition to the operating expenses and reserves associated with
the Projects, payments under the Project Indenture include payments on the
Working Capital Facility, if any, the Project Securities and the Swaps and
reserves and fees therefor. In addition, distributions from the Partnerships to
NE LP and NE LLC are subject to satisfaction of a number of other requirements,
including satisfaction of financial ratio tests and the absence of any default
or event of default under the Project Indenture. Accordingly, payments on the
Securities are, effectively, deeply subordinated.
If a Partnership does not make a payment or otherwise fails to perform
its obligations under the Project Indenture or if the coverage tests are not
met, no distributions will be made to the Partners and no funds will be
available to make payments on the Securities, other than any amounts held by the
Trustee in the accounts described below. Upon the liquidation, bankruptcy,
insolvency or similar proceeding in respect of a Partnership or following any
event of default under the Project Indenture and/or under the NEA Second
Mortgage, all creditors of the Partnerships, including the holders of the
Project Securities, the Working Capital Banks, if any, and the Swap Banks and,
if the Project Indebtedness is no longer outstanding, the NEA Power Purchasers
under the NEA Second Mortgage, will be entitled to receive payment in full of
all amounts due and owing before the Partners will be entitled to receive any
amounts.
Debt service payments in respect of the Securities are entirely
dependent upon the operation of the Projects. Operation of the Projects involves
regulatory risks such as changes in laws or regulations, which could result in
increased compliance costs, the need for additional capital expenditures or the
reduction of certain benefits currently available to the Partnerships, and
involves a variety of other risks, including possible performance of one or both
Projects below expected levels of output or efficiency, interruptions in fuel
supply, disruptions in the off-take of electrical energy or steam, shut-downs
due to the breakdown or failure of equipment or processes, labor disputes,
material changes in governmental permit requirements and catastrophic events
such as fires, earthquakes, explosions, floods, severe storms or similar
occurrences affecting a Project or its power purchasers, steam purchasers, fuel
suppliers or fuel transporters. The occurrence of any of these events could
reduce significantly or eliminate entirely the revenues generated by a Project
and could increase significantly the expenses incurred by that Project. The
Partnerships maintain insurance to protect against many of these risks; however,
not all risks can be insured, and the proceeds of insurance for risks that are
covered may not be adequate to cover a Project's lost revenues or increased
expenses. In addition, although the Projects have been in operation since 1991,
there can be no assurance that the operating and financial results under the New
Operator and the Partners will match the past results described herein.
Regulatory and Financial Pressures on Power Purchasers
If the price to be paid by a Power Purchaser to a Partnership under its
Power Purchase Agreement exceeds such Power Purchaser's actual Avoided Costs for
the electricity purchased, or if a Power Purchaser is experiencing financial,
regulatory or other pressures, such Power Purchaser could attempt to amend or to
terminate its Power Purchase Agreement. See "-- Dependence Upon Third Parties."
17
Currently, the price to be paid by each of the Power Purchasers, other than
Montaup, is projected to be above actual Avoided Costs for the remaining term of
the Power Purchase Agreements. Although the provisions of the Power Purchase
Agreements do not permit amendments or early termination without the consent of
the applicable Partnership and although the provisions of the Project Indenture
and the Indenture prohibit the Partnerships and NE LP, respectively, from giving
such consent if the effect on the bondholders would be materially adverse, it is
conceivable that, upon a change in applicable legislation, case law and/or
regulations, a court or regulatory authority could order such an amendment or
termination. Such amendment or termination could materially and adversely affect
the net revenues of the applicable Partnership and consequently the cash flow
available for payments on the Securities and may constitute an event of default
under the Project Indenture and the Indenture. See "-- Dependence Upon Third
Parties" and "Regulation -- Utility Industry Restructuring."
JCP&L has reported to New Jersey regulators that its above-market costs
for power associated with the NJEA Power Purchase Agreement will total $837.67
million during the remaining life of the NJEA Power Purchase Agreement (present
value of such amount recently estimated by JCP&L to be approximately $509.44
million) and that it intends to pursue efforts to mitigate these costs. In
Massachusetts, pursuant to recently enacted electric deregulation legislation,
utilities and producers that are parties to certain above-market power contracts
are required, subject to certain conditions, to make good-faith efforts to
renegotiate such contracts in order to mitigate stranded costs. See "Regulation
- -- Utility Industry Restructuring."
Security of Partners' Pledges Limited to Economic Rights
Security for the Securities will include a first priority security
interest in NE LLC's and NE LP's limited partner interests in the Partnerships
and a second priority security interest in NE LP's general partner interest in
the Partnerships (second to the first priority security interest that secures
repayment of the Project Indebtedness). Following any default under the
Indenture, so long as the Project Securities or any other Project Indebtedness
is outstanding, security for the Securities is practically limited to the
Partners' economic interests in the Partnerships. The limited partner interests
do not include meaningful voting rights, so that foreclosure on such limited
partner interests will, practically, result only in acquisition of economic
interests. So long as the Project Securities are outstanding, the Trustee will
have no ability to assume or to influence management or control of the
Partnerships.
Limited Recourse
The obligations of NE LP under the Note are non-recourse to the direct
and indirect owners of NE LP. None of the Partnerships or any of their
affiliates or parents (including FPL Energy, ESI Energy and Tractebel Power),
stockholders, officers, directors or employees has any obligation with respect
to payment of the Securities or the Projects' Indebtedness. In addition, the
obligations of NEA and NJEA in connection with the Project and the Project
Indebtedness are non-recourse obligations of the Partnerships. Because NE LP and
NE LLC will have no meaningful revenues other than the distributions they
receive from the Partnerships, NE LP's ability to make payments under the Note
will be limited to payments to be made from amounts payable by the Partnerships
as distributions.
Energy Banks and the NEA Second Mortgage
Each of the Power Purchase Agreements (other than the Commonwealth
Power Purchase Agreements) provides for tracking accounts or "Energy Banks" that
represent the cumulative differences from time to time between (i) amounts
originally estimated to be paid or actually paid, depending upon the Power
Purchaser Agreement, by the Power Purchaser for electric power delivered
pursuant to such Power Purchase Agreement and (ii) the amounts originally
estimated as such Power Purchaser's Avoided Cost (as defined in such Power
18
Purchase Agreement). The balances in the Energy Banks under the Boston Edison II
Power Purchase Agreement and under the JCP&L Power Purchase Agreement have been
reduced to zero resulting in a termination of the Energy Bank provisions in such
agreements. The Energy Bank balances under the Boston Edison I Power Purchase
Agreement and under the Montaup Power Purchase Agreement were $144,547,000 and
$27,035,000, respectively, as of December 31, 1997. The Energy Bank balance for
the Montaup Power Purchase Agreement is expected to increase throughout the term
of such agreement and to be approximately $60 million on December 30, 2011, the
maturity date of the Securities. Each of such agreements provides that any
positive Energy Bank balance will be due and payable by NEA in cash if such
agreement is terminated under the following circumstances: (i) in the case of
the Boston Edison I Power Purchase Agreement, upon the expiration or early
termination following an event of default by NEA (which includes the failure to
deliver a minimum quantity of electricity equal to approximately 50% of
historical levels for two consecutive years) and (ii) in the case of the Montaup
Power Purchase Agreement upon expiration or early termination following NEA's
insolvency or bankruptcy or upon NEA's failure to generate at an annual capacity
factor of 60% or higher for two consecutive years. Any such payment will be
senior in right of payment to the Securities.
The performance by NEA of its obligations under each of the NEA Power
Purchase Agreements is secured by the NEA Second Mortgage. In addition, the NEA
Second Mortgage grants security with respect to all amounts paid by the NEA
Power Purchasers under their respective NEA Power Purchase Agreements in excess
of the particular Power Purchaser's actual avoided costs, plus interest thereon
(the "Avoided Cost Security"). Although the Avoided Cost Security is payable
only from proceeds of any foreclosure sale following an event of default under
the NEA Second Mortgage or from the profits of the NEA Project following
repossession of the NEA Project by the NEA Power Purchasers under the NEA Second
Mortgage, and although none of such remedies may be exercised so long as the
Project Securities are outstanding, the projected amount of the Avoided Cost
Security is sufficiently large that if the Avoided Cost Security were to become
payable, NEA would likely not have sufficient resources to pay such amount and
would likely be rendered insolvent. Because the Project Securities are scheduled
to mature one year prior to the final maturity date of the Securities, it is
possible that, upon the occurrence and continuance of an event of default by NEA
under the NEA Power Purchase Agreements, the NEA Power Purchasers could
foreclose upon the NEA Project or repossess the NEA Project after the
termination or expiration of the Project Indenture and prior to the final
maturity date of the Securities. See "The Projects -- Power Purchase
Agreements."
The existence of the Energy Bank balances and the provisions of the NEA
Second Mortgage reduce the likelihood that holders of the Securities will be
paid if one or more of the NEA Power Purchasers terminate their Power Purchase
Agreements or foreclose upon or repossess the NEA Project under the NEA Second
Mortgage. For a description of the termination provisions under the Power
Purchase Agreements, see "Summary of Principal Project Agreements -- Power
Purchase Agreements."
Expiration of Certain Power Purchase Agreements; Merchant Sales
Project Revenues, and therefore distributions by the Partnerships to
the Partners, depend primarily upon payments to be made by the Power Purchasers.
The JCP&L Power Purchase Agreement expires on August 13, 2011, and the Boston
Edison II Power Purchase Agreement expires on September 15, 2011, four months
and three months, respectively, prior to the final maturity date of the
Securities. NE LP expects that after the expiration of the JCP&L Power Purchase
Agreement the NJEA Project will become a merchant plant with respect to the
portion of the net electrical output currently purchased by JCP&L thereunder and
with respect to the residual portion of the net electrical output expected to be
sold in the merchant markets, subject to certain restrictions and assuming such
merchant buyers are located. Although NE LP expects to find merchant market
purchasers for such additional capacity and plans to begin selling the residual
capacity (to which JCP&L currently has a right of recall at specified rates) in
19
1999, to date none of the additional capacity has been sold by NJEA. No
assurance can be given that JCP&L will agree to such sales by NJEA or that such
sales will materialize. See "-- Dependence Upon Third Parties." NE LP also
expects that NEA may sell approximately 10 MW of the NEA Project's residual
capacity in the merchant markets beginning in 1999 and that after the expiration
of the Boston Edison II Power Purchase Agreement, the NEA Project will become a
merchant plant with respect to approximately 29% of its output. For either of
the Projects to operate as a merchant plant and to sell power at market-based
rates, that Project would first require approval from FERC. FERC would require a
showing that the Project's owners lack market power in the relevant generation
and transmission markets, as well as with respect to other inputs into the
generation of electricity (such as fuel). Market-based rate authority would also
require a showing that there is no opportunity for abusive affiliate
transactions involving regulated affiliates of the Partnerships. In addition, a
merchant plant sells power based upon market conditions at the time of sale, so
that there can be no certainty today about the amount or timing of any revenues
that may be received from merchant power sales in the future. NE LP's
projections of revenues anticipated to be received from merchant sales is
included in Appendix B, although there can be no assurance that such revenues
will be achieved. See "-- Uncertainties of Projections and Assumptions." In any
event, it is likely that Project Revenues from power sales following expiration
of the JCP&L Power Purchase Agreement and the Boston Edison II Power Purchase
Agreement will be lower than Project Revenues payable from JCP&L and Boston
Edison during the terms of the two agreements.
Dependence Upon Third Parties
The viability of the Projects, NE LP's corresponding ability to make
payments on the Note and ESI Tractebel Acquisition's corresponding ability to
make payments on the Securities depend significantly upon the performance by
third parties in accordance with the Project Documents. If the parties to the
Project Documents do not perform their obligations or are excused from
performing their obligations because of non-performance by the Partnerships or
because of force majeure or other events, the Partnerships may not be able to
obtain alternate customers, goods or services to cover such nonperformance, and
NE LP's ability to make Note payments and ESI Tractebel Acquisition's
corresponding ability to make payments on the Securities would likely be
materially and adversely affected.
The NEA Project is dependent upon three electric energy purchasers for
sales of substantially all of the electricity produced by the NEA Project, one
natural gas supplier for substantially all natural gas supplied to the NEA
Project and one purchaser, NECO, for all thermal energy sales required to
maintain the NEA Project's QF status. During 1997 and 1996 Boston Edison's
purchases of electric energy accounted for approximately 75% of the NEA
Project's electricity output and for approximately 76% of NEA's gross revenues.
During 1997 and 1996, ProGas supplied approximately 72% and 74%, respectively,
of the NEA Project's fuel requirements. Although the NEA Project may also be
operated with Number 2 fuel oil, using Number 2 fuel oil is permitted only under
certain limited conditions and for certain limited durations. Other than for
testing purposes, Number 2 fuel oil has never been used at the NEA Project. See
"The Projects -- Gas Supply Arrangements" and "The Projects -- NEA Project --
Project Description." In addition, NECO's obligations to purchase steam under
the NEA Steam Sales Agreements are based on the NEA Project's being fueled only
by 100% pipeline quality natural gas and will be suspended whenever Number 2
fuel oil is used. See "The Projects -- Steam Sales Agreement -- NEA." The
reduction or elimination of NEA's sales of steam to NECO may negatively impact
the NEA Project's QF status.
The NJEA Project is dependent upon one electrical energy purchaser,
JCP&L, for nearly all of its sales of electrical energy. During 1997 and 1996,
JCP&L's purchases accounted for 100% of the NJEA Project's electrical output
sold and all of NJEA's gross operating revenues other than revenues from steam
sales. The NJEA Project's electrical capacity, net of electric power consumed at
20
the NJEA Site, is approximately 287 MW, of which approximately 252 MW are being
sold to JCP&L. Although NE LP expects to find merchant market purchasers for
such additional capacity (to which JCP&L currently has a right of recall at
specified rates) and plans to begin selling such additional capacity in 1999, to
date none of such additional capacity has been sold by NJEA. No assurance can be
given that JCP&L will agree to such sales by NJEA or that such sales will
materialize. See "-- Expiration of Certain Power Purchase Agreements; Merchant
Sales." The NJEA Project is dependent upon two natural gas suppliers, ProGas and
PSE&G, for substantially all natural gas required to operate the Project.
NJEA's gas supply contract with PSE&G expires in August 2011,
approximately four months prior to the final maturity date of the Securities.
PSE&G currently supplies approximately 45% of the NJEA Project's fuel
requirements. NE LP expects that such quantities will be replaced by the Fuel
Manager with natural gas purchased on the spot market. No assurances can be
given, however, that the prices for such natural gas will not be materially
higher than the Partnerships' current costs for the supply of natural gas or
that adequate supplies of natural gas will be available.
Electric utility systems that purchase substantial portions of their
energy supply from non-utility generators under fixed-quantity contracts have
recently expressed a strong interest in lowering consumer rates by extending
dispatch flexibility to include the generating plants of non-utility generators.
General Public Utility's system, of which JCP&L is a part, has publicly
announced and is pursuing its Natural Gas Private Pooling Point Program in which
it would draw on its lower fuel-cost sources of energy before drawing on higher
fuel-cost sources. JCP&L has contacted NJEA regarding this program and has made
a presentation to NJEA regarding JCP&L's proposal to transform NJEA's must-run
contract into a dispatchable contract on terms that are to cover all fixed costs
(debt service and fixed operating expenses) and preserve current net profits
while allowing JCP&L to reduce its purchased power costs. JCP&L has reported to
New Jersey regulators that its above-market costs for power associated with the
NJEA Power Purchase Agreement will total $837.67 million during the remaining
life of the NJEA Power Purchase Agreement (present value of such amount recently
estimated by JCP&L to be approximately $509.44 million) and that it intends to
pursue its efforts to mitigate these costs. In Massachusetts, pursuant to
recently enacted electric deregulation legislation, utilities and producers that
are parties to certain above-market power contracts are required, subject to
certain conditions, to make good-faith efforts to renegotiate such contracts in
order to mitigate stranded costs. See "Regulation -- Utility Industry
Restructuring." Such initiatives aimed at reducing stranded costs may negatively
affect revenues under the Power Purchase Agreements and consequently ESI
Tractebel Acquisition's ability to make payments on the Securities.
NEA and NJEA are dependent upon NECO and Hercules, respectively, for
steam sales. Steam sales are important for the maintenance of QF status. NECO
uses steam to produce carbon dioxide, and is dependent upon two carbon dioxide
purchasers for its own revenues. NECO's obligation to pay rent under its lease
with NEA (the "NECO Lease") and to pay for steam under its steam sales agreement
with NEA (the "NEA Steam Sales Agreement") depends upon whether NECO's revenues
exceed its expenses, and NECO is entitled under such agreements to defer
payments to NEA so long as the amount of its expenses exceeds the amount of its
revenues. NEA has agreed with each of NECO's two customers that upon receipt of
notice of NECO's default on its obligations to such customer, NEA will, within
45 days, replace NECO as lessee of the Carbon Dioxide Plant. NEA may not be able
to locate another company to lease the Carbon Dioxide Plant and to purchase
steam from the NEA Project, in which case the NEA Project's status as a QF and
the amount of NEA's revenues could be adversely affected.
NJEA's steam sales depend upon the continuing operation and viability
of the Hercules plant, which produces smokeless and soluble nitrocellulose and
natrosol. If the Hercules plant closes, NJEA has the right to build another
steam host on land leased from Hercules. Such endeavor would be costly and
time-consuming, however, and there can be no assurance that NJEA would have the
21
funds or be able to borrow the funds to replace the Hercules plant as a steam
host. The NJEA Project's status as a QF depends in part upon Hercules' purchases
of steam, and loss of QF status is an event of default by NJEA under the NJEA
Power Purchase Agreement.
The loss of QF status by NEA would entitle Montaup to renegotiate the
price provisions of its Power Purchase Agreement, and the loss of QF status by
NJEA would entitle JCP&L to terminate its Power Purchase Agreement. The initial
term of NEA's Steam Sales Agreement is scheduled to expire in June 2007, prior
to the final maturity date of the Securities. If the Steam Sales Agreement with
NECO is not renewed or replaced after such expiration date or if NEA's steam
host is not replaced, the risk of loss of QF status would materially increase.
See "Regulation" and "Summary of Principal Project Agreements -- Power Purchase
Agreements."
Gas Supply, Transportation and Transmission Risks
Open Market Purchases. The natural gas supplied by ProGas and by PSE&G
under the Long-term Gas Supply Agreements accounted for approximately 86% of the
natural gas required to operate the Projects in 1996 and approximately 85% of
such in 1997. The Partnerships currently purchase approximately 18% of their
natural gas supplies on the open market and thus are exposed to risks regarding
changes in the availability and market price of natural gas. Certain of the
Power Purchase Agreements link the price payable for electricity delivered
thereunder to the cost of natural gas in specified markets, providing some
protection against gas price volatility, but these pricing links are not
directly tied to the Partnerships' actual gas costs and thus do not provide
complete protection. Although the Fuel Consultant has determined that for NJEA
and NEA there are 95% and 91% correlations, respectively, between price
escalators under the Long-term Gas Supply Agreements, the correlation is not an
exact one. Accordingly, there can be no assurance that the Partnerships' fuel
costs will not materially exceed the costs assumed in the Projections.
Gas Transportation. Although the Long-term Gas Transportation
Agreements provide for firm transportation of all gas purchased under the
Long-term Gas Supply Agreements, the Partnerships do not have firm
transportation arrangements for the delivery of natural gas purchased on the
open market or arrangements for the delivery of gas after certain of the
Long-term Gas Transportation Agreements expire in 2006 and 2011. Transportation
arrangements for open-market purchases may not be available or may not be
available at the prices assumed therefore in the Projections. The Partnerships'
operating expenses will be greater than those indicated in the Projections if
the Partnerships are required to pay higher prices for natural gas or for
transportation, and if the Partnerships are unable to obtain sufficient supplies
of natural gas or natural gas transportation, a reduction in the amount of
electricity that one or both of the Projects could produce would result,
negatively impacting the revenues of the Projects and consequently ESI Tractebel
Acquisition's ability to make payments on the Securities.
Most of the Long-term Gas Transportation Agreements, as well as the
transporters' approved tariffs, contain provisions that permit the transporter
to terminate, suspend or reduce transportation of natural gas to the Projects
under certain circumstances. In addition, applicable governmental agencies have
authority to modify the rates, terms and conditions that govern the services
provided under the Long-term Gas Arrangements, and any such modification could
materially increase the Partnerships' fuel transportation costs. There can be no
assurance, therefore, that the Partnerships' actual transportation costs will
not exceed those assumed in the Projections.
Gas Storage. The Long-term Gas Storage Agreements stipulate that if the
number of dekatherms of gas being stored drops below specified levels, the
contractor may limit delivery or refuse to deliver natural gas to the
Partnerships until the gas storage volumes are replenished. Curtailment of
22
natural gas deliveries from storage would require purchases of additional
natural gas on the open market, which could increase the Partnerships' costs of
operating the Projects.
PSE&G Service Interruptions. PSE&G's gas supply and transportation
services to the NJEA Project are subject to interruption or to higher prices on
days when the forecast mean daily temperature for Newark, New Jersey is 22
degrees F or below. To avoid interruptions in service, NJEA may elect by March
of any year to have service without interruption, but at higher prices, on days
on which the temperature is below 22 degrees F but not below 14 degrees F. Since
1991, when the NJEA Project commenced commercial operation through the winter of
1996-1997, there have been an average of approximately 11 days per winter when
the forecast mean temperature was below 22 degrees F and two days per winter
when the forecast mean temperature was below 14 degrees F.
Transmission of Electrical Power. All of the electrical power sold to
the NEA Power Purchasers is transported through one 345kV line. Boston Edison
owns the Massachusetts section of this line. Commonwealth and Montaup have
access to a portion of the transmission capacity of this line pursuant to
arrangements that are scheduled to expire in 2001. Transmission access in New
England is determined in accordance with rules of NEPOOL and the ISO (as
described under the caption "Regulation -- Utility Industry Restructuring --
NEPOOL"), as such rules may be modified from time to time. The Projections
assume that costs of transmission in 2001 will be equal to the current Boston
Edison rates as filed with FERC. However, rates, terms and conditions of
transmission service after 2001 will depend on NEPOOL and FERC policies at the
time, which are difficult to predict with any certainty. In any event, any new
arrangements for transmitting power from the NEA Project to Commonwealth and
Montaup after 2001 are likely to result in increased transmission costs. NEA may
bear the burden of any such increased costs, and there can be no assurance that
such costs will not exceed the costs assumed therefor in the Projections.
Risks Arising from Regulation
General. The Partnerships are required to comply with numerous federal,
state and local statutory and regulatory standards and to maintain numerous
permits and approvals required for the operation of the Projects. Some of the
permits and regulatory approvals that have been issued to the Partnerships
contain certain conditions. Failure to satisfy any such conditions or approvals
could prevent the operation of either Project or result in additional costs.
There can be no assurance that either Project will continue to operate in
accordance with the conditions established by the permits or approvals. Laws and
regulations affecting ESI Tractebel Acquisition, the Partners, the Partnerships,
ESI Tractebel Funding and other Project participants can be expected to change
during the period in which the Securities are outstanding, and such changes
could adversely affect ESI Tractebel Acquisition, the Partners, the
Partnerships, ESI Tractebel Funding and such other Project participants. For
example, changes in laws or regulations (including but not limited to tax and
environmental laws and regulations) could impose more stringent or comprehensive
requirements on the operation or maintenance of the Projects resulting in
increased compliance costs, the need for additional capital expenditures or the
reduction of certain benefits currently available to the Partnerships, or could
expose ESI Tractebel Acquisition, the Partners, the Partnerships or ESI
Tractebel Funding to liabilities for previous actions taken in compliance with
laws in effect at the time or for actions taken by or conditions caused by the
Sellers or by other third parties. Changes in law could also encourage greater
competition in wholesale electricity markets resulting in a decline in long-term
rates to be paid by electric utilities (in particular under the Montaup Power
Purchase Agreement, which does not include a floor price). Although purchase
prices for electricity under the Power Purchase Agreements (other than the
Montaup Power Purchase Agreement) contain floor price provisions (and the
Projections assume that such floor prices are the prices that will be paid by
such Power Purchasers), a decline in long-term rates to be paid by electric
utilities generally may indirectly adversely affect the Partnerships' profits in
23
connection with its sales to such Power Purchasers and would adversely affect
merchant plant sales. See "-- Regulatory and Financial Pressures on Power
Purchasers."
PURPA provides QFs such as the Projects with certain exemptions from
federal and state law and regulation, including regulation of rates at which
electricity can be sold. As of the date of this Prospectus, none of NE LP or the
Partnerships has received any notice that any of the required regulatory
approvals have been revoked or that FERC or any of the Power Purchasers has
initiated any regulatory proceedings to revoke the QF status of either Project.
If either Project fails to maintain its status as a QF, if amendments to PURPA
are enacted that substantially reduce the benefits currently afforded QFs, or if
the requirements for the Projects to maintain their status as QFs are
substantially changed, the Projects could be adversely affected, which could
affect NE LP's ability to pay interest and principal on the Note and the ability
of ESI Tractebel Acquisition to pay interest and principal on the Securities.
NEA has agreed in certain of its Power Purchase Agreements to use its best
efforts to maintain QF status. The loss of QF status by NEA would entitle
Montaup to renegotiate the price provisions of its Power Purchase Agreement and
the loss of QF status by NJEA would entitle JCP&L to terminate its Power
Purchase Agreement. In addition, the NEA Steam Sales Agreement is scheduled to
expire prior to the final maturity date of the Securities. If the NEA Steam
Sales Agreement is not renewed or replaced after such expiration date or if
NEA's steam host is not replaced, the risk of loss of QF status would materially
increase. See "Regulation" and "Summary of Principal Project Agreements -- Power
Purchase Agreements."
Permitting Risks. The Partnerships are required to maintain and to
comply with certain permits and approvals for the ownership and operation of the
Projects. Although the Partnerships have obtained all material permits and
approvals required for the ownership and operation of the Projects, there can be
no assurance that the requirements contained in such permits will not change or
that the Partnerships will be able to renew or to maintain all permits and
approvals required for continued operation of the Projects throughout the term
of the Securities. Failure to renew or to maintain any required permit or the
inability to satisfy any requirement of any permit may result in limited or
suspended operation of the affected Project.
Environmental Matters. The Partnerships are required to comply with a
number of statutes and regulations relating to protection of the environment and
to the safety and health of the public and of personnel operating the Projects.
Such statutes and regulations, which are always subject to change, include
regulation of Hazardous Materials associated with each Project, limitations on
noise emissions from the Projects, safety and health standards, and practices
and procedures and requirements relating to the discharge of air and water
pollutants. In addition, the Partnerships could become liable for the
investigation and removal of any Hazardous Materials that may be found on the
Project Sites regardless of the sources of such Hazardous Materials. Failure to
comply with any such statutes or regulations or any change in the requirements
of such statutes or regulations could result in civil or criminal liability,
imposition of cleanup liens and fines and large expenditures to bring the
Projects into compliance. The NEA Project location has been the subject of
ongoing remediation relating to the release of fuel oil in 1992. The Operator
has assumed full responsibility for the release and all related remedial
efforts, and has diligently pursued regulatory closure of this matter. Based on
the Independent Engineer's Report, it appears that the applicable regulatory
authorities are satisfied with the Operator's remedial efforts and that the
Operator should be in a position to obtain regulatory closure for the site
without incurring significant additional costs. There can be no assurance,
however, that the Operator will obtain regulatory closure for the site without
incurring significant additional costs, or that the Partnerships will not incur
liability notwithstanding that the Operator has assumed all such responsibility
for the spill.
The 1990 Amendments to the Federal Clean Air Act of 1955 (the "1990
Amendments") require states to develop implementation plans to be approved by
the EPA for attaining national ambient air quality standards for particular
24
pollutants in areas that have not attained those standards. Because each Project
is situated in an ozone non-attainment area, each Project may become subject to
more stringent air emissions standards. There can be no assurance that the
Projects will be able to satisfy all new regulatory requirements that may arise
under the 1990 Amendments.
Federal law also allows the State of New Jersey and the Commonwealth of
Massachusetts to take certain actions regarding the issuance of stormwater
discharge permits. A federal stormwater discharge permitting program has been
established, and the State of New Jersey and the Commonwealth of Massachusetts
have promulgated stormwater management regulations, modeled on the federal
program, which may be applicable to the Projects. The Projects may also be
subject to the federal stormwater permit program. There can be no assurance that
the Projects satisfy or will continue to satisfy all requirements that may
result from action with respect to the stormwater discharge permitting program.
See "Regulation."
As of the date of this Prospectus, neither NE LP nor the Partnerships
has received any notice that any of the required regulatory approvals has been
revoked. There can be no assurance, however, that one or more of such required
regulatory approvals will not be revoked.
Curtailment by Power Purchasers. Each Power Purchase Agreement
authorizes the purchasing utility to curtail purchases for reasons of system
emergency, safety and repair and/or restoration of service. Each of the Power
Purchase Agreements with Boston Edison and Montaup also permits curtailment by
the purchaser for up to an additional 200 hours annually per contract year at
the purchaser's sole discretion. JCP&L is entitled to curtail or to refuse to
accept and purchase power (i) during off-peak periods, for up to 200 hours
annually and (ii) for up to an additional 200 hours annually until 2001 and for
up to an additional 400 hours annually thereafter, during light load periods in
which other member utilities within the PJM Interconnected Power Pool are
required to reduce generation to minimum levels. Under certain circumstances,
PURPA authorizes utilities to limit or discontinue purchases from QFs due to
"operational circumstances." This right to curtail purchases of power from QFs
in the circumstances set forth under PURPA is included in certain of the Power
Purchase Agreements. In the past, there have been several disputes between the
Partnerships and the Power Purchasers concerning curtailment rights, and in the
case of the NEA Project, with respect to the calculation of entitlement
percentages during periods of curtailment. For a more detailed description of
the utilities' curtailment rights, see "Summary of Principal Project Agreements
- -- Power Purchase Agreements."
Uncertainties of Projections and Assumptions
In connection with the Acquisitions and the issuance of the Securities,
NE LP prepared certain assumptions and projections (the "Projections") of the
Projects' revenue generation capacity and the costs associated therewith. The
Projections were provided to the Independent Engineer, and the Independent
Engineer has evaluated the reasonableness of the Projections in light of the
technical operating parameters of the Projects, as well as the operations and
maintenance budgets of the Projects (other than the budgets relating to the
Long-term Gas Arrangements) and the related assumptions and forecasts contained
therein, based upon an inspection and review of certain technical,
environmental, economic and regulatory aspects of the Projects, as set forth in
the Independent Engineer's Report. The Projections were also provided to the
Fuel Consultant, which evaluated the Projections in light of projected gas costs
and alternative gas supply and transportation arrangements, among other factors.
The Independent Engineer's Report and the Fuel Consultant's Report each contains
a discussion of the assumptions and forecasts NE LP utilized in preparing the
Projections, which concern the operations and maintenance budgets of the
Projects and which investors should review carefully.
25
For purposes of preparing the Projections, NE LP made certain
assumptions with respect to general business and economic conditions, the prices
at which the Partnerships will be able to sell electric energy not sold pursuant
to the Power Purchase Agreements, the costs to the Partnerships of obtaining
natural gas supplies and storage and transportation services, taxes payable by
the Partnerships, NE LP or any other person and numerous other material
contingencies and matters that are not within the control of the Partnerships
and the outcome of which cannot be predicted by NE LP, its consultants, the
Independent Engineer, the Fuel Consultant or any other person with any
expectation of complete accuracy. NE LP also made assumptions concerning
operations and maintenance costs and savings and major maintenance costs and
savings during the term of the New O&M Agreements. Although NE LP, the
Independent Engineer and the Fuel Consultant believe that these assumptions and
the other assumptions upon which the Projections were based are reasonable,
assumptions are inherently subject to significant uncertainties, and actual
results are expected to differ, perhaps materially, from those projected.
Accordingly, the Projections are not necessarily indicative of future
performance, and none of NE LP, the Independent Engineer, the Fuel Consultant or
any other person assumes any responsibility for the accuracy of such
Projections. In addition, certain assumptions with respect to future business
decisions of the NE LP and the Partnerships are subject to change. Accordingly,
the Projections and the other forward-looking information contained in this
Prospectus, the Independent Engineer's Report and in the Fuel Consultant's
Report are not necessarily indicative of future performance. Therefore, no
representation is made or intended, nor should any representation be inferred,
with respect to the likely existence of any particular future set of facts or
circumstances, and prospective investors are cautioned not to place undue
reliance on the Projections, the Independent Engineer's Report or the Fuel
Consultant's Report. If actual results are less favorable than those shown or if
the assumptions used in formulating the Projections prove to be incorrect, the
Partnerships' financial performance may also be less favorable, and,
consequently, ESI Tractebel Acquisition's ability to make payment of principal
of and interest on the Securities may be materially adversely affected. See
"Appendix B -- Independent Engineer's Report" and "Appendix C -- Fuel
Consultant's Report."
The Projections were prepared by, and are the responsibility of, NE LP
on the basis of present knowledge and assumptions, which NE LP believes to be
reasonable. Price Waterhouse LLP has neither examined nor compiled the
Projections contained in Exhibit B, and accordingly, Price Waterhouse LLP does
not express an opinion or any other form of assurance with respect thereto. The
Price Waterhouse LLP report included in this Prospectus relates solely to the
Partnerships' historical financial information. It does not extend to the
Projections and should not be read to do so. None of NE LP, the Independent
Engineer or the Fuel Consultant intends to provide to holders of the Securities
any projections or to evaluate any projections other than the Projections set
forth herein.
Absence of a Public Market
The New Securities are being offered to the holders of the Old
Securities. The Old Securities were issued in February 1998 to a small number of
institutional investors and are eligible for trading in the Private Offerings,
Resale and Trading through Automatic Linkages (PORTAL) market. The New
Securities are new securities for which there is currently no established
market. ESI Tractebel Acquisition has been advised by Goldman that it presently
intends to make a market in the New Securities; however Goldman is not obligated
to do so and any such market-making activity may be discontinued at any time
without notice at the discretion of Goldman. ESI Tractebel Acquisition does not
intend to apply for listing of the New Securities on any securities exchange or
to seek approval for quotation through any automated quotation system.
Accordingly, there can be no assurance as to whether an active established
market will develop or, if an established market does develop, as to the
liquidity of the trading market for the New Securities. If an established market
does not develop, the market price and liquidity of the New Securities may be
adversely affected. See "Plan of Distribution."
26
Consequences of Failure to Properly Tender
Issuance of the New Securities in exchange for the Old Securities
pursuant to the Exchange Offer will be made only after timely receipt by the
Exchange Agent of such Old Securities, a properly completed and duly executed
Letter of Transmittal and all other required documents. Therefore, holders of
the Old Securities desiring to tender such Old Securities in exchange for New
Securities should allow sufficient time to ensure timely delivery. ESI Tractebel
Acquisition is under no duty to give notification of defects or irregularities
with respect to tenders of Old Securities for exchange. Old Securities that are
not tendered or that are tendered but not accepted by ESI Tractebel Acquisition
for exchange will, following consummation of the Exchange Offer, continue to be
subject to the existing restriction upon transfer thereof under the 1933 Act
and, upon consummation of the Exchange Offer, certain registration rights under
the Registration Rights Agreement will terminate. In addition, any holder of Old
Securities who tenders in the Exchange Offer for the purpose of participating in
a public distribution of the New Securities may be deemed to be an "underwriter"
(within the meaning of Section 2(11) of the 1933 Act) of the New Securities and,
if so, will be required to comply with the registration and prospectus delivery
requirements in the 1933 Act in connection with any resale transaction. Each
broker-dealer that receives New Securities for its own account in exchange for
Old Securities, where such Old Securities were acquired by such broker-dealer as
a result of market-making activities or other trading activities, must
acknowledge in the Letter of Transmittal that accompanies this Prospectus that
it will deliver a prospectus in connection with any resale of such New
Securities. See "Plan of Distribution". To the extent that Old Securities are
tendered and accepted in the Exchange Offer, the trading market for untendered
and tendered but unaccepted Old Securities could be adversely affected. See "The
Exchange Offer -- Consequences of Failure to Exchange".
USE OF PROCEEDS
Neither ESI Tractebel Acquisition nor NE LP will receive any proceeds
from the issuance of the New Securities in the Exchange Offer. In consideration
for the New Securities issued by ESI Tractebel Acquisition, as contemplated in
this Prospectus, ESI Tractebel Acquisition will receive in exchange a like
principal amount of Old Securities. The Old Securities surrendered in exchange
for the New Securities will be retired. Accordingly, the issuance of the New
Securities will not result in any change in the indebtedness of ESI Tractebel
Acquisition. The proceeds received by ESI Tractebel Acquisition from the sale of
Old Securities ($220,000,000 less certain expenses of the Offering of
approximately $6,663,300) were loaned by ESI Tractebel Acquisition to NE LP. NE
LP used the net proceeds to reimburse certain of ESI Energy's and Tractebel
Power's subsidiaries for expenses of the Offering and for a portion of the
original $534 million equity contribution that was used to finance the cost of
the Acquisitions.
CAPITALIZATION
Because NE LP and ESI Tractebel Acquisition were formed November 21,
1997 and Janurary 12, 1998, respectively, NE LP's historical balance sheet and
capitalization data as of December 31, 1997 had no activity and ESI Tractebel
Acquisition had no historical financial statements as of December 31, 1997. The
following table sets forth the pro forma capitalization at December 31, 1997 of
(i) NE LP as adjusted to reflect the Acquisitions and as adjusted to reflect the
Offering and the application of the estimated proceeds therefrom as described in
"Use of Proceeds" and (ii) ESI Tractebel Acquisition as adjusted to reflect the
Offering and the application of the estimated proceeds therefrom as described in
"Use of Proceeds," as if all such transactions occurred on December 31, 1997.
This table should be read in conjunction with the "Unaudited Pro Forma Financial
Statements" included elsewhere in this Prospectus.
27
Pro Forma Capitalization at December 31, 1997
ESI
Tractebel
NE LP Acquisition
as Adjusted for as Adjusted
the Acquisitions for the
and the Offering Offering
---------------- ------------
(In Thousands)
Short-Term debt:
Current portion of loans
payable(1)....................... $ 21,563 $ --
---------- ---------
Long-Term debt:
Loan payable--ESI Tractebel --
Acquisition...................... 220,000
Loans payable-- related party.. 468,724 --
Securities payable............. -- 220,000
Energy Bank balances(2)........ 171,581 --
---------- ---------
Total long-term debt... 860,305 220,000
---------- ---------
Partners'/stockholders' equity:
Partners' equity............... 226,820 --
Stockholders' equity........... -- --
---------- ---------
Total partners'/stockholders'
equity............... 226,820 --
---------- ---------
Total capitalization... $1,108,688 $ 220,000
========== =========
- ----------
(1) Does not include amounts available under the Working Capital Facility.
(2) Energy Bank balances represent cumulative payments made to the Partnerships
by Power Purchasers under certain Power Purchase Agreements in excess of
rates scheduled or specified in such agreements (plus interest accrued
thereon). Under the terms of these agreements, such excess constitutes a
liability of the applicable Partnership to the applicable Power Purchaser,
which will be reduced by subsequent sales of electric power to such Power
Purchaser to the extent in later periods that the scheduled or specified
rate has risen above the contract rate, and must be repaid under certain
circumstances in cash.
28
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
Because NE LP was formed November 21, 1997, it had no activity as of
and for the year ended December 31, 1997. The following unaudited pro forma
financial statements give effect to the Acquisitions based on the historical
combined financial statements of the Partnerships, under the assumptions and
adjustments set forth in the notes accompanying the unaudited pro forma
financial statements. NE LP has accounted for the Acquisitions as a purchase for
financial reporting purposes. The unaudited pro forma financial statements are
based on a preliminary allocation of the purchase price ($534.442 million) plus
certain costs of the Acquisitions (estimated to be $10.363 million), and
proceeds of the Offering ($220 million) less certain expenses of the Offering
(estimated to be $6,663,300), and are subject to change as additional
information becomes available. The unaudited pro forma statement of operations
for the year ended December 31, 1997 assumes that the Acquisitions and the
Offering were consummated on January 1, 1997. The unaudited pro forma balance
sheet as of December 31, 1997 assumes that the Acquisitions and the Offering
were consummated on December 31, 1997. The adjustments contained in the
unaudited pro forma statement of operations do not give effect to any
nonrecurring costs directly associated with the Acquisitions that might be
incurred within the next twelve months. The unaudited pro forma statement of
operations also does not give effect to any potential cost savings and synergies
that could result from the Acquisitions such as those described under "Certain
Transactions." The unaudited pro forma financial statements have been prepared
for informational purposes only and are not necessarily indicative of the actual
or future results of operations or financial condition that would have been
achieved had the Acquisitions and the Offering occurred at the dates assumed.
The unaudited pro forma financial statements should be read in conjunction with
the historical combined financial statements of the Partnerships and related
notes thereto included elsewhere in this Prospectus.
29
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1997
Pro Forma
-----------------------------
NE LP
As Adjusted
for the
Acquisition Acquisitions
Partnerships and Offering and the
Historical Adjustments Offering
------------- ------------ ------------
(In Thousands of Dollars)
Revenue:
Power sales to utilities(1)......... $ 307,530 -- $ 307,530
Steam sales......................... 4,624 -- 4,624
--------- -------- ---------
Total revenue............... 312,154 -- 312,154
--------- -------- ---------
Costs and expenses:
Cost of power and steam sales....... 151,476 (20,846)(A) 130,630
Operation and maintenance........... 25,689 (4,687)(B) 21,002
Depreciation and amortization....... 24,992 47,074 (C) 72,066
General and administrative expenses. 15,984 (1,060)(D) 14,924
--------- -------- ---------
Total costs and expenses.... 218,141 (20,481) 238,622
--------- -------- ---------
Operating income............ 94,013 (20,481) 73,532
--------- -------- ---------
Other (income) expenses:
Amortization of financing costs..... 2,163 (2,163)(E) --
Non-capitalizable acquisition costs. -- 273 (F) 273
Interest expense.................... 47,673 18,183 (G) 65,856
Interest expense on Energy Bank
balances............................ 17,435 -- 17,435
Interest income..................... (9,931) 7,123 (H) (2,808)
---------- -------- ---------
Total other expenses............. 57,340 23,416 80,756
--------- -------- ---------
Net income (loss)................ $ 36,673 $(43,897) $ (7,224)
========= ======== =========
- ----------
(1) Power sales to utilities are net of change in Energy Bank principal
balance. Energy Bank principal balances represent cumulative payments
made to the Partnerships by Power Purchasers under certain Power
Purchase Agreements in excess of rates specified or scheduled in such
agreements. Under the terms of these agreements, such excess
constitutes a liability of the applicable Partnership to the applicable
Power Purchaser, which will be reduced by subsequent sales of electric
power to such Power Purchaser to the extent in later periods that the
scheduled or specified rate has risen above the contract rate, and must
be repaid under certain circumstances in cash.
(A) To reflect the amortization of the purchase price, including acquisition
costs, allocated to the above market fuel contracts over 16 years.
(B) To reflect the amortization of the purchase price, including acquisition
costs, allocated to the above market O&M contracts over 4 years.
(C) To reflect the depreciation and amortization of the purchase price,
including acquisition costs, allocated to the property, plant and equipment
over 34 years and to the Power Purchase Agreements over the remaining
respective contract periods, respectively.
(D) To remove the effect of the pre-paid heat rate bonus reflected on the
Partnerships' books pursuant to application of purchase accounting.
(E) To remove the amortization of financing costs reflected on the
Partnerships' books pursuant to application of purchase accounting.
(F) To reflect non-capitalizable acquisition costs pursuant to the application
of purchase accounting.
(G) To reflect the interest expense associated with the Note payable to ESI
Tractebel Acquisition of $220,000,000 at an assumed interest rate of 7.99%
and amortization of debt issuance costs of $6,663,300 over 14 years, using
the effective interest method.
(H) To remove the interest income associated with the release of the cash and
investments from the Debt Service Reserve Fund and the Energy Bank Cash
Collateral Proceeds upon completion of the Acquisitions.
30
UNAUDITED PRO FORMA BALANCE SHEET
AS OF DECEMBER 31, 1997
Pro Forma
-------------------------------
NE LP
Acquisition As Adjusted for
Partnerships and Offering the Acquisitions
Historical Adjustments and the Offering
------------ ------------ ----------------
(In Thousands of Dollars)
Current assets
Cash and cash equivalents............ $ 61,203 $ (33,270)(A) $ 27,933
Accounts receivable.................. 34,036 -- 34,036
Fuel inventories..................... 4,752 -- 4,752
Prepaid expenses and other current
assets.............................. 3,052 (2,495)(B) 557
--------- --------- ----------
Total current assets.............. 103,043 (35,765) 67,278
--------- --------- ----------
Other assets
Restricted cash...................... 69,156 (69,156)(C) --
Power purchase agreements............ -- 888,756 (D) 888,756
Unamortized financing costs.......... 15,674 (15,674)(E) --
Debt issue costs..................... -- 6,663 (F) 6,663
Other assets......................... 4,193 (4,008)(G) 185
--------- --------- ----------
Total other assets................ 89,023 806,581 895,604
--------- --------- ----------
Property, plant and equipment, net..... 349,365 166,499 (H) 515,864
--------- --------- ----------
Total assets........................... $ 541,431 $ 937,315 $1,478,746
========= ========= ==========
Current liabilities
Accounts payable and other accrued
liabilities......................... $ 16,876 $ -- $ 16,876
Current portion of loans payable..... 21,563 -- 21,563
Future obligations under interest
rate swap agreements................ 889 -- 889
--------- --------- ----------
Total current liabilities.............. 39,328 -- 39,328
--------- --------- ----------
O&M/Fuel contract obligations.......... -- 352,293 (I) 352,293
--------- --------- ----------
Long-term debt
Loans payable -- ESI Tractebel
Acquisition......................... -- 220,000 (J) 220,000
Loans payable -- ESI Tractebel
Funding Corp........................ 468,724 -- 468,724
Energy Bank liability................ 230,565 (58,984)(K) 171,581
--------- --------- ----------
Total long-term debt................... 699,289 161,016 860,305
--------- --------- ----------
Partners' (deficit) equity............. (197,186) 741,991 (L) 226,820
(104,921)(M)
(213,064)(N)
--------- --------- ----------
Total liabilities and partners' equity. $ 541,431 $ 937,315 $1,478,746
========= ========= ==========
- ---------
(A) To reflect the reduction in cash for the withdrawal of the Debt Service
Reserve Fund ($33.270 million).
(B) To reflect the reduction in interest receivable pursuant to adjustment (C).
(C) To reflect the reduction in restricted cash for the withdrawal of the
Energy Bank Cash Collateral Proceeds.
(D) To reflect the allocation of the purchase price, including acquisition
costs, to above-market Power Purchase Agreements.
(E) To reflect the removal of unamortized financing costs from the
pre-acquisition balance sheets.
(F) To reflect estimated debt issuance costs of the Offering.
(G) To remove the effect from the balance sheet of the pre-paid heat rate bonus
reflected on the pre-acquisition balance sheet.
(H) To allocate the remainder of the purchase price, including acquisition
costs to property, plant and equipment.
(I) To reflect the allocation of the purchase price, including acquisition
costs, to above-market fuel and O&M contracts.
(J) To reflect the issuance of the Securities in the Offering.
(K) To reflect the revaluation of the Energy Bank balances in connection with
purchase accounting.
31
(L) To eliminate the historical Partners' deficit and to adjust Partners'
equity to reflect the acquisition price of $544.805 million, including
$10.363 million of reimbursable capitalizable costs.
(M) To reflect the reduction in equity associated with the distributions to the
Partners pursuant to adjustments (A), (B) and (C).
(N) To reflect the reduction in equity associated with the reimbursement to the
Partners of NE LP upon receipt of the proceeds of the Offering ($220
million), net of certain expenses of the Offering (estimated to be
$6,663,300) and non-capitalizable acquisition costs (estimated to be
$273,000).
32
SELECTED HISTORICAL COMBINED FINANCIAL DATA
The selected historical combined financial data set forth below as of
December 31, 1996 and 1997 and for the years ended December 31, 1995, 1996 and
1997 are derived from the Partnerships' combined financial statements included
elsewhere in this Prospectus, which have been audited by Price Waterhouse, LLP,
independent accountants. The selected historical combined financial data set
forth below as of December 31, 1993, 1994 and 1995 and for the years ended
December 31, 1993 and 1994 are derived from the Partnerships' audited combined
financial statements not included in this Prospectus. This data should be read
in conjunction with, and is qualified by reference to, the Partnerships' audited
combined financial statements and related notes thereto included elsewhere in
this Prospectus, and "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
33
Years Ended December 31,
-------------------------------------------------------
1993(2) 1994 1995 1996 1997
--------- -------- -------- -------- --------
(In thousands)
Statement Of Operations Data:
Revenue:
Power sales to utilities net of
Energy Bank changes(1)........... $234,142 $234,933 $276,022 $267,789 $307,530
Steam sales........................ 4,684 3,779 4,527 4,473 4,624
-------- -------- -------- -------- --------
Total revenue................ 238,826 238,712 280,549 272,262 312,154
-------- -------- -------- -------- --------
Costs and expenses:
Cost of power and steam sales...... 132,580 128,402 132,839 138,727 151,476
Operation and maintenance.......... 20,283 20,808 24,699 22,854 25,689
Depreciation....................... 24,919 24,314 24,904 24,978 24,992
General and administrative expenses 14,162 11,012 12,010 14,424 15,984
-------- -------- -------- -------- --------
Total operating costs and
expenses................... 191,944 184,536 194,452 200,983 218,141
-------- -------- -------- -------- --------
Operating income............. 46,882 54,176 86,097 71,279 94,013
-------- -------- -------- -------- --------
Other (income) expenses:
Amortization of financing costs.... 2,599 2,333 2,305 2,373 2,163
Interest expense................... 38,992 38,068 50,930 49,841 47,673
Interest expense on Energy Bank
balances......................... 7,252 11,676 16,657 19,675 17,435
Interest income.................... (700) (1,656) (10,652) (10,534) (9,931)
Expense related to
future obligations under
interest rate swap
agreements(3).................... -- 6,734 -- -- --
-------- -------- -------- -------- --------
Total other expenses......... 48,143 57,155 59,240 61,355 57,340
-------- -------- -------- -------- --------
(Loss) income before
extraordinary item...... (1,261) (2,979) 26,857 9,924 36,673
Extraordinary item:
Loss on extinguishment of debt(3).. -- 13,937 -- -- --
-------- -------- -------- -------- --------
Net income (loss)............ $ (1,261) $(16,916) $ 26,857 $ 9,924 $ 36,673
======== ======== ======== ======== ========
Distributions to partners............ $ 10,878 $ 27,472 $ 64,506 $ 66,826 $ 46,380
Ratio of earnings to fixed
charges (4)...................... -- -- 1.38 1.18 1.70
As of December 31,
-------------------------------------------------------
1993(2) 1994 1995 1996 1997
--------- -------- --------- -------- --------
(In thousands)
Balance Sheet Data:
Working capital...................... $ 19,754 $ 74,145 $ 71,975 $ 58,846 $ 63,715
Total assets......................... 546,484 650,027 617,034 566,392 541,431
Total loans payable.................. 465,458 560,000 539,566 514,362 490,287
Energy Bank balances(1).............. 111,398 155,496 188,053 220,922 230,565
Partners' deficit.................... (48,540) (92,928) (130,577) (187,479) (197,186)
- ----------
(1) Energy Bank balances represent cumulative payments made to the
Partnerships by Power Purchasers in excess of projected scheduled
estimates of cumulative Avoided Costs specified in certain Power
Purchase Agreements. Under the terms of these agreements, such excess
constitutes a liability of the applicable Partnership to the applicable
Power Purchaser, which is expected to be reduced over future years as
cumulative Avoided Costs eventually rise above cumulative payments. See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations -- General."
(2) Certain reclassifications have been made to the 1993 financial statements
to conform with the 1994, 1995, 1996 and 1997 presentation. These
reclassifications had no effect on net income for 1993.
(3) As a result of the Partnerships' refinancing of the Original Project
Indenture on November 15, 1994, the Partnerships' Swaps no longer
qualified as hedges and therefore, the fair value of these swaps, $6.7
million was charged to the statement of operations. In addition, as a
result of the refinancing, unamortized debt issuance costs of $13.9
million, associated with the Original Project Indenture, were charged
to the statement of operations.
(4) The ratio of earnings to fixed charges is determined by dividing the sum of
pre-tax income (net income) and fixed charges (consisting of interest
expense, amortization of debt issue costs, the estimated interest component
of rent expense and equipment rentals) by fixed charges. The earnings for
1993, 1994 and pro forma 1997 were inadequate to cover fixed charges. The
coverage deficiencies during 1993, 1994 and pro forma 1997 are $1.261
million, $2.979 million and $7.224 million, respectively.
34
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion relates to the financial condition and results
of operations of the Partnerships, not of the Partners. The Partners were formed
at the end of 1997 and have no significant assets other than their interests in
the Partnerships. The financial statements for periods prior to the Acquisition
Date are not necessarily comparable to or indicative of results for any period
following the Acquisitions. See "Use of Proceeds," "Unaudited Pro Forma
Financial Statements," "Selected Historical Combined Financial Data," and the
Partnerships' audited combined financial statements and notes thereto included
elsewhere in this Prospectus.
General
The Partnerships commenced commercial operations in the second half of
1991. The Partnerships' consolidated revenues are derived from, and costs are
incurred in connection with, the generation and sale of electricity and, to a
much lesser extent, the production and sale of thermal energy (steam).
Revenue from sales of electricity is recognized based on electricity
delivered at rates stipulated in the Power Purchase Agreements, except that
revenue recognition is deferred to the extent that such rates are in excess of
rates scheduled or specified in such agreements above which payment is subject
to recovery by certain of the Power Purchasers under certain circumstances. The
portion subject to deferred revenue recognition, which is referred to as the
"Energy Bank," is recorded as a liability of the applicable Partnership for
financial statement purposes. See "The Projects -- Power Purchase Agreements."
The capitalized costs of the Projects include initial acquisition
costs, increased by subsequent development and construction costs, including
test period operations, construction management fees and interest during
construction. The capitalization period ceased when construction of each Project
was complete and satisfactorily tested. Capitalized costs are depreciated over
the estimated useful life of each Project. Costs incurred during the development
and construction period that were not directly related and incremental to
project development and construction were expensed in the period incurred.
The Acquisitions
The Partners acquired all of the partnership interests in each of the
Partnerships on January 14, 1998, pursuant to the Purchase Agreement. In
connection with the acquisition of all of the partnership interests in the
Partnerships, ESI Funding and Tractebel Power each acquired a thirty-seven and
one-half percent (37.5%) interest in ESI Tractebel Funding. The partners paid
the purchase price for all of the Partnership interests in the Partnerships and
for seventy-five percent (75%) of the outstanding shares of capital stock in ESI
Tractebel Funding from contributions made by each of ESI GP, Tractebel GP, ESI
LP and Tractebel LP, the partners of NE LP. The Acquisitions were accounted for
under the purchase method; accordingly, the carrying value of the assets
acquired and liabilities assumed of the Partnerships were adjusted based upon
the final purchase price allocation, including an allocation to above-market
power purchase contracts.
Results of Operations
The following table sets forth the combined results of the
Partnerships' operations and the percentage of gross operating revenues and
receipts represented by certain components of operating costs and income for the
three years ended December 31, 1997.
35
Years Ended December 31,
-------------------------------------------------------------
1995 1996 1997
------------------- ------------------ -------------------
Gross operating revenues and
receipts(1)................... $ 296,449 100% $ 285,456 100% $ 304,363 100%
Operating costs................. 157,538 53% 161,581 57% 177,165 58%
Depreciation.................... 24,904 8% 24,978 9% 24,992 8%
General and administrative...... 12,010 4% 14,424 5% 15,984 5%
--------- --------- ---------
Operating income plus Energy Bank
accruals(1)................... 101,997 34% 84,473 30% 86,222 29%
--------- --------- ---------
Amortization of financing costs. 2,305 1% 2,373 1% 2,163 1%
Interest expense(2)............. 50,930 17% 49,841 17% 47,673 16%
Interest income................. (10,652) (4%) (10,534) (4%) (9,931) (3%)
--------- --------- ---------
Net income (loss) plus Energy
Bank Accruals and interest
thereon....................... $ 59,414 $ 42,793 $ 46,317
========= ========= =========
- ----------
(1) Gross operating revenue and receipts represents total revenues plus (less),
as applicable, annual change in Energy Bank principal balances.
(2) Interest expense excludes interest on Energy Bank principal balances.
Calendar Year 1997 Compared to Calendar Year 1996
Gross Operating Revenue and Receipts. Gross operating revenue and
receipts for the year ended December 31, 1997 of $304.4 million increased by
$18.9 million (6.6%) as compared to the year ended December 31, 1996. This
increase was primarily due to higher generation and increased prices. The
increase in generation was primarily a result of no scheduled major maintenance
outages at the NEA Project (during the second quarter of 1996 a major inspection
and maintenance program, scheduled at five year intervals, was conducted at the
NEA Project) and fewer curtailment hours requested by JCP&L.
Operating Costs. Cost of power and steam sales was $151.5 million, or
49.8% of gross operating revenue and receipts for the year ended December 31,
1997 as compared to $138.7 million, or 48.6% of gross operating revenues and
receipts for the year ended December 31, 1996. The increased cost is primarily
due to price increases under a fuel supply contract that services both
facilities. Partially offsetting the increase in natural gas prices was a
reduction in extended gas services rights exercised by a NJEA fuel supplier
during the first quarter of 1997 as compared to 1996.
Operation and maintenance (O&M) costs increased $2.8 million (12.4%) as
compared to the same period in 1996. The primary cause of the increased cost was
the performance bonus (which is directly related to higher generation) payable
to the Operator under the NEA O&M Agreement. Escalation of the O&M Agreement of
approximately 4% also contributed to the increased costs.
General and Administrative Expenses. General and administrative
expenses for the year ended December 31, 1997 increased $1.6 million or 11% as
compared to the year ended December 31, 1996. The primary cause for this
increase was the write-off of approximately $1.5 million in accounts receivable.
Other increases included annual escalation of management fees as well as
increased consulting and overhead costs.
Interest Expenses and Interest Income. Interest expense for the year
ended December 31, 1997 decreased $2.1 million, or 4.3% as compared to the year
ended December 31, 1996. Interest on debt decreased as a result of declining
principal balances. Principal payments on Project Securities are made
semiannually on June 30 and December 30. During the year ended December 31,
1997, the Partnerships' average amount of debt outstanding was $508.3 million at
an average rate of 9.31%. During 1996, the Partnerships average amount of debt
outstanding was $533.3 million at an average rate of 9.26%. These decreases were
a result of changes in the underlying amounts accrued for Energy Bank balances.
Interest income during the year ended December 31, 1997 totaled approximately
36
$9.9 million as compared to approximately $10.5 million during the year ended
December 31, 1996, decreasing $.6 million. As discussed below, interest income
is expected to decrease materially beginning in 1998.
Calendar Year 1996 Compared to Calendar Year 1995
Gross Operating Revenues and Receipts. Gross operating revenues and
receipts for the year ended December 31, 1996 of $285.5 million decreased by
$11.0 million (3.7%) as compared to the year ended December 31, 1995. This
decrease was primarily due to lower availability as a result of scheduled
maintenance outages. Availability was approximately 91% in 1996 versus
approximately 95% in 1995. During the second quarter of 1996 a major inspection
and maintenance program (scheduled at five-year intervals) took place at the NEA
Project. During the fourth quarter of 1996 a scheduled overhaul and inspection
took place at the NJEA Project. Power purchase rates, on a combined basis,
increased slightly over the prior year.
Operating Costs. Cost of power and steam sales was $138.7 million, or
48.6% of gross operating revenues and receipts for the year ended December 31,
1996 as compared to $132.8 million, or 44.8% of gross operating revenues and
receipts in the prior year. The increased costs were primarily attributable to
increases in fuel costs, including higher market prices of Spot Gas and
additional charges applicable under NJEA's extended gas service arrangement with
a fuel supplier. Extended gas service occurs when temperatures are below 22
degrees F. There were sixteen such days during the first quarter of 1996
compared with four days in the first quarter of 1995. A portion of these
increases was offset by gains on natural gas swap agreements (which were entered
into in an attempt to limit exposure to market price fluctuations).
Operation and maintenance expenses in 1996 decreased by $1.8 million
(7.5%) as compared to 1995. This decrease was a result of a lower performance
bonus payable to the Operator in 1996 as a result of scheduled maintenance
outages and a 1995 water franchise fee. Offsetting these cost decreases were
normal and expected escalations under the O&M Agreements.
General and Administrative Expenses. General and administrative
expenses in 1996 increased by $2.4 million (20.1%) as compared to 1995. The
increase was primarily due to increased management costs, insurance premiums and
legal and consulting costs related to potential industry restructuring.
Interest Expense and Interest Income. Interest expense for the year
ended December 31, 1996 decreased by $1.1 million (2.1%) as compared to the year
ended December 31, 1995. During 1995, the Partnerships' average amount of debt
outstanding was $554.9 million at an average rate of 9.23%. During 1996, the
Partnerships' average amount of debt outstanding was $533.3 million at an
average rate of 9.26%. Interest income in 1996 totaled $10.5 million as compared
to $10.7 million in 1995. This decrease was primarily a result of reduced cash
collateral being held in support of letters of credit.
Year 2000
The Partnerships are working to resolve the potential impact of the
year 2000 on the processing of information by its computer systems. An
assessment of identified software, including vendor-supplied software, has been
completed and work has begun to make the necessary modifications. The estimated
cost of addressing year 2000 issues in software applications is not expected to
have a material adverse effect on the Partnership's financial statements. The
Partnerships continue to assess the potential financial and operational impacts
of computerized processes embedded in operating equipment.
37
Liquidity and Capital Resources
To date, the Partnerships have obtained cash from their operations and
from proceeds of nonrecourse project financing. The Partnerships have utilized
this cash to develop and construct the Projects and the Carbon Dioxide Plant,
service debt obligations, fund operations and fund distributions to partners.
As of December 31, 1997, the Partnerships' cash and cash equivalents
totaled approximately $61.2 million, as compared to $49.9 million at December
31, 1996. The increase in cash and cash equivalents was the net effect of $82.2
million provided by operations, offset by investing and financing activities,
including debt principal payments of $24.1 million and $46.4 million in
distributions to partners.
As of December 31, 1997, there were no outstanding loans under the
Sanwa Working Capital Facility. NE LP terminated the Sanwa Working Capital
Facility and the Sanwa Credit Agreement in February 1998. NE LP does not
anticipate the need to arrange for a new Working Capital Facility. Debt Service
Reserve Requirements were fully funded as of December 31, 1997.
Non-operating income for periods prior to the Acquisitions included
investment income received from the Cash Collateral Proceeds that secured the
Partnerships' obligations to Sanwa Bank under the Sanwa Credit Agreement and
investment income received from investments in the Debt Service Reserve Fund
held by the Project Trustee. As permitted under the Project Indenture, NE LP in
January 1998, arranged for the release of, and distributed to the Partners, cash
in the amount of $33,270,000 from the Debt Service Reserve Fund following the
issuance of Substitute Letters of Credit by BankBoston and Bank Brussels
Lambert. In February 1998, NE LP also arranged for the release of cash in the
amount of $69,156,000, plus interest receivable, constituting the Cash
Collateral Proceeds, following the issuance of the FPL Group Capital Guaranty.
Such cash was distributed to the Partners upon its release. As a result, NE LP
expects that the Partnerships' investment income will be materially reduced in
future years.
Working Capital Facility. The Project Indenture permits the
Partnerships to enter into revolving credit arrangements from time to time with
financial institutions with maximum available borrowings of up to $20 million to
provide for the working capital requirements of the Partnerships (the "Working
Capital Facility"). Pursuant to the Sanwa Credit Agreement, the Partnerships
entered into the Sanwa Working Capital Facility, which provided for maximum
available borrowings of up to $15 million subject to a borrowing base calculated
based on outstanding receivables and fuel. The Sellers have advised NE LP that
the Working Capital Facility has never been utilized. In February 1998, NE LP
terminated the Working Capital Facility and the Sanwa Credit Agreement and does
not anticipate the need to arrange for a new Working Capital Facility. See
"Summary."
Project Letter of Credit Facility. The Partnerships are required by the
terms of certain of the Power Purchase Agreements to provide the letters of
credit to the Power Purchasers thereunder to support the Partnerships' Energy
Bank Obligations. See "Summary of Principal Project Agreements -- Power Purchase
Agreements." Under the Project Indenture, the Partnerships have agreed to
provide such Energy Bank Letters of Credit and to secure the Partnerships'
obligations to reimburse the Project Letter of Credit Banks with cash
collateral, one or more back-up letters of credit (each a "Back-up Letter of
Credit") and/or a FPL Group Capital Guaranty. NE LP's obligation to reimburse
FPL Group Capital for any of the amount paid by FPL Group Capital Guaranty is
subject to the prior payment of any amounts payable under the Indenture in
respect of the Securities. In addition, the Partnerships may require letters of
credit for certain other purposes in the ordinary course of business.
38
Pursuant to the Sanwa Credit Agreement, Sanwa Bank delivered the
Project Letters of Credit in an aggregate amount up to $82,000,000 for the
purpose of supporting the Partnerships' Energy Bank Obligations and for certain
other purposes. The aggregate amount of Energy Bank Letters of Credit issued and
outstanding as of December 31, 1997 was $67,656,000. In February 1998, NE LP
arranged for the delivery of letters of credit of BankBoston and NationsBank in
face amounts of $12.656 million and $54.0 million, respectively, in substitution
for the letters of credit of Sanwa Bank and terminated the Sanwa Credit
Agreement and the Sanwa Letters of Credit.
Swaps. In connection with the initial variable-rate financing of the
Projects under the Original Project Credit Agreement, the Partnerships entered
into certain interest rate swap agreements (the "Swaps") with certain financial
institutions (the "Swap Banks"), providing for payments thereunder on a notional
principal amount of indebtedness to be made by the Partnerships at fixed
interest rates in exchange for payments to be made by the Swap Banks at floating
interest rates.
Such Swaps remained in effect after the issuance of the fixed-rate
Project Securities. In connection with the issuance of the Project Securities,
the Partnerships entered into counter swap agreements to hedge the obligations
of the Partnerships under such existing Swaps. As a result of the foregoing
arrangements, after giving effect to the net payments to be made and received by
the Partnerships pursuant to all of the Swaps (including the counter swaps), the
Partnerships' net payments are equivalent to a fixed net interest rate of
approximately 1.8% on the specified notional principal amount, which is
scheduled to decline periodically until the scheduled expiration of the Swaps in
1999. After giving effect to the counter swaps, the Partnerships' net payments
under the Swaps will total approximately $718,275 in 1998 and approximately
$195,535 in 1999 (the scheduled year of termination of the Swaps).
The following tables set forth the notional principal amount and
related fair value of the Swaps as of the dates shown together with the
additional interest incurred for the years ended December 31, 1995, 1996 and
1997.
December 31, 1995 December 31, 1996 December 31, 1997
----------------- ----------------- -----------------
Notional Amount............. $ 27,596,000 $ 20,335,000 $12,940,000
Fair value (liability)(1)... $ (3,654,000) $ (2,022,000) $ (889,000)
Net Effect of Swaps on
Interest Expense (2)...... $ (486,000) $ 137,000 $ 103,000
- ----------
(1) The estimated fair value of each existing Swap is the estimated amount
that the applicable Swap Bank would receive to terminate such Swap at
the respective dates, taking into account current interest rates and
the current creditworthiness of the Swap counter-parties.
(2) Represents the net effect of the Swaps on the interest expenses in the
statement of operations. The interest expense on the Swaps is reduced by
the change in the fair value of the Swaps.
Natural Gas Hedging Instruments
Approximately 20% of the fuel supply for the Projects must be provided
from sources other than the Long-term Gas Arrangements. To mitigate the price
risk associated with spot purchases of natural gas, the Partnerships may, from
time to time, enter into certain hedging transactions either through public
exchanges such as the NYMEX, or by means of over-the-counter transactions with
specific counterparties pursuant to the Fuel Management Agreements or otherwise.
These hedging transactions include (a) natural gas call options that give the
Partnerships the right, but not the obligation, to purchase specified quantities
of natural gas at a predetermined price, (b) gas purchase swap agreements that
require the Partnerships to pay a fixed price in return for a variable price on
a notional specified quantity of natural gas, and (c) forward purchases of
natural gas.
39
The effect of these transactions is to fix the price of natural gas
purchases made on the open market and, as such, these transactions have not had
a material effect on total fuel costs.
Seasonality
The performance of the Projects is dependent on ambient conditions
(principally air temperature, air pressure and humidity), which affect the
efficiency and capacity of the combustion turbines. Ambient conditions also
affect the steam turbine cycle efficiency of the Projects by affecting the
operation of the air cooled condenser, and, therefore, the steam turbine exhaust
back pressure. Payments due to NJEA under the JCP&L Power Purchase Agreement
during winter and summer peak-hour periods are substantially higher than those
in spring and fall. Otherwise, the business of the Partnerships is not
materially subject to seasonal factors.
Industry Deregulation
On November 25, 1997, the Massachusetts legislature passed a
comprehensive electric deregulation bill, the purpose of which is to establish a
comprehensive framework for the restructuring of the electric utility industry.
Additionally, industry restructuring efforts are also underway in New Jersey.
While the Partnerships do not expect electric utility industry restructuring to
result in material adverse changes to the Partnerships' Power Purchase
Agreements, the impact of electric utility industry restructuring on the
companies that purchase power from the Partnerships is uncertain. See
"Regulation -- Utility Industry Restructuring."
40
BUSINESS
General
ESI Tractebel Acquisition and ESI Tractebel Funding were created as
pass-through funding entities with no operations of their own.
The sole business of the two Partnerships is the ownership and
management of the Projects and, in the case of NEA, the ownership of the Carbon
Dioxide Plant. Each Partnership contracts to sell capacity and electrical energy
produced by its Project to electrical utility customers and in addition,
contracts for the sale of steam.
Independent Power Market
Utilities in the United States have been the predominant producers of
electric power intended primarily for sale to third parties since the early
1900s. In 1978, however, PURPA removed regulatory constraints relating to the
production and sale of electric energy by certain non-utility power producers
and required electric utilities to buy electricity from certain types of
non-utility power producers under certain conditions, thereby encouraging
companies other than electric utilities to enter the electric power production
market. Utilities are required to comply with state law guidelines and, in
general, are required to buy electricity from non-utility generators if there is
a need for such electricity and if it is priced at or below the utility's
avoided cost at the time of the agreements.
According to the Edison Electric Institute, as of December 31, 1996
non-utility generators represent approximately 8.4% of the United States'
installed capacity, accounting for approximately 12% of the total electric
generation in 1996. Between December 31, 1993 and December 31, 1996, non-utility
generators represented 52.3% of the new capacity added in the United States.
Competition in the non-utility power production market is not a material factor
in the Partnerships' operations, except as described in "Risk Factors --
Dependence Upon Third Parties" and as described below.
Electric utility systems that purchase a substantial portion of their
energy supply from non-utility generators under contracts that require purchases
of fixed or minimum quantities of energy have recently expressed an interest in
lowering consumer rates by extending their dispatch flexibility to include the
generating plants of their non-utility generators. Under this approach lower
fuel cost sources of energy would be drawn on before higher fuel cost sources.
General Public Utility's system, of which JCP&L is a part, has publicly
announced and is pursuing its Natural Gas Private Pooling Point Program in which
it would draw on its lower fuel cost sources of energy before drawing on higher
fuel cost sources. JCP&L has contacted NJEA regarding this program and has made
a presentation to NJEA regarding JCP&L's proposal to transform NJEA's must-run
contract into a dispatchable contract on terms that are to cover all fixed costs
(debt service and fixed operating expenses) and preserve current net profits
while allowing JCP&L to reduce its purchased power costs. JCP&L has reported to
New Jersey regulators that its above-market costs for power associated with the
NJEA Power Purchase Agreement will total $837.67 million during the remaining
life of the NJEA Power Purchase Agreement (present value of such amount recently
estimated by JCP&L to be approximately $509.44 million) and that it intends to
pursue its efforts to mitigate these costs.
In November 1997, legislation was enacted in Massachusetts requiring
electric companies and sellers under purchased-power contracts to make
good-faith efforts to renegotiate contracts that contain a price for electricity
that is above-market as of March 1, 1998. A good-faith effort under the Act does
not require accepting all proposals or making unlimited concessions but does
require the parties to show that they have actively participated in negotiations
41
and have shown a willingness to make reasonable concessions. See "Regulation --
Utility Industry Restructuring -- Massachusetts."
It is not possible to predict the outcomes of various regulatory
initiatives in connection with utility restructuring or changes that may be
requested by JCP&L or the NEA Power Purchasers. Except as provided in the
Project Indenture and the Indenture, any requested changes to the Power Purchase
Agreements would require the consents of NEA or NJEA, as applicable, and of a
majority of the holders of the Project Securities and of the Securities.
THE PROJECTS
General
The Projects are cogeneration facilities, designed to produce
sequentially both electricity and useful thermal energy in the form of steam by
means of an integrated process using a single fuel source. Both Projects are
fueled by natural gas, although under limited circumstances, the NEA Project may
also be operated with Number 2 fuel oil. Substantially all electricity produced
by the Projects is sold pursuant to six Power Purchase Agreements with four
regulated utilities. The Boston Edison II Power Purchase Agreement and the JCP&L
Power Purchase Agreement are scheduled to expire in September 2011 and August
2011, respectively, three months and four months prior to the final maturity
date of the Securities, subject to certain extension rights of the power
purchaser in the case of the JCP&L Power Purchase Agreement. Substantially all
of the steam produced by the Projects is sold pursuant to two Steam Sales
Agreements with two steam purchasers. NEA's Steam Sales Agreement with NECO is
scheduled to expire in June 2007, prior to the final maturity date of the
Securities, subject to NECO's extension rights. There are long-term contracts
for the purchase, transportation and storage of natural gas, although some of
such agreements are scheduled to expire prior to the final maturity date of the
Securities. See "Summary of Principal Project Agreements -- Power Purchase
Agreements, Steam Sales Agreements, Gas, Transportation and Storage Agreements."
The Projects were developed and are currently operated as QFs under
PURPA. The Projects must satisfy certain annual operating and efficiency
standards to maintain QF status, which exempts the Projects from certain federal
and state regulations. See "Regulation -- Energy Regulation."
The Projects were designed and constructed by Westinghouse Electric and
are currently being operated and maintained by Westinghouse Services, a
subsidiary of Westinghouse Electric, under the O&M Agreements, scheduled to
expire on September 15, 2001. On November 15, 1997, Westinghouse Electric
announced that it intended to sell all of its industrial businesses, including
the business of Westinghouse Services, to Siemens AG. Pursuant to the New O&M
Agreements entered into by NE LP and the New Operator, a direct wholly-owned
subsidiary of ESI Energy, and assigned by NE LP to the Partnerships, the New
Operator has agreed to operate and maintain the Projects following the
expiration or early termination of the O&M Agreements and prior to such date, to
provide certain transition services. The New Operator operates eight power
projects and will soon operate a ninth power project, totaling 1,367 MW (743 MW
of which are gas-powered projects), located in California, South Carolina
(currently under construction), Virginia and Nevada.
For descriptions of the O&M Agreements and the New O&M Agreements, see
"Summary of Principal Project Agreements -- Operations and Maintenance
Agreements" and for a description of some of the savings NE LP expects the
Partnerships to realize during the term of the New O&M Agreements, see "Certain
Transactions."
42
The NEA Project
Project Description. The NEA Project began commercial operation in
September 1991, and consists of a nominal 300 MW gas-fired cogeneration
facility, which is designed to produce approximately 287 MW of electricity, net
of electrical power consumed at the NEA Site and the Carbon Dioxide Plant, while
exporting between 60,000 and 70,000 pounds per hour of steam. Westinghouse
Services is currently operating and maintaining the NEA Project. Pursuant to the
New NEA O&M Agreement, the New Operator is providing certain services for the
NEA Project and has agreed to replace Westinghouse Services as the operator of
the NEA Project upon the expiration or early termination of the NEA O&M
Agreement. The NEA Project is certified as a QF under PURPA and is exempt from
rate regulation as an electric utility under federal and state law, provided
that the NEA Project continues to meet the applicable requirements of PURPA. See
"Regulation -- Energy Regulation."
The NEA Project is powered by two Westinghouse W501D5 combustion
turbine generators, each fitted with a heat recovery steam generator ("HRSG")
that produces steam that drives a steam turbine generator. This steam turbine
generator produces additional electricity, as described below, and supplies
steam to the Carbon Dioxide Plant. Project steam is also used to control nitrous
oxide emissions from the NEA Project. The NEA Project is designed to permit
flexible operation, including the production of both electricity and sufficient
steam to meet QF requirements, using either one or both of the combustion
turbine generators, with or without the one steam turbine generator.
The combustion and steam turbines and their associated auxiliary
equipment are located within a single building. Other project facilities include
mechanical and electrical auxiliaries, a 2.3 million gallon back-up fuel oil
storage tank with spill prevention and fire protection, air cooled condensers,
export steam distribution and condensate return lines, a "zero discharge"
wastewater treatment system that collects and treats all process aqueous wastes
and recycles all water for process use, cooling systems, a continuous emission
monitoring system, other instrumentation and control equipment and office space.
The combustion turbines use natural gas as their primary fuel and, subject to
the limitations contained in the NEA Project's air quality permit, can use
Number 2 fuel oil as a back-up fuel. The NEA Project has an air quality permit
allowing it to burn Number 2 fuel oil for up to 1,440 turbine hours each year in
the event of certain curtailments in the gas supplies for the NEA Project.
The NEA Power Purchase Agreements provide for the purchase by Boston
Edison, Commonwealth and Montaup of all the net electric power currently
produced by the NEA Project. Approximately 11 MW of the NEA Project's electric
power is consumed at the NEA Site and at the Carbon Dioxide Plant. NE LP's
Projections include an assumption that NEA will be able to arrange approximately
10 MW of additional power sales at market prices beginning in 1999. See "Risk
Factors -- Expiration of Certain Power Purchase Agreements; Merchant Sales."
The Carbon Dioxide Plant is adjacent to the NEA Project. The Carbon
Dioxide Plant is owned by NEA and is leased to NECO for an initial 15-year term
that expires on June 1, 2007, subject to certain rights of NECO to extend the
term. Fluor Daniel Inc. ("Fluor Daniel") designed and built the Carbon Dioxide
Plant, and Westinghouse Services currently operates the Carbon Dioxide Plant for
NECO. The Carbon Dioxide Plant uses technology developed by Dow Chemical Company
and acquired by Fluor Daniel to extract carbon dioxide from approximately 15% of
the NEA Project's exhaust flue gas and is designed to produce up to 350 tons per
day of food-grade carbon dioxide at an ambient temperature of 75 degrees F.
Approximately 60,000 to 70,000 pounds per hour of steam supplied by the NEA
Project is used by the Carbon Dioxide Plant in the carbon dioxide production
process. NECO produces food-grade carbon dioxide for a variety of uses,
including carbonated beverages and dry ice for food handling.
43
Site. The NEA Project and the Carbon Dioxide Plant are located on an
industrially zoned 44-acre site in the town of Bellingham, Massachusetts (the
"NEA Site"). The NEA Site is located on the upper Charles River and is
accessible from Interstate Route 495 and by a railroad line belonging to
Consolidated Rail Corporation ("Conrail"). The NEA Project is interconnected to
Boston Edison's Medway Substation, which is located on a 345 kV power line
collectively owned by Boston Edison, Commonwealth and Northeast Utilities. The
Algonquin Gas Transmission Company's ("Algonquin") gas pipeline runs within the
site boundary. Railroad service can be supplied by a connection to an existing
Conrail line that accesses the NEA Site.
Water is supplied from two wells on the NEA Site and by three wells
located on land owned by the Town of Bellingham within one-half mile of the NEA
Site. Water is delivered to the NEA Site by a dedicated pipeline that runs
directly from the wells to the NEA Project and the Carbon Dioxide Plant. A 2.5
million gallon water storage tank is located at the NEA Site to be used as a
buffer supply, and a 1.0 million gallon raw water tank contains a 360,000 gallon
standpipe that provides a dedicated fire protection supply.
Fuel oil is stored on the NEA Site in a single 2.3 million gallon tank
with spill-prevention protection and ancillary loading and unloading facilities.
Operating History. During the year ended December 31, 1997, the NEA
Project produced an average of approximately 309 MW (net) of electrical energy
and 62.144 pounds per hour of steam. Since the commencement of commercial
operation in September 1991, the NEA Project has exceeded its electrical output
guarantee (which includes a guarantee of availability) and fuel efficiency
guarantee under the NEA O&M Agreement. The NEA Project's operating history for
the 1993-1997 calendar years are summarized below.
NEA Project
Calendar Year
----------------------------------------------
1993 1994 1995 1996 1997
----- ----- ----- ----- -----
Total Power Produced
(GWh)....................... 2,484 2,483 2,595 2,518 2,641
Net Plant Heat Rate
(Btu/kWh)................... 8,289 8,297 8,336 8,251 8,299
Total Steam Produced (MM
lbs.)(1).................... 535 492 568 533 544
Equivalent Availability
Factor(2)................... 93.7% 91.2% 95.5% 91.6% 96.2%
Curtailment................... 1.2% 2.3% 1.4% 1.3% 1.2%
- ----------
Source: Independent Engineer's Report except as noted below.
(1) Source: NEA records.
(2) The average number of equivalent hours that the NEA Project was
available to run at approximately 290 MW, as a percentage of the total
number of hours in the year, without taking into account curtailment
hours.
For a detailed discussion of the NEA Project's operating history and
prospects and for a description of the condition and maintenance requirements of
the NEA Project, see "Appendix B -- Independent Engineer's Report." Gas supply
and transportation and storage arrangements are described in "Appendix C --Fuel
Consultant's Report."
44
The NJEA Project
Project Description. The NJEA Project began commercial operations in
August 1991, and consists of a nominal 300 MW gas-fired cogeneration facility
that was designed to produce approximately 287 MW (net) of electricity while
exporting between 200,000 and 210,000 pounds per hour of steam. The NJEA Project
is designed so that a reduction in the export of steam would raise the
production of electricity; the NJEA Project generally exports an average of
125,000 pounds of steam per hour, and exports at that level result in increased
electric capacity of approximately 35 MW. Westinghouse Services is currently
operating and maintaining the NJEA Project. Pursuant to the New NJEA O&M
Agreement, the New Operator is providing certain services for the NJEA Project
and has agreed to replace Westinghouse Services as the operator of the NJEA
Project following the expiration or early termination of the NJEA O&M Agreement.
The NJEA Project is certified as a QF under PURPA and is exempt from rate
regulation as an electric utility under federal and state law, provided that the
NJEA Project continues to meet the applicable requirements of PURPA. See
"Regulation -- Energy Regulation."
Like the NEA Project, the NJEA Project is powered by two Westinghouse
W501D5 combustion turbine generators, each fitted with an HRSG that produces
steam which drives a steam turbine generator. This steam turbine generator
produces additional electricity, as described below, and supplies steam to
Hercules, the steam host. Project steam is also used to control nitrous oxide
emissions from the NJEA Project. The NJEA Project is designed to permit flexible
operation, including the production of both electricity and sufficient steam to
meet QF requirements, using either one or both of the combustion turbine
generators, with or without the one steam turbine generator.
The combustion and steam turbines and their associated auxiliary
equipment are located within a single building. Other project facilities include
mechanical and electrical auxiliaries, air cooled condensers, export steam
distribution and make up water return lines, cooling systems, a continuous
emission monitoring system, other instrumentation and control equipment and
office space. The combustion turbines use only natural gas as fuel.
NJEA sells to JCP&L approximately 252 MW of the NJEA Project's baseload
power. Approximately 5.5 MW of the NJEA Project's electric power is consumed at
the NJEA Site. Although NE LP expects to find purchasers for the additional 35
MW (subject to a right of recall by JCP&L), to date none of such additional
capacity has been sold by NJEA. See "Risk Factors -- Expiration of Certain Power
Purchase Agreements; Merchant Sales."
Steam generated by the NJEA Project is supplied to Hercules for use in
its Parlin, New Jersey facility in the production of smokeless and soluble
nitrocellulose as well as natrosol. Smokeless nitrocellulose is used in the
production of ammunition, soluble nitrocellulose is used in the manufacture of
coatings, and natrosol is used as a viscosity agent in water soluble polymers.
Site. The NJEA Project is located on an industrially zoned 49-acre site
in the Borough of Sayreville, New Jersey (the "NJEA Site"). The NJEA Site is
accessible from the Garden State Parkway and by a railroad line belonging to
Conrail. A natural gas pipeline owned by Transcontinental Gas Pipe Line
Corporation ("Transco") runs within 200 yards of the site boundary, and natural
gas is transported from the Transco pipeline to the NJEA Project through a
pipeline owned by PSE&G. The site is interconnected through a one-mile power
line to a 230kV power line owned by JCP&L.
Pursuant to a ground lease dated as of June 28, 1989, the NJEA Site has
been leased to IEC Urban Renewal Corporation ("IECURC"), a direct wholly-owned
subsidiary of NJEA. IECURC has leased back the NJEA Site to NJEA pursuant to a
sublease dated as of June 28, 1989.
45
Water is supplied from the municipal water system by a pipeline from
the road, and raw water in an amount equal to 115% of the steam delivered to
Hercules is supplied by Hercules to the NJEA Project from a nearby private water
supply owned by Dubernal Water Company. A 1.0 million gallon water storage tank
containing a 360,000 gallon standpipe provides a dedicated fire protection
supply.
Operating History. During the year ended December 31, 1997, the NJEA
Project produced an average of approximately 253 MW of electrical energy and
exported an average of 123.636 pounds per hour of steam. Since the commencement
of commercial operation in August 1991, the NJEA Project has exceeded its
electrical output guarantee (which includes a guarantee of availability) and
fuel efficiency guarantee under the NJEA O&M Agreement. The NJEA Project's
operating history for the 1993-1997 calendar years are summarized below.
NJEA PROJECT
Calendar Year
----------------------------------------------
1993 1994 1995 1996 1997
----- ----- ----- ----- ----
Total Power Produced
(GWh)....................... 2,005 1,830 2,104 2,019 2,026
Net Plant Heat Rate
(Btu/kWh)................... 9,078 8,884 9,066 9,073 8,954
Total Steam Produced (MM
Lbs.)(1).................... 1,108 823 1,013 1,039 1,083
Equivalent Availability
Factor(2)................... 91.1% 83% 94% 91% 91.6%
Curtailment................... 2.3% 3.8% 2.9% 3.8% 3.1%
- ----------
Source: Independent Engineer's Report.
(1) Source: NJEA records.
(2) The number of equivalent hours that the NEA Project was available to
run at approximately 250 MW, as a percentage of the total number of
hours in the year, without taking into account curtailment hours.
For a detailed discussion of the NJEA Project's operating history and
prospects and for a description of the condition and maintenance requirements of
the NJEA Project, see "Appendix B -- Independent Engineer's Report." Gas supply
and transportation and storage arrangements are described in "Appendix C -- Fuel
Consultant's Report."
Power Purchase Agreements
NEA's primary sources of revenue are five Power Purchase Agreements
with Boston Edison, Commonwealth and Montaup. NJEA's primary source of revenue
is a Power Purchase Agreement with JCP&L. All six Power Purchase Agreements
provide for the substantially continuous provision of base-load power.
46
The following table sets forth the applicable Power Purchaser's nominal
entitlement (its share of capacity and associated energy contracted by the
facilities) and the date of scheduled expiration with respect to each of the
Power Purchase Agreements.
Purchaser's
Nominal Expiration
Entitlement Of Contract
-------------------- ------------------
NEA Project:
Boston Edison I Power Purchase Agreement 135MW 46% September 15, 2016
Boston Edison II Power Purchase Agreement 84 29 September 15, 2011
Commonwealth I Power Purchase Agreement. 25 9 September 15, 2016
Commonwealth II Power Purchase Agreement 21 7 September 15, 2016
Montaup Power Purchase Agreement........ 25 9 September 15, 2021
--- ---
NEA Total....................... 290MW 100%
NJEA Project:
JCP&L Power Purchase Agreement.......... 252MW 100% August 13, 2011
The JCP&L Power Purchase Agreement is scheduled to expire in August
2011, four months prior to the final maturity date of the Securities. Upon such
expiration, it is anticipated that the NJEA Project will become a merchant
facility subject to approval of FERC. See "Risk Factors -- Expiration of Certain
Power Purchase Agreements; Merchant Sales." Prior to such date, NJEA may arrange
to sell electricity in excess of the approximately 252 MW sold to JCP&L to
purchasers in the merchant market, although JCP&L has a right to purchase excess
power that is produced. NE LP's Projections include an assumption that NE LP
will be able to arrange some excess power sales at market prices beginning in
1999.
The Boston Edison II Power Purchase Agreement is also scheduled to
expire in September 2011, three months prior to the final maturity date of the
Securities. Upon such expiration, it is anticipated that the NEA Project will
become a merchant facility as to the portion of the energy output of the NEA
Project covered by the Boston Edison II Power Purchase Agreement, subject to
approval of FERC. NE LP's Projections also include an assumption that NEA will
be able to arrange approximately 10 MW of additional power sales at market
prices beginning in 1999. See "Risk Factors -- Expiration of Certain Power
Purchase Agreements; Merchant Sales." Under the Boston Edison II Power Purchase
Agreement, Boston Edison has certain rights of first refusal, proportionate to
its percentage entitlement to the output of the NEA Project, with respect to
power sales arrangements following the expiration of the Boston Edison II Power
Purchase Agreement.
Energy Banks
The Power Purchase Agreements (other than the Commonwealth Power
Purchase Agreements) provide for tracking accounts, or Energy Banks, to be
calculated during the terms of such Power Purchase Agreements. The Energy Banks
represent the cumulative differences from time to time between (i) the amount
originally estimated to be paid or actually paid, depending on the Power
Purchaser Agreement, by the applicable Power Purchaser for electric power
delivered under the applicable Power Purchase Agreement and (ii) the amounts
originally estimated as such Power Purchaser's Avoided Cost ("PPA Avoided Cost")
of electric power, adjusted in certain cases for peak and off-peak deliveries of
electric power from the Projects. Depending upon the Power Purchase Agreement,
47
PPA Avoided Cost is either set at a scheduled amount per kWh of power, or
determined by reference to the Power Purchaser's actual Avoided Cost over time.
If the price paid under a Power Purchase Agreement exceeds the applicable Power
Purchaser's PPA Avoided Cost, a positive balance will build up in the applicable
Energy Bank, which depending upon the terms of the particular Power Purchase
Agreement, must be either fully or partially secured by Energy Bank Letters of
Credit and, in the case of the Power Purchase Agreements for the NEA Project, by
the NEA Second Mortgage. A positive balance in an Energy Bank represents a
liability of the applicable Partnership to the applicable Power Purchaser that
will be reduced by subsequent sales of electric power to such Power Purchaser to
the extent that, in later periods, PPA Avoided Costs are above the contract
rate. Under certain circumstances (in particular, following an early termination
of a Power Purchase Agreement resulting (i) in the case of the Boston Edison I
Power Purchase Agreement, from an Event of Default by NEA (which includes the
failure to deliver a minimum quantity of electricity equal to approximately 50%
of historical levels for two consecutive years) and (ii) in the case of the
Montaup Power Purchase Agreement, from NEA's insolvency or bankruptcy or NEA's
failure to generate electricity at an annual capacity factor of 60% or higher
for two successive years) such liability, if any, must be repaid in cash. The
Energy Bank balances under the JCP&L Power Purchase Agreement and the Boston
Edison II Power Purchase Agreement have been reduced to zero and, consequently,
the Energy Bank provisions set forth in such Power Purchase Agreements have
terminated. As of December 31, 1997, the Energy Bank liability under the Montaup
Power Purchase Agreement was approximately $27,035,000 and under the Boston
Edison I Power Purchase Agreement was approximately $144,547,000. The Energy
Bank balance under the Montaup Power Purchase Agreement is expected to increase
throughout the term of the Agreement and to be approximately $69,677,000 on
December 31, 2013. The Energy Bank balance under the Boston Edison I Power
Purchase Agreement is expected to decrease to zero by 2007.
Second Mortgage
The performance of NEA's obligations under the NEA Power Purchase
Agreements is secured by the NEA Second Mortgage, which is expressly subordinate
to the NEA Project Mortgage that secures the Project Indebtedness. Under the
subordination provisions set forth in the NEA Second Mortgage, such remedies
cannot be exercised so long as the Project Securities are outstanding. The last
series of Project Securities will, however, mature in 2010, one year before the
final maturity date of the Securities.
For a more detailed summary of the Power Purchase Agreements, see
"Summary of Principal Project Agreements -- Power Purchase Agreements."
Gas Supply Arrangements
The fuel supply arrangements for the Projects are designed to create
flexibility with respect to the Projects' major fuel supplier, ProGas. The
Long-term Gas Supply Agreements are designed to manage the risk of precipitous
increases in the price of natural gas (i) by indexing the prices paid by the
Partnerships to ProGas for a portion of the natural gas to the energy prices
paid by NEA's customers, (ii) by indexing the prices paid to ProGas for
additional natural gas to the cost of natural gas purchased by New Jersey
electrical utilities (including NJEA's customer, JCP&L), as reported in FERC
Form 423 and (iii) by allowing the Partnerships the flexibility to shift gas
purchased from ProGas between the Projects. Such fuel supply and management
arrangement, however, cannot eliminate entirely the risks associated with gas
price volatility. See "Risk Factors -- Gas Supply, Transportation and
Transmission Risks."
Approximately 80% of the Projects' combined fuel requirements of
natural gas are supplied under the Long-term Gas Arrangements on a "firm" basis,
that is, without interruption except for events of force majeure and in other
limited circumstances. The remaining natural gas supplies are purchased on the
open market and are transported by various means to the Projects. The Long-term
Gas Arrangements consist of two long-term contracts with ProGas for supply and
delivery of gas into the United States, one long-term contract with PSE&G for
supply and delivery of gas, several contracts for the transportation on a firm
basis by various transporters of gas purchased under the gas supply and storage
contracts and contracts for the storage of gas. All of the Long-term Gas
Arrangements (with the exception of the ProGas Agreements and one firm gas
transportation agreement with Algonquin) will expire prior to the final maturity
date of the Securities. See "Risk Factors -- Dependence Upon Third Parties." For
a more detailed summary of the contracts comprising the Long-term Gas
Arrangements, see "Summary Of Principal Project Agreements -- Gas Purchase
Agreements; -- Gas Transportation and Storage Agreements."
48
Although it is expected that the Projects will use natural gas almost
exclusively, the NEA Project's air quality permit allows the NEA Project to burn
Number 2 fuel oil for up to 1,440 turbine generating hours per year (equivalent
to approximately 60 days per year, assuming one turbine is burning oil and
operating at base load) in the event of certain curtailments in the gas supplies
for the NEA Project, and the NEA Project has a 2.3 million gallon fuel tank for
storage of approximately a nine-day supply (assuming only one turbine is burning
oil) of Number 2 fuel oil as a back-up fuel. There is no fixed-price fuel
purchase agreement for the purchase or delivery of Number 2 fuel oil. To date,
the NEA Project has not been operated using Number 2 fuel oil (except for
testing purposes). Use of Number 2 fuel oil would result in the suspension of
NEA's sales of steam to NECO. See "Risk Factors -- Dependence Upon Third
Parties" and "The Projects -- Steam Sales Agreements -- NEA."
The air quality permits for the NJEA Project do not allow fuel oil to
be burned.
The table below illustrates natural gas supply consumed by the Projects
during the year ended December 31, 1997, expressed as a percentage of the total
gas requirement for each Project and for the combine total gas requirement for
both Projects.
Natural Gas Consumption for the Projects
For the year ended December 31, 1997
Sources of
Gas Consumed Contract
by the Projects NEA NJEA Total Expiration
(Bef) (Bef) (Bef)
ProGas(1) 14.3 65% 9.2 50% 23.5 59% 2013
PSE&G - 0% 7.9 44% 7.9 20% 2011
Market Purchases 6.2 28% - 0% 6.2 15% N/A
From Storage(2) 1.4 7% 1.1 6% 2.5 6% 2012
------ ------- ------ ------ ------- ------- -------
TOTAL 21.9 100% 18.2 100% 40.1 100%
====== ======= ====== ====== ======= =======
- -------------
(1) ProGas volumes are adjusted to reflect exchanges between the Projects.
(2) Gas from storage includes both volumes purchased as market purchases and
volumes purchased under the Long-term Gas Agreement from ProGas.
Steam Sales Arrangements
NEA
FERC regulations require that at least 5% of a QF's total energy output
be useful thermal energy. To meet this requirement, the NEA Project sells 60,000
to 70,000 pounds per hour of steam (equal to approximately 6 to 7% of the
Project's total energy output) to NECO for use by NECO in the operation of the
Carbon Dioxide Plant, pursuant to the NEA Steam Sales Agreement.
Steam Sales. NEA has leased the Carbon Dioxide Plant to NECO for an
initial term that expires on June 1, 2007, renewable at NECO's option for up to
four renewal periods of five years each and subject to termination by NEA for
the convenience of NEA or following an event of default by NECO. The NEA Steam
Sales Agreement, which also expires on June 1, 2007, provides for NEA to sell to
NECO at least 60,000 pounds per hour of steam during each hour that the NEA
Project is being fueled by 100% pipeline quality natural gas. NECO is required
to buy all its steam from the NEA Project whenever the NEA Project is operating
and to return all condensate. In any hour in which the NEA Project is being
fueled by 100% pipeline quality natural gas, NECO has contracted to accept steam
49
quantities at least equal to 5% of the NEA Project's total energy output. The
price of steam is adjusted annually according to an index that takes into
account the blended base prices of gas supplied to NEA under the NEA ProGas
Agreement and to NJEA under the NJEA ProGas Agreement, subject to a floor price
of $3.50 per 1,000 pounds. The average price of steam under the NEA Steam Sales
Agreement during 1996 and 1997 was $3.52 per 1,000 pounds. NE LP expects to
renew the NECO Lease and the NEA Steam Sales Agreement with NECO following its
scheduled expiration in 2007. In the event that such renewal is not obtained, NE
LP expects that NEA, as owner of the Carbon Dioxide Plant, will be successful in
replacing NECO with another steam purchaser.
NECO's ability to pay for steam depends upon its successful operation
of the Carbon Dioxide Plant and the performance by NECO's two carbon dioxide
customers described below. The NEA Steam Sales Agreement permits NECO to defer
payment for all or a portion of the steam it takes if, after deferring its
payments under the NECO Lease, NECO's monthly expenses still exceed its monthly
revenues. In addition, NEA has agreed with NECO's two carbon dioxide customers
that if NECO fails to satisfy its obligations under the Carbon Dioxide Sales
Agreements described below, NEA will, within 45 days after receipt of notice
from such customer, terminate the NECO Lease, also terminating the NEA Steam
Sales Agreement, and will replace NECO as lessee. For more detailed summaries of
the NEA Steam Sales Agreement and the NECO Lease, See "Summary of Principal
Project Agreements -- Steam Sales Agreements -- NEA."
In addition to steam, the NEA Project provides exhaust gas from the
combustion turbines to the Carbon Dioxide Plant for use as a feedstock. Only the
exhaust from burning natural gas (and not Number 2 fuel oil) can be used for
carbon dioxide production. The Carbon Dioxide Plant can be run at full
operational output provided that at least one combustion turbine is run on gas
only. Under the Long-term Gas Arrangements, it is expected that there will be
sufficient natural gas to run at least one turbine year-round in this manner.
NEA will be obligated to pay liquidated damages to NECO if the NEA Project fails
to provide exhaust gas from at least one turbine running only on natural gas for
at least approximately 80% of the available hours per year.
Carbon Dioxide Sales Agreements. As required by the NECO Lease, NECO
has entered into carbon dioxide sales agreements with BOC Gases and Praxair
(collectively, the "Carbon Dioxide Sales Agreements"), whereby NECO agrees to
dedicate 55% of the Carbon Dioxide Plant's output to Praxair and 45% of the
Carbon Dioxide Plant's output to BOC Gases. BOC Gases and Praxair are two of the
largest suppliers and distributors of carbon dioxide in the United States. Under
the Carbon Dioxide Sales Agreements, 88% of Praxair's allocation and 65% of BOC
Gases' allocation are subject to a mandatory take-and-pay clause, up to a
maximum of 55,660 tons per year for Praxair and 35,000 tons per year for BOC
Gases. The price to be paid to NECO by BOC Gases is subject to adjustment based
upon the New England carbon dioxide market price and is protected by a floor
price of $38.00 per ton, unless and until a competitive plant is constructed and
becomes operational. Upon construction of such a plant, the floor price will be
reduced to $33.00 per ton and BOC Gases has a one-time option, exercisable
within six months after construction of the competitive plant, to lower the
floor price to $30.00 per ton. The price to be paid to NECO by Praxair is
subject to quarterly adjustment with the wholesale carbon dioxide market price.
The price to be paid by Praxair may not be reduced below $38.00 per ton, unless
and until a competitive plant is built in New England or in parts of New York or
New Jersey. After construction of such a plant, the floor price may be reduced
to $30.00 per ton. See "Summary of Principal Project Agreements -- Steam Sales
Agreements -- NEA."
Operation and Maintenance. The Carbon Dioxide Plant is operated for
NECO by Westinghouse Services pursuant to an agreement between NECO and
Westinghouse Services. On November 15, 1997, Westinghouse Electric announced
50
that it intended to sell all of its industrial businesses, including the
business of Westinghouse Services, to Siemens AG.
NJEA
NJEA has entered into the NJEA Steam Sales Agreement with Hercules to
sell steam to Hercules' Parlin, New Jersey facility. The Hercules plant is
located approximately 1.5 miles from the NJEA Project and is connected by a
steam pipeline over land owned by Hercules. NJEA's sales of steam to Hercules
enable NJEA to satisfy FERC's rules with respect to useful thermal output
necessary to maintain the NJEA Project's QF status. To meet this requirement,
the NJEA Project sells approximately 125,000 pounds per hour of steam (equal to
approximately 15% of the NJEA Project's total energy output) to Hercules.
Steam Sales. The NJEA Steam Sales Agreement has an initial term that
expires on August 13, 2011, subject to renewal for two five-year terms. Under
the NJEA Steam Sales Agreement, Hercules must, for any hour in which it takes
steam, take a minimum of 30,000 pounds of steam. Although Hercules may require a
maximum of 205,000 pounds of steam per hour, Hercules' actual requirements have
averaged approximately 125,000 pounds of steam per hour. NJEA is required to pay
liquidated damages to Hercules in the event that (i) it fails to make delivery
on an average annual basis of at least 85% of the steam used by Hercules up to a
maximum of 205,000 pounds per hour or (ii) there are more than five total forced
outages annually or more than 15 partial forced outages annually. Hercules is
obligated under the contract to take sufficient process steam to maintain the
NJEA Project's QF status. The NJEA Steam Sales Agreement is terminable upon
Hercules' closing its Parlin plant, although in such case Hercules has agreed to
lease to NJEA sufficient land to construct an alternative steam host. The NJEA
Steam Sales Agreement's scheduled expiration date (2011) is the same as the
scheduled expiration date for the JCP&L Power Purchase Agreement. Following the
expiration of the JCP&L Power Purchase Agreement, the maintenance of the NJEA
Project's QF status may not be required. In such case, NE LP expects that a
replacement for or a renewal of the NJEA Steam Sales Agreement may not be
obtained. For a more detailed summary of the NJEA Steam Sales Agreement, see
"Summary of Principal Project Agreements -- Steam Sales Agreements -- NJEA Steam
Sales Agreement."
Employees
None of the Partnerships, ESI Tractebel Funding, ESI Tractebel
Acquisition or the Partners have any employees. Pursuant to the Administrative
Services Agreement, ESI GP has agreed to provide administrative services to NE
LP. The Operator, the Fuel Manager and the New Operator are to provide certain
operation and maintenance, oversight and fuel management services for the
Projects. See "Management" and "Certain Transactions."
Legal Proceedings
No material legal proceedings are presently pending against either of
the Partnerships, ESI Tractebel Acquisition or NE LP.
Properties
The Partnerships' principal properties are as follows:
51
Approximate Building
Location Principal Use Square Footage
-------- ------------- --------------------
NEA
Bellingham, MA
NEA Project(1)....... Power Production 70,000
Carbon Dioxide
Plant(2)........... Carbon Dioxide Production 9,000
Certain residential
Properties(3)...... Residences 27,500
NJEA
Sayreville, NJ
NJEA Project(4)...... Power Production 60,000
- ----------
(1) NEA owns the NEA Project and the land upon which it is located, with
the exception of an approximately 15.25-acre parcel that is leased from
The Prestwich Corporation, pursuant to a 26 year operating lease that
expires on May 31, 2012. Subject to certain conditions, NEA has the
option under such operating lease to extend the term of such lease for
an additional 25 years.
(2) NEA owns the Carbon Dioxide Plant, which has been leased to NECO
pursuant to the NECO Lease. See "Summary of Principal Project Agreements --
Steam Sales Agreements -- NEA."
(3) NEA owns 12 single-family dwellings located on land immediately adjacent to
the NEA Site.
(4) NJEA owns the NJEA Project and the land upon which it is located. The NJEA
Site is leased to IECURC (a direct, wholly-owned subsidiary of NJEA) and
leased back to NJEA.
The NEA Site, the NEA Project, the Carbon Dioxide Plant and all other
related improvements and fixtures on the NEA Site owned by NEA are subject to
the NEA Project Mortgage. The NEA Site and the NEA Project are also subject to
the NEA Second Mortgage. The NJEA Site, the NJEA Project and all other related
improvements and fixtures on the NJEA Site owned by NJEA are subject to the NJEA
Project Mortgage. The residential properties referred to in the chart above are
subject to the NEA Additional Properties Mortgage.
REGULATION
Energy Regulation
PURPA
PURPA provides an electric generating project with rate and regulatory
incentives if the project is a QF. Under PURPA, a cogeneration facility is a QF
if (i) the facility sequentially produces both electricity and a useful thermal
energy output during any calendar year which constitutes at least 5% of its
total energy output and which is used for industrial, commercial, heating or
cooling purposes, (ii) during any calendar year the sum of the useful power
output of the facility plus one-half of its useful thermal energy output equals
or exceeds 42.5% of the total energy input of natural gas and oil, or, in the
event that the facility's useful thermal energy output is less than 15% of the
facility's total energy output, such sum equals or exceeds 45% of such total
energy input and (iii) the facility is not more than 50% owned, directly or
indirectly, by an electric utility, electric utility holding company or any
combination of the above.
Under PURPA, QFs receive two primary benefits. First, PURPA exempts QFs
from the Public Utility Holding Company Act of 1935 ("PUHCA"), most provisions
of the Federal Power Act (the "FPA") and certain state laws relating to
financial, organization and rate regulation. Second, FERC's regulations
promulgated under PURPA require (i) that electric utilities purchase electricity
generated by QFs, construction of which commenced on or after November 9, 1978,
at a price based on the purchasing utility's full Avoided Costs, and (ii) that
the utilities sell supplementary, back-up, maintenance and interruptible power
to QFs on a just and reasonable and nondiscriminatory basis. PURPA defines
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"Avoided Costs" as the "incremental costs to an electric utility of electric
energy or capacity or both which, but for the purchase from the qualifying
facility or qualifying facilities, such utility would generate itself or
purchase from another source." Utilities may also purchase power at prices other
than Avoided Costs pursuant to negotiations as provided by FERC regulations.
NE LP expects the Projects to continue to meet all of the criteria
required for certification as QFs under PURPA. If either Project were to fail to
meet such criteria, the related Partnership and, by virtue of the Partnerships'
common Partners, the other Partnership may become subject to regulation as a
public utility company or its equivalent under PUHCA, the FPA and state utility
laws. Certain of the Power Purchase Agreements require that the applicable
Partnership use its best efforts to maintain QF status, and others may be
terminated or be subject to price renegotiation if QF status is lost. In
addition, each of the O&M Agreements may be suspended by the Operator if the
applicable Project is operated in a manner likely to result in the loss of QF
status, and if such potential loss is certified by an independent engineer. See
"Summary of Principal Project Agreements -- Operations and Maintenance
Agreements."
PUHCA
PUHCA provides that any corporation, partnership or other entity or
organized group that owns, controls or holds power to vote 10% or more of the
outstanding voting securities of a "public utility company" or a company that is
a "holding company" of a "public utility company" is subject to registration
with the SEC and to regulation under PUHCA, unless exempted by Commission rule,
regulation or order. An entity may also be deemed to be a holding company if the
Commission determines, after providing notice and an opportunity for hearing
that such entity exercises a controlling influence over the management or
policies of any public utility or holding company as to make it necessary or
appropriate in the public interest or for the protection of investors or
consumers that such entity be regulated as a holding company. Unless an
exemption is obtained, PUHCA requires registration for a holding company of a
public utility company, and requires a public utility holding company to limit
its utility operations to a single integrated utility system and to divest any
other operations not functionally related to the operation of the utility
system. In addition, a public utility company that is a subsidiary of a
registered holding company under PUHCA is subject to financial and
organizational regulation, including approval by the Commission of its financing
transactions.
The Energy Policy Act of 1992 (the "Policy Act") contains amendments to
PUHCA that may allow the Partnerships to operate their businesses without
becoming subject to PUHCA in the event that either Project loses its status as a
QF. Under the Policy Act, a company engaged exclusively in the business of
owning and/or operating one or more facilities used for the generation of
electric energy exclusively for sale at wholesale may be exempted from PUHCA. To
qualify for such an exemption, a company must apply to FERC for a determination
of eligibility, pursuant to implementing rules promulgated by FERC. If QF status
is lost, however, obtaining this exemption would not eliminate the need to amend
or replace certain of the Power Purchase Agreements. Moreover, although the
Policy Act and its implementing rules provide certain exemptions from PUHCA, the
Policy Act may also encourage greater competition in wholesale electricity
markets, which could result in a decline in long-term rates to be paid by
electric utilities, including those party to the Power Purchase Agreements. Even
if a Partnership obtained an exemption from PUHCA pursuant to the Policy Act and
implementing rules, in the event that QF status is revoked, the applicable
Partnership would be subject to regulation under the FPA, as described below.
FPA
Under the FPA, FERC has exclusive rate-making jurisdiction over
wholesale sales of electricity and transmission in interstate commerce. These
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rates may be based on a cost of service approach or may be determined through
competitive bidding or negotiation. If a Project were to lose its QF status, the
rates set forth in each of the Power Purchase Agreements would have to be filed
with FERC and would be subject to review by FERC under the FPA. Under FERC
policy, the rates under those circumstances could be no higher than the price
such Power Purchasers would have paid for energy had they not been required to
purchase from such Project under PURPA's mandatory purchase requirements, i.e.
such Power Purchaser's economy energy (incremental) cost during the period of
non-compliance, unless the applicable power purchase agreement otherwise
provides for alternative rates to apply in the event of such loss of QF status.
Certain of the Power Purchase Agreements contain provisions for a renegotiation
of the rates to be paid for electric energy in the event of loss of QF status,
and loss of QF status constitutes an event of default under the JCP&L Power
Purchase Agreement.
The FPA and FERC's authority under the FPA subject public utilities to
various other requirements, including accounting and record-keeping
requirements; FERC approval requirements applicable to activities such as
selling, leasing or otherwise disposing of facilities; FERC approval
requirements for mergers, consolidations, acquisitions and the issuance of
securities; and certain restrictions regarding affiliations of officers and
directors.
State Regulation
The Projects, by virtue of being QFs, are exempt from New Jersey and
Massachusetts rate, financial and organizational regulations that are applicable
to public utilities. QFs, however, are not exempt from the state regulatory
commissions' general supervisory powers relating to environmental and safety
matters. In addition, the NEA Project is required to file reports used by the
Massachusetts Department of Public Utilities to forecast long-term electrical
power needs.
In the event that the NEA Project loses its QF status, in addition to
FPA and PUHCA regulation, NEA and the NEA Project would be subject to a wide
range of state regulations applicable to Massachusetts "electric companies,"
including requirements for the filing of annual reports and approval by the
Massachusetts Department of Telecommunications and Energy of any issuance of
securities. Similarly, in the event that the NJEA Project loses its QF status,
in addition to FPA and PUHCA regulation, NJEA and the NJEA Project could,
depending upon the character and extent of the business activities of NJEA with
respect to sales of electricity from the NJEA Project, and whether NJEA engages
in retail sales of electricity (such retail sales subject to the implementation
of retail competition in New Jersey pursuant to deregulation imposed by the New
Jersey Board of Public Utilities ("NJBPU")), be subject to a wide range of state
statutes and regulations applicable to New Jersey public utilities, which
includes the ability of the NJBPU to fix the rates charged by NJEA for the sale
of the electric energy generated by the NJEA Project, the approval by the NJBPU
of the issuance of securities by NJEA and the requirements for periodically
furnishing to the NJBPU detailed reports of NJEA's finances and operations.
Wheeling and Interconnection
Under the FPA, FERC is authorized to regulate the rates, terms and
conditions for the transmission of electric energy in interstate commerce. This
has been interpreted to mean that FERC has jurisdiction to prescribe the terms
of and to set the rates contained in agreements for the transmission of electric
energy when the applicable transmission system is interconnected and capable of
transmitting energy across a state boundary, even if the utility has no direct
connection with another utility outside its state but is interconnected with
another utility that in turn has interstate connections with other utilities.
Accordingly, the rates to be paid by NEA to Boston Edison under the Boston
Edison Interconnection Agreement are subject to the jurisdiction of FERC under
the FPA. Boston Edison submitted the Boston Edison Interconnection Agreement to
FERC on October 13, 1993. FERC accepted such filing; however, the terms thereof
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and the rates thereunder remain subject to review and potential modification
pursuant to the jurisdiction of FERC. See "Summary of Principal Project
Agreements -- Boston Edison Interconnection Agreement."
FERC's authority under the FPA to require electric utilities to provide
transmission service to QFs and other wholesale electricity producers has been
significantly expanded by the Policy Act. Pursuant to the Policy Act, the
Partnerships may apply to FERC for an order requiring a utility to provide
transmission services in order to transmit power to a wholesale purchaser. FERC
may issue such an order if FERC determines that such order would promote the
economically efficient transmission and generation of electricity, would be just
and reasonable and not unduly discriminatory or preferential and otherwise would
be in the public interest, provided that the reliability of the affected
electric systems would not be unreasonably impaired. The Policy Act may enhance
the Partnerships' ability to obtain transmission access necessary to sell
electric energy or capacity to purchasers other than those with which the
Partnerships presently have Power Purchase Agreements and NEA's ability to
obtain transmission line access for electrical sales to Commonwealth and Montaup
following the scheduled expiration in 2001 of Commonwealth's and Montaup's
access rights to Boston Edison's Medway Substation, which interconnects the NEA
Project with Montaup and Commonwealth's respective grids. There can be no
assurance however, that FERC would issue any such order or that the rates for
such transmission service would be economical for the Partnerships. The Policy
Act may also result in greater competition among wholesale electric energy
producers. See "Risk Factors -- Gas Supply, Transportation and Transmission
Risks -- Transmission of Electrical Power."
Utility Industry Restructuring
State and federal regulators are in the process of a major examination
of the organization of the electric utility industry, which is dominated by
vertically integrated investor-owned utilities.
Federal
In the Spring of 1996, FERC promulgated its Order No. 888, an order
containing significant policy initiatives designed to open the market for
generation of electricity to competition. In its order, FERC promulgated rules
requiring utilities owning transmission facilities to file uniform,
non-discriminatory open access tariffs. These filings were made during the
summer of 1996. The utilities themselves must use these tariffs for their
wholesale sales. The order permits the utilities an opportunity to recover
stranded costs (described below) associated with wholesale transmission.
Additionally, FERC directed the regional power pools that control the major
electric transmission networks to file uniform, non-discriminatory open access
tariffs. Among the power pools that are subject to this mandate are the New
England Power Pool ("NEPOOL") and the Pennsylvania-New Jersey-Maryland
Interconnection ("PJM"), the two power pools that control transmission of
electricity within the areas in which the Projects are located. Both NEPOOL and
PJM filed proposals for open access tariffs prior to the FERC's deadline,
December 3, 1996. FERC granted conditional approval of both of the proposed
tariffs in the Fall of 1997. The Partners do not expect Order No. 888 to have a
material impact on Partnerships' ability to obtain access to transmission lines
for electrical sales to those utilities with whom they have power purchase
agreements.
In the Spring of 1996, FERC also issued its Order No. 889. This order
requires utilities owning transmission facilities to adopt procedures for an
open-access same-time information system ("OASIS") that will make available, on
a real-time basis, pertinent information concerning each transmission utility's
services. The order also promulgated standards of conduct to ensure that the
utilities functionally separate their transmission and wholesale power merchant
functions to prevent self-dealing.
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In the Spring of 1997, FERC issued its orders on rehearing of Order
Nos. 888 and 889. In these orders FERC upheld the bulk of its rulings in Order
Nos. 888 and 889, while making changes to a few of its rules to implement its
open-access policies. Transmitting utilities were required to submit revised
tariffs to FERC during the summer of 1997 to reflect FERC's orders on rehearing.
In November 1997, FERC issued further orders on rehearing affirming, with
certain clarifications, its previous orders. Certain aspects of Order Nos. 888
and 889 have been appealed to the U.S. Court of Appeals.
Congress is considering legislation to modify federal laws affecting
the electric industry. Bills have been introduced in the current Congress to
provide retail electric customers with the right to choose their power
suppliers. Modifications of PUHCA and PURPA have also been proposed.
NEPOOL
NEPOOL was initially organized in 1971 and presently has over 130
members representing more than ninety-nine percent (99%) of the electric
business in New England. NEPOOL is a voluntary association which operates to
assure that the bulk electric power supply of the New England region is provided
through central dispatch of virtually all of the generation and transmission
facilities in New England as a single control area.
On December 31, 1996, as supplemented February 14, April 18, May 1 and
June 5, 1997, NEPOOL filed with FERC a comprehensive restructuring proposal. The
restructuring proposal was intended to: (1) comply with the requirements of
Order No. 888; (2) transfer control of the NEPOOL transmission grid to an
independent system operator; and (3) provide a more open, competitive market for
wholesale sales and purchases of electric energy in the New England region
through a bilateral market and a regional power exchange.
On June 25, 1997, FERC unconditionally authorized the establishment of
the independent system operator and authorized the transfer of control of pool
transmission facilities ("PTFs") owned by the public utility members of NEPOOL
to the independent system operator. FERC concluded that this was both consistent
with the public interest and would serve to maximize the potential for reliable,
competitive bulk power operations in the region. The independent system operator
is responsible for, among other things, monitoring the regional power market
which includes maintaining system reliability, operating the NEPOOL control area
and control center, administering the 7 spot markets, administering the NEPOOL
tariff, and promoting efficient and competitive functioning within the market.
PJM
The PJM power pool is a voluntary association of eight member electric
utility companies in the mid-Atlantic region, originally formed in 1927, with a
pooled generating capacity of over 56,000 megawatts. Under the historic PJM
power pool structure, the member companies jointly own and control the bulk
power transmission systems in the region and jointly plan transmission systems
upgrades. On December 31, 1996, the PJM filed with FERC a proposal to
restructure PJM to introduce open access transmission and otherwise to implement
FERC Order 888. On February 28, 1997, FERC approved PJM's filing subject to
further orders. FERC, on an interim basis, approved the PJM open access
transmission tariffs effective April 1, 1997, and incorporated such proposal
with respect to all issues except for congestion pricing. With implementation of
a pool-wide open-access transmission tariff on April 1, 1997, PJM began
operating a regional bid-based energy market. Participants buy and sell spot
energy, schedule bilateral transactions, and reserve transmission service using
the PJM OASIS.
On November 25, 1997, FERC approved a restructuring plan for the PJM
interconnection. The comprehensive plan included the approval of the PJM
Operating Agreement, the PJM Open-Access Transmission Tariff, the Transmission
56
Owners Agreement, and the Reliability Assurance Agreement. FERC modifications to
the Agreement will be made in subsequent compliance filings by PJM. PJM has
requested an April 1, 1998 implementation date for the approved PJM Open-Access
Transmission Tariff. On March 30, 1998, FERC issued an order accepting for
filing certain revisions to PJM's open access transmission tariff and operating
agreement, and permitted them to go into effect on April 1, 1998.
Massachusetts
On November 25, 1997 the Massachusetts legislature passed a
comprehensive electric deregulation bill entitled "AN ACT RELATIVE TO
RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY IN THE COMMONWEALTH, REGULATING THE
PROVISIONS OF ELECTRICITY AND OTHER SERVICES, AND PROMOTING ENHANCED CONSUMER
PROTECTIONS THEREIN" (the "Act"). The purpose of the Act is to establish a
comprehensive framework for the restructuring of the electric utility industry.
In furtherance of this, the Act eliminates the existing Department of Public
Utilities, replacing it with a five-member Department of Telecommunications and
Energy ("DTE").
Divestiture
The Act provides that each electric company may, in its sole
discretion, divest itself of its existing generation facilities. An electric
company that chooses not to divest all of its non-nuclear generation facilities,
is required to subject its nuclear and non-nuclear generation facilities and
purchased power contracts to a valuation under which the DTE determines the
market value of such generation facilities and contracts. The DTE is to require
a reconciliation of projected transition costs to actual transition costs by
March 1, 2000, and for every 18 months thereafter through March 1, 2008, or the
termination date of any transition charge allowed to be assessed.
If an electric company chooses to divest itself of its existing
non-nuclear generation facilities, such company shall transfer or separate
ownership of generation, transmission, and distribution facilities into
independent affiliates.
Commonwealth, Montaup and Boston Edison are all in various stages of
divestiture.
Stranded Costs
The Act also requires the DTE to identify and determine stranded costs
that may be allowed to be recovered through a non-bypassable transition charge.
DTE approval is required for any plan to recover such costs, DTE may not grant
such approval unless it finds that the company has taken all reasonable steps to
mitigate the total amount of such costs that will be recovered and minimize the
impact of such costs on ratepayers.
Above-Market Power Purchase Contracts
The Act further provides that to mitigate the projected above market
cost of power associated with purchased power contracts ("PPCs") approved by the
DTE or by its predecessor, the Department of Public Utilities Commission, by
December 31, 1995, except with respect to trash to energy facilities, electric
companies and sellers under such contracts are required to make good-faith
efforts to renegotiate those contracts that contain a price for electricity that
is above-market as of March 1, 1998. In order to meet this standard, the parties
must show that they have actively participated in negotiations and have shown a
willingness to make reasonable concessions to mitigate equitably stranded costs.
A good-faith effort under the Act does not require accepting all proposals and
57
making unlimited concessions. Beginning July 1, 1998, and at least annually
thereafter, the DTE is required to continue to review such PPCs to determine if
the contracts are above-market as of the date of review. If such contract is
above-market, the electric company and the seller under the contract must
attempt to make a good-faith effort to renegotiate such contract to achieve
further reductions in the transition charge. If an electric company has assigned
such contract to a buyer having adequate financial resources under a
DTE-approved divestiture plan, the electric company is deemed to have met its
obligations. If the seller under such contract has consented to the assignment
and has agreed to release the electric company from all obligations under such
contract, the seller is deemed to have met its obligations.
If the DTE finds that a negotiated contract buyout or other
modification is likely to achieve savings to the ratepayers and is otherwise in
the public interest, the remaining amounts in excess of market value associated
with such contract shall be included in the transition charges. If the DTE finds
that a seller has made a bona fide offer for such a contract buyout or
modification that has been refused by the purchasing electric company, only
those amounts in excess of market value associated with such contract that would
not have been mitigated by such offer shall be included in the transition
charges, and the seller is deemed to have met its obligation to negotiate in
good faith.
New Jersey
Industry restructuring efforts are also underway in New Jersey. On
April 30, 1997, the New Jersey Board of Public Utilities ("NJBPU" or "Board")
issued its Final Report in the Energy Master Planning Process entitled
"Restructuring the Electric Power Industry in New Jersey: Findings and
Recommendations." The principal announced goal of the NJBPU in its restructuring
initiative is to open the electric generation market to increased competition.
On July 15, 1997, each of New Jersey's four electric utility companies filed:
(1) a Restructuring Plan, (2) an Unbundled Rate Filing, and (3) a Stranded Costs
Filing with the NJBPU pursuant to the NJBPU's Final Report.
Stranded Costs
The stranded costs filing of each utility will determine the specific
initial level of non-mitigatable stranded costs to be recovered by the local
electric distribution company. The stranded cost filing for each utility has
been transmitted to the Office of Administrative Law for evidentiary hearings.
The JCP&L hearing commenced on December 2, 1997; the Initial Decision from the
Administrative Law Judge is due on May 15, 1998, with a Final Decision by the
NJBPU due thereafter.
Stranded costs are defined by the NJBPU as the potential shortfall in
revenues, or "loss," which would be experienced by the electric utilities as
competition is introduced and their traditional monopolies are opened up to
competitors. The Board seeks to address the stranded costs that may be created
as a result of its recommendation to open the power generation and supply market
up to competition. The Board has determined to limit the eligibility for
stranded cost surcharge recovery to costs related directly to power supply
including utility generation plant, long- and short-term power purchase
contracts with other utilities and long-term power purchase contracts with
non-utility generators.
The NJBPU concluded in its April 30, 1997 report that electric
utilities should be given an opportunity to recover from customers the costs
associated with past financial commitments made by the utility for the purpose
of procuring generating supplies to serve the retail electric customers in their
service territory, notwithstanding the emergence of competition in the
generation market. Such pronouncement is not binding at the present, and is
subject to future regulatory proceedings and actions by the New Jersey
Legislature. Additionally, federal legislation has been proposed that may alter
a state's ability to regulate the emerging competitive market and the recovery
of stranded costs. See "Risk Factors -- Dependence on Third Parties."
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Above Market Power Purchase Contracts
The NJBPU stated in its final report that utilities should make a
reasonable good faith effort to mitigate stranded costs, including the buy-out
or renegotiation of existing purchased power contracts with non-utility
generators. The Board has acknowledged that it appears to lack jurisdiction to
order modification of non-utility generators' contracts, and has determined that
the "non-mitigatable costs associated with all such contracts which have
previously been reviewed and approved by the Board, notwithstanding the specific
date, must be eligible for stranded cost recovery."
The NJBPU based its determination that it lacks jurisdiction to order
modification of non-utility generators' contracts on the decision of the Third
Circuit Court of Appeals in Freehold Cogeneration Associates, L.P. v. Board of
Regulatory Commissioners of New Jersey, 44 F.3d. 1178 (3rd Cir. 1995), cert.
den., 116 S. Ct. 68, which held that
Once the [NJBPU] approved the power purchase agreement between Freehold
and JCP&L, on the grounds that the rates were consistent with avoided cost, any
action or order by the [NJBPU] to reconsider its approval or to deny the passage
of those rates to JCP&L consumers under purported state authority was preempted
by federal law. (Id., Freehold, 44 F.3d at 1194).
The NJBPU has interpreted the Freehold decision to mean that "without
legislative action at the federal or State level, a State regulator has minimal
ability to subsequently adjust the pricing in such non-utility generators
contracts once approved."
Notwithstanding the NJBPU's acknowledgment that it appears to lack
jurisdiction to order modification of non-utility generators' contracts under
current law it has "strongly encouraged all stakeholders to renew their efforts
to explore all reasonable means to mitigate IPP contracts." The Board further
stated that the appropriate legislative bodies may wish to review this issue to
"provide an added impetus for parties to these [non-utility generators']
contracts to seriously consider mitigation." JCP&L has reported to the NJBPU
that it intends to pursue efforts to mitigate its above-market costs for
non-utility generator purchase power agreements. JCP&L has contacted NJEA and
made a presentation to NJEA regarding a preliminary proposal by JCP&L to
transform NJEA's must-run contract into a dispatchable contract on terms that
are to cover all fixed costs (debt service and fixed operating expenses) and
preserve current net profits while allowing JCP&L to reduce its purchase power
costs. See "Risk Factors -- Dependence Upon Third Parties."
While NE LP does not expect utility industry restructuring to result in
any material adverse change to the Partnerships' Power Purchase Agreements, the
impact of electrical industry restructuring on the companies that purchase power
from Partnerships is uncertain.
Permit Status
The Independent Engineer has confirmed that as of the date of this
Prospectus all material permits required for the operation of the Projects have
been obtained.
The 1990 Amendments to the Clean Air Act require states and the federal
government to implement certain measures that may affect the operation of the
Projects. The State of New Jersey and the Commonwealth of Massachusetts are
required to incorporate new, more stringent requirements into their plans for
bringing the air quality in the areas in which the Projects are located into
compliance with national air quality standards. In addition, thirteen
northeastern states, including Massachusetts and New Jersey, have entered into a
Memorandum of Understanding to address problems associated with the
cross-boundary transport of ozone (the "MOU"). Under the MOU, the states have
59
agreed to reduce emissions of nitrogen oxides ("NOx"), which is a precursor to
ozone, in two phases. In 1999, utility sources in Massachusetts and New Jersey
generally will be expected to meet a 0.20 lbs/mmBtu effective NOx emissions
rate. In 2003 and thereafter, such sources will be expected to meet a 0.15
lbs/mmBtu effective NOx emissions rate. The Projects currently meet an effective
NOx emissions rate of .09 lbs/mmBtu, and thus it appears that the Projects are
favorably positioned to meet the NOx emissions limits contemplated under the MOU
without the need for additional capital expenditures. In the event that the
Projects are unable to meet the NOx emissions limitations contemplated under the
MOU or other regulations, it is possible that each Project could be required to
install a selective catalytic reduction (SCR) system in order to meet any such
limitations, at a cost of approximately $1.2 to $1.5 million per system.
The 1990 Amendments also require each state to implement an operating
permit program that incorporates all of a facility's Clean Air Act requirements
into a single permit and that includes sufficient monitoring requirements to
ensure compliance. In addition, states are authorized to impose fees of at least
$25 per ton of air pollutants emitted by a facility, even if such emissions are
within permitted limits. The Departments of Environmental Protection for each of
New Jersey and Massachusetts are currently reviewing the operating permit
applications for the NJEA Project, the NEA Project and the Carbon Dioxide Plant,
respectively.
SUMMARY OF PRINCIPAL PROJECT AGREEMENTS
The following is a summary of selected provisions of certain principal
agreements related to the Projects and is not considered to be a full statement
of the terms of such 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
summary to any agreement shall mean such agreement and all schedules, exhibits
and attachments thereto as amended, supplemented or otherwise modified and in
effect as of the date hereof.
Power Purchase Agreements
NEA Power Purchase Agreements
Boston Edison I Power Purchase Agreement
The Power Purchase Agreement entered into by NEA and Boston Edison as
of April 1, 1986 (the "Boston Edison I Power Purchase Agreement"), provides for
the sale to Boston Edison of 46% of the net power actually generated by the NEA
Project.
Term. The Boston Edison I Power Purchase Agreement extends for an
initial term of 25 years expiring September 15, 2016, subject to earlier
termination in accordance with its terms. Following the initial term, Boston
Edison has the right to extend the Boston Edison I Power Purchase Agreement for
an additional five years upon six months written notice. Following any such
renewal, the Boston Edison I Power Purchase Agreement will remain in effect
until terminated by either party by giving the other party six month's written
notice of such termination.
Purchase and Delivery. Pursuant to the Boston Edison I Power Purchase
Agreement, NEA is obligated to deliver to Boston Edison, and Boston Edison is
obligated to accept, a portion of the available capacity and hourly generation
of the NEA Project equal to the ratio of 135 MW to the Net Electrical Capability
(as defined herein) of 290 MW of the NEA Project multiplied by 100% of the
available capacity and hourly generation of the NEA Project, or 46% of the net
power actually generated. Plant output is dependent, among other things, on
ambient temperatures, and is therefore subject to some variation. Whenever the
NEA Project is operating above or below its Net Electrical Capability of 290 MW,
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the output sold to Boston Edison and other NEA Power Purchasers will be
increased or reduced proportionately. NEA is obligated, however, to make
available and dedicate to Boston Edison capacity and electric energy in the
amount of 135 MW. Boston Edison has a right of first refusal, on terms to be
agreed, to purchase a proportionate share based on its then current entitlement
of any increased capacity resulting from an expansion of or addition to the NEA
Project or from any other electricity generating facility on the NEA Site. All
power is to be delivered to the nearest Boston Edison interconnection point,
which is presently Boston Edison's Medway Station.
Curtailment. Boston Edison has the right under the Boston Edison I
Power Purchase Agreement to refuse power from the NEA Project for up to 200
hours per year (in addition to its other curtailment rights described below).
Boston Edison also has the right to interrupt, reduce or refuse to purchase
electric energy and NEA has the right to interrupt, reduce or refuse to deliver
electric energy in order to install equipment, make inspections or perform
maintenance and repairs. In addition, Boston Edison has the right to curtail or
interrupt the taking of electric energy for as long as reasonably necessary in
the event of an emergency.
Interconnection. NEA has agreed to secure and pay all expenses of
interconnection for the delivery of electrical energy at the delivery point.
While Boston Edison may, at its option (subject to certain conditions), enter
into transmission and interconnection agreements if necessary to ensure
continued transmission and delivery of electrical energy, the expense and the
risk of loss of such transmission are to be borne by NEA. All necessary
interconnection agreements have been entered into. See "-Boston Edison
Interconnection Agreement" below.
Pricing. The Boston Edison I Power Purchase Agreement provides for a
fixed capacity payment of 1.04 cents per kWh for all power delivered to Boston
Edison plus an energy payment per kWh delivered equal to a percentage of the
"Qualifying Facility Power Purchase Rate," which is a rate determined under
Massachusetts law. It has been agreed that this percentage shall be 80% in each
contract year through 2003, 75% from 2004 through 2007, 80% from 2008 through
2010, 85% in 2011 and 90% thereafter. If Boston Edison elects to exercise its
right to extend the Boston Edison I Power Purchase Agreement, the energy payment
for the period of any such extension will be 100% of the Qualifying Facility
Power Purchase Rate. The Boston Edison I Power Purchase Agreement further
provides that the minimum total payment for both energy and capacity to be
received by NEA (in all cases whether or not such minimum amount is greater than
the applicable percentage of the "Qualifying Facility Power Purchase Rate")
shall not be less than 7.50 cents per kWh through 1997, after which the minimum
payment becomes 6.50 cents per kWh until the end of the initial term. There is
no minimum for any extension period. In 1997 the price per kWh was 7.50 cents.
If, due to transmission constraints, Boston Edison must purchase power from NEA
rather than a lower priced source, the purchase price for such power will be the
lower price Boston Edison was forced to forego. However, such substitute rate is
only available for up to 100 hours in any contract year.
Energy Bank. The Boston Edison I Power Purchase Agreement provides for
a special account referred to as the Energy Bank or Balance Account, and the
Energy Bank balances therein are to be increased or decreased based upon a
formula that prices power delivered to Boston Edison at its projected avoided
cost, which is determined by reference to a fixed schedule specifying dollar
amounts per kWh sold for each year of the Boston Edison I Power Purchase
Agreement. As of December 31, 1997, the Energy Bank balance under the Boston
Edison I Power Purchase Agreement was approximately $144,547,000 and is
projected to decrease to zero by 2007. The Boston Edison I Power Purchase
Agreement requires that approximately 50% of all positive Energy Bank balances
be supported by an irrevocable letter of credit, subject to a maximum letter of
credit requirement of $54 million. See "Business -- Power Purchase Agreements."
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Contract Security. To secure its performance under the Boston Edison I
Power Purchase Agreement (as well as the other NEA Power Purchase Agreements),
NEA has granted Boston Edison, Commonwealth and Montaup the NEA Second Mortgage
on the NEA Site and the NEA Project, subordinated only to the rights of the
holders of the Project Securities ("the Project Secured Parties") pursuant to
the NEA Project Mortgage and certain replacements thereof. In addition, NEA has
granted Boston Edison an unsubordinated declaration of easements, encumbering
the NEA Project for the term of the Boston Edison I Power Purchase Agreement.
This declaration provides Boston Edison with limited access to the NEA Project
under certain specified conditions and obligates any subsequent owner of the NEA
Project to sell to Boston Edison its entitlement under the Boston Edison I Power
Purchase Agreement. See "-- Accommodation Agreement."
Sale of Power to Other Purchasers. The Boston Edison I Power Purchase
Agreement contains a "most-favored nation" clause specifying that if any of the
Commonwealth Power Purchase Agreements and the Montaup Power Purchase Agreement
are amended or if NEA enters into any additional power purchase agreements, and
Boston Edison believes the terms of such amendment or such power purchase
agreement are more favorable to the applicable third party than the terms of the
Boston Edison I Power Purchase Agreement are to Boston Edison, NEA shall make
such terms available to Boston Edison for the remaining term of the Boston
Edison I Power Purchase Agreement, provided Boston Edison accepts the other
substantive terms of such amendment or power purchase agreement. Pursuant to a
Consent and Agreement, dated as of June 28, 1989, and confirmed in a
Confirmation Agreement, dated September 16, 1994, subject to conditions
contained therein, Boston Edison has irrevocably waived its rights to invoke the
"most-favored nation" clause. NEA may not enter into any contract for the sale
of electricity from any addition to or expansion of the NEA Project or from any
other electricity generation facilities located at the NEA Site unless it first
offers Boston Edison an amount of electricity proportionate to its then current
entitlement on substantially the same business terms specified in any proposal
or letter of intent with the applicable third party and Boston Edison does not
accept such terms.
Right of First Offer. Other than in connection with the financing or
refinancing of the NEA Project, or with the sale of equity participations in the
form of partnership interests or otherwise, NEA has agreed under the Boston
Edison I Power Purchase Agreement that if it desires to sell all or any portion
of the NEA Project, it will first offer the terms of such sale to Boston Edison,
which will have 60 days to respond to such offer. If Boston Edison declines the
offer, NEA, will be free to offer the same terms to any third party, but in the
event that an agreement is reached with such third party on terms more favorable
than those proposed to Boston Edison, NEA is obligated to offer such terms to
Boston Edison. The right of first offer is subject to adjustments proportionate
to increases in entitlements of Commonwealth and Montaup.
Qualifying Facility Status. The Boston Edison I Power Purchase
Agreement does not require that the NEA Project's QF status be maintained.
However, NEA has warranted to Boston Edison that NEA will use its best efforts
to maintain the NEA Project's QF status.
Events of Default and Remedies; Termination. The occurrence of any one
or more of the following events constitutes an event of default under the Boston
Edison I Power Purchase Agreement and may result in termination of the Boston
Edison I Power Purchase Agreement and the exercise of other remedies by the
non-defaulting party: (i) the dissolution or liquidation of either party; (ii)
failure by either party to perform or observe any of the material terms of the
Boston Edison I Power Purchase Agreement, where such failure has not been cured
within 45 days of notice thereof by the non-defaulting party or, where cure is
not practicable within 45 days, cure has not been undertaken within 45 days and
completed within a reasonable period not to exceed two years; (iii) certain
events of bankruptcy or insolvency; (iv) the failure of NEA to deliver at least
591.3 million kWh of electricity per year (equivalent to 135 MW at 50% capacity
factor annually) to Boston Edison in each of two consecutive contract years,
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whether or not such failure is due to force majeure; and (v) either party
contests the enforceability of the Boston Edison I Power Purchase Agreement. In
addition, Boston Edison may terminate the Boston Edison I Power Purchase
Agreement in the event of NEA's failure to pay costs and expenses, if any,
associated with transmission services, filing fees, administrative costs and any
interest accrued thereon in accordance with such contract.
Boston Edison II Power Purchase Agreement
The Power Purchase Agreement entered into by NEA and Boston Edison as
of January 28, 1988 (the "Boston Edison II Power Purchase Agreement"), provides
for the sale to Boston Edison of 29% of the net power actually generated by the
NEA Project, subject to certain limitations described below.
Term. The Boston Edison II Power Purchase Agreement extends for a term
of 20 years expiring September 15, 2011, subject to earlier termination in
accordance with its terms. The Boston Edison II Power Purchase Agreement does
not include any right to extend its term.
Purchase and Delivery. Pursuant to the Boston Edison II Power Purchase
Agreement, NEA is obligated to deliver to Boston Edison, and Boston Edison is
obligated to accept, a portion of the available capacity and hourly generation
of the NEA Project equal to the ratio of 84 MW to the Net Electrical Capability
of 290 MW of the NEA Project multiplied by 100% of the available capacity and
hourly generation of the NEA Project, or 29% of the net power actually
generated, not to exceed 68 MW during the Summer Period (June through September)
or 92 MW during the Winter Period (October through May). The maximum delivery
amount under the Boston Edison II Power Purchase Agreement during any contract
year is 735.84 million kWh (equivalent to 84 MW at 100% capacity factor
annually). Boston Edison is not obligated to accept energy in excess of the
amounts stated. Project output is dependent, among other things, on ambient
temperatures, and is therefore subject to some variation. Whenever the NEA
Project is operating above or below its Net Electric Capability of 290 MW, the
output sold to Boston Edison and other NEA Power Purchasers will be increased or
reduced proportionately subject to Boston Edison's maximum purchase obligations
described above. All power is to be delivered to an interconnection point
mutually agreed to by Boston Edison and NEA, which is presently Boston Edison's
Medway Station.
Curtailment. Boston Edison has the right under the Boston Edison II
Power Purchase Agreement to interrupt, reduce or refuse to purchase electric
energy, and NEA has the right to interrupt, reduce or refuse to deliver electric
energy in order to install equipment, make inspections or perform maintenance
and repair. Boston Edison also has the right to curtail or interrupt the taking
of electric energy for as long as reasonably necessary in the event of an
emergency.
Interconnection. NEA has agreed to pay all expenses of interconnection
for the delivery of electrical energy at the delivery point. All necessary
interconnection agreements have been entered into. See "-Boston Edison
Interconnection Agreement."
Pricing. The Boston Edison II Power Purchase Agreement provides for
fixed payments for all power delivered to Boston Edison averaging 4.50 cents per
kWh in 1992, 4.84 cents per kWh in 1993, and rising thereafter at a fixed
escalation rate of 7.5% per year. In 1997, this rate was 6.46 cents per kWh.
Escrow Account. NEA is required by the Boston Edison II Power Purchase
Agreement to maintain an escrow account for plant maintenance of $1.275 million.
Pursuant to Boston Edison's consent to the issuance of the Project Securities,
the security provided for the Project Debt Service Reserve Fund will be deemed
to fulfill this obligation.
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Energy Bank Liability and Support. Although the Boston Edison II Power
Purchase Agreement provides for an Energy Bank, there is no liability remaining
for the Energy Bank under the Boston Edison II Power Purchase Agreement.
Contract Security. To secure its performance under the Boston Edison II
Power Purchase Agreement (as well as the other NEA Power Purchase Agreements),
NEA has granted Boston Edison, Commonwealth and Montaup the NEA Second Mortgage
on the NEA Site and the NEA Project, subordinated only to the rights of the
Project Secured Parties pursuant to the NEA Project Mortgage and certain
replacements thereof. In addition, NEA has granted Boston Edison an
unsubordinated declaration of easements, encumbering the NEA Project for the
term of the Boston Edison II Power Purchase Agreement. This declaration provides
Boston Edison with limited access to the NEA Project under certain specified
conditions and obligates any subsequent owner of the NEA Project to sell to
Boston Edison its entitlement under the Boston Edison II Power Purchase
Agreement. See "-- Accommodation Agreement" below.
Sale of Power to Other Purchasers. The Boston Edison II Power Purchase
Agreement provides that NEA may not enter into any contract for the sale of
electricity from the NEA Project or any additions to the NEA Project unless it
first offers Boston Edison an amount of electricity proportionate to its then
current entitlement on substantially the same business terms specified in any
letters or notice of intent with the applicable third party and Boston Edison
does not accept such terms.
Qualifying Facility Status. The Boston Edison II Power Purchase
Agreement does not require that the NEA Project's QF status be maintained.
However, NEA has warranted to Boston Edison that NEA will use its best efforts
to maintain the NEA Project's QF status.
Events of Default and Remedies; Termination. The occurrence of any one
or more of the following events constitutes an Event of Default under the Boston
Edison II Power Purchase Agreement and may result in termination of the Boston
Edison II Power Purchase Agreement and the exercise of other remedies by the
non-defaulting party: (i) the dissolution or liquidation of either party; (ii)
the failure by either party to perform or observe any of the material terms of
the Boston Edison II Power Purchase Agreement, where such failure has not been
cured within 45 days of notice thereof by the non-defaulting party, or, where
cure is not practicable within 45 days, cure has not been undertaken within 45
days and completed within a reasonable period not to exceed two years (subject
to force majeure); (iii) certain events of bankruptcy and insolvency; (iv) the
failure of NEA (other than due to the acts or omissions of Boston Edison) to
deliver at least 367.92 million kWh of electricity per year (equivalent to 84 MW
at 50% capacity factor annually) to Boston Edison in each of three consecutive
contract years, whether or not such failure is due to force majeure, except that
such failure shall not be an event of default if (x) on or before the final day
of such three year period, NEA delivers to Boston Edison the report of an
independent engineer stating that the NEA Project is expected to be generating
electricity at or near its 290 MW Net Electrical Capability within 90 days, and
(y) the NEA Project begins generating at such level within 90 days; and (v)
either party contests the enforceability of the Boston Edison I Power Purchase
Agreement.
Commonwealth I Power Purchase Agreement
The Power Purchase Agreement entered into by NEA and Commonwealth as of
November 26, 1986 (the "Commonwealth I Power Purchase Agreement"), provides for
the sale to Commonwealth of approximately 9% of the net power actually generated
by the NEA Project.
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Term. The Commonwealth I Power Purchase Agreement extends for a term of
25 years expiring September 15, 2016. The Commonwealth I Power Purchase
Agreement does not have any provision for extension of its term.
Purchase and Delivery. Pursuant to the Commonwealth I Power Purchase
Agreement, NEA is obligated to sell and deliver to Commonwealth, and
Commonwealth is obligated to accept, a portion of the available capacity and
hourly generation of the NEA Project equal to the ratio of 25 MW to the Net
Electrical Capability of 290 MW of the NEA Project multiplied by 100% of the
available capacity and hourly generation of the NEA Project, or approximately 9%
of the net power actually generated. Project output is dependent, among other
things, on ambient temperatures, and is therefore subject to some variation.
Whenever the NEA Project is operating above or below its Net Electrical
Capability of 290 MW, the output sold to Commonwealth and other NEA Power
Purchasers will be increased or reduced proportionately. NEA has the right to
withdraw the NEA Project from service and to cease to supply electricity to
Commonwealth as necessary to perform any maintenance or repair of the NEA
Project.
Curtailment. Commonwealth has the right under the Commonwealth I Power
Purchase Agreement to curtail or interrupt the taking of electricity when, in
its reasonable judgment, such curtailment or interruption is needed or desirable
in order to restore service on Commonwealth's system or those systems with which
it is directly or indirectly connected or whenever any of such systems
experience a system emergency.
Pricing. The Commonwealth I Power Purchase Agreement provides for a
payment per kWh for all power delivered to Commonwealth consisting of (i) a
fixed capacity payment of 2.00 cents per kWh, (ii) an energy payment of 3.375
cents per kWh through December 31, 1998, and 2.70 cents per kWh thereafter,
multiplied by the ratio of (x) the actual price per barrel of Number 6 fuel oil
to (y) a base price of $16.69 per barrel, and (iii) a production factor not to
exceed plus or minus 0.4 cents, depending on the extent to which availability in
the preceding year has exceeded or been less than 85%. The energy payment
component of the foregoing price is subject to the floor price of at least 4.50
cents per kWh through December 31, 2000. The foregoing price is required to be
paid for 99% of the kWh delivered to Commonwealth minus non-pool transmission
facility losses. As a result of the foregoing formula, the price paid by
Commonwealth will be influenced significantly by changes in the price of Number
6 fuel oil. During 1997, the average price per kWh under this contract was 6.76
cents.
Contract Security. To secure its performance under the Commonwealth I
Power Purchase Agreement (as well as the other NEA Power Purchase Agreements),
NEA has granted Commonwealth, Boston Edison and Montaup the NEA Second Mortgage
on the NEA Site and the NEA Project, subordinated only to the rights of the
Project Secured Parties pursuant to the NEA Project Mortgage and certain
replacements thereof. In addition, NEA has granted Commonwealth an
unsubordinated declaration of easements, encumbering the NEA Project for the
term of the Commonwealth I Power Purchase Agreement. This declaration provides
Commonwealth with limited access to the NEA Project under certain specified
conditions and obligates any subsequent owner of the NEA Project to sell to
Commonwealth its entitlement under the Commonwealth I Power Purchase Agreement.
See "-- Accommodation Agreement" below.
Sale of Power to Other Purchasers. The Commonwealth I Power Purchase
Agreement has a "most favored nation" clause specifying that Commonwealth will
be given the benefit of any more favorable terms established in future NEA power
sales contracts or any amendment to any other NEA Power Purchase Agreement
provided that it agrees to be bound by the other substantive provisions thereof.
Pursuant to a Consent and Agreement, dated as of June 28, 1989, and confirmed in
a Confirmation Agreement, dated October 13, 1994, subject to conditions
contained therein, Commonwealth has irrevocably waived its rights to invoke the
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"most-favored nation" clause. The Commonwealth I Power Purchase Agreement also
specifies that NEA shall not enter into any contract for the sale of electricity
from any additions to the NEA Project unless it first offers a contract to
Commonwealth for the sale of a proportionate amount of such electricity
according to Commonwealth's then current entitlement under the Commonwealth I
Power Purchase Agreement on the same terms as those specified in any proposal to
another party.
Transmission. Under the Commonwealth I Power Purchase Agreement, NEA
bears all risk and expenses with respect to the provision of transmission
services to Commonwealth for the term of the contract.
Qualifying Facility Status. Commonwealth's obligations under the
Commonwealth I Power Purchase Agreement were conditioned upon the NEA Project's
being certified as a QF on the in-service date, which condition was satisfied.
NEA has agreed to use its best efforts to maintain such status, and in the event
that the QF status of the NEA Project is revoked, NEA has agreed to use its best
efforts to regain the certification and both parties have agreed to continue to
purchase and sell electrical power on the terms set forth in the Commonwealth I
Power Purchase Agreement (including those relating to price).
Commonwealth II Power Purchase Agreement
The Power Sale Agreement entered into by NEA and Commonwealth as of
August 15, 1988 (the "Commonwealth II Power Purchase Agreement") provides for
the sale to Commonwealth of approximately 7% of the net power actually generated
by the NEA Project.
Term. The Commonwealth II Power Purchase Agreement extends for a term
of 25 years expiring September 15, 2016. The Commonwealth II Power Purchase
Agreement does not have any provision for extension of its term.
Purchase and Delivery. Pursuant to the Commonwealth II Power Purchase
Agreement, NEA is obligated to sell and deliver and Commonwealth is obligated to
accept a portion of the available capacity and hourly generation of the NEA
Project equal to the ratio of 21 MW to the Net Electrical Capability of 290 MW
of the NEA Project multiplied by 100% of the available capacity and hourly
generation of the NEA Project, or approximately 7% of the net power actually
generated. Project output is dependent, among other things, on ambient
temperatures, and is therefore subject to some variation. Whenever the NEA
Project is operating above or below its Net Electrical Capability of 290 MW, the
output sold to Commonwealth and other NEA Power Purchasers will be increased or
reduced proportionately. NEA has the right to withdraw the NEA Project from
service and to cease to supply electricity to Commonwealth as necessary to
perform any maintenance or repair to the NEA Project.
Curtailment. Commonwealth has the right under the Commonwealth II Power
Purchase Agreement to curtail or interrupt the taking of electricity when, in
its reasonable judgment, such curtailment or interruption is needed or desirable
in order to restore service on Commonwealth's system or those systems with which
it is directly or indirectly connected or whenever any of such systems
experience a system emergency.
Pricing. The Commonwealth II Power Purchase Agreement provides for
fixed payments of 4.5 cents per kWh for all power delivered to Commonwealth in
1992 and 4.84 cents per kWh in 1993, rising thereafter at a fixed escalation
rate of 7.5% per year, which are payable with respect to 99% of the kWh
delivered to Commonwealth minus non-pool transmission facility losses. The rate
per kWh in 1997 was 6.46 cents.
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Contract Security. To secure its performance under the Commonwealth I
Power Purchase Agreement (as well as the other NEA Power Purchase Agreements),
NEA has granted Commonwealth, Boston Edison and Montaup the NEA Second Mortgage
on the NEA Site and the NEA Project, subordinated only to the rights of the
Project Secured Parties pursuant to the NEA Project Mortgage and certain
replacements thereof. In addition, NEA has granted Commonwealth an
unsubordinated declaration of easements, encumbering the NEA Project for the
term of the Commonwealth II Power Purchase Agreement. This declaration provides
Commonwealth with limited access to the NEA Project under certain specified
conditions and obligates any subsequent owner of the NEA Project to sell to
Commonwealth its entitlement under the Commonwealth II Power Purchase Agreement.
See "-- Accommodation Agreement" below. Finally, The Commonwealth II Power
Purchase Agreement requires that NEA's obligations be secured by a letter of
credit in the amount of $1 million until September 15, 1998.
Sale of Power to Other Purchasers. The Commonwealth II Power Purchase
Agreement has a "most favored nation" clause specifying that Commonwealth will
be given the benefit of any more favorable terms established in future NEA power
sales contracts or any amendment to any other NEA Power Purchase Agreement
provided that it agrees to be bound by the other substantive provisions thereof.
Pursuant to a Consent and Agreement, dated as of June 28, 1989, and confirmed in
a Confirmation Agreement, dated October 13, 1994, subject to conditions
contained therein, Commonwealth has irrevocably waived its rights to invoke the
"most-favored nation" clause. The Commonwealth II Power Purchase Agreement also
specifies that NEA shall not enter into any contract for the sale of electricity
from any additions to the NEA Project unless it first offers a contract to
Commonwealth for the sale of a proportionate amount of such electricity
according to Commonwealth's then current entitlement under the Commonwealth II
Power Purchase Agreement on the same terms as those specified in any proposal to
another party.
Transmission. Under the Commonwealth I Power Purchase Agreement, NEA
bears all risk and expenses with respect to the provision of transmission
services to Commonwealth for the term of the contract.
Qualifying Facility Status. Commonwealth's obligations under the
Commonwealth II Power Purchase Agreement were initially conditioned upon the NEA
Project's being certified as a QF on the in-service date, which condition was
satisfied. NEA has agreed to use its best efforts to maintain such status, and
in the event that the NEA Project's QF status is revoked, NEA has agreed to use
its best efforts to regain the certification and both parties have agreed to
continue to purchase and sell power on the terms set forth in the Commonwealth
II Power Purchase Agreement (including those relating to price).
Montaup Power Purchase Agreement
The Power Purchase Agreement entered into by NEA and Montaup as of
October 17, 1986 (the "Montaup Power Purchase Agreement") provides for the sale
to Montaup of approximately 9% of the net power actually generated by the NEA
Project.
Term. The Montaup Power Purchase Agreement extends for an initial term
of 30 years expiring September 15, 2021, subject to earlier termination in
accordance with its terms. The Montaup Power Purchase Agreement will remain in
effect thereafter until either party terminates the contract by giving the other
party six months' written notice of such termination.
Purchase and Delivery. Pursuant to the Montaup Power Purchase
Agreement, NEA is obligated to deliver to Montaup, and Montaup is obligated to
accept, a portion of the available capacity and hourly generation of the NEA
Project equal to the ratio of 25 MW to the Net Electrical Capability of 290 MW
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of the NEA Project multiplied by 100% of the available capacity and hourly
generation of the NEA Project, or approximately 9% of the net power actually
generated. Project output is dependent, among other things, on ambient
temperatures, and is therefore subject to some variation. Whenever the NEA
Project is operating below its Net Electrical Capacity of 290 MW, the output
sold to Montaup and other NEA Power Purchasers will be reduced proportionately.
Whenever the NEA Project is operating above its Net Electrical Capacity of 290
MW, NEA may sell the increased output to Montaup or another power purchaser
subject to Montaup's right of first refusal.
Curtailment. Montaup has the right under the Montaup Power Purchase
Agreement to refuse power for up to 200 hours per year, at its reasonable
discretion, in addition to its other curtailment rights described below. Montaup
has the right to interrupt, reduce or refuse to purchase electric energy, and
NEA has the right to interrupt, reduce or refuse to deliver electric energy, in
order to install equipment, make inspections or perform maintenance and repairs.
In addition, Montaup has the right to curtail or interrupt the taking of
electric energy for as long as reasonably necessary in the event of an
emergency.
Pricing. The Montaup Power Purchase Agreement provides for an energy
payment per kWh for all power delivered to Montaup equal to 75% of Montaup's
Qualifying Facility Power Purchase Rate (described below) in each year through
2000 and at least 75% but no more than 95% of such rate thereafter, dependent
upon the balance in the Energy Bank in such year, together with an average fixed
capacity payment of 1.04 cents per kWh, which is not subject to adjustment
provided that peak-hour availability remains in excess of 80%. The Montaup Power
Purchase Agreement further provides that the minimum rate to be received by NEA
is 6.50 cents per kWh through 2000, after which no minimum rate applies. The
foregoing rates are payable in respect of 99% of the kilowatt hours delivered by
NEA for sale to Montaup under the Montaup Power Purchase Agreement. Montaup's
Qualifying Facility Power Purchase Rate is a rate determined under state law
based on Montaup's Avoided Cost of power production. If, due to transmission
constraints, Montaup must purchase power from NEA rather than a lower priced
source, then the purchase price for such power will be the lower price Montaup
was forced to forego. However, this substitute rate is only available for up to
100 hours annually. During 1997, the payment per kWh under the Montaup Power
Purchase Agreement was 6.5 cents.
Energy Bank Liability and Support. The Montaup Power Purchase Agreement
provides for an Energy Bank, and the Energy Bank balance under the Montaup Power
Purchase Agreement will be increased to the extent that the price paid by
Montaup exceeds the greater of (i) Montaup's Qualifying Facility Power Purchase
Rate and (ii) an Energy Bank floor rate. The Energy Bank floor rate is specified
pursuant to a fixed schedule. Positive Energy Bank balances are reduced to the
extent payments to NEA are less than the foregoing Energy Bank rates. Positive
balances are subject to interest each month at the prime rate as established
from time to time by the First National Bank of Boston. As of December 31, 1997
the Energy Bank balance under the contract was approximately $27,035,000. The
Montaup Power Purchase Agreement requires NEA to deliver a letter of credit to
Montaup securing the payment of positive Energy Bank balances. However, the face
amount of the letter of credit is not required to exceed $12.656 million or (if
less) the remaining Energy Bank balance.
Contract Security. To secure its performance under the Montaup Power
Purchase Agreement, NEA has granted Montaup (as well as other NEA Power
Purchasers), the NEA Second Mortgage, subordinated only to the rights of the
Project Secured Parties pursuant to the NEA Project Mortgage and certain
replacements thereof. In addition, NEA has granted Montaup an unsubordinated
Declaration of Easements, encumbering the NEA Project for the life of the
Montaup Power Purchase Agreement. This declaration provides Montaup with limited
access to the NEA Project and obligates any subsequent owner of the NEA Project
to sell Montaup in contract entitlement. See "-- Accommodation Agreement" below.
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Right of First Refusal. Montaup has a right of first refusal for the
purchase of any additional capacity generated by the NEA Project and not covered
by the Power Purchase Agreements with Boston Edison and Commonwealth,
proportionate to its then current entitlement. Any capacity currently covered by
Boston Edison's or Commonwealth's entitlement which becomes available in the
future is also subject to Montaup's proportionate right of first refusal.
Transmission. Under the Montaup Power Purchase Agreement, NEA is
responsible for, bears all risk with respect to and is required to pay all
expenses in connection with the provision of transmission services to Montaup
for the term of the contract.
Qualifying Facility Status. NEA has warranted to Montaup that as of the
date the NEA Project commenced operations, it would be a QF, and that should the
NEA Project lose its QF status thereafter, NEA would use its best efforts to
regain such status. Montaup is entitled to renegotiate the pricing provisions of
the Montaup Power Purchase Agreement in the event that the NEA Project's QF
status is revoked.
NJEA Power Purchase Agreement
The Power Purchase Agreement entered into by JCP&L and NJEA as of
October 22, 1987 (the "JCP&L Power Purchase Agreement"), provides for the sale
of 250 MW of power from the NJEA Project's baseload power.
Term. The JCP&L Power Purchase Agreement extends for an initial term of
20 years expiring August 13, 2011, and may be extended for an additional five
year period upon written notice by JCP&L to NJEA, subject to the renegotiation
of the price terms for any such extension.
Purchase and Delivery. Pursuant to the JCP&L Power Purchase Agreement,
NJEA is obligated to deliver to JCP&L, and JCP&L is obligated to accept, the
contract capacity of not less than 250 MW and up to 2.2 million MwH per year of
associated energy (250 MW at 100% capacity factor annually) from the NJEA
Project throughout the term of the JCP&L Power Purchase Agreement. JCP&L has
certain rights, but not the obligation, to purchase certain energy produced by
the NJEA Project in excess of 250 MW per hour at a discounted price.
Curtailment. Pursuant to the JCP&L Power Purchase Agreement, JCP&L has
the right, for up to 200 hours annually during the period expiring August 13,
2001, and for 400 hours annually thereafter, to refuse electric power from the
NJEA Project, in any event on no more than 20 separate occasions annually, if
conditions on the PJM Interconnected Power Pool system are such that generators
of all PJM member utilities are required to reduce generation to minimum levels
during periods of low load in accordance with applicable procedures. In
addition, without affecting the number of hours during which JCP&L may refuse
power under the circumstances described above, JCP&L may refuse power: (i) for
up to 200 hours annually during off peak periods (provided that each such
curtailment shall be for a minimum of six hours); (ii) when JCP&L deems such
refusal to be in keeping with prudent utility practices or necessary to
facilitate construction, installation, maintenance, repair or inspection of any
of JCP&L's or NJEA's facilities or equipment, to maintain JCP&L's system
integrity, or due to emergency, forced outages, potential overloading or force
majeure and (iii) if NJEA's operation of the NJEA Project endangers JCP&L
personnel, until such dangerous condition is corrected.
Interconnection. NJEA has agreed to design, construct and provide
during the term of the JCP&L Power Purchase Agreement all interconnection
facilities and protective apparatus necessary to effect delivery of power to
JCP&L's system pursuant to the JCP&L Power Purchase Agreement, subject to
JCP&L's approval and in accordance with its standards.
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Pricing. The JCP&L Power Purchase Agreement provides for payment to
NJEA of: (i) a variable energy payment referencing JCP&L's 1989 cost of gas,
indexed to the cost of gas purchased by New Jersey utilities; (ii) a capacity
payment that is made for power purchased during peak hours in peak season
(approximately 1,800 hours per year); and (iii) a fixed energy payment. For the
elapsed portion of the operating year commencing in August, 1994 (through July
1995), the average variable energy payment has been 2.296 cents per kWh, the
capacity payment has been 6.41 cents per kWh and the average fixed energy
payment has been 2.2 cents per kWh, for a total average payment of 5.85 cents
per kWh. Commencing in July, 1994, and for each year thereafter, if average
annual on-peak electricity generation is less than 85% of the average annual
on-peak generation during the three preceding years, a penalty payment of 3.6
cents for each kWh of shortfall in average on-peak generation for such year will
be due to JCP&L from NJEA.
Energy Bank. Although the JCP&L Power Purchase Agreement provides for
an Energy Bank, there is no liability remaining for the Energy Bank under the
JCP&L Power Purchase Agreement.
Right of First Offer. Other than in connection with the financing or
refinancing of the NJEA Project, NJEA has agreed under the JCP&L Power Purchase
Agreement that it will not sell or transfer all or any portion of the NJEA
Project without the prior written consent of JCP&L. The JCP&L Power Purchase
Agreement also grants a right of first offer to JCP&L for any such sale or
transfer.
Right of First Refusal. If as a result of improvements or the
construction of additional generating units the capacity of the NJEA Projects
increased, then JCP&L has a right of first refusal on such excess capacity
produced by the NJEA Project on terms no less favorable than those offered to
any third party in an arm's length transaction for such excess capacity.
Qualifying Facility Status. NJEA is required under the JCP&L Power
Purchase Agreement to maintain the NJEA Project's QF status for so long as PURPA
or legislation of similar import is in effect. Failure to maintain such status
constitutes an event of default under the JCP&L Power Purchase Agreement.
Remedies; Events of Default; Termination. The occurrence of any one or
more of the following events constitutes an event of default and may result in
termination of the JCP&L Power Purchase Agreement by the non-defaulting party:
(i) a material breach of any material term or condition of the JCP&L Power
Purchase Agreement, including but not limited to failure to maintain the
collateral security, breach of any representation, warranty or covenant and
failure of either party to make a required payment to the other party of amounts
due under the contract, or failure by a party to provide any required schedule,
report or notice if such failure is not cured within 30 days after notice to the
defaulting party; (ii) failure by NJEA to deliver electricity for a period of
365 consecutive days for any reason except as may be excused by force majeure;
(iii) sale or supply of electricity by NJEA from the NJEA Project, or agreement
by NJEA to sell or supply electricity, to anyone other than JCP&L at times when
JCP&L can accept delivery of such electricity; (iv) failure by JCP&L to accept
deliveries of electricity from NJEA Project for a period of 90 consecutive days
for any reason other than force majeure or as otherwise permitted by the
contract; (v) certain events of insolvency or bankruptcy; or (vi) revocation by
FERC at any time during the term of the JCP&L Power Purchase Agreement of the
NJEA Project's certification as a Qualifying Facility. Upon the occurrence of
any event of default, the non-defaulting party may furnish the other party with
a written of default. If the defaulting party does not cure or make a good faith
attempt to cure such event of default within 30 days of such notice, the
non-defaulting party may terminate the JCP&L Power Purchase Agreement and may
exercise all other remedies. Either party may terminate the JCP&L Power Purchase
Agreement upon 10 days' written notice if (i) the NJEA Project is either
substantially damaged or destroyed and NJEA advise JCP&L that it does not intend
to reconstruct or repair the NJEA Project promptly or (ii) an event of force
majeure prevents either party from making substantial performance of its
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respective obligations for a period of 24 consecutive months. In addition,
JCP&L, at its sole election and without any obligation to do so, may assume
management control of and otherwise operate the NJEA Project as necessary to
generate and deliver electric power from the NJEA Project to JCP&L's system (i)
upon the occurrence of an event of default, other than an event of default due
to force majeure, or (ii) in the event that NJEA fails to operate and maintain
the NJEA Project in accordance with the terms and conditions of the JCP&L Power
Purchase Agreement for a period of 60 days after receiving written notice from
JCP&L regarding the need for repairs or replacement of equipment during which
NJEA does not make such necessary repairs or replacements. JCP&L's right to
assume control of and operate the NJEA Project will be limited in time until
such date when NJEA demonstrates to JCP&L's reasonable satisfaction its ability
to resume performance of its obligations under the JCP&L Power Purchase
Agreement. The assumption of control and operation of the NJEA Project by JCP&L
will not, however, create any duty or responsibility on JCP&L to continue
operation of the NJEA Project. NJEA has agreed to indemnify JCP&L from and
against claims (other than those due to JCP&L's gross negligence) stemming from
JCP&L's control and operation of the NJEA Project, and NJEA has waived all
claims it may have against JCP&L in the future (other than for damages arising
from JCP&L's gross negligence) as a result of any injury or damages to any
property during the time of JCP&L's control or operation of the NJEA Project
pursuant to the terms of the JCP&L Power Purchase Agreement. NJEA is required to
reimburse JCP&L for any expenses reasonably incurred by JCP&L in operating the
NJEA Project or JCP&L may set off such expenses against amounts due to NJEA
under the JCP&L Power Purchase Agreement.
Steam Sales Agreements
NEA
The NEA Project is adjacent to the Carbon Dioxide Plant, which is
presently being leased by NEA to NECO pursuant to the NECO Lease. NEA sells
steam to NECO for use in the Carbon Dioxide Plant pursuant to the NEA Steam
Sales Agreement. The principal terms of the NEA Steam Sales Agreement and the
NECO Lease are summarized below.
NEA Steam Sales Agreement
The Amended and Restated NEA Steam Sales Agreement dated as of December
21, 1990 between NEA and NECO (the "NEA Steam Sales Agreement") provides for the
exclusive sale by NEA to NECO of a minimum of 60,000 pounds and a maximum of
120,000 pounds of steam per hour when the NEA Project is being fueled by 100%
pipeline quality natural gas, subject to certain limited exceptions. NECO will
at all times have immediate first call on steam up to such maximum amount,
provided, however, that if NEA is unable to satisfy NECO's steam needs for any
period more than ten days, NECO may seek alternative sources of steam.
Term. The NEA Steam Sales Agreement extends for the same term as that
of the NECO Lease described below, with automatic extension for any renewal
period elected under the NECO Lease.
Price. The monthly base price payable by NECO to NEA for steam
delivered under the NEA Steam Sales Agreement is $3.50 per thousand pounds of
steam, subject to periodic adjustments based on the blended base prices for
natural gas in the ProGas Agreements. The minimum base price also is subject to
adjustment for, among other things, liquidated damages as described below under
"Minimum Output."
Minimum Output. Under the NEA Steam Sales Agreement, NEA has agreed to
deliver a minimum output of 60,000 pounds of steam per hour when the NEA Project
is being fueled by 100% pipeline quality natural gas. All such steam deliveries
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are required to take place for at least 80% of the hours in each year, adjusted
for excused downtime and subject to the force majeure provisions described
below. In every fourth year of the NEA Steam Sales Agreement, the hourly
percentage drops to 75% to allow for routine maintenance. In any operating year
in which the minimum outputs are not met, NEA is obligated to pay liquidated
damages for each hour of shortfall equal to the sum of the hourly cost of NECO's
operating and maintenance expenses, property taxes and basic rent under the NECO
Lease, each calculated as the annual charge for such expenses divided by 8,760
hours per year.
NECO has contracted to purchase (during each hour that the NEA Project
is in commercial operation using 100% pipeline quality natural gas) a minimum of
5% of the total energy output of the NEA Project so as to meet requirements set
by PURPA in order to maintain the NEA Project's QF Status. NECO is obligated to
buy all of its steam from the NEA Project, subject to limited exceptions, and
also is obligated to return all condensate to the NEA Project.
NECO may defer payment for all or a portion of the steam it takes if
after deferring its payments under the NECO Lease, NECO's monthly expenses still
exceed its monthly revenues. If the amounts due to NEA are reduced to zero and
NECO continues to incur losses, NEA may reimburse NECO for such losses or
alternatively, NEA may terminate the NECO Lease and the NEA Steam Sales
Agreement.
Liability. The NEA Steam Sales Agreement provides that the total
cumulative liability of NEA and any of its contractors, subcontractors and
suppliers arising from, or in any way connected with, its obligations under such
agreement shall not in the aggregate exceed $500,000 in any calendar year
prorated for any portion of such year where such agreement is in effect.
Notwithstanding such maximum aggregate liability provision, neither NEA nor any
of its contractors, subcontractors and suppliers will be liable to NECO or any
of its affiliates for any special, incidental, consequential or indirect losses
or for damage to or loss of property or equipment not furnished under the NEA
Steam Sales Agreement, or for loss of use of the facilities, cost of capital,
lost profits or revenues, costs of replacement power or steam or claims of
customers of NECO.
Assignment. The NEA Steam Sales Agreement and the NECO Lease may be
assigned by either party with the written consent of the other party, or by NEA
without any such consent (i) to any NEA affiliate, (ii) to a lender as security
for financing for NEA or its affiliates, (iii) as a security assignment or (iv)
to any successor or entity to NEA. NECO has granted its consent to the
assignment of NEA's rights under the NEA Steam Sales Agreement as collateral
security pursuant to the Project Security Documents.
Breach/Remedies. NEA may temporarily suspend sales of steam under the
NEA Steam Sales Agreement for (i) fraudulent or unauthorized use of NEA's meters
or (ii) an assignment of the NEA Steam Sales Agreement by NECO not made in
accordance with the requirements for assignment under the NEA Steam Sales
Agreement. In addition, NEA may suspend sales of steam in the event of the
occurrence of any life-threatening conditions at the Carbon Dioxide Plant until
such conditions are remedied. Upon the occurrence of any of the above events, if
NECO shall fail to remedy such event within 20 days of notice thereof (unless
such event cannot be remedied within such period to avoid exercise of the
following remedies) NEA may terminate the NEA Steam Sales Agreement. NEA may
also terminate the NEA Steam Sales Agreement if (i) NECO shall fail to pay any
bill for steam within 15 days of such bill's due date, (ii) NECO shall fail to
satisfy its minimum purchase requirement of 5% of the NEA Project's total energy
output, (iii) NECO terminates the NECO Lease at its option or (iv) an event of
default under the NECO Lease shall have occurred and be continuing.
Interconnection Obligations. The NEA Steam Sales Agreement provides
that NEA is responsible for all auxiliary equipment and systems required to
supply steam to the point of interconnection with the Carbon Dioxide Plant.
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Lease of Carbon Dioxide Facility
The NECO Lease, dated as of December 31, 1990, provides for the lease
of the Carbon Dioxide Plant and certain related utilities by NEA to NECO.
Term. The NECO Lease has an initial term of 15 years expiring June 1,
2007. The NECO Lease may be renewed at NECO's option for up to four subsequent
five year periods, with such option to be exercised at the end of the initial
term or any five year renewal period, as applicable. The NECO Lease may be
terminated by NEA upon 30 days' written notice to NECO, subject to payment by
NEA of any amounts that may be due to NECO as a result of certain rent
adjustment provisions of the NECO Lease. The NECO Lease may also be terminated
by NEA for its convenience upon the occurrence of an event of default, as
defined in the NECO Lease. NEA has agreed with Praxair and BOC Gases that if
NECO fails to satisfy its obligations to Praxair or BOC Gases, NEA will
terminate the NECO Lease within 45 days after notice of such failure.
Operation. The Carbon Dioxide Plant is operated by Westinghouse
Services pursuant to a separate operating agreement between Westinghouse
Services and NECO.
Rent. The basic rent payable by NECO to NEA pursuant to the NECO Lease
is $100,000 per month and is subject to adjustment based upon the monthly
profits or losses realized by NECO in connection with the operation of the
Carbon Dioxide Plant.
Right of First Refusal. Absent an event of default under the NECO
Lease, NECO has a right of first refusal with respect to any sale of the Carbon
Dioxide Plant.
Event of Loss. Under the NECO Lease, NECO is required to pay to NEA, as
promptly as practicable and in any event within five days following the receipt
of insurance proceeds with respect to the occurrence of an event of loss (as
defined in the NECO Lease) with respect to the Carbon Dioxide Plant, an amount
equal to the sum of (a) any insurance proceeds so received plus (b) any rent
accrued but unpaid plus (c) any amount payable under the NEA Steam Sales
Agreement accrued but unpaid.
NJEA Steam Sales Agreement
The NJEA Project sells steam to Hercules pursuant to the Industrial
Steam Sales Contract dated as of June 5, 1990 between NJEA and Hercules (the
"NJEA Steam Sales Agreement"). The NJEA Steam Sales Agreement provides for the
sale by NJEA to Hercules of up to an annualized maximum of 205,000 pounds of
steam per hour when both gas turbines at the NJEA Project are fully operational
and up to a maximum of 100,000 pounds of steam per hour when only one gas
turbine is fully operational.
Term. The NJEA Steam Sales Agreement extends for a term of 20 years
expiring August 13, 2011, subject to automatic renewal for two consecutive
five-year terms unless either party to the agreement gives written notice of its
intent not to renew at least two years before the expiration of the then-current
term.
Price. The monthly floor price payable by Hercules to NJEA for steam
delivered under the NJEA Steam Sales Agreement is $2.50 per thousand pounds of
steam, subject to monthly escalation (which began in September, 1991) based on a
national coal price index. After Hercules has purchased steam amounting to
205,000 pounds per hour on an annualized basis or purchased more than 230,000
pounds of steam per hour in any given hour, Hercules also is required to pay the
fuel costs associated with the production of additional steam, payable within 20
days of receipt of NJEA's invoice.
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Minimum Purchase Obligation. Hercules is required, for any hour in
which it purchases steam, to purchase an hourly minimum of 30,000 pounds of
steam, and a minimum of 415.8 million pounds of steam annually. Hercules is
required to apply 378 million pounds of such steam to thermal uses annually,
which will satisfy the minimum thermal use requirement for maintaining the NJEA
Project's QF status under PURPA. However, Hercules has no obligation to continue
purchasing steam in the event that it closes or abandons its Parlin plant. NJEA
is entitled to a minimum of 90 days advance notice of any such closure. NJEA has
an option under the NJEA Steam Sales Agreement to lease the Parlin plant site
from Hercules in the event of any such closure. Pursuant to the NJEA Steam Sales
Agreement, the terms and conditions of any lease entered into pursuant to such
option are subject to negotiation, except that the term of any such lease shall
not be for a period that is less than the unexpired term of the NJEA Steam Sales
Agreement when the parties enter into such lease.
Events of Default and Remedies. Events of default by Hercules under the
NJEA Steam Sales Agreement include (i) failure to pay bills for steam when due
within 30 days of notice of such failure, (ii) fraudulent use of meters which
continues for 90 days after notice thereof and (iii) breach of any other
material obligation under the NJEA Steam Sales Agreement which continues
unremedied for 90 days after notice thereof. NJEA may terminate the NJEA Steam
Sales Agreement in the event of any such event of default. Events of default by
NJEA under the NJEA Steam Sales Agreement include (i) fraudulent use of meters
and failure to cure within 90 days following notice thereof, (ii) failure to
deliver on an annual average basis a minimum of 85% of the total steam used by
Hercules in its Parlin plant, (iii) more than five total forced outages
resulting in total loss of steam production for more than 15 minutes in any full
calendar year and (iv) more than 15 partial forced outages resulting in a loss
of 10% of steam production of more than 15 minutes in any full calendar year. In
the event NJEA fails to deliver at least 85% of Hercules' steam requirement,
NJEA is required to reimburse Hercules for up to $800,000 of Hercules' cost of
making replacement steam. In the event that there are more than five total
outages or more than 15 partial outages in a year, including those due to force
majeure, NJEA is required to pay Hercules $40,000 per total forced outage and
$5,000 per partial forced outage up to a maximum of $200,000 annually.
Gas Purchase Agreements
NEA ProGas Agreement
Quantities. The Gas Purchase Contract dated as of May 12, 1988 and
amended as of April 17, 1989, June 23, 1989, November 1, 1991 and June 30, 1993
between NEA and ProGas (the "NEA ProGas Agreement") provides for the sale by
ProGas to NEA of 49,560 Mcf of natural gas per day, with an equivalent heating
value of at least 48,817 Dth (the "Daily NEA Quantity"). If NEA fails to take
75% of the annualized Daily NEA Quantity in any contract year, then NEA is
required to purchase additional gas in the following contract year to make up
any such deficiency. If NEA fails to purchase such required quantities in any
year, ProGas has the right to bill NEA monthly for interest at the rate of the
then-current Canadian Imperial Bank of Commerce prime rate plus 2% on the
contract price that would have been payable in respect of the shortfall amount.
Further, following any such year in which NEA fails to take such percentage of
the annualized Daily NEA Quantity, ProGas has the right to renegotiate the Daily
NEA Quantity unless NEA was unable to take the required amount due to the
temporary inability of the NEA Project to utilize the gas supplies. If NEA
requests volumes in excess of the Daily NEA Quantity, ProGas may accommodate
74
such requests on a best efforts basis. If ProGas fails to deliver the required
quantities on a sustained basis, ProGas will, contingent on receipt of any
necessary regulatory approvals extend deliveries beyond the primary term in
order to permit NEA to recover such deficiencies. If ProGas fails to deliver the
required quantities in any contract year by an amount greater than ten percent,
NEA has the right to renegotiate the Daily NEA Quantity. If the NEA Facility
experiences certain outages and NEA does not require natural gas for any other
purpose, NEA may notify ProGas that such gas supplies are available to ProGas
for resale. ProGas will use all reasonable efforts to remarket such gas supplies
in order to relieve NEA of its purchase obligations.
Term. The term of the NEA ProGas Agreement is 22 years expiring
November 1, 2013. The final seven years of this term constitutes an extension of
the original 15 year term which has been agreed to by the parties and approved
by the producers and Canadian regulatory authorities.
Delivery Point. Gas delivered by ProGas under the NEA ProGas Agreement
is delivered to the Import Point at Niagara Falls, Ontario/Niagara Falls, New
York. For a description of transportation arrangements for such gas from the
Import Point to the NEA Project, see "-- Gas Transportation and Storage
Agreements" below.
Price. The actual billings to NEA by ProGas are developed through the
use of a two-part rate structure, consisting of a monthly demand charge which is
subject to a commodity charge. The monthly demand charge is the product of the
average Daily NEA Quantity and the monthly demand rate where the monthly demand
rate is the sum of (i) the monthly demand toll per Mcf, as determined by
Canada's National Energy Board, charged to ProGas by TransCanada PipeLines
Limited, a Canadian Transporter ("TransCanada"), (ii) the monthly demand toll
per Mcf charged by NOVA Corporation of Alberta, also a Canadian Transporter, to
ProGas and (iii) the monthly demand toll per Mcf charged by ProGas as approved
by the Alberta Petroleum Marketing Commission. Payments pursuant to this monthly
demand charge are based on the anticipated Daily NEA Quantities under the NEA
ProGas Agreement. The monthly demand charge is payable regardless of the actual
volume of gas delivered.
The commodity charge is applied to volumes of gas actually delivered
under the NEA ProGas Agreement and is the difference between the unitized
monthly heating demand rate and the then applicable "base price" escalated from
U.S. $2.7665 per Dth as of January 1, 1990. The "base price," as theretofore
escalated, was further increased by $.038 per Mcf, effective December 1, 1994.
Escalation of the "base price" is determined by reference to the escalation
rates in the Power Purchase Agreements for both Projects. The "base price" for
approximately 70% of the contract quantities is escalated using the weighted
average of (I) the fixed escalators applicable to NEA's fixed price power sales
and (ii) the changes in fuel prices that determine escalation of price under
NEA's Avoided Cost contracts. No more than 150 MW of Avoided Cost sales are
included in this weighing at a price no lower than a floor price of 6.5 cents
per kWh. The remaining contract quantities, approximately 30%, have a "base
price" adjusted annually by the change in the cost of natural gas purchased by
New Jersey electric utilities as reported in FERC Form 423.
The price of gas sold pursuant to the NEA ProGas Agreement will be
adjusted in the event that (i) the NJEA Project has ceased to operate for a
period of six consecutive months and (ii) ProGas is not selling gas under the
NJEA ProGas Agreement on a monthly basis at least equal to 65% of the Daily NJEA
Quantity (as defined below). The price adjustment will be subject to an
escalator based on natural gas costs as determined by FERC and the pricing
provisions contained in the NJEA ProGas Agreement. In any contract year
commencing on or after November 1, 2001, the contract pricing also is subject to
renegotiation or arbitration if the contract prices do not track comparable
long-term service contracts then prevailing. Arbitration conducted between
November 1, 2001 and October 31, 2006 may result in an increase in the
escalation of the "base price," while arbitration conducted between November 1,
2006 and the end of the term may result in an increase or decrease in the rate
75
of escalation of the "base price." In either time period, the change is not to
impair the ability of NEA to cover operating costs of the NJEA project or to
service the debt on the project, nor is it to cause a materially adverse affect
on NEA's net cash flow from the NJEA project. The actual price of the natural
gas service, however, is not subject to arbitration in either time period.
NEA's Right to Pay Gas Transporters and Gas Producers Directly. In the
event of ProGas' bankruptcy, insolvency or failure to pay any transporter of
gas, or to pay gas producers with reserves dedicated in whole or in part to the
NEA ProGas Agreement any amounts due them for transportation services or sale of
gas relating to transportation of gas for ultimate redelivery to NEA or sale of
gas for resale to NEA, NEA shall have the right to the extent permitted by
ProGas' contractual arrangements with transporters or gas producers and subject
to any limitation imposed by law or regulation, to withhold payments due ProGas,
in whole or in necessary part, and from such withheld amounts to pay directly to
any transporter or gas producer the amount due to it from ProGas.
Termination. In the event NEA is 60 or more days in arrears on
undisputed amounts payable, ProGas may terminate the NEA ProGas Agreement
provided it has given NEA 15 days' written notice of its intent to exercise such
right in the event the arrears is not cured within that period. In addition,
ProGas may terminate the NEA ProGas Agreement in the event that each of the
following conditions has occurred and is continuing: (i) NEA has filed a
petition of bankruptcy, (ii) NEA has failed to take an average of 50% of the
Daily NEA Quantity for six consecutive months or has failed to resume acceptance
at an average of 65% of the Daily NEA Quantity during the last month of the
six-month period and (iii) NEA's failure to take such Daily NEA Quantity for
such period is not the result of a force majeure event. NEA may terminate the
NEA ProGas Agreement in the event that each of the following conditions has
occurred and is continuing: (i) ProGas has filed a petition of bankruptcy, (ii)
ProGas has failed to deliver 50% of the volumes designated for six consecutive
months or has failed to resume delivery at a rate of 65% of the volumes
scheduled for daily delivery during the last month of the six month period and
(iii) ProGas' failure to deliver such volumes for such period is not the result
of a force majeure event. In the event that any change in applicable law has a
materially adverse effect on the terms of performance under the NEA ProGas
Agreement, the party adversely affected may terminate such agreement.
NJEA Gas Purchase Agreements
NJEA ProGas Agreement
Quantities. The Gas Purchase Contract dated as of May 12, 1988 and
amended as of April 17, 1989, June 23,1989, November 1, 1991, and July 30, 1993
between NJEA and ProGas (the "NJEA ProGas Agreement") provides for the sale by
ProGas to NJEA of 22,354 Mcf of natural gas per day, with an equivalent heating
value of at least 22,019 Dth (the "Daily NJEA Quantity"). If NJEA fails to take
75% of the annualized Daily NJEA Quantity in any contract year, then NJEA is
required to purchase additional gas in the following contract year to make up
any such deficiency. If NJEA fails to purchase such required quantities in any
year, ProGas has the right to bill NJEA monthly for interest at the rate of the
then-current Canadian Imperial Bank of Commerce prime rate plus 2% on the
contract price that would have been payable in respect of the shortfall amount.
Further, following any such year in which NJEA fails to take such percentage of
the annualized Daily NJEA Quantity, ProGas has the right to renegotiate the
Daily NJEA Quantity unless NJEA was unable to take the required amount due to
the temporary inability of the NJEA Project to utilize the gas supplies, if NJEA
requests volumes in excess of the Daily NJEA Quantity, ProGas may accommodate
such requests on a best efforts basis. If ProGas fails to deliver the required
quantities on a sustained basis, ProGas will, contingent on receipt of any
required regulatory approvals, extend deliveries beyond the primary term in
order to permit NJEA to recover such deficiencies. If ProGas fails to deliver
the required quantities in any contract year by an amount greater than ten
percent, NJEA has the right to renegotiate the Daily NJEA Quantity. If the NJEA
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Facility experiences certain outages and NJEA does not require natural gas for
any other purpose, NJEA may notify ProGas that such gas supplies are available
to ProGas for resale. ProGas will use all reasonable efforts to remarket such
gas supplies in order to relieve NJEA of its purchase obligations.
Term. The term of the NJEA ProGas Agreement is 22 years expiring
November 1, 2013. The final seven years of this term constitutes an extension of
the original 15 year term, which has been agreed to by the parties and approved
by the producers and Canadian regulatory authorities.
Delivery Point. Gas delivered by ProGas under the NJEA ProGas Agreement
is delivered to the Import Point at Niagara Falls, Ontario/ Niagara Falls, New
York. For a description of transportation arrangements for such gas from the
Import Point to the NJEA Project see "-Gas Transportation and Storage
Agreements" below.
Price. The actual billings to NJEA by ProGas are developed through the
use of a two-part rate structure, consisting of a monthly demand charge which is
subject to a commodity charge. The monthly demand charge is the product of the
average Daily NJEA Quantity and the monthly demand rate where the monthly demand
rate is the sum of (i) the monthly demand toll per Mcf, as determined by
Canada's National Energy Board, charged to ProGas by TransCanada, (ii) the
monthly demand toll per Mcf charged by NOVA Corporation of Alberta, also a
Canadian Transporter, to ProGas and (iii) the monthly demand toll per Mcf
charged by ProGas as approved by the Alberta Petroleum Marketing Commission.
Payments pursuant to this monthly demand charge are based on the anticipated
Daily NJEA Quantities under the NJEA ProGas Agreement. The monthly demand charge
is payable regardless of the actual volume of gas delivered.
The commodity charge is applied to volumes of gas actually delivered
under the NEA ProGas Agreement and is the difference between the unitized
monthly heating demand rate and the then applicable "base price" escalated from
U.S. $2.7665 per Dth as of January 1, 1990. The "base price" as theretofore
escalated, was further increased by $.038 per Mcf, effective December 1, 1994
Such escalation rate is adjusted annually by the change in the cost of natural
gas purchased by New Jersey electric utilities as reported in FERC Form 423.
The price of gas, sold pursuant to the NJEA ProGas Agreement will be
adjusted in the event that (i) the NEA Project has ceased to operate for a
period of six consecutive months and (ii) ProGas is not selling gas under the
NEA ProGas Agreement on a monthly basis at least equal to 65% of the Daily NEA
Quantity (as defined below). The price adjustment will be subject to an
escalator based on natural gas costs as determined by FERC and the pricing
provisions contained in the NEA ProGas Agreement. In any contract year
commencing on or after November 1, 2001, the contract pricing also is subject to
renegotiation or arbitration if the contract prices do not track comparable long
term service contracts then prevailing. Arbitration conducted between November
1, 2001 and October 31, 2006 may result in an increase in the escalation of the
"base price," while arbitration conducted between November 1, 2006 and the end
of the term may result in an increase or decrease in the rate of escalation of
the "base price." In either time period, the change is not to impair the ability
of NJEA to cover operating costs of the NEA project or to. service the debt on
the project, nor is it to cause a materially adverse effect on NJEA's net cash
flow from the NEA project. The actual price of the natural gas service, however,
is not subject to arbitration in either.
NJEA's Right to Pay Gas Transporters and Gas Producers Directly. In the
event of ProGas' bankruptcy, insolvency or failure to pay any transporter of
gas, or to pay gas producers with reserves dedicated in whole or in part to the
NJEA ProGas Agreement any amounts due them for transportation services or sale
of gas relating to transportation of gas for ultimate redelivery to NJEA or sale
of gas for resale to NJEA, NJEA shall have the right to the extent permitted by
ProGas' contractual arrangements with transporters or gas producers and subject
77
to any limitation imposed by law or regulation, to withhold payments due ProGas,
in whole or in necessary part, and from such withheld amounts to pay directly to
any transporter or gas producer the amount due to it from ProGas.
Termination. In the event NJEA is 60 or more days in arrears on
undisputed amounts payable, ProGas may terminate the NJEA ProGas Agreement
provided it has given NJEA 15 days' written notice of its intent to exercise
such right in the event the arrears is not cured within that period. In
addition, ProGas may terminate the NJEA ProGas Agreement in the event that each
of the following conditions has occurred and is continuing: (i) NJEA has filed a
petition of bankruptcy, (ii) NJEA has failed to take an average of 50% of the
Daily NJEA Quantity for six consecutive months or has failed to resume
acceptance at an average of 65% of the Daily NJEA Quantity during the last month
of the six-month period and (iii) NJEA's failure to take such Daily NJEA
Quantity for such period is not the result of a force majeure event. NJEA may
terminate the NJEA ProGas Agreement in the event that each of the following
conditions has occurred and is continuing: (I) ProGas has filed a petition of
bankruptcy, (ii) ProGas has failed to deliver 50% of the volumes designated for
six consecutive months or has failed to resume delivery at a rate of 65% of the
volumes scheduled for daily delivery during the last month of the six-month
period and (iii) ProGas' failure to deliver such volumes for such period is not
the result of a force majeure event. In the event that any change in applicable
law has a materially adverse effect on the terms of performance under the NJEA
ProGas Agreement, the party adversely affected may terminate such agreement.
PSE&G Contract
The Gas Purchase and Sales Agreement dated as of May 4, 1989 between
NJEA and PSE&G (the "PSE&G Contract"), provides for the sale by PSE&G to NJEA of
gas, and for certain gas transportation services.
Sale of Gas. PSE&G sells to NJEA up to 25,000 dekatherms of gas per day
subject to "Service Interruptions" by PSE&G discussed below. NJEA has the option
to purchase additional gas (i) at NJEA's request on a daily basis subject to
PSE&G's ability to provide such amounts, (ii) under an Extended Gas Service (as
defined herein) option if PSE&G retains gas on certain "peak days" and (iii)
commencing November 1 and ending March 31 for "winter-seasonal service" up to a
specified amount with appropriate notice.
Transportation Service. PSE&G transports for NJEA all of the fuel
required to operate the NJEA Project (from points originating in PSE&G's service
territory to the delivery point at the NJEA Project), including all gas
purchased by NJEA from ProGas, gas purchased on the open market and gas
delivered from storage. NJEA may deliver to PSE&G for transport to the NJEA
Project up to 32,500 dekatherms of gas per day purchased from sources other than
PSE&G, and PSE&G is required to redeliver an equal quantity to the NJEA Project
except in certain limited circumstances on "peak days." In the event that NJEA
has delivered to PSE&G for transport in any calendar month an amount less than
the amount redelivered by PSE&G to the NJEA Project in such calendar month and
NJEA falls to correct the resulting imbalance in the immediately following
month, then PSE&G will sell to NJEA at NJEA's request a quantity of gas equal to
up to 10% of the gas used by NJEA in the month of the imbalance at a price equal
to the commodity charge under the PSE&G Contract plus a penalty fee of three
times the "service charge" discussed below.
Term. The term of the PSE&G Contract is 20 years expiring August 12,
2011. The PSE&G Contract does not include any renewal provision.
78
Price. The monthly price payable by NJEA to PSE&G for gas sold under
the PSE&G Contract equals the sum of (i) a "customer charge" (indexed to the
Implicit Price Deflator of GNP as published by the United States Department of
Commerce, Bureau of Economic Analysis in its "Survey of Current Business")
initially set in 1990 at $86 per month and adjusted annually as of the first
calendar day of each succeeding year, (ii) a "commodity charge" per dekatherm
sold by PSE&G to NJEA based upon the average costs incurred by PSE&G in
acquiring gas during such month, (iii) a "service charge" (indexed to the
weighted average change in PSE&G's natural gas rates as approved by the New
Jersey Board of Public Utilities) initially set in 1990 at $0.30 per dekatherm
delivered and (iv) a "loss and shrinkage charge" equal to 1.5% of the monthly
"commodity charge." The price for additional amounts purchased under the
Extended Gas Service option includes a "service charge" and an "extended gas
service charge." The price for additional amounts purchased under the
winter-seasonal service is equal to the "extended gas service charge" plus a
delivery charge. If PSE&G retains gas on certain "peak days" PSE&G will pay to
NJEA a "Peak Gas Service Credit" described below under "Service Interruption."
The monthly price payable by NJEA to PSE&G under the PSE&G Contract for
the transportation of gas purchased by NJEA from gas suppliers other than PSE&G
is the product of the number of dekatherms of gas transported multiplied by the
monthly "service charge" described in clause (iii) above. NJEA may elect to
renegotiate the sales price under the PSE&G Contract if the actual price charged
thereunder to NJEA in any one-year period ending on October 31 exceeds the
comparable average gas cost incurred by New Jersey electric utilities by 15%.
Conversely, if such price is less than 85% of the comparable average gas cost
incurred by New Jersey electric utilities, then PSE&G may elect to renegotiate
the sales price. To date, actual prices have not fallen above or below this
range. If NJEA and PSE&G are unable to renegotiate the sales price, the parties
may elect to terminate the sales provisions contained in the PSE&G Contract
without terminating the transportation provisions contained therein. During
1997, the "customer charge" was approximately $97 per month, the "commodity
charge" was approximately $.32928 per dekatherm, and the "service charge" was
approximately $.32928 per dekatherm.
Quantity Adjustments. All quantities specified in the PSE&G Contract,
upon 30 days' written notice to PSE&G, may be adjusted by NJEA to reflect
changes in the percentage of gas that is retained by Canadian or U.S. pipelines
transporting gas for NJEA in order to provide the NJEA Project with the same
delivered quantity as existed prior to such changes.
Service Interruption. PSE&G may interrupt sales and transportation
service to the NJEA Project on "peak days" when the mean daily temperature
forecast for Newark, New Jersey is 22(degree)F or below. On such days, PSE&G may
retain the gas supplies tendered to it by NJEA. This occurred on 4 days during
1997. At NJEA's election, PSE&G will offer Extended Gas Service on such days,
unless the mean daily temperature forecast is 14(degree) F or below. In the
latter case PSE&G may curtail all service to NJEA and the NJEA Project may not
be able to operate. This occurred on 2 days during 1997. The price of Extended
Gas Service is based upon the cost to PSE&G of propane supplies delivered to its
processing facilities plus a mark-up. During 1997, NJEA purchased 908,290
dekatherms of Extended Gas Service supplies at an average price of $8.813 per
dekatherm.
In exchange for the right to retain NJEA's gas supplies on those
certain peak days described above, PSE&G pays a demand charge to NJEA (the "Peak
Gas Service Credit") which is indexed to demand charges paid by NJEA for the
transportation and storage of its supplies in the U.S. The Peak Gas Service
Credit is subject to a floor of 37% of the PSE&G "service charge" and a cap of
68% of the "service charge." During 1997, PSE&G paid NJEA over $2 million in
Peak Gas Service Credits. In addition, PSE&G pays NJEA for gas retained
according to a formula which prices these supplies at the greater of (i) the
weighted average commodity cost of PSE&G for natural gas supplies purchased from
all sources, or (ii) an amount which is the lesser of the market price of fuel
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oil per dekatherm or PSE&G's propane cost per dekatherm. During 1997, PSE&G
retained 120,288 dekatherms at an average price of $5.199916 per dekatherm.
Termination. In the event either party is in arrears on undisputed
amounts payable, the party to whom payment is owed may provide the other party
with a written protest of failure to pay and suspend performance 15 days later
if the failure continues, and, in addition, may terminate the contract upon
written notice to the other party. In the event regulatory authorities having
jurisdiction take any action that requires an increase in the "service charge"
described above under "Price," or materially alters the method for the
calculation of the sales price, NJEA may terminate the PSE&G Contract on 90
days' notice in writing to PSE&G.
Gas Transportation and Storage Agreements
The following table identifies the Long-term Gas Transportation
Agreements and Long-term Gas Storage Agreements and sets forth certain
information with respect thereto. The Long-term Gas Storage Agreements provide
contractual arrangements for the storage of limited volumes of gas with third
parties for future delivery to the Projects.
NEA -- Transportation Agreements
Maximum Daily Contract
Gas Transporter and Agreements Quantity Expiration Date
- ------------------------------ ------------- -------------------
CNG Transmission Corporation 48,817 Dth November 1, 2011
Firm Transportation Service Agreement
Rate Schedule X-71
CNG Transmission Corporation 1,654 Dth Winter March 31, 1999
Service Agreement Applicable to 828 Dth Summer
Transportation of Natural Gas
Rate Schedule FT:
Transcontinental Gas Pipe Line Corporation 48,800 Mcf October 31 2006
Firm Gas Transportation Agreement
Rate Schedule X-320
Algonquin Gas Transmission Company 62,000 Dth November 30, 2016
Service Agreement
Rate Schedule AFT-1
CNG Transmission Corporation 14,000 Dth March 31, 2012
Service Agreement Applicable to
the Storage of Natural Gas (1)
Rate Schedule FT-GSS-11
Texas Eastern Transmission Corporation 14,000 Dth March 31, 2012
Service Agreement
Rate Schedule FTS-5
- -------------
(1) Includes an agreement for the transportation of natural gas held in storage.
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NJEA - Transportation Agreements
Maximum Daily Contract
Gas Transporter and Agreements Quantity Expiration Date
- ------------------------------ ------------- ----------------
CNG Transmission Corporation Firm 22,019 Dth November 1, 2011
Transportation Service Agreement
Rate Schedule X-70
CNG Transmission Corporation 746 Dth Winter March 31, 1999
Service Agreement Applicable to 372 Dth Summer
Transportation of Natural Gas,
Rate Schedule FT
Transcontinental Gas Pipe Line Corporation 22,019 Mcf October 31, 2006
Firm Gas Transportation Agreement
Rate Schedule X-319
Public Service Electric & Gas Company 32,500 Dth August 12, 2011
Gas Purchase and Sales Agreement
CNG Transmission Corporation 10,508 Dth March 31, 2012
Service Agreement Applicable to
the Storage of Natural Gas (1)
Rate Schedule FT-GSS-11
Texas Eastern Transmission Corporation 10,508 Dth March 31, 2012
Service Agreement
Rate Schedule FTS-5
- -------------
(1) Includes an agreement for the transportation of natural gas held in storage.
NEA -- Storage Agreements
Maximum Daily Contract
Gas Transporter and Agreements Quantity Expiration Date
- ------------------------------- ---------------------- ----------------------
CNG Transmission Corporation Withdrawal: 14,000 Dth March 31, 2012
Service Agreement Applicable to Injection: 10,000 Dth
the Storage of Natural Gas Capacity: 1,400,000 Dth
Rate Schedule GSS-11
NJEA - Storage Agreements
Maximum Daily Contract
Gas Transporter and Agreements Quantity Expiration Date
- ------------------------------- ---------------------- ----------------------
CNG Transmission Corporation Withdrawal: 10,508 Dth March 31, 2012
Service Agreement Applicable to the Injection: 7,506 Dth
Storage of Natural Gas Capacity: 1,050,800 Dth
Rate Schedule GSS-11
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Operations and Maintenance Agreements
NEA Operations and Maintenance Agreement
The Second Amended and Restated Operation and Maintenance Agreement for
the NEA Project dated as of June 28, 1989, as amended, between NEA and
Westinghouse Electric (the "NEA O&M Agreement"), provides for the operation and
maintenance by Westinghouse Services (the "Operator") of the NEA Project.
Term. The term of the NEA O&M Agreement extends for an initial term of
10 years expiring September 15, 2001. The Operator has agreed, pursuant to a
letter agreement with NEA dated as of June 23, 1993, to enter into a successor
agreement for a term of ten years at NEA's option, with payments to be made to
the Operator for certain services on either a firm-price basis, subject to
successful negotiation of terms by the parties, or a cost-plus basis. In the
event that the agreement is not extended on either basis, the Operator is to
provide assistance to effect a transition to a new service provider. Pursuant to
the New NEA O&M Agreement, the New Operator is providing certain services for
the NEA Project, and has agreed to replace Westinghouse Services as the operator
of the NEA Project upon the expiration or early termination of the NEA O&M
Agreement.
Basic Obligations. The Operator has agreed to provide all operations
and maintenance services, including scheduled all major maintenance and has
agreed to provide all personnel, spare parts and consumables necessary in order
to operate and maintain the NEA Project. Such services include all services
necessary or advisable to use, operate and maintain the NEA Project in good
operating condition and in compliance with (i) the NEA Project Documents, (ii)
all insurance policies relating to the NEA Project, (iii) the procedures
established in the operation and maintenance manuals provided pursuant to the
construction contract for the NEA Project, or applicable industry guidelines,
(iv) all applicable prudent industry practices and standards, (v) vendor and
manufacturer requirements or conditions, as applicable, (vi) the standards set
forth in the NEPOOL Agreement, (vii) the operating and maintenance procedures
established by the Operator in accordance with the NEA O&M Agreement and (viii)
any and all governmental approvals, licenses or permits associated with the NEA
Project. Substantive changes to the obligations of the Operator require consent
of NEA and of an independent engineer to a written "change order" request of the
Operator.
Compensation. For the initial term, NEA has agreed to pay the Operator
a monthly fee (the "NEA O&M Fee") of $435,417 (in 1990 dollars) , subject to a
biannual adjustment each January and July calculated on the basis of certain
national indices for the cost of labor, materials and producer prices. The NEA
O&M Fee incurred during 1997 was $6,550,447 (excluding heat rate and performance
bonuses).
Performance Guarantees. The NEA O&M Agreement specifies certain
guaranteed performance levels for the NEA Project, including but not limited to
(i) guaranteed electrical output of approximately 290 MW of capacity, adjusted
for variations from standard operating conditions and excused downtime and by 3%
per annum for plant degradation, at 90% average availability, when the NEA
Project is being fueled by 100% pipeline quality natural gas, (ii) guaranteed
electrical output of approximately 290 MW of capacity, adjusted for variations
from standard operating conditions and excused downtime, at 83% for purposes of
liquidated damages calculations or 85% for purposes of bonus payments average
availability, when the NEA Project is burning a combination of natural gas and
fuel oil, (iii) guaranteed steam output of not less than 5% of the total energy
output of the NEA Project, with an affirmative obligation for the Operator to
correct any deficiency as NEA's sole remedy, (iv) guaranteed fuel consumption,
as adjusted to reflect variations from standard conditions, not in excess of
certain agreed upon levels with an affirmative obligation to correct
inefficiencies and, in certain circumstances, to reimburse excess fuel costs and
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(v) a guarantee that emissions will not exceed certain agreed upon levels, with
remediations the sole liability in the event of failure to maintain such levels.
Catastrophic Loss of Viability. Subject to the provisions regarding
liquidated damages and the limitations on the Operator's liability contained in
the NEA O&M Agreement, the Operator has agreed to pay off the outstanding
balance of NEA's senior debt financing for the NEA Project (which would include
the Project Notes (as defined herein)) upon the occurrence of certain specified
events, including the following: (i) the destruction of the NEA Project; (ii)
the unavailability of insurance proceeds or the lapse of insurance policies in
respect of such destruction, in either case, as a result of the Operator's acts
or omissions; (iii) the inability of NEA to service its senior debt as a result
of a catastrophic loss of viability; (iv) the failure of attempts to cure; and
(v) the acceleration of the entire principal balance of NEA's senior debt
financing for the NEA Project.
Liquidated Damages. The Operator has agreed to pay liquidated damages
to NEA in the following amounts for shortfalls in the annual (adjusted) number
of MWH produced below the guaranteed performance levels described above: (i) $15
per MWH for the first 100,000 MWH of shortfall, (ii) $33 per MWH for the second
100,000 MWH of shortfall and (iii) $50 per MWH for all additional MWH of
shortfall. Aggregate liquidated damages are subject to a maximum cumulative
liability of the Operator (excluding certain indemnities) of $9 million in any
operating year, and $60 million over the initial term of the NEA O&M Agreement.
During any extension period, the maximum liability of the Operator under the NEA
O&M Agreement is reduced to $3 million (in 1993 dollars) in any operating year.
Bonus Payment. In the event that the amount of energy generated by the
NEA Project exceeds the guaranteed electrical output, as adjusted for certain
specified excused outages and seasonal variations from standard operating
conditions, NEA has agreed to pay to the Operator the following amounts as a
bonus for each MWH of energy generated in excess of the guaranteed levels: (i)
$5 per MWH for the first 25,000 MWH of excess, (ii) $10 per MWH for the second
25,000 MWH of excess, and (iii) $15 per MWH for all additional MWH of excess. By
a letter agreement dated as of June 23, 1993, NEA and the Operator agreed that
NEA would pay the Operator the aggregate sum of $3.289 million as the heat rate
bonus for the initial term of the NEA O&M Agreement, payable in installments
(without interest) as follows: (i) an initial payment of $572,000 on December
30, 1992; and (ii) the remaining $2.717 million to be paid in equal annual
installments of $543,400 each on September 30 of each of the succeeding five
years except that in the event of a refinancing of the Original Project Credit
Agreement, a portion of the remaining balance of the heat rate bonus may be
payable at the time of the refinancing based on the amount of net proceeds. No
payment was due to the Operator pursuant to this provision in respect of the
refinancing effected by the issuance of the Project Securities. During any
extension period beyond the initial term of the NEA O&M Agreement, heat rate
bonuses will be payable based upon actual heat rates in each year, subject to a
maximum annual bonus of $1 million (in 1993 dollars). During 1997, NEA incurred
an aggregate heat bonus of $310,514.
Energy Bank. In the event that any Power Purchaser draws against any
letter of credit supporting the Energy Bank balances under its Power Purchase
Agreement solely as a result of the Operator's acts or omissions, the Operator
is obligated to refund the amount of such drawing to NEA.
Termination. With the concurrence of an independent engineer, NEA has
the right to terminate the NEA O&M Agreement if (i) the Operator is in material
breach of any material provision of the NEA O&M Agreement (however, breach of
performance guarantees for which liquidated damages have been paid or
remediation has been undertaken by the Operator does not constitute material
breach for this purpose), and such breach has not been cured within 45 days of
written notice thereof, or as soon as practicable thereafter (ii) the actual
output of the NEA Project for four consecutive quarters is less than 67% of the
adjusted guaranteed MWH or (iii) the Operator is required in any given year to
83
pay the entire $9 million maximum liquidated damages allowed by the NEA O&M
Agreement. The Operator has the right to terminate the NEA O&M Agreement if NEA
fails to make any monthly payment, insurance reimbursement or payment in respect
of fuel off-loading services when due, if NEA fails to cure such failure within
30 days of written notice thereof. Either party may terminate the NEA O&M
Agreement (but only with the concurrence of an independent engineer in the case
of a termination by NEA) if the other party is insolvent, commences bankruptcy,
insolvency or reorganization proceedings or makes a general assignment for the
benefit of its creditors. The NEA O&M Agreement will terminate automatically in
the event that the NEA Project is subject to a catastrophic loss of viability
and the Operator makes the required payment with respect thereto as described
above under "-- Catastrophic Loss of Viability."
After termination of the NEA O&M Agreement by written notice from NEA
to the Operator, NEA is entitled, in addition to its other remedies, to take
possession of the NEA Project and any spare parts located on the NEA Site. If
NEA takes possession of the NEA Project in this manner, the Operator will remain
liable for (i) all liquidated damages accrued but unpaid at the time of such
termination and (ii) for each remaining operating year following termination up
to September 15, 2001, the difference between (x) the amount that would have
been payable to the Operator pursuant to the NEA O&M Agreement as NEA O&M Fees
for such year and (y) the amount payable to a replacement operator for each such
operating year, provided, however, that the Operator's aggregate liability shall
not exceed the lesser of (a) 30% of the aggregate amounts payable to the
Operator in the year of termination or (b) $12.5 million.
The Operator is to have no other liability to NEA.
Right to Suspend Performance for Loss of Qualifying Facility Status. In
the event that the NEA Project is operated in a manner during any three-month
period in any calendar year that would result in the loss of its QF status if
such operation were to be continued for the remainder of such calendar year, and
such projected loss is confirmed by an independent engineer, NEA has agreed to
take reasonable steps to ensure that operating practices will maintain such QF
status. Under certain circumstances relating to a potential or actual loss of QF
status, the Operator may suspend performance under the NEA O&M Agreement and
find a replacement operator. See "Business -- Regulation -- Energy Regulation."
NJEA Operations and Maintenance Agreement
The Amended and Restated Operations and Maintenance Agreement for the
NJEA Project dated as of June 28, 1989, as amended, between NJEA and
Westinghouse Electric (the "NJEA O&M Agreement") provides for the operation and
maintenance by Westinghouse Services (the "Operator") of the NJEA Project.
Term. The term of the NJEA O&M Agreement extends for an initial term of
ten years expiring September 15, 2001. The Operator has agreed, pursuant to a
letter agreement with NJEA dated June 23, 1993, to enter into a successor
agreement for a term of ten years at NJEA's option, with payments to be made to
the Operator for certain services on a fixed price basis, with major maintenance
and certain other items on a firm price basis, subject to negotiation of terms
by the parties, or on a cost-plus basis. Pursuant to the New NJEA O&M Agreement,
the New Operator is providing certain services for the NJEA Project, and has
agreed to replace Westinghouse Services as the operator of the NJEA Project upon
the expiration or early termination of the NJEA O&M Agreement.
Basic Obligations. The Operator has agreed to provide all operations
and maintenance services, including all scheduled major maintenance, and has
agreed to provide all personnel, spare parts and consumables necessary in order
to efficiently operate and maintain the NJEA Project. Such services include all
services necessary or advisable to use, operate and maintain the NJEA Project in
good operating condition and in compliance with (i) the NJEA Project Documents,
84
(ii) all insurance policies relating to the NJEA Project, (iii) the procedures
established in the operation and maintenance manuals provided pursuant to the
construction contract for the NJEA Project, or applicable industry guidelines,
(iv) all applicable prudent industry practices and standards, (v) vendor and
manufacturer requirements or conditions, as applicable, (vi) all applicable
requirements and guidelines adopted by PJM Interconnected Power Pool, including
the PJM Agreement, (vii) the operating and maintenance procedures established by
the Operator in accordance with the NJEA O&M Agreement and (viii) any and all
governmental approvals, licenses or permits associated with the NJEA Project.
Substantive changes to the obligations of the Operator require consent of NJEA
and of an independent engineer to a written "change order" request of the
Operator.
Compensation. For the initial term, NJEA has agreed to pay the Operator
a monthly fee (the "NJEA O&M Fee") of $493,750 (in 1990 dollars), subject to
adjustment in January and in July of each year, calculated on the basis of
certain national indices for the cost of labor, materials and producer prices.
The aggregate NJEA O&M Fee incurred during 1997 was $7,337,011 (excluding heat
rate and performance bonus payments).
Performance Guarantees. The NJEA O&M Agreement specifies certain
guaranteed performance levels for the NJEA Project, including but not limited to
(i) guaranteed electrical output of 90% of the approximately 275 MW of capacity,
adjusted for variations from standard operating conditions and excused downtime
and by 3% per annum for plant degradation, during on-peak hours (8:00 a.m. to
8:00 p.m. Monday through Friday, December through February and June through
September excluding holidays), (ii) guaranteed electrical output of 85% of the
approximately 275 MW of capacity, adjusted for variations from standard
operating conditions, during off-peak hours, (iii) guaranteed steam output of
not less than 5% of the total energy output of the NJEA Project, with an
affirmative obligation for the Operator to correct any deficiency as NJEA's sole
remedy, (iv) guaranteed fuel consumption, as adjusted to reflect variations from
standard conditions, not in excess of certain agreed upon levels with an
affirmative obligation to correct inefficiencies and, in certain circumstances,
to reimburse excess fuel costs as NJEA's sole remedy and (v) a guarantee that
emissions will not exceed certain agreed upon levels, with restriction of the
level of power output or cessation of operation of the NJEA Project until such
emissions guarantee is satisfied being the sole remedy in the event of failure
to maintain such levels.
Catastrophic Loss of Viability. Subject to the provision regarding
liquidated damages and the limitations on the Operator's liability contained in
the NJEA O&M Agreement, the Operator has agreed to pay off the outstanding
balance of NJEA's senior debt financing for the NJEA Project (which would
include the Project Notes) upon the occurrence of certain specified events,
including the following: (i) the destruction of the NJEA Project, (ii) the
unavailability of insurance proceeds or the lapse of insurance policies in
respect of such destruction, in either case, as a result of the Operator's acts
or omissions, (iii) the inability of NJEA to service its senior debt as a result
of a catastrophic loss of viability, (iv) the failure of attempts to cure and
(v) the acceleration of the entire principal balance of NJEA's senior debt
financing for the NJEA Project.
Liquidated Damages. The Operator has agreed to pay liquidated damages
to NJEA in the following amounts for shortfalls in the annual (adjusted) number
of kWh produced below the guaranteed performance levels: (i) 1.5 cents per kWh
of off-peak shortfall, (ii) 2 cents per kWh of on-peak shortfall and (iii) if
actual on-peak output is less than 85% of average actual on-peak output during
the immediately preceding 3 operating years and NJEA is obligated to pay
liquidated damages in respect of such shortfall under the JCP&L Power Purchase
Agreement 3.6 cents per kWh of shortfall below 85% to the extent of NJEA's
liquidated damages obligation to JCP&L (or a total of 5.6 cents per kWh if a
part of the on-peak shortfall is below the requisite level). Aggregate
liquidated damages are subject to a maximum cumulative liability of the Operator
(excluding certain indemnities) of $9 million in any operating year, and $60
million over the initial term of the NJEA O&M Agreement. During any extension
85
period, the maximum liability of the Operator under the NJEA O&M Agreement is
reduced to $3 million (in 1993 dollars) in any operating year. Liquidated
damages payments will be made only if the cumulative downtime in any quarter
exceeds 180 hours during on-peak hours or exceeds 1044 hours during off-peak
hours.
Bonus Payments. In the event that the amount of energy generated by the
NJEA Project during on-peak hours exceeds the guaranteed electrical output, as
adjusted for certain specified excused outages and seasonal variations from
standard operating conditions, NJEA has agreed to pay to the Operator a bonus
for energy generated during such hours in excess of the guaranteed levels of 3.0
cents per kWh. In the event that the amount of energy generated by the NJEA
Project during off-peak hours exceeds the guaranteed electrical output, as
adjusted for certain specified excused outages and seasonal variations from
standard operating conditions, NJEA has agreed to pay to the Operator a bonus
for energy generated during such hours in excess of the guaranteed levels of 0.3
cents per kWh. By a letter agreement dated as of June 23, 1993, NJEA and the
Operator agreed that NJEA would pay the Operator the aggregate sum of $7.711
million as the heat rate bonus for the initial term of the NJEA O&M Agreement,
payable in installments (without interest) as follows: (i) an initial payment of
$1.156 million on December 30, 1992; and (ii) the remaining $6.555 million to be
paid in equal annual installments of $1.311 million each on September 30 of each
of the succeeding five years, except that in the event of a refinancing of the
Original Project Credit Agreement, a portion of the remaining balance of the
heat rate bonus may be payable at the time of the refinancing based on the
amount of the net proceeds. No payment was due to the Operator pursuant to this
provision in respect of the refinancing effected by the issuance of the Project
Securities. During any extension period beyond the initial term of the NJEA O&M
Agreement, heat rate bonuses will be payable based upon actual heat rates in
each year, subject to a maximum annual bonus of $1 million (in 1993 dollars).
Bonus payments will be made if the cumulative downtime in any quarter is less
than 150 hours during on-peak hours or is less than 1,044 hours during off-peak
hours. During 1997 NJEA incurred an aggregate heat rate bonus of $749,142.
Energy Bank. In the event that JCP&L draws against any letter of credit
supporting the Energy Bank obligations under its Power Purchase Agreement solely
as a result of the Operator's actions or omissions, the Operator is obligated to
refund the amount of such drawing to NJEA.
Termination. With the concurrence of an independent engineer, NJEA has
the right to terminate the NJEA O&M Agreement if: (i) the Operator is in
material breach of any material provision of the NJEA O&M Agreement (however,
breach of performance guarantees for which liquidated damages have been paid or
remediation has been undertaken by the Operator does not constitute material
breach for this purpose), and such breach has not been cured within 45 days of
written notice thereof, or as soon as practicable in the event that such a cure
cannot be effected within 45 days, (ii) the actual output of the NJEA Project
for four consecutive quarters is less than 67% of the adjusted guaranteed output
or (iii) the Operator is required in any given year to pay the $9 million
maximum liquidated damages allowed by the NJEA O&M Agreement. The Operator has
the right to terminate the NJEA O&M Agreement if NJEA fails to make any monthly
payment, insurance reimbursement or payment in respect of refuel off-loading
services when due if NJEA fails to cure such failure within 30 days of written
notice thereof. Either party may terminate the NJEA O&M Agreement (but only with
the concurrence of an independent engineer in the case of a termination by NJEA)
if the other party is insolvent, commences bankruptcy, insolvency or
reorganization proceedings or makes a general assignment for the benefit of its
creditors. The NJEA O&M Agreement will terminate automatically in the event that
the NJEA Project is subject to catastrophic loss of viability and the Operator
makes the required payment with respect thereto as described above under
"-- Catastrophic Loss of Viability."
After termination of the NJEA O&M Agreement by written notice from NJEA
to the Operator, NJEA is entitled, in addition to its other remedies, to take
possession of the NJEA Project and any spare parts located on the NJEA Site. If
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NJEA takes possession of the NJEA Project in this manner, the Operator will
remain liable for (i) all liquidated damages accrued but unpaid at the time of
such termination and (ii) for each remaining operating year following
termination up to September 15, 2001, the difference between (x) the amount that
would have been payable to the Operator pursuant to the NJEA O&M Agreement as
NJEA O&M Fees for such year and (y) the amount payable to a replacement operator
for each such operating year, provided, however, that the Operator's aggregate
liability shall not exceed the lesser of (a) 30% of the aggregate amounts
payable to the Operator in the year of termination or (b) $12.5 million.
The Operator is to have no other liability to NJEA.
Right to Suspend Performance for Loss of Qualifying Facility Status. In
the event that the NJEA project is operated in a manner during any three-month
period in any calendar year that would result in the loss of its QF status if
such operation were to be continued for the remainder of such calendar year, and
such projected loss is confirmed by an independent engineer, NJEA has agreed to
take reasonable steps to ensure that operating practices will maintain such QF
status. Under certain circumstances relating to a potential or actual loss of QF
status, the Operator may suspend its performance under the NJEA O&M Agreement
and find a replacement operator. See "Business -- Regulation -- Energy
Regulation."
New NEA and NJEA Operation and Maintenance Agreements
Each of The Operation and Maintenance Agreements, dated as of November
21, 1997 (the "New NEA O&M Agreement" and the "New NJEA O&M Agreement"), by and
between NE LP and ESI Operating Services, Inc. (the "New Operator"), provides
for the operation and maintenance by the New Operator of the NEA and NJEA
Projects respectively on the day following the expiration or early termination
of the NEA and NJEA O&M Agreements (each, an "Operating Period Commencement
Date"). Under the New NEA and NJEA O&M Agreements, the New Operator has agreed
to provide currently Oversight Services (defined below) and has agreed to
provide Transition Services (defined below) , commencing ninety (90) days prior
to the applicable Operating Period Commencement Date (each, a "Transition
Services Commencement Date").
Term. The term of the New NEA and NJEA O&M Agreements extends for an
initial term of eighteen (18) years until January 14, 2016, subject to extension
by mutual agreement of the parties before six months preceding such expiration.
Oversight Services. The New Operator has agreed to provide certain
oversight services (the "Oversight Services") prior to the Operating Period
Commencement Date, including (i) reviewing certain Operator reports, proposed
changes in procedures, facility performance data, operating logs and records of
unplanned outages and annual generation forecasts, (ii) assessing NEA and NJEA
Site conditions on a quarterly basis, (iii) assessing the Operator's personnel,
policies, and procedures, (iv) analyzing all proposed capital expenditures for
the NEA and NJEA Project, (v) providing such technical support as reasonably
requested by NE LP and (vi) monitoring the Operator's activities during major
scheduled outages and major equipment overhauls.
Transition Services. On the Transition Period Commencement Date and
until the Operating Period Commencement Date, the New Operator has agreed to
provide certain transition services consisting of the review of existing
maintenance and operation records and the performance of all activities
necessary to mobilize its personnel (the "Transition Services"), including
without limitation (i) providing the necessary staff to operate and maintain the
NEA and NJEA Projects on the Operating Period Commencement Date, including
relocation of such personnel, review of personnel qualifications, recruiting and
training, (ii) preparing and submitting to NE LP (a) a transition plan and
budget for the orderly transition of operation and maintenance responsibilities
for the NEA and NJEA Projects, (b) an initial operation and maintenance plan for
87
the upcoming year, (c) an initial proposed budget for operating and maintaining
the NEA and NJEA Projects pursuant to such plan and (d) a proposed format for
monthly reports to be delivered by the New Operator following the Operating
Period Commencement Date, (iii) developing the necessary programs and procedures
to perform the operation and maintenance of the NEA and NJEA Projects and (iv)
identifying and procuring as NE LP's agent necessary tools, equipment, goods,
and other items and materials necessary to operate and maintain the NEA and NJEA
Projects.
Operation and Maintenance Services. On and following the Operating
Period Commencement Date, the New Operator has agreed to perform all activities
necessary to operate and maintain the NEA and NJEA Projects (the "O&M
Services"), provided that the O&M Services are not to include, and the New
Operator is not to be responsible for, supplying water, natural gas, appropriate
distillate fuel oil or start up electrical power for the NEA Project, securing
or maintaining certain permits to be obtained by NE LP or arranging for the sale
of steam or electricity, maintaining insurance other than the insurance
described below, and services to be provided by NE LP, as described below. The
O&M Services include without limitation, the following: (i) making available
qualified labor and professional, supervisory and managerial personnel,
including appointing the plant manager, (ii) maintaining the NEA and NJEA
Projects in compliance with all applicable laws and permits, including the
efficiency requirements set forth in 18 C.F.R. 292.205, and in accordance with
Prudent Utility Practices (as defined in the New NEA O&M Agreement), with the
approved annual plan, with the approved plant manual and with the Project
Documents, (iii) seeking appropriate warranties, (iv) performing certain audits
under the NEA and NJEA Power Purchase Agreement(s), (iv) disposing of waste
products from the NEA and NJEA Projects, (v) responding to emergencies in
accordance with certain requirements, (vi) performing all necessary services in
connection with Unscheduled Maintenance (as defined in the New NEA and NJEA O&M
Agreements) and establishing maintenance programs, (vii) performing accounting
activities, (viii) preparing various reports and coordinating with NE LP and the
NEA and NJEA Power Purchasers regarding operations, (ix) maintaining various
records of operation and maintenance, finances, accidents and other related
data, (x) procuring necessary inventory and (xi) providing certain technical
support services.
Owner Services. NE LP has agreed to provide certain services at its
sole cost and expense during certain periods, including without limitation, the
following: (i) providing the New Operator with copies of certain permits,
licenses, authorizations, as-built drawings of the NEA and NJEA Projects,
quarterly reports and Project Documents, (ii) providing access to the NEA and
NJEA Sites and NEA and NJEA Projects, (iii) securing and maintaining all permits
required for NE LP to operate the NEA and NJEA Projects, (iv) providing an
operating account to pay for costs incurred by the New Operator, (v) paying all
taxes relating to the NEA and NJEA Projects (except income taxes of the New
Operator) and (v) taking reasonable steps to allow the NEA and NJEA Projects to
meet QF standards.
Compensation. NE LP has agreed to pay to the New Operator a minimum fee
of $750,000 per annum for each Project, commencing on January 14, 1998, payable
in monthly installments and adjusted on January 1 of each year based on the
Producer Price Index for all Commodities, published by the Department of Labor,
Bureau of Labor Statistics. In addition, NE LP has agreed to pay to the New
Operator all properly incurred costs and expenses of performing the Transition
Services and the O&M Services.
Termination. NE LP, may, by written notice to the New Operator,
terminate the New NEA and NJEA O&M Agreements if, prior to the Operating Period
Commencement Date, an independent engineer has not certified that the New
Operator is capable of operating the NEA and NJEA Projects in accordance with
Prudent Utility Practices. The New Operator may, by written notice to NE LP,
terminate the New NEA and NJEA O&M Agreements, if NE LP fails to make a payment
thereunder within 5 days after the same shall have become due. Either party may
terminate the New NEA and NJEA O&M Agreements by written notice if (i) the other
party defaults in the performance of any material term, covenant or obligation
contained in the New NEA and NJEA O&M Agreements and does not remedy such
88
default within 30 days after such party's receipt of the non-defaulting party's
written notice thereof to such party (or as soon as possible thereafter but in
any event within 180 days, if it cannot be reasonably accomplished in such 30
day period and the defaulting party has commenced all actions required to remedy
such default within such 30 day period and diligently thereafter pursues the
same to completion), (ii) certain bankruptcy or insolvency events as to the
other party occur, (iii) the NEA or the NJEA Project is destroyed or suffers
damage in excess of $100,000,000 and is not rebuilt and in commercial operation
within 24 months after such damage or destruction, (iv) the NEA or the NJEA
Project cannot be operated for a period of at least 18 consecutive months as a
result of a force majeure event, (v) the NEA or the NJEA Project loses its QF
status or (vi) NE LP determines to permanently shut down the NEA or NJEA
Project.
Assignment
Neither party may assign or otherwise convey its rights under the New
NEA and NJEA O&M Agreements, without the prior written consent of the other
party (such consent not unreasonably withheld), except that NE LP has agreed to
assign its rights and obligations under the New NEA O&M Agreement to NEA upon
the later to occur of (i) the applicable Operating Period Commencement Date and
(ii) the execution and delivery by NEA of a counterpart of the New NEA O&M
Agreement to NE LP and the New Operator and except that NE LP has agreed to
assign its rights and obligations under the New NJEA O&M Agreement to NJEA upon
the later to occur of the (i) applicable Operating Period Commencement Date and
(ii) the execution and delivery by NJEA of a counterpart of the New NJEA O&M
Agreement to NE LP and the New Operator.
Accommodation Agreement
NEA, Chase, as agent for the Original Banks, and the NEA Power
Purchasers have entered into an Accommodation Agreement dated as of June 28,
1989 (the "Accommodation Agreement'.") confirming the NEA Power Purchase
Agreements and the declaration of easements, covenants, and restrictions giving
the NEA Power Purchasers certain rights in the event that possession of the NEA
Project is obtained by or transferred to a third party pursuant to an exercise
of remedies under the Project Security Documents, and subordinating the rights
of the NEA Power Purchasers under the NEA Second Mortgage on the NEA Project to
those of the financial institutions party to the Original Project Credit
Agreement (as defined herein) under the NEA Project Mortgage. In connection with
the issuance of the Original Project Securities, each of the NEA Power
Purchasers affirmed the Accommodation Agreement and agreed that the NEA Second
Mortgage will be subordinated to the NEA Project Mortgage.
In addition, the Collateral Agent has confirmed to the NEA Power
Purchasers that the rights granted to the NEA Power Purchasers under the
Accommodation Agreement described above, are in full force and effect with
respect to the Collateral Agent, including the rights granted to the NEA Power
Purchasers under the Declaration. As a result (i) if the Collateral Agent or any
Project Secured Party acquires possession of the NEA Project or the NEA Site, or
NEA's interest therein, pursuant to the exercise of rights or remedies under the
Project Security Documents, or otherwise, then it will be required, among other
things, to use reasonable efforts to perform or cause to be performed the
obligations of NEA under the NEA Power Purchase Agreements subject to certain
conditions, and to honor the Declaration, (ii) if the Collateral Agent or a
Project Secured Party transfers the NEA Project or the NEA Site pursuant to a
foreclosure sale or otherwise, it must require any prospective transferee to
honor the NEA Power Purchase agreement and the declaration of easements,
covenants, and restrictions and (iii) in the event of a casualty to the NEA
Project, the Collateral Agent and the Project Secured Parties will allow the
application of Loss Proceeds (as defined herein) to the repair or restoration of
the NEA Project in accordance with certain provisions specified in the
Accommodation Agreement.
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Boston Edison Interconnection Agreement
The Amended and Restated Interconnection Agreement between Boston
Edison and NEA, dated September 24, 1993 (the "Boston Edison Interconnection
Agreement") provides for the electrical interconnection between the NEA Project
and Boston Edison's high voltage transmission line on its Right-of-Way No. 13.
This interconnection is used for the delivery of electricity to Boston Edison,
Montaup and Commonwealth pursuant to the NEA Power Purchase Agreements.
Term. The Boston Edison Interconnection Agreement will remain in effect
until the termination date of the latest to terminate of the NEA Power Purchase
Agreements. Boston Edison and NEA have agreed to remain interconnected during
the term of the Boston Edison Interconnection Agreement, so long as they can do
so without significant service disruptions and imminent danger to life or
property. An interruption of the interconnection for any of these reasons shall
continue only for so long as is reasonably necessary.
Operation and Maintenance. Each of NEA and Boston Edison owns and
maintains the respective facilities that it has constructed pursuant to the
terms of the Boston Edison Interconnection Agreement. Boston Edison and NEA have
agreed to operate the interconnection in accordance with NEPOOL's rules and
requirements. If NEPOOL ceases to establish such rules and requirements, the
parties have agreed to operate interconnection in compliance with requirements
of Boston Edison, provided that such requirements are reasonable and consistent
with the NEPOOL rules and requirements previously in effect. Boston Edison has
the sole right to schedule maintenance (routine or emergency) for its
transmission lines and other interconnection facilities used for the NEA
Project. Boston Edison has agreed to perform such maintenance and NEA has agreed
to pay Boston Edison the cost thereof. NEA has sole responsibility for operating
and maintaining its transmission lines and interconnection facilities at its own
expense.
Payment. NEA has agreed to (i) pay or reimburse Boston Edison for all
engineering, design and construction costs incurred by Boston Edison in
providing the electrical interconnection, including a percentage of costs
attributable to indirect engineering and corporate overhead and (ii) reimburse
Boston Edison for all operation and maintenance expenses and all taxes
associated with Boston Edison's interconnection facilities used by the NEA
Project. If at any time FERC approves a tariff of Boston Edison applicable to
the interconnection services provided under the Boston Edison Interconnection
Agreement, such tariff shall be used to determine payments and compensation in
lieu of the payment terms contained in the agreement.
Fuel Management Agreements
NEA and NJEA Fuel Management Agreements
Each of the Fuel Management Agreements, dated as of January 20, 1998
(the "NEA Fuel Management Agreement"), by and between NE LP and ESI Northeast
Fuel Management, Inc., an affiliate of ESI Energy (the "Fuel Manager"), assigned
by NE LP to NEA on January 20, 1998, and the Fuel Management Agreement, dated as
of January 20, 1998, effective retroactive to January 14, 1998 (the "NJEA Fuel
Management Agreement" and together with the NEA Fuel Management Agreement, the
"Fuel Management Agreements"), by and between NE LP and the Fuel Manager,
assigned by NE LP to NJEA on January 20, 1998, provides for the management of
all natural gas (and in the case of the NEA Fuel Management Agreement, fuel oil
supply), transportation and storage agreements and the location and purchase of
any additional required natural gas (and in the case of the NEA Fuel Management
Agreement, fuel oil), by the Fuel Manager for each of the Projects.
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Term. The term of the NEA Fuel Management Agreement extends for
twenty-five (25) years, expiring on January 14, 2023, and the term of the NJEA
Fuel Management Agreement extends for twenty-five (25) years, expiring on
January 14, 2023.
Fuel Management Services. The Fuel Manager has agreed to provide fuel
management services for the NEA Project (the "NEA Fuel Management Services") and
for the NJEA Project (the "NEA Fuel Management Services"), including without
limitation: (i) preparation and modification of fuel transportation, storage and
supply plans, (ii) transportation scheduling, transportation balancing,
transportation imbalance reconciliation, proposals and possible utilization of
excess transportation capacity through scheduling and relinquishment or possible
sales to third parties, compliance with pipeline operational orders, general
operational and planning advice, (iii) monitoring of pipeline tariff filings and
possible intervention in FERC hearings, (iv) analysis of the NEA and NJEA
Projects' fuel requirements, (v) analysis of regional supply and demand,
sources, transportation, delivery, supply mechanisms and the regulatory
structure for natural gas (and, in the case of NEA, fuel oil), (vi) screening of
proposals by natural gas and fuel oil suppliers, and if approved by NEA or NJEA,
as the case may be, negotiation and obtainment of additional supply agreements
with such suppliers, (vii) evaluation of price risk management proposals, and if
agreed to by NEA or NJEA, as the case may be, negotiation and obtainment of such
risk management arrangements, (viii) review of existing and potential
transportation and storage arrangements for natural gas and fuel oil advisement
to NEA and NJEA concerning such arrangements, and if approved by NEA or NJEA, as
the case may be, negotiation and obtainment of such additional arrangements,
(ix) advisement concerning changes in cost, reliability, interruption or other
factors affecting supply of natural gas and fuel oil, advisement on alternative
supply arrangements, and if agreed to by NEA or NJEA, as the case may be, the
negotiation and obtainment of such alternative arrangements and (x) location and
purchase of replacement gas and fuel oil or transportation services in emergency
situations.
Compensation. NEA has agreed to pay to the Fuel Manager a minimum
management fee of $450,000 per annum for the services provided under the NEA
Fuel Management Agreement (the "NEA Fuel Management Fee"), and NJEA has agreed
to pay to the Fuel Manager a minimum management fee of $450,000 per annum for
the services provided under the NJEA Fuel Management Agreement (the "NJEA Fuel
Management Fee"), each payable in monthly installments and adjusted annually in
accordance with the Producer Price Index for All Commodities, published by the
Department of Labor, Bureau of Labor Statistics. In addition to the NEA and NJEA
Fuel Management Fees, NEA and NJEA have agreed to pay to the Fuel Manager all
properly incurred costs and expenses of performing the NEA Fuel Management
Services and NJEA Fuel Management Services, respectively.
Termination. NEA may, by written notice to the Fuel Manager, terminate
the NEA Fuel Management Agreement, and NJEA may, by written notice to the Fuel
Manager, terminate the NJEA Fuel Management Agreement, if the Fuel Manager acts,
in a material way, outside the authority granted to it by NEA pursuant to the
NEA Fuel Management Agreement or by NJEA pursuant to the NJEA Fuel Management
Agreement. The Fuel Manager may, by written notice to NEA or NJEA, as the case
may be, terminate their respective Fuel Management Agreements, if the offending
party fails to make a payment thereunder within 10 days after the same shall
have become due. Either party may terminate the NEA Fuel Management Agreement or
the NJEA Fuel Management Agreement by written notice if (i) the other party
fails, for reasons other than force majeure, to perform any of the material
covenants or obligations imposed upon it under and by virtue of the NEA Fuel
Management Agreement or the NJEA Fuel Management Agreement, as the case may be,
and does not remedy or cure such default (and the effects thereof) within 30
days after such party's receipt of the non-defaulting party's written notice
thereof (or within 90 days after receipt of such notice, in the case of defaults
not susceptible of cure within 30 days, provided, however, that the defaulting
party commences and diligently seeks to cure such default within such 30 day
period), (ii) the applicable Project is destroyed or suffers damage in excess of
91
$100,000,000 and is not rebuilt and in commercial operation within 24 months
after such damage or destruction, (iii) the applicable Project cannot be
operated for a period of at least 18 consecutive months as a result of a force
majeure event, (iv) the applicable Project loses its QF status or (v) NEA or
NJEA, as the case may be, determines to permanently shut down the applicable
Project.
Administrative Services Agreement
The Administrative Services Agreement dated as of November 21, 1997
between NE LP and ESI GP (the "Administrative Services Agreement") provides for
the performance by ESI GP of certain services, as summarized below, to assist
the management committee of NE LP with the management and administration of NE
LP and the Partnerships.
Term
The Administrative Services Agreement extends for a term of 20 years
expiring January 14, 2018.
Services
ESI GP's general obligations under the Administrative Services
Agreement consist of (i) leading the negotiation and administration of all
contracts to which NE LP or either of the Partnerships is a party (subject to
certain contracts with Affiliates of ESI GP) (ii) implementing the annual
budgets of each of the Partnerships, NE LP and NE LLC, and other policies and
directions provided by the Management Committee, (iii) managing the affairs of
NE LP and each of the Partnerships and (iv) administering and coordinating any
financing to which NE LP is a party. In the event emergency actions are required
and if ESI GP is unable to consult with the Management Committee, ESI GP may
make any expenditures it deems advisable to protect and safeguard life and
property with respect to the Projects.
ESI GP is also obligated to (i) administer the Fuel Management
Agreements on behalf of NE LP and the Partnerships, and monitor and supervise
the Fuel Manager's compliance therewith, (ii) administer the O&M Agreements and
the New O&M Agreements on behalf of NE LP and the Partnerships, and monitor and
supervise the Operator's and the New Operator's compliance therewith, (iii)
prepare the initial annual budgets of NE LP, NE LLC and the Partnerships for
review and approval by the Management Committee, (iv) report on the receipts and
expenditures of the NE LP, NE LLC and the Partnerships at each meeting of the
Management Committee as of a date reasonably close to the date of the meeting
and will recommend to the Management Committee any changes in the annual budgets
which it considers necessary or appropriate, (v) keep or cause to be kept
complete and accurate books, records and financial statements of NE LP and
supporting documentation of transactions with respect to the conduct of NE LP's
business and (vi) provide specified financial statements and reports to ESI GP,
Tractebel GP, ESI LP and Tractebel LP.
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Administrative Services Fee
NE LP is obligated under the contract to pay to ESI GP a fee, payable
monthly, equal to $600,000 per annum (the "Administrative Services Fee"), as
adjusted upwards or downwards by multiplying the Administrative Services Fee for
the prior year by a fraction the numerator of which will be a producer price
index reported by the Department of Labor Bureau of Labor Statistics for the
immediately preceding December and the denominator of which will be such
producer price index for the month of December one year earlier; provided that
in no event shall the Administrative Services Fee be decreased below $600,000.
Neither of the Partnerships is liable for the payment of the Administration
Services Fee.
Administrative Expenses
NE LP is obligated under the contract to pay to ESI GP all
out-of-pocket costs and expenses of performing the services under the contract.
Termination
NE LP may terminate the Administrative Services Agreement (i) upon
thirty days' notice to ESI GP if ESI GP transfers its general partner interest
in NE LP (other than to an Affiliate) or (ii) upon written notice to ESI GP if
ESI GP materially defaults in the performance of any material term, covenant or
obligation contained in the Administrative Services Agreement and does not
remedy such default within thirty days after ESI GP's receipt of NE LP's written
notice thereof to ESI GP (or within 180 days, if it cannot be reasonably
accomplished in such thirty day period and ESI GP shall diligently take all
appropriate actions to remedy such default as soon as commercially practicable
within such thirty day period), in such case NE LP shall pay to ESI GP all
amounts due and not previously paid to ESI GP for services performed in
accordance with the Administrative Services Agreement through the effective date
of such termination. ESI GP may, by written notice to NE LP, terminate the
Administrative Services Agreement if NE LP (i) fails to make any payment under
the Administrative Services Agreement within 5 days after the same shall have
become due or (ii) materially defaults in the performance of any material term,
covenant or agreement contained therein and does not remedy such default within
thirty days after NE LP's receipt of ESI GP's written notice thereof to the
Partnership (or within 180 days, if it cannot be reasonably accomplished in such
thirty day period and the Partnership shall have commenced all actions required
to remedy such default within such thirty day period). Either party may
terminate the Administrative Services Agreement by written notice to the other
party (but only with the concurrence of ESI GP in the case of termination by NE
LP) if (i) the other party is in bankruptcy or makes a general assignment for
the benefit of creditors; (ii) proceedings are commenced or steps taken for the
appointment of a receiver, custodian, liquidator, trustee or similar person with
respect to all or a substantial portion of the other party's property; or (iii)
any proceedings are commenced or steps taken by any creditor, regulatory agency
or other person relating to the reorganization, arrangement, adjustment
composition, liquidation, dissolution, winding up, custodianship or other
similar relief with respect to such other party.
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MANAGEMENT
Management Committee of NE LP
All management functions of the Partnerships are the responsibility of
NE LP. Pursuant to the NE LP Partnership Agreement, such functions are performed
by the Management Committee of NE LP. The following table lists the names and
ages of the members of the Management Committee of NE LP.
Name Age Affiliation
- ---- --------- -----------
Kenneth P. Hoffman................. 46 FPL Energy
Scot C. Hathaway................... 46 FPL Energy
Eric M. Heggeseth.................. 46 Tractebel Power
W.E. (Wes) Schattner............... 45 Tractebel Power
Kenneth P. Hoffman was appointed to the NE LP Management Committee by
ESI GP in November, 1997. Mr. Hoffman joined ESI Energy in June 1989, and since
1993 has been the Vice President of Business Management. Mr. Hoffman is
currently a Vice President of FPL Energy. Prior to joining ESI Energy, Mr.
Hoffman was employed by FPL. Mr. Hoffman holds an M.B.A. degree from Florida
International University and a B.S. degree from Rochester Institute of
Technology.
Scot C. Hathaway was appointed to the NE LP Management Committee by ESI
GP in April 1998. From November 1990 until December 1995, Mr. Hathaway was the
fuel manager and since January 1995, has been the Director, Fuels and Business
Management of Doswell Limited Partnership ("DLP"), the owner of a 665.6 MW
combined cycle, power generation facility. ESI Energy owns a controlling
interest in DLP. Mr. Hathaway holds an M.S. degree from Northwestern University
and a B.S. degree from Virginia Polytechnic Institute.
Eric M. Heggeseth was appointed to the NE LP Management Committee by
Tractebel GP in March 1998. Since 1992, Mr. Heggeseth has been a vice president
for Tractebel Power, Inc. and related entities. Mr. Heggeseth is a member of the
management committees for the following independent facilities: Hopewell
Cogeneration Facility, a 365 MW gas combined-cycle cogeneration facility in
Hopewell, Virginia; West Windsor Power Project, a 110 MW gas combined-cycle
cogeneration facility in Windsor, Ontario; Appomatox Cogeneration Facility, a 50
MW black liquor, coal and wood waste cogeneration facility in Hopewell,
Virginia; Ryegate Power Station, a 20 MW wood-fired electric facility in East
Ryegate, Vermont and Winooski One Hydro, a 7.5 MW hydro-electric facility in
Winooski, Vermont. Mr. Heggeseth holds a B.S. degree from St. Olaf College.
W.E. (Wes) Schattner was appointed to the NE LP Management Committee by
Tractebel GP in January 1998. Since 1992, Mr. Schattner has been an executive
vice president of Tractebel Power, Inc. and related entities. Mr. Schattner
currently serves on the management committees of Hopewell Cogeneration Facility,
Westwood Properties, a waste coal facility, Ryegate Power Station, Appomattox
Cogeneration Facility and West Windsor Power Project. Mr. Schattner holds a B.S.
degree from Rensselaer Polytechnic Institute.
Pursuant to the Administrative Services Agreement, ESI GP has agreed to
perform services on behalf of NE LP in connection with the management of NE LP,
the Partnerships, ESI Tractebel Funding and ESI Tractebel Acquisition. See
"Summary of Principal Project Agreements -- Administrative Services Agreement."
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EXECUTIVE COMPENSATION
None of the executive officers or directors of ESI Tractebel
Acquisition receives any compensation for his or her services. The members of
the Management Committee of NE LP are not entitled to any direct compensation
from ESI Tractebel Acquisition, ESI Tractebel Funding or the Partnerships. NE LP
is to be paid a management fee by the Partnerships, as described under "Certain
Transactions -- Management Costs."
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth as of May 6, 1998, the direct and
indirect partnership interests in the Partnerships.
Name and Address of Nature of Beneficial
Title of Class Beneficial Owner Ownership Percentage Interest
- -------------- ------------------- -------------------- -------------------
General and Limited Northeast Energy LP(1)(2) General Partner 98% LP
Partnership Interest 1% GP
Limited Partnership Interest Northeast Energy LLC(1)(2) Limited Partner 1% LP
General Partnership Interest ESI GP(1)(2) General Partner in 1% GP
Northeast Energy LP
General Partnership Interest Tractebel GP(3)(4) General Partner in 1% GP
Northeast Energy LP
Limited Partnership Interest ESI LP(1)(2) Limited Partner in 49% LP
Northeast Energy LP
Limited Partnership Interest Tractebel LP(3)(4) Limited Partner in 49% LP
Northeast Energy LP
- ----------------
(1) The address for each of Northeast Energy LP, Northeast Energy LLC, ESI GP
and ESI LP is c/o FPL Energy, Inc., 11760 US Highway 1, Suite 600, North
Palm Beach, Florida 33408.
(2) ESI GP and ESI LP are wholly-owned, direct subsidiaries of ESI Energy. ESI
Energy is a wholly-owned, indirect subsidiary of FPL Group, Inc.
(3) The address for each of Tractebel GP and Tractebel LP is c/o Tractebel
Power, Inc., 1177 West Loop South, Suite 900, Houston, Texas 77027.
(4) Tractebel GP and Tractebel LP are wholly-owned, direct subsidiaries of
Tractebel Power. Tractebel Power is a wholly-owned, indirect subsidiary of
Tractebel, S.A.
The following table sets forth as of May 6, 1998, the number of shares
and percentage owned of ESI Tractebel Acquisition's voting securities
beneficially owned by each Person known by ESI Tractebel Acquisition to be the
beneficial owner of more than five percent (5%) of ESI Tractebel Acquisition's
voting securities.
Name and Address of Amount and Nature of
Title of Class Beneficial Owner Beneficial Ownership Percent of Class
- -------------- ------------------- -------------------- -------------------
Common Stock ESI Northeast Energy 10 shares 50%
Acquisition Funding, Inc.(1)
Common Stock Tractebel Power, Inc.(1) 10 shares 50%
- ---------------
(1) The address for ESI Northeast Energy Acquisition Funding, Inc. is c/o
FPL Energy, Inc., 11760 US Highway 1, Suite 600, North Palm Beach,
Florida 33408 and the address for Tractebel Power, Inc. is 1177 West
Loop South, Suite 900, Houston, Texas 77027.
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CERTAIN TRANSACTIONS
Management Costs
Fees payable by the Partnerships to NE LP are limited to the Management
Costs permitted under the Project Indenture, which consists of four components:
(i) out-of-pocket costs payable to third parties (including allocated rent and
independent legal, consulting and accounting fees and expenses), (ii) general
administrative expenses allocable to the Projects, (iii) compensation (including
salary and related benefits) of individuals and (iv) for each calendar year, an
amount equal to $3,500,000, $1,500,000 of which is the Subordinated Management
Fee (each such amount inflated annually in accordance with the Project
Indenture). All costs identified in clauses (i), (ii) and (iii) may be included
as part of the Management Costs and paid from Project Revenues only to the
extent such costs are certified by the Partnerships as being reasonably
allocable to the Projects. The amounts described in clause (iv) for the year
ending December 31, 1997 and 1996 were approximately $3,758,000 and $3,688,000,
respectively, and are subject to escalation as set forth in the Project
Indenture.
Administrative Services Fee
As compensation to ESI GP for the services it performs pursuant to the
Administrative Services Agreement, NE LP has agreed to pay to ESI GP a fee,
payable monthly, equal to $600,000 per annum, adjusted annually based on a
producer price index (the "Administrative Services Fee"), provided that in no
event is the Administrative Services fee to be decreased below $600,000. Neither
of the Partnerships is liable for the Administrative Services Fee. See "Summary
of Principal Project Agreements -- Administrative Services Agreement."
New O&M Fees
The New Operator, an Affiliate of NE LP, currently is providing certain
oversight and transition services for the Projects and will provide operation
and maintenance services for the Projects following the expiration or early
termination of the O&M Agreements, pursuant to each of the New O&M Agreements.
As compensation for such services, NE LP has agreed under each of the New O&M
Agreements to pay to the New Operator a fee of $750,000 per annum ($1,500,000
per annum in the aggregate), payable monthly and adjusted annually based on a
producer price index (the "New O&M Fees"). In addition, NE LP has agreed to pay
to the New Operator all properly incurred costs and expenses of performing the
transition services and the operation and maintenance services. NE LP expects
that combined operations and maintenance costs for both Projects will be reduced
by approximately $6.5 million per year after 2001, when the O&M Agreements for
the Projects expire. Neither of the Partnerships is liable for the New O&M Fees
prior to the applicable Operating Period Commencement Date. See "Summary of
Principal Project Agreements -- New O&M Agreements."
Fuel Management Fees
The Fuel Manager, an affiliate of FPL Energy, currently is providing
certain fuel management services for the Projects, pursuant to each of the Fuel
Management Agreements. As compensation for such services, each of NEA and NJEA
has agreed to pay to the Fuel Manager a fee under the NEA Fuel Management
Agreement and the NJEA Fuel Management Agreement, respectively, of $450,000 per
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annum, payable monthly and adjusted annually based on a producer price index
(the "NEA Fuel Management Fee" and the "NJEA Fuel Management Fee,"
respectively), provided that neither of such Fuel Management Fees is to be
decreased below $450,000. See "Summary Of Principal Project Agreements -- Fuel
Management Agreements."
THE EXCHANGE OFFER
Purpose of the Exchange Offer
The Exchange Offer is being made by ESI Tractebel Acquisition and NE LP
to satisfy their obligations pursuant to the Registration Rights Agreement,
which requires ESI Tractebel Acquisition and NE LP to use their best efforts to
effect the Exchange Offer under the 1933 Act. A copy of the Registration Rights
Agreement has been filed as an exhibit to the Registration Statement of which
this Prospectus is a part.
Based on an interpretation of the staff of the SEC set forth in
no-action letters issued to third parties in circumstances substantially the
same as those applicable here, ESI Tractebel Acquisition believes that New
Securities issued pursuant to the Exchange Offer in exchange for Old Securities
may be offered for resale, resold and otherwise transferred by a holder thereof
(other than (i) a broker-dealer who purchases such New Securities directly from
the Company to resell pursuant to Rule 144A or any other available exemption
under the 1933 Act or (ii) any such holder which is an "affiliate" of ESI
Tractebel Acquisition or NE LP within the meaning of Rule 405 under the 1933
Act) without compliance with the registration and prospectus delivery provisions
of the 1933 Act provided that such New Securities are acquired in the ordinary
course of such holder's business and such holder has no arrangement or
understanding with any person to participate in the distribution of such New
Securities. Any broker-dealer that receives New Securities for its own account
pursuant to the Exchange Offer must acknowledge that it will deliver a
prospectus in connection with any resale of such New Securities. Although there
has been no indication of any change in the staff's position, there can be no
assurance that the staff of the SEC would make a similar determination with
respect to the resale of the New Securities. A letter accompanying the New
Securities to be delivered to each holder of the Old Securities pursuant to the
Exchange Offer will state that, by delivering a prospectus, a broker-dealer will
not be deemed to admit that it is an "underwriter" within the meaning of the
1933 Act. This Prospectus, as it may be amended or supplemented from time to
time, may be used by broker-dealers in connection with the resale of New
Securities received in exchange for Old Securities where such Old Securities
were acquired by such broker-dealer as a result of market-making activities or
other trading activities. ESI Tractebel Acquisition has agreed that for a period
of up to one year after the date of the consummation of the Exchange Offer, it
will use its best efforts to cause the Registration Statement, of which this
Prospectus is a part, to remain continuously effective. See "Plan of
Distribution."
Terms of the Exchange Offer; Period for Tendering Old Securities
Upon the terms and subject to the conditions set forth in this
Prospectus and in the accompanying Letter of Transmittal (which together
constitute the "Exchange Offer"), ESI Tractebel Acquisition will exchange the
New Securities for the Old Securities which are properly tendered on or prior to
the Expiration Date and not withdrawn as permitted below. As used herein, the
term "Expiration Date" means 5:00 p.m. New York City time, on ________, 1998;
provided, however, if ESI Tractebel Acquisition, in its sole discretion, has
extended the period of time for which the Exchange Offer is open, the term
"Expiration Date" means the latest time and date to which the Exchange Offer is
extended; provided, further that in no event will the Exchange Offer be extended
beyond ____, 1998.
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As of the date of this Prospectus, $220,000,000 in aggregate principal
amount of the Old Securities are outstanding. This Prospectus, together with the
Letter of Transmittal, is being sent as of the date of this Prospectus, to all
registered holders of the Old Securities known to ESI Tractebel Acquisition. ESI
Tractebel Acquisition's obligation to accept the Old Securities for exchange
pursuant to the Exchange Offer is subject to certain conditions as set forth
below under "-- Certain Conditions to the Exchange Offer".
ESI Tractebel Acquisition may extend the Exchange Offer at any time or
from time to time by giving oral or written notice to the Exchange Agent and by
timely public announcement. Without limiting the manner in which ESI Tractebel
Acquisition may choose to make any public announcement and subject to applicable
law, ESI Tractebel Acquisition shall have no obligation to publish, advertise or
otherwise communicate any such public announcement other than by issuing a
release to an appropriate news agency. During any such extension, all Old
Securities previously tendered will remain subject to the Exchange Offer, and
may be accepted for exchange.
The terms of the Old Securities and the New Securities are identical in
all material respects, except for certain transfer restrictions and registration
rights relating to the Old Securities and certain rights to receive Registration
Default Damages. See "-- Registration Rights; Registration Default Damages." The
Old Securities were, and the New Securities will be, issued under the Indenture
and both the Old Securities and the New Securities are entitled to the benefits
of the Indenture.
ESI Tractebel Acquisition expressly reserves the right to amend or
terminate the Exchange Offer and not to accept for exchange any Old Securities
not theretofore accepted for exchange upon the occurrence of any of the
conditions of the Exchange Offer specified below under "-- Certain Conditions to
the Exchange Offer." To the extent the Exchange Offer is terminated, the Old
Securities not accepted for exchange will be returned without expense to the
tendering holder as promptly as practicable after the termination of the
Exchange Offer. ESI Tractebel Acquisition will give oral or written notice of
any extension, amendment, non-acceptance, or termination to the registered
holders of the Old Securities as promptly as practicable, such notice in the
case of any extension to be issued no later than 9:00 a.m., New York City time,
on the next business day following the previously scheduled Expiration Date. For
purposes of the Exchange Offer, a "business day" means any day other than a
Saturday, Sunday, or federal holiday and consists of the time period from 12:01
a.m. through Midnight, New York City time.
Registration Rights; Registration Default Damages
In connection with the issuance of the Old Securities, ESI Tractebel
Acquisition and NE LP entered into the Registration Rights Agreement with
Goldman.
Holders of New Securities (other than as set forth below) are not
entitled to any registration rights with respect to the New Securities. Pursuant
to the Registration Rights Agreement, holders of Old Securities are entitled to
certain registration rights. Under the Registration Rights Agreement, ESI
Tractebel Acquisition and NE LP have agreed, for the benefit of the holders of
the Old Securities, that they will, at their cost, (i) within 90 days after
February 19, 1998, file the Registration Statement with the SEC and (ii) within
180 days after February 19, 1998, use their best efforts to cause such
Registration Statement to be declared effective under the 1933 Act. The
Registration Statement of which this Prospectus is a part constitutes the
Registration Statement. If (i) ESI Tractebel Acquisition and NE LP are not
permitted to consummate the Exchange Offer because the Exchange Offer is not
permitted by applicable law or SEC policy or (ii) any holder of Transfer
Restricted Bonds (as defined) notifies ESI Tractebel Acquisition within the
specified time period that (A) such holder is prohibited by law or SEC policy
from participating in the Exchange Offer, (B) such holder may not resell the New
Securities acquired by it in the Exchange Offer to the public without delivering
a prospectus and this Prospectus is
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not appropriate or available for such resales by such holder or (C) such holder
is a broker-dealer and acquired the Old Securities directly from ESI Tractebel
Acquisition or an Affiliate of ESI Tractebel Acquisition, ESI Tractebel
Acquisition and NE LP will file with the SEC the Shelf Registration Statement to
cover resales of the Transfer Restricted Bonds by the holders thereof who
satisfy certain conditions relating to the provision of information in
connection with the Shelf Registration Statement. ESI Tractebel Acquisition and
NE LP will use their best efforts to cause the applicable registration statement
to be declared effective as promptly as possible by the SEC. For purposes of the
foregoing, "Transfer Restricted Bonds" means each Old Security, until the
earliest to occur of (i) the date on which such Transfer Restricted Bonds has
been exchanged in the Exchange Offer and entitled to be resold to the public by
the holder thereof without complying with the prospectus delivery requirements
of the 1933 Act, (ii) following the exchange by a broker-dealer in the Exchange
Offer of a Transfer Restricted Bond for a New Security, the date on which such
New Security is sold to a purchaser who receives from such broker-dealer on or
prior to the date of such sale a copy of the Prospectus contained in the
Registration Statement, (iii) the date on which such security has been
effectively registered under the 1933 Act and disposed of in accordance with the
Shelf Registration Statement or (iv) the date on which such security is
distributed pursuant to Rule 144 under the 1933 Act.
The Registration Rights Agreement also provides that, (i ) unless the
Exchange Offer would not be permitted by applicable law or SEC policy, ESI
Tractebel Acquisition and NE LP will commence the Exchange Offer and use their
best efforts to issue on or prior to 30 business days after the date on which
the Registration Statement was declared effective by the SEC, New Securities in
exchange for all Transfer Restricted Bonds tendered prior thereto in the
Exchange Offer and (ii) if obligated to file the Shelf Registration Statement,
ESI Tractebel Acquisition and NE LP will file the Shelf Registration Statement
with the SEC on or prior to 30 days after such filing obligation arises and use
their best efforts to keep such Shelf Registration Statement continuously
effective, supplemented and amended until the second anniversary of the date on
which the Shelf Registration Statement becomes effective or such shorter period
that will terminate when all the Transfer Restricted Bonds covered by the Shelf
Registration Statement have been sold pursuant to the Shelf Registration
Statement. If (a) ESI Tractebel Acquisition and NE LP fail to file any of the
registration statements required by the Registration Rights Agreement on or
before the date specified for such filing, (b) any of such registration
statements are not declared effective by the SEC on or prior to the date
specified for such effectiveness (the "Effectiveness Target Date"), (c) the
Company fails to consummate the Exchange Offer within 30 business days of the
effective date of the Registration Statement, or (d) the Shelf Registration
Statement or the Registration Statement is declared effective but thereafter,
subject to certain exceptions, ceases to be effective or usable in connection
with resales of Transfer Restricted Bonds during the periods specified in the
Registration Rights Agreement (each such event referred to in clauses (a)
through (d) above a "Registration Default"), then the Company will pay
Registration Default Damages to each holder of Transfer Restricted Bonds, with
respect to the first 90-day period immediately following the occurrence of such
Registration Default in an amount equal to $.05 per week for each $1,000
principal amount of Transfer Restricted Bonds held by such holder. The amount of
the Registration Default Damages will increase by an additional $.05 per week
with respect to each subsequent 90-day period until all Registration Defaults
have been cured, up to a maximum amount of Registration Default Damages of $.50
per week for each $1,000 principal amount of Transfer Restricted Bonds, as
applicable. Following the cure of all Registration Defaults, the accrual of
Registration Default Damages will cease.
Holders of Transfer Restricted Bonds will be required to deliver
information to be used in connection with the Shelf Registration Statement and
to provide comments on the Shelf Registration Statement within the time periods
set forth in the Registration Agreement in order to have their Transfer
Restricted Bonds included in the Shelf Registration Statement and benefit from
the provisions regarding Registration Default Damages set forth above.
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Procedures for Tendering Old Securities
The tender to ESI Tractebel Acquisition of Old Securities by a holder
as set forth below and the acceptance thereof by ESI Tractebel Acquisition will
constitute a binding agreement between the tendering holder and ESI Tractebel
Acquisition upon the terms and subject to the conditions set forth in this
Prospectus and in the accompanying Letter of Transmittal, and all other
documents required by such Letter of Transmittal. Except as set forth below, a
holder who wishes to tender Old Securities for exchange pursuant to the Exchange
Offer must transmit the Old Securities, together with a properly completed and
duly executed Letter of Transmittal, and all other documents required by such
Letter of Transmittal, by overnight courier or hand delivery or by mail to State
Street Bank and the Trust Company (the "Exchange Agent") at one of the addresses
set forth below under "Exchange Agent", on or prior to the Expiration Date. In
addition, either (i) certificates for such Old Securities must be received by
the Exchange Agent along with the Letter of Transmittal, or (ii) a timely
confirmation of a book-entry transfer (a "Book-Entry Confirmation") of such Old
Securities, if such procedure is available, into the Exchange Agent's account at
The Depository Trust Company ("DTC") pursuant to the procedure for book-entry
transfer described below, must be received by the Exchange Agent prior to the
Expiration Date or (iii) the holder must comply with the guaranteed delivery
procedures described below. THE METHOD OF DELIVERY OF THE OLD SECURITIES,
LETTERS OF TRANSMITTAL, AND ALL OTHER REQUIRED DOCUMENTS IS AT THE ELECTION AND
RISK OF THE HOLDERS. IF SUCH DELIVERY IS BY MAIL, IT IS RECOMMENDED THAT
REGISTERED MAIL, PROPERLY INSURED, WITH RETURN RECEIPT REQUESTED, BE USED. IN
ALL CASES, SUFFICIENT TIME SHOULD BE ALLOWED TO ASSURE TIMELY DELIVERY. NO
LETTERS OF TRANSMITTAL OR OLD SECURITIES SHOULD BE SENT TO ESI TRACTEBEL
ACQUISITION OR NE LP.
Each signature on a Letter of Transmittal or a notice of withdrawal, as
the case may be, must be guaranteed unless the Old Securities surrendered for
exchange pursuant thereto are tendered (i) by a registered holder who has not
completed either the box entitled "Special Issuance Instructions" or the box
entitled "Special Delivery Instructions" on the Letter of Transmittal or (ii) by
an Eligible Institution (as defined below). In the event that a signature on a
Letter of Transmittal or a notice of withdrawal, as the case may be, is required
to be guaranteed, such guaranty must be by a firm which is a member of a
registered national securities exchange or a member of the National Association
of Securities Dealers, Inc., or by a commercial bank or trust company having an
office or correspondent in the United States or by such other "eligible
guarantor institution" within the meaning of Rule 17Ad-15 under the Exchange Act
(collectively, "Eligible Institutions"). If the Old Securities are registered in
the name of the person other than the signer of the Letter of Transmittal, the
Old Securities surrendered for exchange must either (i) be endorsed by the
registered holder, with a signature thereon guaranteed by an Eligible
Institution, or (ii) be accompanied by a bond power, duly executed by the
registered holder, with a signature thereon guaranteed by an Eligible
Institution. The term "registered holder" as used herein with respect to the Old
Securities means any person in whose name the Old Securities are registered on
the books of the Trustee, which is currently the Security Registrar for the
Securities, or, in the case of book-entry Old Securities, any participant in
DTC's system whose name appears on a security position listing as the holder of
such Old Securities.
Tenders may be made in principal amounts of $100,000 and integral
multiples of $1,000 in excess thereof. Subject to the foregoing, holders may
tender less than the aggregate principal amounts represented by the Old
Securities deposited with the Exchange Agent provided they appropriately
indicate this fact on the Letter of Transmittal accompanying the tendered Old
Securities.
All questions as to the validity, form, eligibility (including time of
receipt), acceptance and withdrawal of the Old Securities tendered for exchange
will be determined by ESI Tractebel Acquisition
100
in its sole discretion, which determination shall be final and binding. ESI
Tractebel Acquisition reserves the absolute right to reject any and all tenders
of any of the Old Securities not properly tendered or to reject any of the Old
Securities, the acceptance of which might, in the judgment of ESI Tractebel
Acquisition or its counsel, be unlawful. ESI Tractebel Acquisition also reserves
the absolute right to waive any defects or irregularities in the tender or
conditions of the Exchange Offer as to any of the Old Securities either before,
on or after the Expiration Date (including the right to waive the ineligibility
of any holder who seeks to tender the Old Securities in the Exchange Offer). The
interpretation of the terms and conditions of the Exchange Offer (including the
Letter of Transmittal and the instructions thereto) by ESI Tractebel Acquisition
shall be final and binding on all parties. Unless waived, any defects or
irregularities in connection with tenders of Old Securities for exchange must be
cured within such time as ESI Tractebel Acquisition shall determine. Neither ESI
Tractebel Acquisition, the Exchange Agent, NE LP, nor any other person shall be
under any duty to give notification of defects or irregularities with respect to
lenders of Old Securities for exchange, nor shall any of them incur any
liability for failure to give such notification. Tenders of the Old Securities
will not be deemed to have been made until such irregularities have been cured
or waived.
If any Letter of Transmittal, endorsement, bond power or other document
required by the Letter of Transmittal is signed by a trustee, executor,
administrator, guardian, attorney-in-fact, officer of a corporation or other
person acting in a fiduciary or representative capacity, such person should so
indicate when signing, and, unless waived by ESI Tractebel Acquisition, proper
evidence satisfactory to ESI Tractebel Acquisition of such person's authority to
so act must be submitted.
Each holder that tenders the Old Securities in the Exchange Offer will
be required to represent to ESI Tractebel Acquisition that (i) the New
Securities to be acquired by such holder are being acquired in the ordinary
course of such holder's business, (ii) such holder has no intent or arrangement
with any person to participate in the "distribution" of the New Securities
within the meaning of the 1933 Act and (iii) that such holder is not an
"affiliate" of ESI Tractebel Acquisition or NE LP as defined in Rule 405
promulgated under the 1933 Act.
Acceptance of the Old Securities for Exchange, Delivery of New Securities
Upon satisfaction or waiver of all the conditions to the Exchange
Offer, ESI Tractebel Acquisition will, promptly after the Expiration Date,
accept all the Old Securities properly tendered and will promptly thereafter
issue the New Securities. See "-- Certain Conditions to the Exchange Offer". For
purposes of the Exchange Offer, ESI Tractebel Acquisition shall be deemed to
have accepted Old Securities that are tendered for exchange when, as and if ESI
Tractebel Acquisition has given oral or written notice thereof to the Exchange
Agent, with written confirmation of any oral notice to be given promptly
thereafter. The Exchange Agent will act as agent for the tendering holders of
Old Securities for the purposes of receiving the New Securities from ESI
Tractebel Acquisition and delivering the New Securities to such holders.
The form and terms of the New Securities will be identical to the form
and terms of the Old Securities, except for certain changes to such forms to
reflect the consummation of the Exchange Offer. The New Securities will bear
interest from the last interest payment date of the Old Securities. Holders
whose Old Securities are accepted for exchange will not receive interest on such
Old Securities for any period subsequent to the last interest payment date of
the Old Securities to occur prior to the issue date of the New Securities and
will be deemed to have waived the right to receive any payment in respect of
interest on the Old Securities accrued from and after such interest payment
date. See "Description of Securities".
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In all cases, issuance of the New Securities for Old Securities that
are accepted for exchange pursuant to the Exchange Offer will be made only after
timely receipt by the Exchange Agent of the Old Securities, a properly completed
and executed Letter of Transmittal and all other required documents; provided,
however, that ESI Tractebel Acquisition reserves the absolute right to waive any
defects or irregularities in the tender or conditions of the Exchange Offer. If
any tendered Old Securities are not accepted for any reason set forth in the
terms and conditions of the Exchange Offer or if the Old Securities are
submitted for a greater principal amount than the holder desires to exchange,
such unaccepted Old Securities or substitute Old Securities evidencing the
unaccepted portion, as appropriate, will be returned (or, in the case of Old
Securities tendered by book entry transfer through DTC, will be credited to an
account maintained with DTC) without expense to the tendering holder as promptly
as practicable after the rejection of tender or the Expiration Date.
Exchanging Book-Entry Old Securities
The Exchange Agent and DTC have confirmed that any financial
institution that is a participant in DTC's system (a "Participant") may utilize
DTC's Automated Tender Offer Program ("ATOP") to tender Old Securities.
The Exchange Agent will request that DTC establish an account with
respect to the Old Securities for purposes of the Exchange Offer within two
business days after the date of this Exchange Offer. Any Participant may make
book-entry delivery of Old Securities by causing DTC to transfer such Old
Securities into such Exchange Agent's account in accordance with DTC's ATOP
procedures for transfer. However, the exchange for the Old Securities so
tendered will only be made after timely confirmation ( a "Book-Entry
Confirmation") of such book-entry transfer of Old Securities into the Exchange
Agent's account, and timely receipt by the Exchange Agent of the Letter of
Transmittal, and any other documents required by the Exchange Agent and forming
part of a Book-Entry Confirmation, which states that DTC has received an express
acknowledgement from a Participant tendering Old Securities which are the
subject of such Book-Entry Confirmation that such Participant has received and
agrees to be bound by the terms of the Letter of Transmittal, and that ESI
Tractebel Funding may enforce such agreement against such Participant.
The method of delivery of Old Securities is at the option and risk of
the tendering holder and, except as otherwise provided in the Letter of
Transmittal, the delivery will be deemed to be made only when actually received
by the Exchange Agent.
Guaranteed Delivery Procedures
Holders who wish to tender their Old Securities and (i) whose Old
Securities are not immediately available, (ii) who cannot deliver their Old
Securities, the Letter of Transmittal or any other required documents to the
Exchange Agent prior to the Expiration Date or (iii) who cannot comply with the
procedures for book entry tender on a timely basis, may effect a tender if:
(a) the tender is made through an Eligible Institution:
(b) prior to the Expiration Date, the Exchange Agent receives from such
Eligible Institution a properly completed and duly executed Notice of Guaranteed
Delivery (by facsimile transmission, mail or hand delivery) setting forth the
name and address of the holder of the Old Securities, the certificate number or
numbers of such Old Securities (except in the case of book-entry tenders) and
the principal amount of Old Securities tendered (regardless of the means of
tendering); stating that the tender is being made thereby and guaranteeing that,
within five New York Stock Exchange trading days after the Expiration Date, the
Letter of Transmittal (or facsimile thereof) together with Old Securities to be
102
tendered in proper form for transfer and any other documents required by the
Letter of Transmittal will be deposited by the Eligible Institution with the
Exchange Agent; and
(c) such properly completed and executed Letter of Transmittal (or
facsimile thereof), all tendered Old Securities in proper form for transfer (or
a Book-Entry Confirmation with respect to such Old Securities) and all other
documents required by the Letter of Transmittal are received by the Exchange
Agent within five New York Stock Exchange trading days after the Expiration
Date.
Withdrawal Rights
Tenders of Old Securities may be withdrawn at any time prior to the
Expiration Date.
For a withdrawal to be effective, a written notice of withdrawal must
be received by the Exchange Agent at the address set forth below prior to 5:00
p.m., New York City time, on the Expiration Date. Any such notice of withdrawal
must (i) specify the name of the person having deposited the Old Securities to
be withdrawn (the "Depositor"), (ii) identify the Old Securities to be withdrawn
(including the certificate number or numbers and principal amount of the Old
Securities), (iii) be signed in the same manner required for the Letter of
Transmittal by which such Old Securities were tendered (including any required
signature guarantees, endorsements, and/or bond powers) and (iv) specify the
name in which any such Old Securities are to be registered if different from
that of the Depositor. If the Old Securities have been tendered pursuant to the
procedure for book-entry tender set forth above under "-- Exchanging Book-Entry
Old Securities", a notice of withdrawal must specify, in lieu of certificate
numbers, the name and account number at DTC to be credited with the withdrawn
Old Securities. All questions as to the validity, form and eligibility
(including time of receipt) of such notices will be determined by ESI Tractebel
Acquisition, whose determinations shall be final and binding on all parties. Any
Old Securities so withdrawn, if any, will be deemed not to have been validly
tendered for exchange for purposes of the Exchange Offer. Any Old Securities
which have been tendered for exchange but which are withdrawn will be returned
to the holder without cost to such holder as soon as practicable after
withdrawal. Properly withdrawn Old Securities may be tendered by following one
of the procedures described under "-- Procedures for Tendering Old Securities"
above at any time on or prior to the Expiration Date.
Certain Conditions to the Exchange Offer
Notwithstanding any other provision of the Exchange Offer, ESI
Tractebel Acquisition shall not be required to accept for exchange, or to issue
the New Securities in exchange for, any Old Securities and may terminate or
amend the Exchange Offer, if at any time before the acceptance of the Old
Securities for exchange or the exchange of the Old Securities for the New
Securities, any of the following events shall occur which occurrence, in the
sole judgment of ESI Tractebel Acquisition and regardless of the circumstances
(including any action by ESI Tractebel Acquisition) giving rise to any such
event, makes it inadvisable to proceed with the Exchange Offer or with such
acceptance for exchange or with such exchange:
(a) there shall be threatened, instituted or pending any action or
proceeding before, or any injunction, order, or decree shall have been issued
by, any court or governmental agency or other governmental regulatory or
administrative agency or commission (i) seeking to restrain or prohibit the
making or consummation of the Exchange Offer or any other transaction
contemplated by the Exchange Offer, or assessing or seeking any damages as a
result thereof, or (ii) resulting in a material delay in the ability of ESI
Tractebel Acquisition to accept for exchange all or some of the Old Securities;
or any statute, rule, regulation, order or injunction shall be sought, proposed,
introduced, enacted, promulgated or deemed applicable to the Exchange Offer or
any of the transactions contemplated by the Exchange Offer by any domestic or
foreign government or governmental authority or any action shall have been
103
taken, proposed or threatened by any domestic or foreign government or
governmental authority or agency or court, that, in the sole judgment of ESI
Tractebel Acquisition, might directly or indirectly result in any of the
consequences referred to in clause (i) or (ii) above or, in the sole judgment of
ESI Tractebel Acquisition, might result in the holders of the New Securities
having obligations with respect to resales and transfers of New Securities that
are greater than those described in the interpretation of the SEC referred to on
the cover page of this Prospectus or would otherwise make it inadvisable to
proceed with the Exchange Offer;
(b) there shall have occurred (i) any general suspension of or general
limitation on prices for or trading in, securities on any national securities
exchange or the over-the-counter market, (ii) any limitation by any governmental
agency or authority which adversely affects the ability of ESI Tractebel
Acquisition to complete the transactions contemplated by the Exchange Offer,
(iii) a declaration of a banking moratorium or any suspension of payments in
respect of banks in the United States or any limitation by any governmental
agency or authority which adversely affects the extension of credit, or (iv) a
commencement of a war, armed hostilities, or other similar international
calamity directly or indirectly involving the United States, or in the case of
any of the foregoing existing at the time of the commencement of the Exchange
Offer, a material escalation or worsening thereof; or
(c) any change (or any development involving a prospective change)
shall have occurred or be threatened in the business, properties, assets,
liabilities, financial condition, operations, results of operations or prospects
of ESI Tractebel Acquisition, NE LP or either of the Partnerships that, in the
sole judgment of ESI Tractebel Acquisition, is or may have adverse significance
with respect to the values of the Old Securities or the New Securities.
The foregoing conditions are for the sole benefit of ESI Tractebel
Acquisition and may be asserted by ESI Tractebel Acquisition regardless of the
circumstances giving rise to any such condition or may be waived by ESI
Tractebel Acquisition in whole or in part at any time and from time to time in
its sole discretion. The failure by ESI Tractebel Acquisition at any time to
exercise any of the foregoing rights shall not be deemed a waiver of any such
right and each such right shall be deemed an ongoing right which may be asserted
at any time and from time to time. Any determination by ESI Tractebel
Acquisition concerning the events described above will be final and binding upon
all parties.
In addition, ESI Tractebel Acquisition will not accept for exchange any
Old Securities tendered, and no New Securities will be issued in exchange for
any such Old Securities, if at such time any stop order shall be threatened or
in effect with respect to the Registration Statement or the qualifications of
the Indenture under the Trust Indenture Act of 1939.
If any of the conditions described above exist, ESI Tractebel
Acquisition will refuse to accept any Old Securities and will promptly return
(or, in the case of Old Securities tendered by book-entry transfer through DTC,
will promptly credit to an account maintained with DTC) all tendered Old
Securities to exchanging holders of the Old Securities.
Exchange Agent
State Street Bank and the Trust Company has been appointed as the
Exchange Agent for the Exchange Offer. The Exchange Agent also acts as Trustee
under the Indenture. All executed Letters of Transmittal and Notices of
Guaranteed Delivery should be directed to the Exchange Agent at the addresses
set forth below. Questions and requests for assistance, requests for additional
copies of this Prospectus or for the Letter of Transmittal and requests for
Notices of Guaranteed Delivery should be directed to the Exchange Agent
addressed as follows:
104
Deliver to: State Street Bank and Trust Company, Exchange Agent:
- --------------------------------------- -------------------------------------- --------------------------------------
By Hand Delivery: By Overnight Courier By Mail:
----------------- -------------------- --------
State Street Bank and Trust Company State Street Bank and Trust Company State Street Bank and Trust Company
Corporate Trust Department Corporate Trust Department Corporate Trust Department
Two International Place Two International Place, 4th Floor P.O. Box 778
Fourth Floor Boston, Massachusetts 02110 Boston, Massachusetts 02110
Corporate Trust Window
Boston, Massachusetts 02110
- --------------------------------------- -------------------------------------- --------------------------------------
DELIVERY OF A LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET
FORTH ABOVE DOES NOT CONSTITUTE A VALID DELIVERY OF SUCH LETTER OF TRANSMITTAL.
Fees and Expenses
ESI Tractebel Acquisition will not make any payment to brokers, dealers
or others soliciting acceptances of the Exchange Offer. ESI Tractebel
Acquisition will, however, pay the Exchange Agent reasonable and customary fees
for its services and will reimburse it for reasonable out-of-pocket expenses in
connection therewith. ESI Tractebel Acquisition will also pay brokerage houses
and other custodians, nominees and fiduciaries the reasonable out-of-pocket
expenses incurred by them in forwarding copies of this Prospectus and related
documents to the beneficial owners of the Old Securities and in handling tenders
for their customers. The expenses to be incurred in connection with the Exchange
Offer, including the fees and expenses of the Exchange Agent and printing,
accounting, registration and legal fees, will be paid by ESI Tractebel
Acquisition and are estimated to be approximately $500,000.
Transfer Taxes
Holders who tender their Old Securities for exchange will not be
obligated to pay any transfer taxes in connection therewith, except that holders
who instruct ESI Tractebel Acquisition to register New Securities in the name
of, or request that Old Securities not tendered or not accepted in the Exchange
Offer be returned to, a person other than the registered tendering holder will
be responsible for the payment of any applicable transfer tax thereon.
Appraisal Rights
HOLDERS OF OLD SECURITIES WILL NOT HAVE DISSENTERS' RIGHTS OR APPRAISAL
RIGHTS IN CONNECTION WITH THE EXCHANGE OFFER.
Consequences of Failure to Exchange
Holders of Old Securities who do not exchange their Old Securities for
New Securities pursuant to the Exchange Offer will continue to be subject to the
restrictions on transfer of such Old Securities as set forth in the legend
thereon as a consequence of the issuance of the Old Securities pursuant to the
exemptions from, or in transactions not subject to, the registration
requirements of the 1933 Act and applicable state securities laws. In general,
the Old Securities may not be offered or sold, unless registered under the 1933
Act, except pursuant to an exemption from, or in a transaction not subject to,
the 1933 Act and applicable state securities laws. ESI Tractebel Acquisition
does not currently anticipate that it will register the Old Securities under the
1933 Act. Based on interpretations by the staff of the SEC set forth in certain
no-action letters addressed to other parties in other transactions, New
Securities
105
issued pursuant to the Exchange Offer may be offered for resale, resold or
otherwise transferred by holders thereof (other than (i) a broker-dealer who
purchases such New Securities directly from the Company to resell pursuant to
Rule 144A or any other available exemption under the 1933 Act or (ii) any such
holder which is an "affiliate" of ESI Tractebel Acquisition or NE LP within the
meaning of Rule 405 under the 1933 Act) without compliance with the registration
and prospectus delivery provisions of the 1933 Act provided that such New
Securities are acquired in the ordinary course of such holders' business and
such holders have no arrangement with any person to participate in the
distribution of such New Securities. If any holder has any arrangement or
understanding with respect to the distribution of the New Securities to be
acquired pursuant to the Exchange Offer, such holder (i) could not rely on the
applicable interpretations of the staff of the SEC and (ii) must comply with the
registration and prospectus delivery requirements of the 1933 Act in connection
with a secondary resale transaction. In addition, to comply with the securities
laws of certain jurisdictions, if applicable, the New Securities may not be
offered or sold unless they have been registered or qualified for sale in such
jurisdiction pursuant to the Registration Rights Agreement and subject to
certain specified limitations therein, to register or qualify the New Securities
for offer or sale under the securities or blue sky laws of such jurisdictions as
any holder of the Securities reasonably requests in writing. Upon consummation
of the Exchange Offer, due to the restriction on transfer of the Old Securities
described above and the absence of such restriction applicable to the New
Securities (subject to the qualifications described above), it is likely that
the market, if any, for Old Securities will be relatively less liquid than the
market for New Securities.
DESCRIPTION OF SECURITIES
General
The New Securities are identical in all material respects to the Old
Securities. The only significant difference is that the New Securities are
registered pursuant to the 1933 Act and thus are not subject to Registration
Default Damages. The New Securities are to be issued under the same Indenture
under which the Old Securities have been issued. The following summary of the
material provisions of the Indenture does not purport to be complete and is
qualified in its entirety by reference to the Indenture, including the
definitions therein of certain terms used below. Copies of the Indenture and the
Pledge Agreements have been filed as exhibits to the Registration Statement. See
"Available Information." The definitions of certain terms used in the following
summary are set forth below under the caption "-- Certain Definitions."
NE LP has unconditionally guaranteed the payment of the principal of
premium, if any, interest and Registration Default Damages, if any, on the
Securities pursuant to the Bond Guaranty executed and delivered to the Trustee.
The Securities will rank senior in right of payment to all subordinated
Indebtedness, if any, of ESI Tractebel Acquisition incurred in the future and
will rank pari passu in right of payment with all senior Indebtedness, if any,
of ESI Tractebel incurred in the future. Payment of the Securities will be
secured by: (a) a perfected, first priority pledge of (i) 100% of the partner
interests of NE LP, (ii) 100% of the member interests in NE LLC and (iii) NE
LP's 98% limited partner interest in each of the Partnerships and NE LLC's one
percent limited partner interest in each of the Partnerships, which will
include, among other things, all rights to receive distributions with respect to
the respective partner interests (such distributions to be made directly to the
Trustee by the Project Trustee (after taking into consideration the terms and
conditions set forth in the Project Indenture) and deposited into the Revenues
Account); (b) a second priority pledge of the one percent general partner
interest in each of the Partnerships (the first priority pledge of such general
partner interest securing the obligations of the Partnerships in respect of the
Project Indebtedness, which pledge will include, among other things, a pledge of
all of NE LP's rights to receive distributions with respect to its general
partner interest (such distributions to be made directly to the Trustee as
described in clause (a)(iii) immediately above); (c) a perfected, first priority
pledge of the Note evidencing NE LP's obligation to repay the Bond Loan; (d) a
106
perfected, first priority lien on the funds in the Accounts (as defined below);
and (e) a perfected, first priority pledge of all of the outstanding Capital
Stock of ESI Tractebel Acquisition.
The Securities are payable solely from payments to be made by NE LP
under the Note and from other moneys that may be available from time to time in
the Accounts (as defined below) held by the Trustee. NE LP's obligations to make
payments under the Note are non-recourse to the direct and indirect owners of NE
LP (including ESI Energy and Tractebel Power). Except as described below under
the caption "-- Acceptable Credit Support," neither the Partners nor any of the
direct or indirect owners of the Partners will be obligated to contribute
additional funds if moneys in the Accounts are insufficient for the payment of
debt service in respect of the Securities. So long as any of the Project
Indebtedness is outstanding, distributions to NE LP and NE LLC from the
Partnerships will constitute "Restricted Payments" under and as defined in the
Project Indenture and may be paid only from and to the extent of amounts then on
deposit with the Project Trustee in the Partnership Distribution Fund under the
Project Indenture. Transfers to the General Subfund of the Partnership
Distribution Fund may be made only upon satisfaction of several conditions,
including among others, that (i) the amount then on deposit in all of the other
funds under the Project Indenture are equal to or exceed the amounts then
required to be on deposit therein; (ii) no Default or Event of Default (as
defined in the Project Indenture) has occurred and is continuing; (iii) no Debt
is outstanding under the Working Capital Facility; (iv) either the Debt Service
Coverage Ratio for the Rolling Prior Year or the Substitute Debt Service
Coverage Ratio for the Rolling Prior Year (each as defined in the Project
Indenture) is equal to or exceeds 1.25:1; and (v) the Partnerships have no
knowledge of any event or circumstance that could reasonably be expected to
result in the Debt Service Coverage Ratio for the following two consecutive
fiscal quarters, treated as a single period, being less than 1.25:1. See
"Outstanding Project Indebtedness -- Flow of Funds" for a more detailed
description of the flow of funds under the Project Indenture and of the
conditions that must be satisfied prior to any distributions to NE LP and NE LLC
from the General Subfund of the Partnership Distribution Fund.
Except as otherwise permitted by the Indenture, NE LP and NE LLC will
hold all of the partner interests of NEA and NJEA. All revenues actually
received by NE LP and NE LLC from any source (other than the Released Cash
Collateral (as defined below), the payment of Management Costs and the
Non-Operating Revenues), including distributions from NEA and NJEA (other than
distributions constituting Non-Operating Revenues), and any earnings from funds
deposited in the Accounts (as defined below), will constitute "Operating
Revenues." The proceeds of any financing undertaken by NE LP, NE LLC or ESI
Tractebel Acquisition, distributions made by the Partnerships to NE LP or NE LLC
with the proceeds of any financing or with funds required to be used for the
extraordinary mandatory redemption of the Securities as described under the
caption "--Extraordinary Mandatory Redemption" and any other extraordinary
revenues (including any buyout or similar payment made to a Partnership under
any Power Purchase Agreement) will constitute "Non-Operating Revenues" (together
with the Operating Revenues, the "Revenues"). Any cash obtained from the
Partnerships by the Sponsors, NE LP or NE LLC at or following the Acquisitions
due to the release of cash collateral and the substitution therefor of
alternative collateral pursuant to the Project Indenture (the "Released Cash
Collateral") and any payment of Management Costs (as defined in the Project
Indenture as in effect on the date of the Indenture) will not (a) be subject to
the lien of the Collateral Documents, (b) be deposited in the Accounts or (c)
constitute Revenues. The Indenture will provide for the allocation of Revenues
and for the establishment and maintenance of a Revenues Account, a Debt Service
Account, a Debt Service Reserve Account and a Distribution Account
(collectively, the "Accounts"). All Revenues will be paid into the Revenues
Account, from which funds will be transferred on a monthly basis in the order of
priority set forth below under the caption "-- Flow of Funds." The Trustee will
be required to apply amounts in the Debt Service Account to make payments on the
Securities when due.
107
Payments in respect of the Note and, therefore, in respect of the
Securities will be effectively subordinated to payment of all Indebtedness and
other liabilities and commitments (including trade payables and lease
obligations) of NEA and NJEA, including the guarantee by NEA and NJEA of the
Project Indebtedness. Any right of NE LP and NE LLC to receive the assets of any
of their Subsidiaries (including NEA and NJEA) upon the latter's liquidation or
reorganization (and the consequent right of the Holders of the Securities to
participate in those assets) will be effectively subordinated to the claims of
such Subsidiaries' creditors (including the holders of the Project
Indebtedness), except to the extent that NE LP or NE LLC are themselves
recognized as creditors of such Subsidiaries, in which case the claims of NE LP
and NE LLC would still be subordinate to any security in the assets of such
Subsidiaries and any Indebtedness of such Subsidiaries senior to the
Indebtedness held by NE LP and NE LLC. On December 31, 1997, after giving pro
forma effect to the Acquisitions and the Offering, NE LP would have had
approximately $860,305,000 of long-term Indebtedness outstanding. See "Risk
Factors -- Holding Company Structure; Dependence upon Operations of Projects"
and "Risk Factors -- Substantial Leverage."
Security
Payment of the Securities will be secured by, among other things, a
perfected, first priority pledge by NE LP and NE LLC of their respective limited
partner interests in NEA and NJEA and a second priority pledge by NE LP of its
general partner interest in NEA and NJEA. Such pledges by NE LP and NE LLC will
include, among other things, all of their rights to receive distributions from
NEA and NJEA. All such distributions are to be made directly to the Trustee by
the Project Trustee and deposited into the Revenues Account and the sub-accounts
thereof. See "-- Flow of Funds."
ESI Tractebel Acquisition, NE LP and NE LLC will be subject to a Pledge
Agreement (the "Issuer and Partner Pledge Agreement") providing for (a) the
perfected, first priority pledge by NE LP to the Trustee as collateral agent (in
such capacity, the "Collateral Agent"), for the benefit of the Trustee and the
holders of the Securities, of (i) NE LP's 100% member interest in NE LLC and
(ii) NE LP's 98% limited partner interest in each of NEA and NJEA; (b) the
second priority pledge by NE LP to the Collateral Agent, for the benefit of the
Trustee and the Holders of the Securities, of NE LP's one percent general
partner interest in each of NEA and NJEA; (c) the perfected, first priority
pledge by NE LLC to the Collateral Agent, for the benefit of the Trustee and the
Holders of the Securities, of NE LLC's one percent limited partner interest in
each of NEA and NJEA; (d) the perfected, first priority pledge by ESI Tractebel
Acquisition to the Collateral Agent, for the benefit of the Trustee and the
Holders of the Securities, of the Note evidencing the Bond Loan. The Indenture
will provide for a perfected, first priority lien on the Accounts and all funds
deposited therein granted to the Trustee, for the benefit of the Collateral
Agent, the Trustee and the holders of the Securities, by NE LP and NE LLC.
In addition, the Sponsor Pledgors (as defined herein) are subject to a
pledge agreement (the "Sponsor Pledge Agreement") providing for (a) the
perfected, first priority pledge by each of ESI Northeast Energy GP, Inc., ESI
Northeast Energy LP, Inc., Tractebel Associates Northeast LP, Inc. and Tractebel
Northeast Generation GP, Inc. (collectively, the "Sponsor Pledgors") to the
Collateral Agent for the benefit of the Collateral Agent, the Trustee and the
holders of the Securities, of all of such Sponsor Pledgors' partner interests in
NE LP and (b) a perfected, first priority pledge by each owner of ESI Tractebel
Acquisition to the Collateral Agent, for the benefit of the Collateral Agent,
the Trustee and the holders of the Securities, of all of the outstanding Capital
Stock of ESI Tractebel Acquisition. The Indenture and the Pledge Agreements will
secure the payment and performance when due of all of the Obligations of ESI
Tractebel Acquisition under the Indenture and the Securities, of NE LP and NE
LLC under the Indenture and of NE LP under the Note and the Bond Guaranty, as
provided in the Indenture and the Pledge Agreements.
108
So long as no Default or Event of Default has occurred and is
continuing, and subject to certain terms and conditions in the Indenture and the
Pledge Agreements, all Revenues will be allocated to the appropriate Accounts in
the manner described under the caption "-- Flow of Funds." Upon the occurrence
and during the continuance of a Default or Event of Default, (a) all rights of
NE LP and NE LLC and the owners thereof and of ESI Tractebel Acquisition to
exercise any voting or other consensual rights in respect of the pledged
Collateral will cease, and all such rights will become vested in the Trustee,
which, to the extent permitted by law, will have the sole right to exercise such
voting and other consensual rights, (b) the Trustee may sell the pledged
Collateral or any part thereof in accordance with the terms of the Collateral
Documents and (c) the Trustee shall have all rights of a "secured party" under
the Uniform Commercial Code of the State of New York. All funds distributed
under the Pledge Agreements and the Indenture and received by the Trustee for
the benefit of the holders will be distributed by the Trustee in accordance with
the provisions of the Indenture.
Under the terms of the Collateral Documents, the Trustee will determine
the circumstances and manner in which the Collateral will be disposed of,
including, but not limited to, the determination of whether to release all or
any portion of the Collateral from the Liens created by the Collateral Documents
and whether to foreclose on the Collateral following a Default or Event of
Default. Upon the full and final payment and performance of all Obligations in
respect of the Bond Loan, the Indenture and the Securities, the Collateral
Documents will terminate and the Collateral will be released.
Principal, Maturity and Interest
The Securities will be limited in aggregate principal amount to
$220,000,000 and will mature on December 30, 2011. Principal of the Securities
will be payable in semi-annual installments to the holders thereof as follows:
Scheduled Payment Date Principal Amount Payable
---------------------- ------------------------
June 30, 1998........... $ 0
December 30, 1998....... 0
June 30, 1999........... 0
December 30, 1999....... 0
June 30, 2000........... 0
December 30, 2000....... 0
June 30, 2001........... 0
December 30, 2001....... 0
June 30, 2002........... 4,400,000
December 30, 2002....... 4,400,000
June 30, 2003........... 4,400,000
December 30, 2003....... 4,400,000
June 30, 2004........... 4,400,000
December 30, 2004....... 4,400,000
June 30, 2005........... 4,400,000
December 30, 2005....... 4,400,000
June 30, 2006........... 6,600,000
December 30, 2006....... 6,600,000
June 30, 2007........... 11,000,000
December 30, 2007....... 11,000,000
June 30, 2008........... 11,000,000
December 30, 2008....... 11,000,000
June 30, 2009........... 13,200,000
December 30, 2009....... 13,200,000
June 30, 2010........... 17,600,000
December 30, 2010....... 17,600,000
June 30, 2011........... 33,000,000
December 30, 2011....... 33,000,000
The New Securities will bear interest from the last interest payment
date of the Old Securities to occur prior to the issue date of the New
Securities at the rate shown on the cover page hereof and will be payable
semi-annually in arrears on June 30 and December 30, commencing on the first
such date to occur after the exchange of the New Securities for Old Securities,
to holders of record at the close of
109
business on June 15 or December 15, as the case may be, next preceding such
interest payment date. Interest on the New Securities will accrue from the most
recent date to which interest has been paid or, if no interest has been paid,
from the date of original issuance of the Old Securities. Interest will be
computed on the basis of a 360-day year comprised of twelve 30-day months.
Subject to the provisions set forth under the caption "-- Same Day Settlement
and Payment," principal, premium, if any, interest and Registration Default
Damages, if any, on the Securities will be payable at the office or agency of
the Trustee, as paying agent (the "Paying Agent"), maintained for such purpose
within the City and State of New York or, at the option of ESI Tractebel
Acquisition, payment of interest and Registration Default Damages, if any, may
be made by check mailed to the holders of the Securities at their respective
addresses set forth in the register of holders; provided that all payments of
principal, premium, interest and Registration Default Damages, if any, with
respect to Securities the holders of which have given wire transfer instructions
to ESI Tractebel Acquisition will be required to be made by wire transfer of
immediately available funds to the accounts specified by the holders thereof.
Until otherwise designated by ESI Tractebel Acquisition, ESI Tractebel
Acquisition's office or agency in New York will be the office of the Trustee
maintained for such purpose. The Securities will be issued in denominations of
$100,000 and integral multiples of $1,000 in excess thereof. See "-- Book-Entry,
Delivery and Form." Additional Securities may be issued from time to time after
the date of this Prospectus, subject to the provisions of the Indenture
described below under the caption "-- Certain Covenants -- Incurrence of
Indebtedness and Issuance of Preferred Stock."
Ratings
The Securities have received ratings of "Ba1" from Moody's and "BB"
from S&P.
Optional Redemption
The Securities will not be redeemable at ESI Tractebel Acquisition's
option prior to June 30, 2008. Thereafter, the Securities will be subject to
redemption at any time at the option of ESI Tractebel Acquisition at the
direction of NE LP, in whole or in part, upon not less than 30 nor more than 60
days' notice, at the redemption prices (expressed as percentages of principal
amount) set forth below plus accrued and unpaid interest, thereon to the date
fixed for redemption, if redeemed during the twelve-month period beginning on
June 30 of the years indicated below:
Year Percentage
---- -----------
2008.............. 101.844%
2009.............. 101.229%
2010.............. 100.615%
2011 and thereafter 100.000%
Extraordinary Mandatory Redemption
The Securities will be subject to extraordinary mandatory redemption
pro rata, at a redemption price equal to the outstanding principal amount
thereof plus accrued and unpaid interest to the date fixed for redemption if (1)
(a) any event occurs which triggers the mandatory redemption or repurchase of
any or all of the Project Securities pursuant to the terms of the Project
Indenture and (b) any funds so required to be applied to such redemption or
repurchase remain after giving effect to such redemption or repurchase of
Project Securities, and such excess funds equal at least $2,000,000 and are
distributed to NE LP or NE LLC or (2) a buyout or similar payment is made to a
Partnership under any Power Purchase Agreement and any such funds are
distributed to NE LP or NE LLC in accordance with the terms of the Project
Indenture and terms of the Indenture, provided that, in each such case, only
such funds so distributed must be applied to the extraordinary mandatory
redemption.
110
Selection and Notice
Subject to the book-entry system described herein, if less than all of
the Securities are to be redeemed at any time, selection of Securities for
redemption will be made by the Trustee in compliance with the requirements of
the principal national securities exchange, if any, on which the Securities are
listed, or, if the Securities are not so listed, on a pro rata basis or by such
other method as the Trustee deems fair and appropriate; provided that, except in
the case of an extraordinary mandatory redemption, no Securities will be
redeemed in part if the unredeemed portion will be in an unauthorized
denomination. Notices of redemption shall be mailed by first class mail at least
30 but not more than 60 days before the redemption date to each holder to be
redeemed at its registered address. Notices of redemption may not be conditional
and will be irrevocable. If any Security is to be redeemed in part only, the
notice of redemption that relates to such Security will state the portion of the
principal amount thereof to be redeemed and that a new Security in principal
amount equal to the unredeemed portion thereof will be issued in the name of the
holder thereof upon cancellation of the original Security. Securities called for
redemption become due on the date fixed for redemption. On and after the date
fixed for redemption, interest ceases to accrue on Securities or portions of
Securities to be redeemed. Except as a result of a redemption as described under
the caption "-- Extraordinary Mandatory Redemption," no Securities will be
permitted to be in denominations other than the authorized denominations.
Repurchase at the Option of Holders Upon a Change of Control
Upon the occurrence of a Change of Control (which will not occur if
Moody's and S&P confirm that the then existing ratings of the Securities will
not be lowered as a result of any of the events that, in the absence of such
confirmed rating, would constitute a Change of Control), ESI Tractebel
Acquisition will be required to offer to each holder to repurchase all or any
part (equal to $100,000 or an integral multiple of $1,000 in excess thereof) of
such holder's Securities pursuant to the offer described below (the "Change of
Control Offer") at a purchase price in cash equal to 101% of the aggregate
principal amount thereof plus accrued and unpaid interest thereon, if any, to
the date of purchase (the "Change of Control Payment"). Within ten days
following any Change of Control, ESI Tractebel Acquisition will be required to
mail a notice to each holder describing the transaction or transactions that
constitute the Change of Control and offering to repurchase Securities on the
date specified in such notice, which date shall be no earlier than 30 days and
no later than 60 days from the date such notice is mailed (the "Change of
Control Payment Date"), pursuant to the procedures required by the Indenture and
described in such notice. ESI Tractebel Acquisition will be required to comply
with the requirements of Rule 14e-1 under the Exchange Act and any other
securities laws and regulations thereunder to the extent such laws and
regulations are applicable in connection with the repurchase of the Securities
as a result of a Change of Control.
On the Change of Control Payment Date, ESI Tractebel Acquisition will
be required, to the extent lawful, to (1) accept for payment all Securities or
portions thereof properly tendered pursuant to the Change of Control Offer, (2)
deposit with the Paying Agent an amount equal to the Change of Control Payment
in respect of all Securities or portions thereof so tendered and (3) deliver or
cause to be delivered to the Trustee the Securities so accepted together with an
Officers' Certificate stating the aggregate principal amount of Securities or
portions thereof purchased by ESI Tractebel Acquisition. The Paying Agent will
be required to promptly pay to each holder that has so tendered Securities the
Change of Control Payment for such Securities, and the Trustee will promptly
authenticate and mail (or cause to be transferred by book entry) to each holder
a new Security equal in principal amount to any unpurchased portion of the
Securities surrendered, if any; provided that each such new Security will be in
a principal amount of $100,000 or an integral multiple of $1,000 in excess
thereof. ESI Tractebel Acquisition will be required to announce publicly the
results of the Change of Control Offer on or as soon as practicable after the
Change of Control Payment Date.
111
The Change of Control provisions described above will be applicable
whether or not any other provisions of the Indenture are applicable. Except as
described above with respect to a Change of Control, the Indenture does not
contain provisions that require ESI Tractebel Acquisition to repurchase or to
redeem the Securities in the event of a takeover, recapitalization or similar
transaction.
ESI Tractebel Acquisition will not be required to make a Change of
Control Offer upon a Change of Control if a third party makes the Change of
Control Offer in the manner, at the times and otherwise in compliance with the
requirements set forth in the Indenture applicable to a Change of Control Offer
made by ESI Tractebel Acquisition and purchases all Securities validly tendered
and not withdrawn under such Change of Control Offer.
"Change of Control" means the occurrence of any of the following: (i)
the sale, lease, transfer, conveyance or other disposition (other than by way of
merger or consolidation), in one or a series of related transactions, of all or
substantially all of the assets of NE LP, NE LLC, NEA or NJEA to any "person" or
"group" (as each such term is used in Section 13(d)(3) and 14(d)(2) of the
Exchange Act) other than the Sponsors or their Related Parties; (ii) the
adoption of a plan relating to the liquidation or dissolution of NE LP, NE LLC,
NEA or NJEA (other than as permitted by the Indenture); (iii) the consummation
of any transaction or series of related transactions (including, without
limitation, any merger or consolidation) the result of which is that any person
or group (as defined above), other than the Sponsors and their Related Parties,
becomes the "beneficial owner" (as such term is defined in Rule 13d-3 and Rule
13d-5 under the Exchange Act, except that a person or group shall be deemed to
have "beneficial ownership" of all securities that such person or group has the
right to acquire, whether such right is currently exercisable or is exercisable
only upon the occurrence of a subsequent condition), directly or indirectly, of
more than 50% of the voting power of any general partner of NE LP, NEA or NJEA
or of the voting power of the managing member of NE LLC by way of merger or
consolidation or otherwise other than a transaction involving an acquisition of
FPL Group or Tractebel S.A., (iv) the consummation of any transaction or series
of related transactions the result of which is that any person or group (as
defined above) owns, directly or indirectly, more of the economic and voting
interest of the Sponsors, NE LP, NE LLC, NEA or NJEA or of the voting power of
the managing member of NE LLC than do FPL Group and Tractebel S.A.; or (v) the
consummation of any transaction or series of related transactions the result of
which is that any person or group (as defined above) other than the Sponsors and
the Related Parties owns, directly or indirectly, more of the voting power of
any general partner of NE LP, NEA or NJEA than do the Sponsors and their Related
Parties; provided that, notwithstanding the foregoing, a Change of Control will
not occur if Moody's and S&P confirm that the then existing ratings of the
Securities will not be lowered as a result of any of the foregoing events.
If any of the events described in clauses (i) through (v) of the
definition of "Change of Control" occurs, but ESI Tractebel Acquisition is not
required to offer to purchase the Securities because Moody's and S&P confirm
that the then existing rating of the Securities will not be lowered as a result
of such event, then immediately after such event, the definitions of "Sponsor"
and "Related Parties" in the Indenture will be amended by supplemental indenture
(without the consent of the holders of the Securities) to mean the entity or
entities that Moody's and S&P relied upon, if any, in confirming the then
existing ratings of the Securities.
The definition of Change of Control includes a phrase relating to the
sale, lease, transfer, conveyance or other disposition of "all or substantially
all" of the assets of NE LP, NE LLC, NEA or NJEA. Although there is a developing
body of case law interpreting the phrase "substantially all," there is no
precise established definition of the phrase under applicable law. Accordingly,
whether ESI Tractebel Acquisition will be required to repurchase such Securities
as a result of a sale, lease, transfer, conveyance or other disposition of less
than all of the assets of NE LP, NE LLC, NEA or NJEA to another person or group
(as defined above) may be uncertain. In addition, ESI Tractebel Acquisition's
ability to pay cash to the holders of Securities upon a repurchase may be
limited by ESI Tractebel Acquisition's then existing financial resources.
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Flow of Funds
All Revenues will be required to be deposited into an account
designated the "Revenues Account." The funds in the Revenues Account will be
transferred on a monthly basis in following order of priority:
Debt Service Account
The funds from the Revenues Account will be transferred, first, to an
account designated the "Debt Service Account," into which shall be deposited an
amount equal to the difference between (i) the amount then on deposit therein
and (ii) the aggregate amount of principal, premium, if any, interest and
Registration Default Damages, if any, scheduled to be paid in respect of the
Securities on the next semi-annual payment date and any trustee, registration or
other administrative expenses due with respect to the Securities during the next
six months. The Trustee will apply the funds on deposit in the Debt Service
Account to make payments on the Securities when due and to pay up to $10,000 of
the trustee, registration or other administrative expenses with respect to the
Securities when due.
Debt Service Reserve Account
The funds from the Revenues Account will be transferred, second, to an
account designated the "Debt Service Reserve Account," into which shall be
deposited an amount equal to the difference between (i) the sum of the amount
then on deposit therein and the undrawn amount of any Acceptable Credit Support
credited thereto and (ii) the aggregate principal, premium, if any, interest and
Registration Default Damages, if any, scheduled to be paid on the Securities on
the next semi-annual payment date (the "Required DSRA Balance"). The funds on
deposit in the Debt Service Reserve Account (including any amounts available to
be drawn under Acceptable Credit Support credited thereto) shall be available to
pay amounts due and payable in respect of the Securities to the extent that
there are insufficient funds in the Debt Service Account to do so. The
consummation of this Offering will be conditioned upon depositing funds or
Acceptable Credit Support (in accordance with the Indenture) into the Debt
Service Reserve Account on the date of such consummation in an amount equal to
the then current Required DSRA Balance.
Distribution Account
Any amount remaining in the Revenues Account will be transferred,
finally, to an account designated the "Distribution Account" if and only if, at
the time of and after giving effect to such transfer and the deemed removal of
funds from the Distribution Account pursuant to the covenants described under
the caption "-- Certain Covenants -- Restricted Payments":
(a) the Debt Service Account and Debt Service Reserve Account
are funded to their then required levels;
(b) no Default or Event of Default under the Indenture has
occurred and is continuing or would occur as a consequence thereof; and
(c) and the Debt Service Coverage Ratio and the Projected Debt
Service Coverage Ratio equal or exceed 1.4 to 1, provided that, in
calculating the Debt Service Coverage Ratio for purposes of this clause
(c) at any time prior to December 30, 1998 the Operating Revenues
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received and scheduled debt service payments referred to in clauses (i)
and (ii) of the definition thereof shall be measured for the period of
months that has elapsed from the date of the Acquisitions to the date
of such calculation.
Notwithstanding the foregoing, no funds will be permitted to be
transferred to the Distribution Account prior to June 30, 1998. Thereafter upon
satisfaction of the requirements described above, moneys in the Distribution
Fund may be released to or at the direction of NE LP.
Acceptable Credit Support
Provided that no Default or Event of Default has occurred and is
continuing, ESI Tractebel Acquisition may deposit Acceptable Credit Support in
an equal amount in place of all or a portion of the cash deposited or required
to be deposited in the Debt Service Reserve Account. Upon such deposit of
Acceptable Credit Support and receipt by the Trustee of a written request
accompanied by the documents required pursuant to the Indenture, the Trustee
will be authorized and required to release such replaced cash to or at the
direction of NE LP. "Acceptable Credit Support" means (a) an irrevocable
unconditional letter of credit in form and substance acceptable to the Trustee
from an entity whose long term debt is rated A2 or higher by Moody's and A or
higher by S&P and/or (b) a Guarantee by FPL Group Capital in the form provided
in the Indenture so long as the long-term debt of FPL Group Capital is rated A2
or higher by Moody's and A or higher by S&P, provided that a letter of credit in
form and substance acceptable to the Trustee from Bank Brussels Lambert shall be
satisfactory as Acceptable Credit Support so long as its long-term debt is rated
A2 or higher by Moody's and its short-term debt is rated A-1 or higher by S&P.
The Indenture will provide that the Trustee will be the beneficiary under any
letter of credit or Guarantee constituting Acceptable Credit Support and the
Acceptable Credit Support will allow drawings by the Trustee if it is not
renewed at least 30 days prior to its expiration date or if the ratings of any
guarantor or letter of credit issuer fall below the required level and
alternative Acceptable Credit Support or cash is not provided to the Trustee
within 15 days thereafter. ESI Tractebel Acquisition of or account party to any
letter of credit or Guarantee may have rights of subrogation against ESI
Tractebel Acquisition, NE LP or NE LLC so long as (a) the Obligations of ESI
Tractebel Acquisition, NE LP and NE LLC in respect thereof are subordinated to
the repayment of the Bond Loan and the Securities and are payable only to the
extent Restricted Payments can be made and (b) such issuer or account party
waives its rights to exercise remedies in respect thereof so long as the
Securities are outstanding.
Certain Covenants
Restricted Payments
The Indenture provides that ESI Tractebel Acquisition, NE LP and NE LLC
may make Restricted Payments only from, and to the extent of, amounts on deposit
in the Distribution Account from time to time. "Restricted Payments" means the
direct or indirect: (i) declaration or payment of any dividend or any other
payment or distribution on account of ESI Tractebel Acquisition's, NE LP's or NE
LLC's Equity Interests (including, without limitation, any payment in connection
with any merger or consolidation involving ESI Tractebel Acquisition, NE LP or
NE LLC) or to the direct or indirect holders of ESI Tractebel Acquisition's, NE
LP's or NE LLC's Equity Interests in any capacity (other than dividends or
distributions payable in Equity Interests (other than Disqualified Stock) of ESI
Tractebel Acquisition, NE LP or NE LLC or to ESI Tractebel Acquisition, NE LP or
NE LLC); (ii) repayment of any indebtedness owed by NE LP or NE LLC to the
Sponsors or their Affiliates, including, without limitation, any reimbursement
obligations with respect to any letters of credit or guarantees provided by the
Sponsors or their Affiliates as Acceptable Credit Support; (iii) purchase,
redemption or other acquisition or retirement for value (including, without
limitation, in connection with any merger or consolidation involving ESI
Tractebel Acquisition, NE LP or NE LLC) of any Equity Interests of ESI Tractebel
Acquisition, NE LP or
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NE LLC or any direct or indirect parent of ESI Tractebel Acquisition, NE LP or
NE LLC; or (iv) payment on or with respect to, or purchase, redemption,
defeasance or other acquisition or retirement for value of any Indebtedness that
is pari passu with or subordinated to the Securities (other than the
Securities), except a scheduled payment of interest or principal.
Incurrence of Indebtedness and Issuance of Preferred Stock
The Indenture provides that ESI Tractebel Acquisition, NE LP and NE LLC
will not, directly or indirectly, create, incur, issue, assume, guarantee,
otherwise become directly or indirectly liable, contingently or otherwise, with
respect to (collectively, "incur") any Indebtedness, other than Permitted
Indebtedness, and will not issue any Disqualified Stock, unless (a) such
Indebtedness will be pari passu with or subordinated to the Note and the
Securities, (b) the proceeds of such incurrence or issuance are used to make
equity contributions to either or both of NEA or NJEA, (c) the proceeds of such
incurrence or issuance are used to finance the completion of Required
Improvements or capital expenditures for the Projects other than Required
Improvements, (d) if the proceeds of such Indebtedness are used to finance the
completion of Required Improvements (as defined in the Project Indenture as in
effect on the date of the Indenture), (i) the Projected Debt Service Coverage
Ratio (determined on a pro forma basis giving effect to the incurrence and the
application of the net proceeds therefrom and the construction of the Required
Improvements) measured on each remaining semi-annual payment date in respect of
the Securities is at least 1.2 to 1 and (ii) an independent engineer acceptable
to the Trustee (which may, absent any conflict or the objection of the Trustee,
be the Independent Engineer with respect to the Project Securities) certifies
that the improvements are Required Improvements (as defined in the Project
Indenture as in effect on the date of the Indenture) and that there will be
sufficient funds available to construct the Required Improvements after the
incurrence and (e) if the proceeds of such Indebtedness are used to finance
capital expenditures for the Projects other than Required Improvements, (i) the
Projected Debt Service Coverage Ratio (determined on a pro forma basis giving
effect to the incurrence and the application of the net proceeds therefrom and
the proposed capital expenditures) measured on each remaining semi-annual
payment date of the Securities is at least 2 to 1 and the average of such
Projected Debt Service Coverage Ratios is at least 3 to 1 and (ii) Moody's and
S&P confirm that the then current ratings of the Securities will not be lowered
as a result of such incurrence. "Permitted Indebtedness" means subordinated
loans or reimbursement obligations owing to a Sponsor or any Affiliate thereof
(i) which can only be repaid to the extent Restricted Payments can be made, (ii)
in respect of which remedies cannot be exercised by such Sponsor or Affiliate so
long as the Securities are outstanding, (iii) incurred at a time when the
minimum Projected Debt Service Coverage Ratio (assuming, for purposes of such
calculation, that scheduled debt service payments in respect of Permitted
Indebtedness that is subordinate in right of payment to the Securities, the Bond
Note and the Bond Guaranty is included in clause (ii) of the definition of
"Projected Debt Service Coverage Ratio") on each semi-annual payment date of the
Securities is at least 1.5 to 1 (provided that the incurrence of reimbursement
obligations subordinated to the Securities of NE LP to the issuers of Acceptable
Credit Support under the Indenture and in respect of Guarantees issued by FPL
Group Capital and/or Backup Letters of Credit and Substitute Letters of Credit
pursuant to the Project Indenture will not be subject to such Projected Debt
Service Coverage Ratio test) or Moody's and S&P confirm that the then current
ratings of the Securities will not be lowered as a result of such incurrence and
(iv) the proceeds of which are used to make equity contributions to either NEA
or NJEA.
The Indenture also provides that ESI Tractebel Acquisition, NE LP and
NE LLC will not be permitted to incur any Indebtedness that is contractually
subordinated in right of payment to any other Indebtedness of ESI Tractebel
Acquisition, NE LP or NE LLC, as applicable, unless such Indebtedness is also
contractually subordinated in right of payment to the Securities and the Bond
Loan on substantially identical terms; provided, however, that no Indebtedness
of ESI Tractebel Acquisition, NE LP or NE LLC shall be deemed to be
contractually subordinated in right of payment to any other Indebtedness of ESI
Tractebel Acquisition, NE LP or NE LLC, as applicable, solely by virtue of being
unsecured.
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Limitations on Project Indebtedness
The Indenture provides that notwithstanding the terms of the Project
Indenture, NE LP and NE LLC will not permit ESI Tractebel Funding Corp. or the
Partnerships to create, issue, incur, assume, guarantee, otherwise become liable
for or suffer to exist any Debt (as defined in the Project Indenture as in
effect on the date of the Indenture) to finance the construction of Required
Improvements unless, after giving effect to the incurrence of such Debt and the
application of the proceeds thereof, the Projected Debt Service Coverage Ratio
for the 12-month period beginning on the date of such incurrence and for each
succeeding 12-month period thereafter through the final maturity of the
Securities is at least 1.2 to 1.
The Indenture also provides that notwithstanding the terms of the
Project Indenture, NE LP and NE LLC will not permit ESI Tractebel Funding Corp.
or the Partnerships to create, issue, incur, assume, guarantee, otherwise become
liable for or suffer to exist any Debt (as defined in the Project Indenture as
in effect on the date of the Indenture), other than Debt to finance the
construction of Required Improvements, unless after giving effect to the
incurrence of such Debt and the application of the proceeds thereof, (i) the
Projected Debt Service Coverage Ratio measured on each remaining semi-annual
payment date of the Securities is at least 2 to 1 and (ii) the average of such
Projected Debt Service Coverage Ratios is at least 3 to 1.
Finally, the Indenture provides that NE LP and NE LLC will not permit
ESI Tractebel Funding Corp. or the Partnerships to create, incur, assume,
guarantee, otherwise become liable for or suffer to exist any Indebtedness,
Guarantees or indemnity obligations following the repayment, prepayment or
defeasance of all of the Project Securities or the termination or expiration of
the Project Indenture, other than as described in one of the two preceding
paragraphs.
Limitation on Senior Subordinated Debt
The Indenture provides that none of ESI Tractebel Acquisition, NE LP or
NE LLC will, nor will any such party permit any of its Subsidiaries or
Affiliates to, create, issue, incur, assume, guarantee, otherwise become liable
for or suffer to exist any Indebtedness that is subordinated or junior in right
of payment to the Project Indebtedness and senior in any respect in right of
payment to the Securities, the Note or the Bond Guaranty (other than
Indebtedness expressly permitted to be incurred by the Project Indenture and the
Indenture).
Limitations on Liens
The Indenture provides that ESI Tractebel Acquisition, NE LP and NE LLC
will not, directly or indirectly, create, incur, assume or otherwise cause or
suffer to exist or become effective any Lien on any of their assets or
properties now owned or hereafter acquired, or any income or profits therefrom,
or assign or convey any right to receive income therefrom, except for Permitted
Liens.
Dividend and Other Payment Restrictions Affecting Subsidiaries
The Indenture provides that ESI Tractebel Acquisition, NE LP and NE LLC
will not, and will not permit any of its or their Subsidiaries (including NEA
and NJEA), directly or indirectly, to create or otherwise cause or suffer to
exist or become effective any encumbrance or restriction on the ability of any
Subsidiary thereof to (i)(a) pay dividends or make any other distributions to
ESI Tractebel Acquisition, NE LP and NE LLC or any of its or their Subsidiaries
(1) on its Capital Stock or (2) with respect to any
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other interest or participation in, or measured by, its profits, or (b) pay any
indebtedness owed to ESI Tractebel Acquisition, NE LP and NE LLC or any of its
or their Subsidiaries, (ii) make loans or advances to ESI Tractebel Acquisition,
NE LP or NE LLC or any of its or their Subsidiaries or (iii) transfer any of its
properties or assets to ESI Tractebel Acquisition, NE LP or NE LLC or any of its
or their Subsidiaries. However, the foregoing restrictions will not apply to
encumbrances or restrictions under or by reason of (a) the Project Indenture and
the other Transaction Documents (as defined in the Project Indenture as in
effect on the date of the Indenture) and, in each case, as in effect on the date
of the Indenture, (b) the Indenture and the Securities, (c) applicable law, (d)
customary non-assignment provisions in leases entered into in the ordinary
course of business and consistent with past practices and (e) purchase money
obligations for property acquired in the ordinary course of business that impose
restrictions of the nature described in clause (iii) above on the property so
acquired.
Merger, Consolidation, or Sale of Assets
The Indenture provides that none of ESI Tractebel Acquisition, NE LP,
NE LLC, NEA or NJEA will consolidate or merge with or into (whether or not such
entity is the surviving entity), or sell, assign, transfer, lease, convey or
otherwise dispose of all or substantially all of its properties or assets or all
or any of the partner interests of NEA or NJEA in one or more related
transactions to any Person unless (a) such consolidation, merger, sale,
assignment, lease, conveyance or other disposition (i) does not constitute a
Change of Control or (ii) constitutes a Change of Control and a Change of
Control Offer is made as set forth under the caption "-- Repurchase at the
Option of Holders Upon a Change of Control," (b) (i) ESI Tractebel Acquisition,
NE LP or NE LLC (as the case may be) is the surviving entity or the Person
formed by or surviving any such consolidation or merger (if other than ESI
Tractebel Acquisition, NE LP or NE LLC, as the case may be) or the entity to
which such sale, assignment, transfer, lease, conveyance or other disposition
shall have been made (1) is a corporation or a partnership organized or existing
under the laws of the United States, any state thereof or the District of
Columbia and (2) assumes all of the Obligations of ESI Tractebel Acquisition, NE
LP or NE LLC (as the case may be) under the Note, the Securities, the Indenture,
the Bond Guaranty and the Registration Rights Agreement, (c) immediately after
giving effect to such transaction, no Default or Event of Default exists, (d)
Moody's and S&P confirm that the then current ratings of the Securities will not
be lowered as a result thereof and (e) ESI Tractebel Acquisition, NE LP and NE
LLC would be permitted to incur one dollar of Indebtedness the proceeds of which
would be used to finance capital expenditures other than Required Improvements
for NEA and/or NJEA under the provisions described in the first paragraph under
the caption "-- Incurrence of Indebtedness and Issuance of Preferred Stock."
Transactions with Affiliates
The Indenture provides that ESI Tractebel Acquisition, NE LP and NE LLC
may not make any payment to, or sell, lease, transfer or otherwise dispose of
any of its properties or assets to, or purchase any property or assets from, or
enter into or make or amend any transaction, contract, agreement, understanding,
loan, advance or Guarantee with, or for the benefit of, any Affiliate thereof
(each of the foregoing, an "Affiliate Transaction"), unless such Affiliate
Transaction is on terms that are no less favorable to ESI Tractebel Acquisition,
NE LP or NE LLC (as the case may be) than those that would have been obtained in
a comparable transaction by ESI Tractebel Acquisition, NE LP or NE LLC with an
unrelated Person. Notwithstanding the foregoing, the following shall not be
deemed to be Affiliate Transactions: (i) transactions between or among ESI
Tractebel Acquisition, NE LP, NE LLC or any of their Affiliates contemplated by
any agreement entered into prior to the date of the Indenture; (ii) payments of
reasonable directors' fees to Persons who are not otherwise Affiliates of ESI
Tractebel Acquisition, NE LP or NE LLC; and (iii) Restricted Payments that are
permitted by the provisions of the Indenture described above under the caption
"-- Restricted Payments."
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Limitations on Issuances of Guarantees and Indemnities
The Indenture provides that ESI Tractebel Acquisition, NE LP and NE LLC
may not, directly or indirectly, incur or have outstanding any Guarantees or
indemnities or assume any other suretyship obligations, except (a) the Bond
Guaranty, (b) Guarantees arising in the ordinary course of business not to
exceed $250,000 in the aggregate at any one time outstanding and (c) indemnities
or reimbursement obligations with respect to any Acceptable Credit Support or
otherwise, so long as such indemnities or reimbursement obligations are payable
only to the extent Restricted Payments can be made and the party in respect of
whom such indemnities or reimbursement obligations run in favor waives its
rights to exercise remedies in respect thereof so long as the Securities are
outstanding.
Limitations on Investments
The Indenture provides that ESI Tractebel Acquisition, NE LP and NE LLC
may not make any Investment other than Permitted Investments.
Amendments to, and Assignments of, Project Documents
The Indenture provides that ESI Tractebel Acquisition, NE LP and NE LLC
will not permit or suffer NEA or NJEA (a) to waive a right under, or modify,
terminate or amend, any material governmental consent, any material term of any
Project Document (as defined in the Project Indenture as in effect on the date
of the Indenture), other than any Power Purchase Agreement, or any material term
of the Project Indenture unless such waiver, modification, termination or
amendment could not reasonably be expected to have a material adverse effect on
ESI Tractebel Acquisition, NE LP, NE LLC or the holders of the Securities or (b)
to assign any of its rights under any of the Project Documents (as defined in
the Project Indenture as in effect on the date of the Indenture) other than as
permitted by the Indenture or the Project Indenture. The Indenture also provides
that ESI Tractebel Acquisition, NE LP and NE LLC will not permit or suffer NEA
or NJEA to waive a right under, or modify, terminate or amend, any material term
of any Power Purchase Agreement unless (i) NE LP delivers to the Trustee a
certificate, in form and substance reasonably satisfactory to the Trustee, of an
independent engineer acceptable to the Trustee (which may, absent any conflict
or the objection of the Trustee, be the Independent Engineer with respect to the
Project Securities), certifying that such waiver, modification, termination or
amendment could not reasonably be expected to have a material adverse effect on
ESI Tractebel Acquisition, NE LP, NE LLC or the holders of the Securities and
(ii) Moody's and S&P confirm that the then existing ratings of the Securities
will not be lowered as a result of such waiver, modification, termination or
amendment.
Business Activities
The Indenture provides that (a) ESI Tractebel Acquisition may not
engage in any business other than the issuance of the Securities and the
incurrence of the other Indebtedness permitted by the Indenture to be incurred
by ESI Tractebel Acquisition and (b) NE LP and NE LLC may not engage in any
business other than holding, directly or indirectly, the partner interests of
NEA and NJEA, and, with respect to NE LP, acting as general partner of NEA and
NJEA, and the issuance of the Note and the Bond Guaranty and the incurrence of
the other Indebtedness permitted by the Indenture to be incurred by NE LP and NE
LLC.
Limitations on Loans and Advances
The Indenture provides that ESI Tractebel Acquisition, NE LP and NE LLC
may not, directly or indirectly, make any loans or advances to, or acquire any
stock, obligations or securities of, any Person, except in connection with the
incurrence of Permitted Indebtedness.
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Reporting Requirements
The Indenture provides that, whether or not required by the rules and
regulations of the Securities and Exchange Commission (the "Commission"), so
long as any Securities are outstanding, ESI Tractebel Acquisition will be
required to furnish to the holders of the Securities and to any beneficial owner
of Securities who so requests ESI Tractebel Acquisition in writing (i) all
quarterly and annual financial information that would be required to be
contained in a filing with the Commission on Forms 10-Q and 10-K if ESI
Tractebel Acquisition were required to file such Forms, including a
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and, with respect to the annual information only, a report thereon
by ESI Tractebel Acquisition's independent accountants and (ii) all current
reports that would be required to be filed with the Commission on Form 8-K if
ESI Tractebel Acquisition were required to file such reports, in each case
within the time periods specified in the Commission's rules and regulations. In
addition, following the consummation of the Exchange Offer, whether or not
required by the rules and regulations of the Commission, ESI Tractebel
Acquisition will be required to file a copy of all such information and reports
with the Commission for public availability within the time periods specified in
the Commission's rules and regulations (unless the Commission will not accept
such a filing) and make such information available to securities analysts and
prospective investors upon request. In addition, ESI Tractebel Acquisition has
agreed that, for so long as any Securities remain outstanding, it will furnish
to the holders and to securities analysts and prospective investors, upon their
request, the information required to be delivered pursuant to Rule 144A(d)(4)
under the 1933 Act. In addition, and whether or not ESI Tractebel Acquisition is
subject to the reporting requirements of Section 13 or Section 15(d) of the
Securities Exchange Act (the "Exchange Act") of 1934, as amended, ESI Tractebel
Acquisition will be required to file with the SEC and provide to the Trustee and
the holders of the Securities, and (upon request) to broker-dealers and
prospective investors, all information, documents and reports specified in
Section 13 and Section 15(d) of the Exchange Act.
NE LP will also be required to provide to the Trustee, the holders of
the Securities and any beneficial owner of Securities who so requests ESI
Tractebel Acquisition in writing (i) all notices, financial statements and other
information required to be given by ESI Tractebel Funding Corp., NEA or NJEA to
the Project Trustee under the Project Indenture, (ii) calculations of the Debt
Service Coverage Ratio and the Projected Debt Service Coverage Ratio, together
with the information required to substantiate such calculations, on each
semi-annual payment date in respect of the Securities, at the time any amounts
are to be transferred into the Distribution Account and at any other time such
ratios are required to be provided by the terms of the Indenture and (iii)
calculations of the Debt Service Coverage Ratio and the Substitute Debt Service
Coverage Ratio for the Rolling Prior Year (each as defined in the Project
Indenture as in effect on the date of the Indenture), together with the
information required to substantiate such calculations and a copy of the
certificate of the management committee of NE LP on behalf of the Partnerships
delivered pursuant to the Project Indenture certifying that it has no knowledge
of any event or circumstance that could reasonably be expected to result in the
Debt Service Coverage Ratio for the period of two fiscal quarters commencing on
the expiration date of the Rolling Prior Year, treated as a single period, being
less than 1.25:1, on each semi-annual payment date in respect of the Securities,
at the time any amounts are to be transferred into the General Subfund of the
Partnership Distribution Fund (as defined in the Project Indenture as in effect
on the date of the Indenture) and at any other time such ratios are required to
be provided by the terms of the Project Indenture. Finally, each of ESI
Tractebel Acquisition, NE LP and NE LLC will be required to advise the Trustee
promptly in writing of (i) the occurrence of any Event of Default of which it
has knowledge and the occurrence of any "Event of Default" as defined in the
Project Indenture as in effect on the date of the Indenture and (ii) any
material litigation or claim against or concerning any of ESI Tractebel
Acquisition, NE LP, NE LLC or any of its property or assets.
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Compliance
Each of ESI Tractebel Acquisition, NE LP and NE LLC will be required at
all times to obtain, maintain and comply in all material respects with all
material governmental consents and all applicable laws. NE LP will be required
at all times, in its capacity as general partner of NEA and NJEA, to cause NEA
and NJEA to comply with all material terms and provisions of the Project
Indenture (as in effect as of the date of the Indenture), unless the failure to
comply could not reasonably be expected to have a material adverse effect on ESI
Tractebel Acquisition, NE LP, NE LLC or the holders of the Securities.
Notwithstanding the expiration or termination of the Project Indenture (whether
at the stated maturity of the last to mature of the Project Securities or
otherwise) or the exercise by holders of the Project Securities of their rights
with respect to satisfaction and discharge of the Project Indenture, legal or
covenant defeasance or any other prepayment of the Project Securities permitted
or required by the Project Indenture, NE LP will be required, in its capacity as
general partner of NEA and NJEA, to cause NEA and NJEA to comply with the
covenants and provisions contained in certain sections of the Project Indenture,
as if such covenants and provisions were still in full force and effect, which
covenants and provisions relate to such matters as the maintenance of existence
of the Partnerships, the maintenance of rights necessary to conduct the business
of the Partnerships, the operation and maintenance of the Projects, compliance
with the formation documents of the Partnerships, the maintenance of
governmental approvals, compliance with laws, the maintenance of insurance, the
payment of taxes, the incurrence of liens and guaranties, the prohibition on
certain dispositions of assets, the nature of business conducted by the
partnerships, employee benefit plans, certain transactions with affiliates, the
making of investments and the maintenance of QF status by the Partnerships.
Maintaining Rights Under Project Documents
Subject to the covenants described under the captions "-- Amendments
to, and Assignments of, Project Documents" and "-- Compliance," ESI Tractebel
Acquisition, NE LP and NE LLC will be required to take all actions necessary to
cause NEA and NJEA to maintain and preserve the material rights granted to NEA
and NJEA pursuant to the Project Documents and to comply therewith unless the
failure to maintain and preserve such rights could not reasonably be expected to
have a material adverse effect on ESI Tractebel Acquisition, NE LP, NE LLC or
the holders of the Securities.
Partnership Distributions
NE LP will be required, in its capacity as general partner of NEA and
NJEA, to cause NEA and NJEA to distribute to NE LP and NE LLC all amounts
released to NEA and NJEA or permitted to be withdrawn by NEA or NJEA from the
Partnership Distribution Fund (as defined in the Project Indenture as in effect
on the date of the Indenture) or any subfund thereof in accordance with the
Project Indenture, and, following the expiration or termination of the Project
Indenture, will be required, in its capacity as general partner of NEA and NJEA,
to cause NEA and NJEA to distribute to NE LP and NE LLC all amounts available
for distribution pursuant to the Project Indenture.
Payment of Taxes
ESI Tractebel Acquisition, NE LP and NE LLC are required to pay all
taxes and other governmental charges before they become delinquent unless the
same are being contested in good faith by appropriate proceedings and adequate
reserves in conformity with GAAP are being maintained.
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Auditor
ESI Tractebel Acquisition and NE LP are required to appoint and
maintain an internationally recognized auditor.
Use of Proceeds
ESI Tractebel Acquisition, NE LP and NE LLC are required to use the net
proceeds of the Offering (and the proceeds of the Bond Loan) as set forth under
the caption "Use of Proceeds."
Existence
Except as expressly permitted by the Indenture, each of ESI Tractebel
Acquisition, NE LP and NE LLC are required at all times to maintain its
existence.
Events of Default and Remedies
The Indenture provides that each of the following constitutes an Event
of Default: (i) default for 15 days in the payment when due of the principal of
or premium, if any, on the Securities or the Note; (ii) default for 15 days in
the payment when due of interest on, with respect to the Securities or the Note;
(iii) failure by ESI Tractebel Acquisition, NE LP or NE LLC to comply with the
provisions described under the captions "-- Repurchase at the Option of Holders
Upon a Change of Control," "-- Certain Covenants -- Restricted Payments," "--
Certain Covenants -- Incurrence of Indebtedness and Issuance of Preferred Stock"
or "-- Certain Covenants -- Merger, Consolidation or Sale of Assets;" (iv)
failure by ESI Tractebel Acquisition, NE LP or NE LLC for 60 days to comply with
any of its other agreements in the Indenture or any of the Collateral Documents;
(v) default by ESI Tractebel Acquisition, NE LP or NE LLC in the payment when
due (after giving effect to any applicable grace periods) of any principal of or
premium, if any, or interest on any Indebtedness (other than the Securities or
the Note) the principal amount of which exceeds $3 million in the aggregate;
(vi) failure by ESI Tractebel Acquisition, NE LP or NE LLC to pay final
judgments aggregating in excess of $3 million, which judgments are not paid,
discharged or stayed for a period of at least 60 days; (vii) the
unenforceability of any material provisions of the Collateral Documents or the
cessation or failure of any lien granted thereby or the priority thereof (and
such unenforceable provisions, cessation or failure is not cured within 10 days
after ESI Tractebel Acquisition, NE LP or NE LLC has obtained knowledge
thereof); (viii) certain events of bankruptcy or insolvency with respect to ESI
Tractebel Acquisition, NE LP or NE LLC; (ix) any limited partnership or limited
liability company agreement of NE LP or NE LLC as amended from time to time
ceases to be valid and binding and in full force and effect in all material
respects; (x) a default by any counterparty under any of the Material Project
Agreements (as defined in the Project Indenture as in effect on the date of the
Indenture) that would likely have a material adverse effect on ESI Tractebel
Acquisition, NE LP, NE LLC or the holders of the Securities and such default is
not cured within 180 days (or 360 days if the applicable Partnership has
promptly commenced and is diligently using its best efforts to cure such
default); (xi) an "Event of Default" (as defined in the Project Indenture as in
effect on the date of the Indenture) occurs (other than as a result of the
breach of an immaterial covenant); and (xii) the acceleration of the maturity
date of the Project Securities.
If any Event of Default occurs and is continuing, the Trustee or the
holders of at least 25% in aggregate principal amount of the then outstanding
Securities may declare by written notice to ESI Tractebel Acquisition the
principal amount of the Securities then outstanding to be due and payable
immediately. Notwithstanding the foregoing, in the case of an Event of Default
arising from certain events of bankruptcy or insolvency with respect to ESI
Tractebel Acquisition, NE LP or NE LLC, the principal amount of all outstanding
Securities will become due and payable without further action or
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notice. Holders of the Securities may not enforce the Indenture or the
Securities except as provided in the Indenture. Subject to certain limitations,
holders of a majority in principal amount of the then outstanding Securities may
direct the Trustee in its exercise of any trust or power. The Trustee may
withhold from holders of the Securities notice of any continuing Default or
Event of Default (except a Default or Event of Default relating to the payment
of principal or interest) if it determines that withholding notice is in their
interest.
In the case of any Event of Default occurring by reason of any willful
action (or inaction) taken (or not taken) by or on behalf of ESI Tractebel
Acquisition with the intention of avoiding payment of the premium that ESI
Tractebel Acquisition would have had to pay if ESI Tractebel Acquisition then
had elected to redeem the Securities pursuant to the optional redemption
provisions of the Indenture, an equivalent premium shall also become and be
immediately due and payable to the extent permitted by law upon the acceleration
of the Securities. If an Event of Default occurs prior to June 30, 2008 by
reason of any willful action (or inaction) taken (or not taken) by or on behalf
of ESI Tractebel Acquisition with the intention of avoiding the prohibition on
optional redemption of the Securities prior to June 30, 2008, then the Make
Whole Premium shall also become immediately due and payable to the extent
permitted by law upon the acceleration of the Securities.
The holders of a majority in aggregate principal amount of the
Securities then outstanding by notice to the Trustee may on behalf of the
holders of all of the Securities waive any existing Default or Event of Default
and its consequences under the Indenture except a continuing Default or Event of
Default in the payment of interest and Registration Default Damages, if any, on,
or the principal of, the Securities.
ESI Tractebel Acquisition is required to deliver to the Trustee
annually a statement regarding compliance with the Indenture, and ESI Tractebel
Acquisition is required upon becoming aware of any Default or Event of Default
to deliver to the Trustee a statement specifying such Default or Event of
Default.
Amendment, Supplement and Waiver
Except as provided in the next two succeeding paragraphs, the
Indenture, the Securities and the other Financing Agreements may be amended or
supplemented by ESI Tractebel Acquisition, NE LP, NE LLC and the Trustee, and
Events of Default and compliance with the provisions of the Financing Agreements
may be waived, with the consent of the holders of at least a majority in
aggregate outstanding principal amount of the Securities (including, without
limitation, consents obtained in connection with a purchase of, or tender offer
or exchange offer for, Securities).
Without the consent of each holder affected, an amendment or waiver may
not (with respect to any Security held by a non-consenting holder): (i) reduce
the principal amount of Securities whose holders must consent to an amendment,
supplement or waiver; (ii) reduce the principal of or change the fixed maturity
of any Security or alter the provisions with respect to extraordinary or
optional redemption of the Securities (other than provisions relating to the
covenant described above under the caption "--Repurchase at the Option of
Holders Upon a Change of Control"); (iii) reduce the rate of or change the time
for payment of interest on any Security; (iv) waive a Default or Event of
Default in the payment of principal of or premium, if any, or interest or
Registration Default
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Damages, if any, on the Securities (except a rescission of acceleration of the
Securities by the holders of at least a majority in aggregate principal amount
of the Securities then outstanding and a waiver of the payment default that
resulted from such acceleration); (v) make any Security payable in money other
than that stated in the Securities; (vi) make any change in the provisions of
the Indenture relating to waivers of past Defaults or the rights of holders to
receive payments of principal of or premium, if any, or interest or Registration
Default Damages, if any, on the Securities; (vii) waive a redemption payment
with respect to any Security (other than a payment required by the covenant
described above under the caption "-- Repurchase at the Option of Holders Upon a
Change of Control"); (viii) make a change in or waive the security provisions of
any of the Financing Agreements (ix) make any change in or waive the
applicability of the Bond Guaranty; or (x) make any change in the foregoing
amendment and waiver provisions.
Notwithstanding the foregoing, without the consent of any holder, ESI
Tractebel Acquisition, NE LP, NE LLC and the Trustee may amend or supplement the
Financing Agreements (other than the Pledge Agreements, which may be amended by
the parties thereto for the purposes that follow) to cure any ambiguity, defect
or inconsistency, to provide for uncertificated Securities in addition to or in
place of certificated Securities, to provide for the assumption of ESI Tractebel
Acquisition's obligations to holders in the case of a merger or consolidation or
sale of all or substantially all of ESI Tractebel Acquisition's assets, to make
any change that would provide any additional rights or benefits to the holders
or that does not adversely affect the legal rights under the Indenture of any
holder, or to comply with requirements of the Commission in order to effect or
maintain the qualification of the Indenture under the Trust Indenture Act.
No Personal Liability of Directors, Officers, Employees and Stockholders
No director, officer, employee, incorporator, partner, member or
stockholder of ESI Tractebel Acquisition, NE LP or NE LLC as such shall have any
liability for any Obligations of ESI Tractebel Acquisition under the Securities,
the Indenture or NE LP under the Indenture, the Note or the Bond Guaranty for
any claim based on, in respect of, or by reason of, such Obligations or their
creation. Each holder by accepting a Security waives and releases all such
liability. The waiver and release are part of the consideration for issuance of
the Securities. Such waiver may not be effective to waive liabilities under the
federal securities laws and it is the view of the Commission that such a waiver
is against public policy.
Legal Defeasance and Covenant Defeasance
ESI Tractebel Acquisition may, at its option and at any time, elect to
have all of its obligations discharged with respect to the outstanding
Securities ("Legal Defeasance") except for (i) the rights of holders of
outstanding Securities to receive payments in respect of the principal of,
premium, if any, and interest if any, on such Securities when such payments are
due from the trust referred to below, (ii) ESI Tractebel Acquisition's
obligations with respect to the Securities concerning issuing temporary
Securities, registration of Securities, mutilated, destroyed, lost or stolen
Securities and the maintenance of an office or agency for payment and money for
security payments held in trust, (iii) the rights, powers, trusts, duties and
immunities of the Trustee, and ESI Tractebel Acquisition's obligations in
connection therewith and (iv) the Legal Defeasance provisions of the Indenture.
In addition, ESI Tractebel Acquisition may, at its option and at any time, elect
to have the obligations of ESI Tractebel Acquisition released with respect to
certain covenants that are described in the Indenture ("Covenant Defeasance")
and, thereafter, any failure to comply with such obligations shall not
constitute a Default or Event of Default with respect to the Securities. In the
event Covenant Defeasance occurs, certain events (other than nonpayment,
bankruptcy, receivership, rehabilitation and insolvency events) described under
the caption "-- Events of Default and Remedies" will no longer constitute Events
of Default with respect to the Securities.
In order to exercise either Legal Defeasance or Covenant Defeasance:
(i) ESI Tractebel Acquisition must irrevocably deposit with the Trustee, in
trust, for the benefit of the holders of the Securities, cash in U.S. dollars,
non-callable Government Securities, or a combination thereof, in such amounts as
will be sufficient, in the opinion of a nationally recognized firm of
independent public accountants, to pay the principal of, premium, if any,
interest and Registration Default Damages, if any,
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on the outstanding Securities on the stated maturity or on the applicable
redemption date, as the case may be, and ESI Tractebel Acquisition must specify
whether the Securities are being defeased to maturity or to a particular
redemption date; (ii) in the case of Legal Defeasance, ESI Tractebel Acquisition
must have delivered to the Trustee an opinion of counsel in the United States
reasonably acceptable to the Trustee confirming that (A) ESI Tractebel
Acquisition has received from, or there has been published by, the Internal
Revenue Service a ruling or (B) since the date of the Indenture, there has been
a change in the applicable federal income tax law, in either case to the effect
that, and based thereon such opinion of counsel shall confirm that, the holders
of the outstanding Securities will not recognize income, gain or loss for
federal income tax purposes as a result of such Legal Defeasance and will be
subject to federal income tax on the same amounts, in the same manner and at the
same times as would have been the case if such Legal Defeasance had not
occurred; (iii) in the case of Covenant Defeasance, ESI Tractebel Acquisition
shall have delivered to the Trustee an opinion of counsel in the United States
reasonably acceptable to the Trustee confirming that the holders of the
outstanding Securities will not recognize income, gain or loss for federal
income tax purposes as a result of such Covenant Defeasance and will be subject
to federal income tax on the same amounts, in the same manner and at the same
times as would have been the case if such Covenant Defeasance had not occurred;
(iv) no Default or Event of Default shall have occurred and be continuing on the
date of such deposit (other than a Default or Event of Default resulting from
the borrowing of funds to be applied to such deposit) or insofar as Events of
Default from bankruptcy or insolvency events are concerned, at any time in the
period ending on the 91st day after the date of the deposit; (v) such Legal
Defeasance or Covenant Defeasance will not result in a breach or violation of,
or constitute a default under any material agreement or instrument (other than
the Indenture) to which ESI Tractebel Acquisition, NE LP or NE LLC is a party or
by which ESI Tractebel Acquisition, NE LP or NE LLC is bound; (vi) ESI Tractebel
Acquisition must have delivered to the Trustee an opinion of counsel to the
effect that after the 91st day following the deposit, the trust funds will not
be subject to the effect of any applicable bankruptcy, insolvency,
reorganization or similar laws affecting creditors' rights generally; (vii) ESI
Tractebel Acquisition must have delivered to the Trustee an Officers'
Certificate stating that the deposit was not made by ESI Tractebel Acquisition
with the intent of preferring the holders of Securities over the other creditors
of ESI Tractebel Acquisition with the intent of defeating, hindering, delaying
or defrauding creditors of ESI Tractebel Acquisition or others; and (viii) ESI
Tractebel Acquisition must have delivered to the Trustee an Officers'
Certificate and an opinion of counsel, each stating that all conditions
precedent provided for in the Indenture relating to the Legal Defeasance or the
Covenant Defeasance have been complied with.
Transfer and Exchange
A holder may transfer or exchange Securities in accordance with the
Indenture. The Registrar and the Trustee may require a holder, among other
things, to furnish appropriate endorsements and transfer documents and ESI
Tractebel Acquisition may require a holder to pay any taxes and fees required by
law or permitted by the Indenture. ESI Tractebel Acquisition is not required to
transfer or exchange any Security selected for redemption. Also, ESI Tractebel
Acquisition is not required to transfer or exchange any Security for a period of
15 days before a selection of Securities to be redeemed. See "-- Book-Entry,
Delivery and Form."
The registered holder of a Security will be treated as the owner of
such Security for all purposes.
Concerning the Trustee
The Indenture contains certain limitations on the rights of the
Trustee, should it become a creditor of ESI Tractebel Acquisition, to obtain
payment of claims in certain cases, or to realize on certain property received
in respect of any such claim as security or otherwise. The Trustee will be
permitted to engage in other transactions; however, if it acquires any
conflicting interest it must eliminate such conflict within 90 days, apply to
the Commission for permission to continue or resign.
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The holders of a majority in principal amount of the then outstanding
Securities will have the right to direct the time, method and place of
conducting any proceeding for exercising any remedy available to the Trustee,
subject to certain exceptions. The Indenture will provide that in case an Event
of Default occurs (which is not cured), the Trustee will be required, in the
exercise of its power, to use the degree of care of a prudent man in the conduct
of his own affairs. Subject to such provisions, the Trustee will be under no
obligation to exercise any of its rights or powers under the Indenture at the
request of any holder, unless such holder shall have offered to the Trustee
security and indemnity satisfactory to it against any loss, liability or
expense.
Book-Entry, Delivery and Form
The Securities were offered and sold to qualified institutional buyers
in reliance on Rule 144A ("Rule 144A Securities") and in offshore transactions
in reliance on Regulation S ("Regulation S Securities"). Rule 144A Securities
are in registered, global form without interest coupons (the "Rule 144A Global
Securities"). Regulation S Securities are in registered, global form without
interest coupons (the "Regulation S Securities" and together with the Rule 144A
Securities, the "Global Securities"). The Global Securities will be deposited
upon issuance with the Trustee as custodian for DTC in New York, New York, and
registered in the name of DTC or its nominee, in each case for credit to an
account of a direct or indirect participant in DTC as described below.
Beneficial interests in the Rule 144A Global Securities may not be exchanged for
beneficial interests in the Regulation S Global Bonds at any time except in the
limited circumstances described below. See "-- Exchanges Between Regulation S
Securities and Rule 144A Securities."
Except as set forth below, the Global Securities may be transferred, in
whole or in part, only to another nominee of DTC or to a successor of DTC or its
nominee, Beneficial interests in the Global Securities may not be exchanged for
Securities in certificated form except in the limited circumstances described
below. See "-- Exchange of Book Entry Securities for Certificated Securities."
Except in the limited circumstances described below, owners of beneficial
interests in the Global Securities will not be entitled to receive physical
delivery of Certificated Securities (as defined below).
Transfers of beneficial interests in the Global Securities will be
subject to the applicable rules and procedures of DTC and its direct or indirect
participants (including, if applicable, those of the Euroclear System
("Euroclear") and Cedel, S.A. ("Cedel"), which may change from time to time.
Initially, the Trustee will act as Paying Agent and Registrar. The
Securities may be presented for registration of transfer and exchange at the
offices of the Registrar.
Depository Procedures
The following description of the operations and procedures of DTC,
Euroclear and Cedel are provided solely as a matter of convenience. These
operations and procedures are solely within the control of the respective
settlement systems and are subject to changes by them from time to time. ESI
Tractebel Acquisition takes no responsibility for these operations and
procedures and urges investors to contact the systems or their participants
directly to discuss these matters.
DTC has advised ESI Tractebel Acquisition that DTC is a limited-purpose
trust company created to hold securities for its participating organizations
(collectively, the "Participants") and to facilitate the clearance and
settlement of transactions in those securities between Participants through
electronic book-
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entry changes in accounts of its Participants. The Participants include
securities brokers and dealers (including Goldman), banks, trust companies,
clearing corporations and certain other organizations. Access to DTC's systems
is also available to other entities such as banks, dealers and trust companies
that clear through or maintain a custodial relationship with a Participant,
either directly or indirectly (collectively, the "Indirect Participants").
Persons who are not Participants may beneficially own securities held by or on
behalf of DTC only through the Participants or the Indirect Participants. The
ownership interests in, and transfers of ownership interests in, each security
held by or on behalf of DTC are recorded on the records of the Participants and
Indirect Participants.
DTC has also advised ESI Tractebel Acquisition that, pursuant to
procedures established by it, (i) upon deposit of the Global Securities, DTC
will credit the accounts of Participants designated by ESI Tractebel Acquisition
with portions of the principal amount of the Global Securities and (ii)
ownership of such interests in the Global Securities will be shown on, and the
transfer of ownership thereof will be effected only through, records maintained
by DTC (with respect to the Participants) or by the Participants and the
Indirect Participants (with respect to other owners of beneficial interests in
the Global Securities)
Investors in the Rule 144A Global Securities may hold their interests
therein directly through DTC, if they are Participants in such system, or
indirectly through organizations (including Euroclear and Cedel) which are
Participants in such system. Investors may hold interests in the Regulation S
Global Securities through Participants in the DTC system other than Euroclear
and Cedel. Euroclear and Cedel will hold interests in the Regulation S Global
Securities on behalf of their participants through customers' securities
accounts in their respective names on the books of their respective
depositories, which are Morgan Guaranty Trust Company of New York, Brussels
office, as operator of Euroclear, and Citibank, N.A., as operator of Cedel. All
interests in a Global Security, including those held through Euroclear or Cedel,
may be subject to the procedures and requirements of DTC. Those interests held
through Euroclear and Cedel may also be subject to the procedures and
requirements of such systems. The laws of some states require that certain
persons take physical delivery in definitive form of securities that they own.
Consequently, the ability to transfer beneficial interests in a Global Security
to such persons will be limited to that extent. Because DTC can act only on
behalf of Participants, which in turn act on behalf of Indirect Participants and
certain banks, the ability of a person having beneficial interests in a Global
Security to pledge such interests to persons or entities that do not participate
in the DTC system, or otherwise take actions in respect of such interests, may
be affected by the lack of a physical certificate evidencing such interests.
Except as described herein, owners of interest in the Global Securities
will not have Securities registered in their names, will not receive physical
delivery of Securities in certificated form and will not be considered the
registered owners or "holders" thereof under the Indenture for any purpose.
Payments in respect of the principal of, premium, if any, interest and
Registration Default Damages, if any, on a Global Security registered in the
name of DTC or its nominee will be payable to DTC in its capacity as the
registered holder under the Indenture. Under the terms of the Indenture, ESI
Tractebel Acquisition and the Trustee will treat the persons in whose names the
Securities, including the Global Securities, are registered as the owners
thereof for the purpose of receiving such payments and for any and all other
purposes whatsoever. Consequently, neither ESI Tractebel Acquisition, the
Trustee nor any agent of ESI Tractebel Acquisition or the Trustee has or will
have any responsibility or liability for (i) any aspect of DTC's records or any
Participant's or Indirect Participant's records relating to or payments made on
account of beneficial ownership interest in the Global Securities, or for
maintaining, supervising or reviewing any of DTC's records or any Participant's
or Indirect Participant's records relating to the beneficial ownership interests
in the Global Securities or (ii) any other matter relating to the actions and
practices of DTC or any of its Participants or Indirect Participants. DTC has
advised ESI Tractebel Acquisition that its current practice, upon receipt of any
payment in respect of securities such as the
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Securities (including principal and interest), is to credit the accounts of the
relevant Participants with the payment on the payment date, in amounts
proportionate to their respective holdings in the principal amount of beneficial
interest in the relevant security as shown on the records of DTC unless DTC has
reason to believe it will not receive payment on such payment date. Payments by
the Participants and the Indirect Participants to the beneficial owners of
Securities will be governed by standing instructions and customary practices and
will be the responsibility of the Participants or the Indirect Participants and
will not be the responsibility of DTC, the Trustee or ESI Tractebel Acquisition.
Neither ESI Tractebel Acquisition nor the Trustee will be liable for any delay
by DTC or any of its Participants in identifying the beneficial owners of the
Securities, and ESI Tractebel Acquisition and the Trustee may conclusively rely
on and will be protected in relying on instructions from DTC or its nominee for
all purposes.
Except for trades involving only Euroclear and Cedel participants,
interest in the Global Securities are expected to be eligible to trade in DTC's
Same-Day Funds Settlement System and secondary market trading activity in such
interests will, therefore, settle in immediately available funds, subject in all
cases to the rules and procedures of DTC and its Participants. See "-- Same Day
Settlement and Payment."
Transfers between Participants in DTC will be effected in accordance
with DTC's procedures, and will be settled in same day funds, and transfers
between participants in Euroclear and Cedel will be effected in the ordinary way
in accordance with their respective rules and operating procedures.
Cross-market transfers between the Participants in DTC, on the one
hand, and Euroclear or Cedel participants, on the other hand, will be effected
through DTC in accordance with DTC's rules on behalf of Euroclear or Cedel, as
the case may be, by its respective depositary; however, such cross-market
transactions will require delivery of instructions to Euroclear or Cedel, as the
case may be, by the counterparty in such system in accordance with the rules and
procedures and within the established deadlines (Brussels time) of such system.
Euroclear or Cedel, as the case may be, will, if the transaction meets its
settlement requirements, deliver instructions to its respective depositary to
take action to effect final settlement on its behalf by delivering or receiving
interests in the relevant Global Security in DTC, and making or receiving
payment in accordance with normal procedures for same-day funds settlement
applicable to DTC. Euroclear participants and Cedel participants may not deliver
instructions directly to the depositories for Euroclear or Cedel.
DTC has advised ESI Tractebel Acquisition that it will take any action
permitted to be taken by a holder of Securities only at the direction of one or
more Participants to whose account DTC has credited the interests in the Global
Securities and only in respect of such portion of the aggregate principal amount
of the Securities as to which such Participant or Participants has or have given
such direction. However, if there is an Event of Default under the Securities,
DTC reserves the right to exchange the Global Securities for legended Securities
in certificated form, and to distribute such Securities to its Participants.
Although DTC, Euroclear and Cedel have agreed to the foregoing
procedures to facilitate transfers of interests in the Regulation S Global
Securities and the Rule 144A Global Securities among Participants in DTC,
Euroclear and Cedel, they are under no obligation to perform or to continue to
perform such procedures, and such procedures may be discontinued at any time.
Neither ESI Tractebel Acquisition nor the Trustee nor any of their respective
agents will have any responsibility for the performance by DTC, Euroclear or
Cedel or their respective participants or indirect participants of their
respective obligations under the rules and procedures governing their
operations.
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Exchange of Book-Entry Securities for Certificated Securities
A Global Security is exchangeable for definitive Securities in
registered certificated form ("Certificated Securities") only if (i) DTC (x)
notifies ESI Tractebel Acquisition that it is unwilling or unable to continue as
depositary for the Global Securities and ESI Tractebel Acquisition thereupon
fails to appoint a successor depositary within 90 days or (y) has ceased to be a
clearing agency registered under the Exchange Act, (ii) ESI Tractebel
Acquisition, at its option, notifies the Trustee in writing that it elects to
cause the issuance of the Certificated Securities, (iii) there shall have
occurred and be continuing a Default or Event of Default with respect to the
Securities or (iv) upon the written request of a beneficial owner of Securities
in accordance with the Indenture. In all cases, Certificated Securities
delivered in exchange for any Global Security or beneficial interests therein
will be registered in the names, and issued in any approved denominations
(except as otherwise expressly set forth herein), requested by or on behalf of
the depositary (in accordance with its customary procedures).
Exchange of Certificated Securities for Book-Entry Securities
Securities issued in certificated form may not be exchanged for
beneficial interests in any Global Securities unless the transferor first
delivers to the Trustee a written certificate (in the form provided in the
Indenture) to the effect that such transfer will comply with the appropriate
transfer restrictions applicable to such Securities.
Exchanges Between Regulation S Securities and Rule 144A Securities
Beneficial interests in a Rule 144A Global Security may be transferred
to a person who takes delivery in the form of an interest in the Regulation S
Global Security, only if the transferor first delivers to the Trustee a written
certificate (in the form provided in the Indenture) to the effect that such
transfer is being made in accordance with Rule 903 or 904 of Regulation S or
Rule 144 (if available).
Transfers involving an exchange of a beneficial interest in the
Regulation S Global Security for a beneficial interest in a Rule 144A Global
Security or vice versa will be effected in DTC by means of an instruction
originated by the Trustee through the DTC Deposit/Withdraw at Custodian system.
Accordingly, in connection with any such transfer, appropriate adjustments will
be made to reflect a decrease in the principal amount of the Regulation S Global
Security and a corresponding increase in the principal amount of the Rule 144A
Global Security or vice versa, as applicable. Any beneficial interest in one of
the Global Securities that is transferred to a person who takes delivery in the
form of an interest in the other Global Security will, upon transfer, cease to
be an interest in such Global Security and will become an interest in the other
Global Security and, accordingly, will thereafter be subject to all transfer
restrictions and other procedures applicable to beneficial interest in such
other Global Security for so long as it remains such an interest.
Same Day Settlement and Payment
The Indenture will require that payments in respect of the Securities
represented by the Global Securities (including principal, premium, if any,
interest and Registration Default Damages, if any) be made by wire transfer of
immediately available funds to the accounts specified by the Global Security
Holder. With respect to Securities in certificated form, ESI Tractebel
Acquisition will make all payments of principal, premium, if any, interest and
Registration Default Damages, if any, by wire transfer of immediately available
funds to the accounts specified by the holders thereof or, if no such account is
specified, by mailing a check to each such holder's registered address. The
Securities represented by the Global Securities are expected to be eligible to
trade in the PORTAL market and to trade in the Depositary's Same-Day Funds
Settlement System, and any permitted secondary market trading activity in
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such Securities will, therefore, be required by DTC to be settled in immediately
available funds. ESI Tractebel Acquisition expects that secondary trading in any
certificated Securities will also be settled in immediately available funds.
Because of time zone differences, the securities account of a Euroclear
or Cedel participant purchasing an interest in a Global Security from a
Participant in DTC will be credited, and any such crediting will be reported to
the relevant Euroclear or Cedel participant, during the securities settlement
processing day (which must be a business day for Euroclear and Cedel)
immediately following the settlement date of DTC. DTC has advised ESI Tractebel
Acquisition that cash received in Euroclear or Cedel as a result of sales of
interests in a Global Security by or through a Euroclear or Cedel participant to
a Participant in DTC will be received with value on the settlement date of DTC
but will be available in the relevant Euroclear or Cedel cash account only as of
the business day for Euroclear or Cedel following DTC's settlement date.
Other Information Concerning DTC
Conveyance of notices and other communications by DTC to Direct
Participants, by Direct Participants to Indirect Participants, and by Direct
Participants and Indirect Participants to beneficial owners will be governed by
arrangements among them, subject to any statutory or regulatory requirements as
may be in effect from time to time.
Neither DTC nor Cede & Co. will consent or vote with respect to the
Securities. Under its usual procedures, DTC mails an Omnibus Proxy to ESI
Tractebel Acquisition as soon as possible after the record date. The Omnibus
Proxy assigns Cede & Co.'s consenting or voting rights to those Direct
Participants to whose accounts the Securities are credited on the record date
(identified in a listing attached to the Omnibus Proxy).
DTC may discontinue providing its services as securities depository
with respect to the Securities at any time by giving reasonable notice to ESI
Tractebel Acquisition or the Trustee. Under such circumstances, in the event
that a successor securities depositary is not obtained, Security certificates
are required to be printed and delivered. If ESI Tractebel Acquisition decides
to discontinue use of the system of book-entry transfers through DTC (or a
successor securities depositary), Security certificates will be printed and
delivered.
Ratings
Moody's Investors Service, Inc., and Standard & Poor's Corporation have
assigned the Securities ratings of "Ba1" and "BB", respectively. Each such
rating reflects only the view of the applicable rating agency at the time the
rating was issued, and any explanation of the significance of such rating may
only be obtained from such rating agency. There is no assurance that any such
credit rating will remain in effect for any given period of time or that such
rating will not be lowered, suspended or withdrawn entirely by the applicable
rating agency, if, in such rating agency's judgment, circumstances so warrant.
Any such lowering, suspension or withdrawal of any rating may have an adverse
effect on the market price or marketability of the Securities.
Certain Definitions
Set forth below are certain defined terms used in the Indenture.
Reference is made to the Indenture for a full disclosure of all such terms, as
well as any other capitalized terms used herein for which no definition is
provided.
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"Affiliate" of any specified Person means any other Person directly or
indirectly controlling or controlled by or under direct or indirect common
control with such specified Person. For purposes of this definition, "control"
(including, with correlative meanings, the terms "controlling," "controlled by"
and "under common control with"), as used with respect to any Person, means the
possession, directly or indirectly, of the power to direct or cause the
direction of the management or policies of such Person, whether through the
ownership of voting securities, by agreement or otherwise; provided that
beneficial ownership of 10% or more of the Voting Stock of a Person shall be
deemed to be control.
"Capital Lease Obligation" means, at the time any determination thereof
is to be made, the amount of the liability in respect of a capital lease that
would at such time be required to be capitalized on a balance sheet in
accordance with GAAP.
"Capital Stock" means (i) in the case of a corporation, corporate
stock, (ii) in the case of an association or business entity, any and all
shares, interests, participations, rights or other equivalents (however
designated) of corporate stock, (iii) in the case of a partnership or limited
liability company, partnership or membership interests (whether general or
limited) and (iv) any other interest or participation that confers on a Person
the right to receive a share of the profits and losses of, or distributions of
assets of, the issuing Person.
"Cash Equivalents" means (i) United States dollars, (ii) securities
issued or directly and fully guaranteed or insured by the United States
government or any agency or instrumentality thereof (provided that the full
faith and credit of the United States is pledged in support thereof) having
maturities of not more than six months from the date of acquisition, (iii)
certificates of deposit and eurodollar time deposits with maturities of six
months or less from the date of acquisition, bankers' acceptances with
maturities not exceeding six months and overnight bank deposits, in each case
with any domestic commercial bank having capital and surplus in excess of $500
million and a Thompson Bank Watch Rating of "B" or better, (iv) repurchase
obligations with a term of not more than seven days for underlying securities of
the types described in clauses (ii) and (iii) above entered into with any
financial institution meeting the qualifications specified in clause (iii)
above, (v) commercial paper having the highest rating obtainable from Moody's or
S&P and in each case maturing within six months after the date of acquisition
and (vi) money market funds at least 95% of the assets of which constitute Cash
Equivalents of the kinds described in clauses (i) through (v) of this
definition.
"Collateral" means all collateral pledged, or in respect of which a
lien is granted, pursuant to the Indenture and the Pledge Agreements.
"Collateral Documents" means the Pledge Agreements and the Indenture.
"Debt Service Coverage Ratio" means the ratio of (i) the Operating
Revenues actually received directly by NE LP and NE LLC during the 12-month
period preceding the date as of which such ratio is calculated (net of any
operating expenses paid by any of ESI Tractebel Acquisition, NE LP and NE LLC
during such period) to (ii) the scheduled debt service payments (including
principal, interest, premia, penalties and fees) on the Securities and all other
indebtedness (other than any Permitted Indebtedness) of ESI Tractebel
Acquisition, NE LP and NE LLC during such 12-month period, (provided that, for
purposes of this calculation, the corresponding payments in respect of the Note
and the Securities shall be deemed to constitute only one payment).
"Default" means any event that is or that with the passage of time or
the giving of notice or both would be an Event of Default.
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"Disqualified Stock" means any Capital Stock that, by its terms (or by
the terms of any security into which it is convertible, or for which it is
exchangeable, at the option of the holder thereof), or upon the happening of any
event, matures or is mandatorily redeemable, pursuant to a sinking fund
obligation or otherwise, or redeemable at the option of the holder thereof, in
whole or in part, on or prior to the date that is 91 days after the date on
which the Securities mature; provided, however, that any Capital Stock that
would constitute Disqualified Stock solely because the holders thereof have the
right to require the Issuer to repurchase such Capital Stock upon the occurrence
of a Change of Control shall not constitute Disqualified Stock if the terms of
such Capital Stock provide that ESI Tractebel Acquisition may not repurchase or
redeem any such Capital Stock pursuant to such provisions unless such repurchase
or redemption complies with the covenant described above under the caption "--
Certain Covenants -- Restricted Payments."
"Equity Interests" means Capital Stock and all warrants, options or
other rights to acquire Capital Stock (but excluding any debt security that is
convertible into, or exchangeable for, Capital Stock).
"Financing Agreements" means, collectively, the Indenture, the
Securities, the Note, the Bond Guaranty, the Registration Rights Agreement and
the Pledge Agreements.
"GAAP" means generally accepted accounting principles set forth in the
opinions and pronouncements of the Accounting Principles Board of the American
Institute of Certified Public Accountants and statements and pronouncements of
the Financial Accounting Standards Board or in such other statements by such
other entity as have been approved by a significant segment of the accounting
profession, which are in effect from time to time.
"Guarantee" means a guarantee (other than by endorsement of negotiable
instruments for collection in the ordinary course of business), direct or
indirect, in any manner (including, without limitation, by way of a pledge of
assets or through letters of credit or reimbursement agreements in respect
thereof), of all or any part of any Indebtedness.
"Hedging Obligations" means, with respect to any Person, the
obligations of such Person under (i) interest rate swap agreements, interest
rate cap agreements and interest rate collar agreements and (ii) other
agreements or arrangements designed to protect such Person against fluctuations
in interest rates.
"Indebtedness" means, with respect to any Person, any indebtedness of
such Person, whether or not contingent, in respect of borrowed money or
evidenced by bonds, notes, debentures or similar instruments or letters of
credit (or reimbursement agreements in respect thereof) or banker's acceptances
or representing Capital Lease Obligations or the balance deferred and unpaid of
the purchase price of any property or representing any Hedging Obligations,
except any such balance that constitutes an accrued expense or trade payable, if
and to the extent any of the foregoing (other than letters of credit and Hedging
Obligations) would appear as a liability upon a balance sheet of such Person
prepared in accordance with GAAP, as well as all Indebtedness of others secured
by a Lien on any asset of such Person (whether or not such Indebtedness is
assumed by such Person) and, to the extent not otherwise included but without
duplication, the Guarantee by such Person of any indebtedness of any other
Person. The amount of any Indebtedness outstanding as of any date shall be (i)
the accreted value thereof, in the case of any Indebtedness issued with original
issue discount, and (ii) the principal amount thereof, together with any
interest thereon that is more than 30 days past due, in the case of any other
Indebtedness.
"Investments" means, with respect to any Person, all investments by
such Person in other Persons (including Affiliates) in the forms of direct or
indirect loans (including guarantees of Indebtedness or other obligations),
advances or capital contributions (excluding commission, travel and similar
advances
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to officers and employees made in the ordinary course of business), purchases or
other acquisitions for consideration of Indebtedness, Equity Interests or other
securities, together with all items that are or would be classified as
investments on a balance sheet prepared in accordance with GAAP. If ESI
Tractebel Acquisition, NE LP, NE LLC or any Subsidiary thereof sells or
otherwise disposes of any Equity Interests of any direct or indirect Subsidiary
such that, after giving effect to any such sale or disposition, such Person is
no longer a Subsidiary thereof, ESI Tractebel Acquisition, NE LP, NE LLC or any
Subsidiary thereof shall be deemed to have made an Investment on the date of any
such sale or disposition.
"Lien" means, with respect to any asset, any mortgage, lien, pledge,
charge, security interest or encumbrance of any kind in respect of such asset,
whether or not filed, recorded or otherwise perfected under applicable law
(including any conditional sale or other title retention agreement, any lease in
the nature thereof, any option or other agreement to sell or give a security
interest in and any filing of or agreement to give any financing statement under
the Uniform Commercial Code (or equivalent statutes) of any jurisdiction).
"Make Whole Premium" means an amount equal to the excess, if any, of
(i) the present value of all interest and principal payments scheduled to become
due after the date of the Event of Default in respect of the Securities (such
present value to be determined on the basis of a discount rate equal to the
yield to maturity on the U.S. treasury instruments with a maturity as close as
practicable to the remaining average life of the Securities) over (ii) the
outstanding principal amount of the Securities.
"Moody's" means Moody's Investors Service, Inc.
"NE LLC" means Northeast Energy, LLC and its successors.
"NE LP" means Northeast Energy, LP and its successors.
"Obligations" means any principal, interest, penalties, fees,
indemnifications, reimbursements, damages and other liabilities payable under
the documentation governing any Indebtedness.
"Permitted Indebtedness" has the meaning given in the covenant
described under the caption "-- Incurrence of Indebtedness and Issuance of
Preferred Stock."
"Permitted Investments" means Cash Equivalents, the Bond Loan, NE LLC's
Investment in the Partnerships and NE LP's Investment in NE LLC and the
Partnerships.
"Permitted Liens" means: (i) Liens in favor of ESI Tractebel
Acquisition, NE LP or NE LLC; (ii) Liens on the property of a Person existing at
the time such Person is merged into or consolidated with ESI Tractebel
Acquisition, NE LP or NE LLC, provided that such Liens were in existence prior
to the contemplation of such merger or consolidation and do not extend to any
assets other than those of the Person merged into or consolidated with ESI
Tractebel Acquisition, NE LP or NE LLC; (iii) Liens on property existing at the
time of acquisition thereof by ESI Tractebel Acquisition, NE LP or NE LLC,
provided that such Liens were in existence prior to the contemplation of such
acquisition; (iv) Liens to secure the performance of statutory obligations,
surety or appeal bonds, performance bonds or other obligations of a like nature
incurred in the ordinary course of business; (v) Liens in favor of the Trustee
pursuant to the Collateral Documents; (vi) the first priority pledge of the one
percent general partner interest in each of the Partnerships in favor of the
holders of the Project Indebtedness; and (vii) Liens for taxes, assessments or
governmental charges or claims that are not yet delinquent or that are being
contested in good faith by appropriate proceedings promptly instituted and
diligently concluded, provided that any reserve or other appropriate provision
as shall be required in conformity with GAAP shall have been made therefor.
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"Projected Debt Service Coverage Ratio" means the ratio of (i) the
Operating Revenues projected to be received directly by NE LP and NE LLC during
the 12-month period following the date as of which such ratio is calculated (net
of any operating expenses projected to be paid by ESI Tractebel Acquisition, NE
LP and NE LLC during such period) to (ii) the scheduled debt service payments
(including principal, interest, premia, penalties and fees) on the Securities
and all other indebtedness (other than any Permitted Indebtedness) of ESI
Tractebel Acquisition, NE LP and NE LLC during such 12-month period, (provided
that, for purposes of this calculation, the corresponding payments in respect of
the Note and the Securities shall be deemed to constitute only one payment).
"Related Party" means, with respect to any Sponsor, (A) any controlling
stockholder thereof or Subsidiary at least 80% of which is owned by such Sponsor
or (B) any trust, corporation, partnership or other entity, the beneficiaries,
stockholders, partners, owners or Persons beneficially holding an 80% or more
controlling interest of which consist of such Sponsor and/or such other Persons
referred to in the immediately preceding clause (A).
"Revenues" has the meaning given under the caption "-- General."
"Sponsors" means ESI Energy, Inc. and Tractebel Power, Inc.
"S&P" means Standard & Poor's Rating Services, a division of the
McGraw-Hill Companies, Inc.
"Subsidiary" means, with respect to any Person, (i) any corporation,
association or other business entity of which more than 50% of the total voting
power of shares of Capital Stock entitled (without regard to the occurrence of
any contingency) to vote in the election of directors, managers or trustees
thereof is at the time owned or controlled, directly or indirectly, by such
Person or one or more of the other Subsidiaries of that Person (or a combination
thereof) and (ii) any partnership (a) the sole general partner or the managing
general partner of which is such Person or a Subsidiary of such Person or (b)
the only general partners of which are such Person or of one or more
Subsidiaries of such Person (or any combination thereof).
"Voting Stock" of any Person as of any date means the Capital Stock of
such Person that is at the time entitled to vote in the election of the Board of
Directors of such Person.
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OUTSTANDING PROJECT INDEBTEDNESS
The ability of ESI Tractebel Acquisition to pay the principal of and
premium, if any, and interest on the Securities, from payments to be made by NE
LP under the Note, depends upon, among other things, the prior payment of the
Project Indebtedness and the satisfaction of the other conditions set forth in
the agreements that govern the Project Indebtedness.
The following summaries of certain provisions of the Project Indenture
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 Project Indenture,
including the definitions therein. Copies of the Project Indenture are available
for review. See "Available Information."
The Project Securities
The Project Securities were issued by IEC Funding Corp. (now ESI
Tractebel Funding) in May 1995, in exchange for securities that were issued in
December 1994 (i) to refinance the Original Project Notes that were issued in
1989 to finance the costs of constructing the Projects, (ii) to provide the cash
collateral to secure the Partnerships' obligations to reimburse Sanwa Bank for
any drawings under the Sanwa Letters of Credit, (iii) to fund the Debt Service
Reserve Fund and the Note Subfunds of the Interest Fund and the Principal Fund
for the Project Securities, and (iv) to pay certain transaction costs. The
Project Securities, of which $490,286,720 remain outstanding as of December 31,
1997, were issued pursuant to the Original Project Indenture in four series as
the 8.43% Senior Secured Notes Due 2000, Series A (the "2000 Project Notes"),
the 9.16% Senior Secured Notes Due 2002, Series A (the "2002 Project Notes"),
the 9.32% Senior Secured Bonds Due 2007, Series A (the "2007 Project Bonds"),
and the 9.77% Senior Secured Bonds Due 2010, Series A (the "2010 Project
Bonds").
Principal Amount, Interest Rate and Stated Maturity
The original principal amounts, outstanding principal amounts, interest
rates and maturity dates of the Project Securities are set forth below.
Original Principal Outstanding
Series Amount Principal Amount(1) Interest Rate Final Maturity
------ ------ ------------------- ------------- --------------
2000 Project Notes $141,120,000 $ 71,406,720 8.43% December 30, 2000
2002 Project Notes 31,500,000 31,500,000 9.16% June 30, 2002
2007 Project Bonds 215,740,000 215,740,000 9.32% December 30, 2007
2010 Project Bonds 171,640,000 171,640,000 9.77% December 30, 2010
- ----------
(1) As of December 31, 1997.
Payment of Principal and Interest
Interest on the Project Securities is payable semiannually on each June
30 and December 30, and principal is payable in semiannual installments on the
same dates.
Redemption and Repurchase
The Project Securities are not subject to optional redemption. The
Project Securities are subject to mandatory redemption or repurchase in certain
limited circumstances involving the failure or inability to Restore a Project
(as defined in the Project Indenture) upon an Event of Loss.
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Project Guaranty
The obligations of ESI Tractebel Funding to pay the principal and
premium, if any, and interest on the Project Securities when due are
unconditionally guaranteed, jointly and severally, by the Partnerships pursuant
to the Project Guaranty.
Limitation on Liability
The Project Indenture and related documents provide that ESI Tractebel
Funding's obligations under the Project Indenture are solely corporate
obligations of ESI Tractebel Funding and that no personal liability shall attach
to any affiliate of ESI Tractebel Funding or any such incorporator, stockholder,
officer, employee or director. The Project Indenture and related documents also
provide that satisfaction of the obligations of the Partnerships shall be had
solely from the Project Collateral, and that no recourse shall be had in the
event of any non-performance by the Partnerships of such obligations to any
assets of the Partners (other than their respective interests in the Project
Collateral) or to any Partner or any affiliate of any Partner or either
Partnership or any incorporator, stockholder, officer, employee or director of
any such Partner or affiliate, or any predecessor or successor thereof.
Flow of Funds
Securities are payable only from distributions made by the Partnerships
to the Partners and from any funds available in the Accounts. Such distributions
are "Restricted Payments" under the Project Indenture and may be made only from
amounts on deposit from time to time in the General Subfund of the Partnership
Distribution Fund created under the Project Indenture and transferred to the
Trustee, and then only if certain conditions are met. The Project Indenture
requires that prior to their deposit in the Partnership Distribution Fund,
Project Revenues be transferred first to the Revenue Fund and then to the
following funds and accounts in the following order, in each case taking into
account moneys then on deposit in such fund. Such transfers generally are to be
made on the first business day of each month.
First: to the Working Capital Fund, the amount required to repay the
Working Capital Loans (or such lesser amount of such loans as the
Partnerships elect to repay), plus all interest, fees and other
amounts due and payable under the Working Capital Facility during
such month. The Working Capital Facility has not been utilized by
the Partnerships and NE LP does not anticipate that the
Partnerships will maintain a Working Capital Facility.
Second: to the General Subfund of the Operating Fund, the amount of
Operating Expenses for such month as estimated by the
Partnerships, including Management Fees but excluding Subordinated
Management Fees. Moneys in the General Subfund of the Operating
Fund are to be applied to the payment of Operating Expenses but
may also be withdrawn to make up any deficiencies in the Working
Capital Fund and the Good Faith Contest Fund.
Third: beginning in 2001, to the Major Overhaul Reserve Fund, the sum of
the Monthly MOR Contribution Amount, plus any MOR Deficiency. The
MOR Contribution Amount is the amount set forth in the Project
Indenture to be reserved annually for the payment of the projected
major maintenance costs. For the NEA Project, the amounts to be
deposited annually range from $2,869,000 in 2001 to $9,115,000 in
2003 to $2,099,000 in 2010. For the NJEA Project, the amounts to
be deposited annually range from $3,004,000 in 2001 to $9,419,000
in 2003 to $2,401,000 in 2010. These amounts may be changed,
provided that the Independent Engineer (currently, Sargent &
Lundy) confirms that the new MOR Contribution Amount is
reasonable. NE LP expects that under the New O&M Agreement for the
NEA Project the MOR Contribution Amount will be reduced to amounts
that range from
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$3,206,000 in 2001, to $4,982,000 in 2003 and zero in 2010. For
the NJEA Project, NE LP expects that the MOR Contribution amount
will range from $3,457,000 in 2001, to $478 in 2003, $4,947,000 in
2008 and zero in 2010. In the event the amounts on deposit in the
Major Overhaul Reserve Fund are not sufficient to pay any Major
Overhaul Expense, such excess Major Overhaul Expense is to be
treated as an Operating Expense payable from the General Subfund
of the Operating Fund. In the event an O&M Agreement is amended or
replaced to provide for payment by the operator of Major Overhaul
Expenses, the Major Overhaul Reserve Requirement will be
recalculated, any excess in the Major Overhaul Reserve Fund will
be transferred to the Revenue Fund and amounts owed to such
operator for such Major Overhaul Expenses will then be paid as
Operating Expenses. Under the New O&M Agreements, the New Operator
has agreed to pay Major Overhaul Expenses, and NE LP has agreed to
reimburse the New Operator for such costs. Moneys in the Major
Overhaul Reserve Fund may also be withdrawn to make up any
deficiency in the Working Capital Fund.
Fourth: to the Note Subfund of the Interest Fund, the amount payable on
the Project Securities on the next interest payment date (or on
such transfer date if such transfer date is an interest payment
date) and to the Other Obligations Subfund, the amount estimated
to be payable during such month in respect of Permitted Purchase
Money Indebtedness and/or Permitted Unsecured Indebtedness and
amounts estimated to be payable during such month to the Swap
Banks. In the event amounts in one subfund are not sufficient,
moneys are to be withdrawn from the other subfund to make up the
difference prior to transferring funds from any other fund. In
addition, moneys may be borrowed under the Working Capital
Facility for this purpose and must be borrowed if a deficiency
still exists two business days later. Moneys in the Interest Fund
may also be withdrawn to make up any deficiencies in the Working
Capital Fund and in the Operating Fund.
Fifth: to the L/C Fee Fund, the amounts estimated to be payable to the
Letter of Credit Banks during such month (other than the principal
of and interest on any reimbursement obligations). Moneys in the
L/C Fee Fund may also be withdrawn to make up any deficiencies in
the Working Capital Fund, the Operating Fund and the Interest
Fund.
Sixth: to the Note Subfund of the Principal Fund, the aggregate principal
amount of the Project Notes to become due on the next principal
payment date (or on the monthly transfer date if the monthly
transfer date is a principal payment date) and to the Other
Obligations Subfund of the Principal Fund (i) the Aggregate
Amortization Reserve Amount (relating to Permitted Purchase Money
Indebtedness and to Permitted Unsecured Indebtedness), (ii)
without duplication, the principal amount estimated to become due
during such month in respect of any Permitted Purchase Money
Indebtedness due as a consequence of the permitted sale or other
disposition of the property to which such indebtedness relates and
(iii) without duplication, the principal amount estimated to
become due and payable during the next six months in respect of
Permitted Purchase Money Indebtedness and/or Permitted Unsecured
Indebtedness, unless in the case of (iii) the amount then on
deposit in the Debt Service Reserve Fund is less than the current
Debt Service Reserve Requirement and unless there is any GSR
Deficiency, referred to below. In the event of any deficiency in
one subfund, amounts are to be transferred from the other subfund
before transfers are made from the other funds to cure such
deficiency. Amounts may also be borrowed if the deficiency
continues for two business days. Moneys in the Principal Fund may
also be withdrawn to make up any deficiencies in the Working
Capital Fund, the Operating Fund, the Interest Fund and the L/C
Fee Fund.
136
Seventh: to the Subordinated Management Fee Subfund of the Operating Fund,
the amount of Subordinated Management Fees then due and payable
during the following month. Moneys may be withdrawn from this
Subfund to make up deficiencies in Working Capital Fund, the
Operating Fund, the Interest Fund, the L/C Fee Fund and the
Principal Fund.
Eighth: to the Tax Payment Subfund of the Partnership Distribution Fund,
the aggregate amount of Tax Requirements then estimated to become
due on the Quarterly Tax Payment Dates during the following six
months. Moneys in the Tax Payment Subfund may also be withdrawn to
make up deficiencies in the Working Capital Fund, the Operating
Fund, the Interest Fund, the L/C Fee Fund and the Principal Fund.
Ninth: to the Debt Service Reserve Fund, the amount required to make the
amount on deposit therein equal to the then-current Debt Service
Reserve Requirement. In accordance with the Project Indenture, NE
LP arranged for the delivery of two Substitute Letters of Credit
in lieu of cash that was held in the Debt Service Reserve Fund.
Proceeds from a drawing under a Substitute Letter of Credit may be
withdrawn to make up any deficiency in the Working Capital Fund,
the Operating Fund, the Interest Fund, the L/C Fee Fund, the
Principal Fund and the Tax Payment Subfund. As provided in the
Project Indenture, only NE LP, and not the Partnerships, is
obligated to reimburse a Substitute Letter of Credit Bank for
amounts, if any, drawn under a Substitute Letter of Credit.
Tenth: to the Gas Transmission Reserve Fund, beginning 15 months before
the earliest Transco Agreement Expiration Date (October 31, 2006),
the amount of the Gas Transmission Reserve Requirement, provided
that the aggregate amount of transfers is not to exceed the sum of
$10,600,000 plus the aggregate amount of withdrawals from the Gas
Transmission Reserve Fund (other than amounts transferred to the
Revenue Fund after the Transco Agreement Expiration Date, a
Transco Extension Event or a Transco Substitution Event or after
the recalculation of the Gas Transmission Reserve Requirement
following the occurrence of a Partial Transportation Extension
Event). Moneys in the Gas Transmission Reserve Fund are to be
transferred to the Revenue Fund beginning one month after the
earliest Transco Agreement Expiration Date, until the occurrence
of a Transco Agreement Extension Event with respect to both
Transco Agreements or a Transco Agreement Substitution Event.
Moneys may also be withdrawn from the Gas Transmission Reserve
Fund to make up deficiencies in the Working Capital Fund, the
Operating Fund, the Interest Fund, the L/C Fee Fund, the principal
Fund and the Tax Payment Subfund.
Eleventh: to the Gas Supply Reserve Fund, on certain days and in amounts as
specified in the Project Indenture. At the time of issuance of the
Original Project Securities, the agreements extending the term of
the ProGas Agreements from 2006 to 2013 remained subject to
certain contingencies. In order to mitigate the risk that such
extensions might ultimately be ineffective, the Project Indenture
provides for the establishment of a Gas Supply Reserve Fund. Such
extensions, however, have since become final and non-appealable,
and accordingly there is no longer any requirement to fund the Gas
Supply Reserve Fund.
Twelfth: to the Partnership Suspense Fund, the remaining balance on deposit
in the Revenue Fund. Amounts on deposit in the Partnership
Suspense Fund may be transferred to the funds described above in
the event of any deficiencies therein. In addition, upon
satisfaction of the conditions set forth in the Project Indenture
and described below, amounts on deposit in the Partnership
Suspense Fund, but not exceeding the Distributable Percentage, may
be transferred to the General Subfund of the Partnership
Distribution Fund for payment at any time to the Partnerships. The
Distributable Percentage ranges from 100%, if the Debt Service
137
Coverage Ratio for the Rolling Prior Year is greater than or equal
to 1.40:1, to 25% if the Debt Service Coverage Ratio is less than
1.30:1 but not less than 1.25:1. No transfers to the General
Subfund of the Partnership Distribution Fund may be made, however,
unless the conditions described below under "Restricted Payments"
are satisfied. As described above moneys permitted to be
transferred to the General Subfund will be transferred directly to
the Trustee and deposited to the Debt Service Account held by the
Trustee under the Indenture.
Restricted Payments
Under the Project Indenture, distributions to the Partners and payments
in respect of permitted subordinated indebtedness of the Partnerships, other
than for amounts in respect of taxes and certain management fees and costs, may
be made by the Partnerships only from, and to the extent of, amounts then on
deposit in the General Subfund of the Partnership Distribution Fund. The
transfer of amounts into the General Subfund of the Partnership Distribution
Fund is subject to the prior satisfaction of a number of conditions set forth in
the Project Indenture. Among other conditions, the Project Trustee must
determine that (i) the amounts on deposit in the other Funds are equal to or
greater than the amounts then required to be on deposit therein under the
Project Indenture; (ii) no default or event of default under the Project
Indenture has occurred and is continuing; (iii) no debt is outstanding under the
Working Capital Facility, (iv) either the Debt Service Coverage Ratio or the
Substitute Debt Service Coverage Ratio for the Rolling Prior Year equals or
exceeds 1.25:1; and (v) the Partnerships have certified that they have no
knowledge of any event or circumstance that could reasonably be expected to
result in the Debt Service Coverage Ratio for the period of two fiscal quarters
commencing on the expiration date of the Rolling Prior Year, treated as a single
period, being less than 1.25:1. If such conditions are satisfied, funds may be
transferred to the General Subfund of the Partnership Distribution Fund in an
amount equal to a percentage of the amounts then on deposit in the Partnership
Suspense Fund, with such percentage to be determined by reference to the Debt
Service Coverage Ratio for the Rolling Prior Year. Such percentage will be (i)
100% if such ratio equals or exceeds 1.40:1, (ii) 75% if such ratio equals or
exceeds 1.35:1, but is less than 1.40:1, (iii) 50% if such ratio equals or
exceeds 1.30:1 but is less than 1.35:1 or (iv) 25% if such ratio equals or
exceeds 1.25:1 but is less than 1.30:1. The amount to be transferred may be
increased based upon the Substitute Debt Service Coverage Ratio for the Rolling
Prior Year.
Limitations on Debt
ESI Tractebel Funding is not permitted to create or incur or to suffer
to exist any Debt, except the Project Securities and Additional Project
Securities.
Neither Partnership is permitted to create or incur or suffer to exist
any Debt, except (i) Debt arising under the Project Credit Agreement in an
aggregate principal amount equal to the aggregate outstanding principal amount
of the Project Securities and any Additional Project Securities; (ii) Debt in
respect of Project Letters of Credit in an aggregate amount at no time greater
than the lesser of (a) the combined maximum amount of the Energy Bank
Obligations for both Partnerships required by the terms of any Power Purchase
Agreement to be supported by Energy Bank Letters of Credit at any time prior to
the final maturity of the Project Securities plus certain other obligations as
provided in the Project Indenture and (b) $82 million; (iii) Debt under the
Working Capital Facility in an aggregate principal amount at any time not
greater than $20 million; (iv) obligations of the Partnerships under the Swaps;
(v) Debt arising under any of the Project Documents; (vi) Subordinated Debt not
to exceed an aggregate principal amount of $50 million, the proceeds of which
are applied to the payment of Capital Expenditures for the Projects; (vii)
Permitted Purchase Money Indebtedness; (viii) certain trade accounts payable;
(ix) Permitted Unsecured Indebtedness; (x) certain permitted Project Guarantees;
(xi) Debt in respect of fuel price hedging arrangements related to the
acquisition of fuel reasonably necessary for the operation of the Projects; and
(xii) Debt incurred by either Partnership to the other Partnership.
138
Certain Other Covenants
Among the other provisions contained in the Project Indenture are
requirements to maintain insurance, limitations on liens and on mergers,
consolidations and similar transactions and limitations on the rights of ESI
Tractebel Funding's and of the Partnerships to amend or terminate material
agreements. See Appendix E for a more detailed summary of covenants contained in
the Project Indenture.
The Working Capital Facility
The Project Indenture permits the Partnerships to enter into revolving
credit arrangements from time to time with financial institutions with maximum
available borrowings of up to $20 million in order to provide for the working
capital requirements of the Partnerships (the "Working Capital Facility"). The
obligations of the Partnerships in respect of any Working Capital Facility are
secured by the same collateral that secures the obligations in respect of the
Project Securities, the Project Guaranty and the Swaps, but upon an exercise of
remedies in respect of such collateral, the Working Capital Banks will be
entitled to payment in full of all amounts payable in respect of such Working
Capital Facility prior to the payment of any amounts in respect of such other
obligations and prior to the payment of any amounts in respect of the
Securities. In February 1998, NE LP terminated the Sanwa Working Capital
Facility and does not anticipate a need to replace it with another Working
Capital Facility. See "Summary."
The Project Letter of Credit Facility
The Partnerships are required by the terms of certain of their
respective Power Purchase Agreements to provide Energy Bank Letters of Credit to
the Power Purchasers thereunder to support the Partnerships' Energy Bank
Obligations. See "Summary of Principal Project Agreements -- Power Purchase
Agreements." Under the Project Indenture the Partnerships have agreed to provide
for such Energy Bank Letters of Credit and to secure the obligations under such
Project Letter of Credit Facility, subject to certain terms and conditions set
forth in the Project Indenture.
Upon the termination of the Sanwa Letters of Credit, BankBoston issued
a letter of credit in a face amount of $12.656 million to support NEA's Energy
Bank Obligations to Montaup, and NationsBank issued a letter of credit in a face
amount of $54.0 million to support NEA's Energy Bank Obligations to Boston
Edison.
Any drawings under the Energy Bank Letters of Credit are to be
reimbursed by FPL Group Capital, and pursuant to the Reimbursement Agreement, NE
LP is obligated to reimburse FPL Group Capital. The Partnerships are not
obligated to reimburse FPL Group Capital for such drawings.
The Swaps
The Partnerships entered into the Swaps with certain financial
institutions. The remaining Swaps are scheduled to expire in 1999. Payments
under the Swaps are to be made from the Interest Fund on a parity with the
interest payments on the Project Securities. For a summary of the terms of the
Swaps, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources -- Swaps."
Collateral Security
In 1994, the holders of the Project Securities (represented by the
Project Trustee), Sanwa Bank, the Swap Banks, the Collateral Agent and the
Project Trustee (collectively, the "Project Secured Parties") entered into the
Collateral Agency Agreement with IEC Funding Corp. (now ESI Tractebel Funding)
and the Partnerships, pursuant to which the Collateral Agent acts as agent for
the Project Secured Parties under the Project Security Documents. The rights of
the Project Secured Parties in respect of the Project Collateral are shared
among the Project Secured Parties in accordance with the Collateral Agency
Agreement. In addition, a mortgage on the NEA Site and the NEA Project
(subordinate to the mortgage and security interests in favor of the Project
Secured Parties) has been granted by NEA to the NEA Power Purchasers pursuant to
the NEA Second Mortgage to secure NEA's obligations under the NEA Power Purchase
Agreements See "Summary of Principal Project Agreements -- Power Purchase
Agreements -- NEA Power Purchase Agreements."
139
CERTAIN FEDERAL TAX CONSIDERATIONS
The Exchange
The following discussion is a summary of the material United States
federal income tax consequences expected to apply to the exchange of New
Securities for Old Securities under currently applicable law. The summary is
based on laws, regulations, rulings and decisions now in effect, all of which
are subject to change. The discussion does not cover all aspects of federal
taxation that may be relevant to, or the actual tax effect that any of the
matters described herein will have on, particular holders, and does not address
state, local, foreign or other tax laws. Certain holders (including insurance
companies, tax-exempt organizations, financial institutions, broker-dealers,
taxpayers subject to the alternative minimum tax and foreign persons) may be
subject to special rules not discussed below. Each holder should consult with
its own tax advisor in determining the federal, state, local and any other tax
consequences to the particular holder of the exchange of New Securities for Old
Securities.
The exchange of New Securities for Old Securities will not be a taxable
event to holders for federal income tax purposes. The exchange of New Securities
for the Old Securities pursuant to the Exchange Offer should not be treated as
an "exchange" for federal income tax purposes because the New Securities will
not be considered to differ materially in kind or extent from the Old
Securities. If, however, the exchange of the New Securities for the Old
Securities were treated as an exchange for federal income tax purposes, such
exchange would constitute a recapitalization for federal income tax purposes.
Accordingly, the New Securities will have the same issue price as the Old
Securities, and a holder will have the same adjusted basis and holding period in
the New Securities as it had in the Old Securities immediately before the
exchange.
Non-United States Holders
The following is a general discussion of certain United States federal
income and estate tax consequences of the acquisition, ownership and disposition
of Securities by an initial beneficial owner of Securities that, for United
States federal income tax purposes, is not a "United States person" (a
"Non-United States Holder"). This discussion is based upon the United States
federal tax law now in effect, which is subject to change, possibly
retroactively. For purposes of this discussion, a "United States person" means a
citizen or resident of the United States (except as may be provided in
regulations), a corporation, partnership or other entity created or organized in
the United States or under the laws of the United States or of any political
subdivision thereof, an estate whose income is includible in gross income for
United States federal income tax purposes regardless of its source or a trust,
if a U.S. court is able to exercise primary supervision over the administration
of the trust and one or more U.S. persons have the authority to control all
substantial decisions of the trust. The tax treatment of the holders of the
Securities may vary depending upon their particular situations. United States
persons acquiring the Securities are subject to different rules than those
discussed below. In addition, certain other holders may be subject to special
rules not discussed below. Further, the consequences to the holders of the
equity interests in a Non-United States Holder of that Non-United States Holder
are not discussed. Prospective investors are urged to consult their tax advisors
regarding the United States federal tax consequences of acquiring, holding and
disposing of Securities, as well as any tax consequences that may arise under
the laws of any foreign, state, local or other taxing jurisdiction.
Interest
Interest paid by ESI Tractebel Acquisition to a Non-United States
Holder will not be subject to United States federal income or withholding tax if
such Non-United States Holder has no connection with
140
the United States other than owning Securities, and in particular such interest
is not effectively connected with the conduct of a trade or business within the
United States by such Non-United States Holder and such Non-United States Holder
(i) does not actually or constructively own 10% or more of the total combined
voting power of all classes of stock of ESI Tractebel Acquisition or ESI Energy
or Tractebel Power; (ii) does not actually or constructively own 10% or more of
the capital or profits or interest in NE LP (iv) is not a controlled foreign
corporation with respect to which ESI Tractebel Acquisition, ESI Energy,
Tractebel Power or NE LP is a "related person" within the meaning of the United
States Internal Revenue Code of 1986 (the "Code") and (v) certifies, under
penalties of perjury, that such holder is not a United States person and
provides such holder's name and address.
Gain on Disposition
A Non-United States Holder will generally not be subject to United
States federal income tax on gain recognized on a sale, redemption or other
disposition of a Security provided such holder has no connection with the United
States other than holding Securities and in particular (i) the gain is not
effectively connected with the conduct of a trade or business within the United
States by the Non-United States Holder or (ii) in the case of a Non-United
States Holder who is a nonresident alien individual and holds the Security as a
capital asset, such holder is not present (or treated as present) in the United
States for 183 or more days in the taxable year and certain other requirements
are met.
Federal Estate Taxes
If interest on the Securities is exempt from withholding of United
States federal income tax under the rules described above, the Securities
generally will not be included in the estate of a deceased Non-United States
Holder for United States federal estate tax purposes.
Information Reporting and Backup Withholding
ESI Tractebel Acquisition will, where required, report to the holders
of Securities and the Internal Revenue Service the amount of any interest paid
on the Securities in each calendar year and the amounts of tax withheld, if any,
with respect to such payments.
In the case of payments of interest to Non-United States Holders,
temporary Treasury regulations provide that the 31% backup withholding tax and
certain information reporting will not apply to such payments with respect to
which either the requisite certification, as described above, has been received,
or an exemption has otherwise been established; provided that neither ESI
Tractebel Acquisition nor its payment agent has actual knowledge that the holder
is a United States person or that the conditions of any other exemption are not
in fact satisfied. Under temporary Treasury regulations, these information
reporting and backup withholding requirements will apply, however, to the gross
proceeds paid to a Non-United States Holder on the disposition of the Securities
by or through a United States office of a United States or foreign broker,
unless the holder certifies to the broker under penalties of perjury as to its
name, address and status as a foreign person or the holder otherwise establishes
an exemption. Information reporting requirements, but not backup withholding,
will also apply to a payment of the proceeds of a disposition of the Securities
by or through a foreign office of a United States broker or foreign brokers with
certain types of relationships to the United States unless such broker has
documentary evidence in its file that the holder of the Securities is not a
United States person, and such broker has no actual knowledge to the contrary,
or the holder establishes an exception. Neither information reporting nor backup
withholding generally will apply to a payment of the proceeds of a disposition
of the Securities by or through a foreign office of a foreign broker not subject
to the preceding sentence.
141
Backup withholding is not an additional tax. Any amounts withheld under
the backup withholding rules may be refunded or credited against the Non-United
States Holder's United States federal income tax liability, provided that the
required information is furnished to the Internal Revenue Service.
The Treasury Department recently promulgated final regulations
regarding the withholding and information reporting rules discussed above. In
general, the final regulations do not significantly alter the substantive
withholding and information reporting requirements but rather unify current
certification procedures and forms and clarify reliance standards. The final
regulations are generally effective for payments made after December 31, 1999,
subject to certain transition rules. Non-United States Holders should consult
their own tax advisers with respect to the impact, if any, of the new final
regulations.
PLAN OF DISTRIBUTION
Any broker-dealer that receives New Securities for its own account
pursuant to the Exchange Offer must acknowledge that it will deliver a
prospectus in connection with any resale of such New Securities. This
Prospectus, as it may be amended or supplemented from time to time, may be used
by broker-dealers in connection with the resale of New Securities received in
exchange for Old Securities where such Old Securities were acquired by such
broker-dealer as a result of market-making activities or other trading
activities.
Neither ESI Tractebel Acquisition nor NE LP will receive any proceeds
from any sales of New Securities by broker-dealers. New Securities received by
broker-dealers for their own account pursuant to the Exchange Offer may be sold
from time to time at prices determined at the time of sale directly to
purchasers or to or through broker-dealers who may receive compensation in the
form of commissions or concessions from any such broker-dealer and/or the
purchasers of any such New Securities. Any broker-dealer that resells New
Securities 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 New
Securities may be deemed to be an "underwriter" within the meaning of the 1933
Act and any profit on any such resale of New Securities and any commissions or
concessions received by any such persons may be deemed to be underwriting
compensation under the 1933 Act. A letter accompanying the New Securities to be
delivered to each holder that tendered Old Securities pursuant to the Exchange
Offer will state that by delivering a prospectus, a broker-dealer will not be
deemed to admit that it is an "underwriter" within the meaning of the 1933 Act.
For a period of up to one year after the date of the consummation of
the Exchange Offer ESI Tractebel Acquisition will use its best efforts to
maintain the Registration Statement of which this Prospectus is a part
continuously effective. ESI Tractebel Acquisition and NE LP have agreed to pay
all expenses incident to the performance of their obligation to effect the
Exchange Offer other than commissions or concessions of any brokers or dealers
and will indemnify certain holders of New Securities against certain liabilities
arising from resales of the New Securities pursuant to this Prospectus and any
amendment or supplement to this Prospectus, including liabilities under the 1933
Act.
LEGAL MATTERS
The validity of the New Securities and certain other legal matters in
connection with the offering of the New Securities are being passed upon for ESI
Tractebel Acquisition and NE LP by Orrick, Herrington & Sutcliffe LLP as special
counsel for ESI Tractebel Acquisition and NE LP.
142
EXPERTS
The combined financial statements of the Partnerships as of December
31, 1996 and 1997 and for each of the three years in the period ended December
31, 1997 included in this Prospectus have been so included in reliance on the
report of Price Waterhouse LLP, independent accountants, given on the authority
of said firm as experts in auditing and accounting.
Sargent & Lundy has prepared the Independent Engineer's Report included
as Appendix B to this Prospectus. The Independent Engineer's Report should be
read in its entirety for additional information with respect to the Projects and
the related subjects discussed therein. As stated in the Independent Engineer's
Report, Sargent & Lundy has made a number of assumptions in reaching its
conclusions, all of which are set forth therein, and has utilized the sources of
information described therein. Sargent & Lundy believes that the use of such
information and assumptions is reasonable for the purposes of its Independent
Engineer's Report. The Independent Engineer's Report has been included in this
Prospectus in reliance upon the conclusions therein of Sargent & Lundy and upon
such firm's experience in preparing independent engineer's reports for similar
projects.
The Fuel Consultant's Report on the Projects included as Appendix C to
this Prospectus has been prepared by Benjamin Schlesinger and Associates, Inc.
and is included herein in reliance upon the authority of such firm and its
affiliates as experts in fuel supply arrangements.
TRUSTEE
State Street Bank and Trust Company, the trustee under the Indenture
and the Collateral Agent under the Pledge Agreements, is also the Project
Trustee and the Collateral Agent in connection with the Project Securities.
State Street is also acting as the Exchange Agent in connection with the
Exchange Offer. Broad Street Contract Services, Inc., an affiliate of State
Street Bank & Trust Company, owns 25% of the outstanding shares of stock of ESI
Tractebel Funding, the issuer of the Project Securities for the purpose of
providing an independent director. Broad Street has no economic interest in the
cash flow of the Partnerships. Broad Street Contract Services, Inc. receives a
fee for its services.
143
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP; AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
INDEX TO FINANCIAL STATEMENTS
Page
----
Northeast Energy Associates, A Limited Partnership, and North Jersey Energy
Associates, A Limited Partnership
Report of Independent Accountants F-2
Combined Balance Sheet at December 31, 1996 and 1997 F-3
Combined Statement of Operations for the years ended December 31,
1995, 1996 and 1997 F-4
Combined Statement of Partners' Deficit for the years ended December 31,
1995, 1996 and 1997 F-5
Combined Statement of Cash Flows for the years ended December 31, 1995, 1996
and 1997 F-6
Notes to Combined Financial Statements F-8
F-1
Report of Independent Accountants
To the Partners of Northeast Energy Associates, A Limited Partnership,
and North Jersey Energy Associates, A Limited Partnership
In our opinion, the accompanying combined balance sheet and the related combined
statements of operations, of partners' deficit and of cash flows present fairly,
in all material respects, the financial position of Northeast Energy Associates,
A Limited Partnership, and North Jersey Energy Associates, A Limited
Partnership, at December 31, 1996 and 1997, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1997, in conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Partnerships' managements;
our responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards 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 audits provide a reasonable basis for the opinion expressed
above.
Price Waterhouse LLP
Boston, Massachusetts
March 24, 1998
F-2
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Combined Balance Sheet
- -------------------------------------------------------------------------------
December 31,
----------------------
1996 1997
---- ----
(In thousands)
Assets
Current assets:
Cash and cash equivalents $ 49,861 $61,203
Accounts receivable 43,671 34,036
Fuel inventories 5,410 4,752
Prepaid expenses and other current assets 2,566 3,052
-------- --------
Total current assets 101,508 103,043
-------- --------
Cogeneration facilities and carbon dioxide facility (net of accumulated
depreciation of $129,068,000 and $153,963,000 at December 31, 1996 and
1997, respectively) 373,781 349,365
Other fixed assets (net of accumulated depreciation of $438,000 and
$535,000 at December 31, 1996 and 1997, respectively) 304 181
Unamortized financing costs 17,837 15,674
Other assets 3,806 4,012
Restricted cash 69,156 69,156
-------- --------
Total non-current assets 464,884 438,388
-------- --------
Total assets $566,392 $541,431
======== ========
Liabilities and Partners' Deficit
Current liabilities:
Current portion of loans payable - ESI Tracetebel Funding Corp. $ 24,075 $21,563
(formerly IEC Funding Corp.)
Accounts payable 14,528 15,450
Other accrued expenses 2,037 1,426
Future obligations under interest rate swap agreements 2,022 889
-------- --------
Total current liabilities 42,662 39,328
-------- --------
Loans payable - ESI Tracetebel Funding Corp. 490,287 468,724
(formerly IEC Funding Corp.)
Amounts due utilities for energy bank balances 220,922 230,565
-------- --------
Total non-current liabilities 711,209 699,289
-------- --------
Total liabilities 753,871 738,617
-------- --------
Partners' deficit:
General partner (4,616) (4,714)
Limited partners (182,863) (192,472)
-------- --------
Total partners' deficit (187,479) (197,186)
-------- --------
Commitments and contingencies (Note 6) - -
-------- --------
Total liabilities and partners' deficit $566,392 $541,431
======== ========
The accompanying notes are an integral part of these financial statements.
F-3
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Combined Statement of Operations
- -------------------------------------------------------------------------------
For the year ended December 31,
---------------------------------------
1995 1996 1997
---- ---- ----
(In thousands)
Revenue:
Power sales to utilities $276,022 $267,789 $307,530
Steam sales 4,527 4,473 4,624
-------- -------- --------
Total revenue 280,549 272,262 312,154
-------- -------- --------
Costs and expenses:
Cost of power and steam sales 132,839 138,727 151,476
Operation and maintenance 24,699 22,854 25,689
Depreciation 24,904 24,978 24,992
General and administrative expenses 12,010 14,424 15,984
-------- -------- --------
Total costs and expenses 194,452 200,983 218,141
-------- -------- --------
Operating income 86,097 71,279 94,013
-------- -------- --------
Other expenses (income):
Amortization of financing costs 2,305 2,373 2,163
Interest expense 50,930 49,841 47,673
Interest expense on energy bank balances 16,657 19,675 17,435
Interest income (10,652) (10,534) (9,931)
-------- -------- --------
Total other expenses, net 59,240 61,355 57,340
-------- -------- --------
Net income $26,857 $9,924 $36,673
======== ======== ========
The accompanying notes are an integral part of these financial statements.
F-4
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Combined Statement of Partners' Deficit
- -------------------------------------------------------------------------------
General Limited Partners'
Partner Partners Deficit
------- -------- -------
(In thousands)
Balance at December 31, 1994 $ (3,670) $ (89,258) $ (92,928)
Net income 268 26,589 26,857
Distribution to partners (645) (63,861) (64,506)
--------- ---------- ----------
Balance at December 31, 1995 (4,047) (126,530) (130,577)
Net income 99 9,825 9,924
Distribution to partners (668) (66,158) (66,826)
--------- ---------- ----------
Balance at December 31, 1996 (4,616) (182,863) (187,479)
Net income 366 36,307 36,673
Distribution to partners (464) (45,916) (46,380)
--------- ---------- ----------
Balance at December 31, 1997 $ (4,714) $ (192,472) ($197,186)
========= ========== ==========
The accompanying notes are an integral part of these financial statements.
F-5
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Combined Statement of Cash Flows
- --------------------------------------------------------------------------------
For the year ended December 31,
--------------------------------------------
Increase (Decrease) in Cash and Cash Equivalents 1995 1996 1997
---- ---- ----
(In thousands)
Cash flows from operating activities:
Cash received from utilities and other customers $287,638 $294,942 $314,293
Cash paid to suppliers (164,875) (170,531) (184,234)
Interest paid (53,869) (51,435) (48,794)
Bank commitment fees paid (38) (38) (37)
Interest received 8,854 10,807 9,602
Cash payments to general partner for operating activities (2,914) (5,031) (4,897)
Cash payments to owners/management (3,566) (3,688) (3,758)
-------- -------- --------
Net cash provided by operating activities 71,230 75,026 82,175
-------- -------- --------
Cash flows from investing activities:
Net expenditures for facilities (1,885) (808) (334)
Expenditures for other fixed assets (76) (16) (44)
Decrease in restricted cash 3,432 9,412 --
-------- -------- --------
Net cash provided by (used for) investing activities 1,471 8,588 (378)
-------- -------- --------
Cash flows from financing activities:
Principal payments on debt (20,434) (25,204) (24,075)
Payment of financing costs (5,739) -- --
Distributions to partners (64,506) (66,826) (46,380)
-------- -------- --------
Net cash used for financing activities (90,679) (92,030) (70,455)
-------- -------- --------
Net (decrease) increase in cash and cash equivalents (17,978) (8,416) 11,342
Cash and cash equivalents at beginning of year 76,255 58,277 49,861
-------- -------- --------
Cash and cash equivalents at end of year $58,277 $49,861 $61,203
======== ======== ========
Non-cash Investing Activities
In 1996 and 1997, total capitalized facility costs which were accrued at year
end for payment were approximately $165,000 and $240,000, respectively.
The accompanying notes are an integral part of these financial statements.
F-6
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Combined Statement of Cash Flows (continued)
- --------------------------------------------------------------------------------
For the year ended December 31,
--------------------------------------------------
Increase (Decrease) in Cash and Cash Equivalents 1995 1996 1997
---- ---- ----
(In thousands)
Reconciliation of Net Income to Net Cash Provided by
Operating Activities
Net income $ 26,857 $ 9,924 $ 36,673
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation 24,904 24,978 24,992
Amortization of financing costs 2,305 2,373 2,163
(Increase) decrease in accounts receivable (11,346) 7,794 9,635
(Increase) decrease in fuel inventories 0 (894) 658
(Increase) decrease in prepaid expenses
and other current assets (1,765) 347 (486)
Increase in accounts payable 633 129 847
Increase (decrease) in other accrued expenses 651 (67) (611)
(Decrease) in future obligations
under interest rate swap agreements (2,771) (1,632) (1,133)
Increase in amounts due utilities for energy
bank balances 32,557 32,869 9,643
(Increase) in other assets (795) (795) (206)
--------- --------- ---------
Net cash provided by operating activities $ 71,230 $ 75,026 $ 82,175
========= ========= =========
The accompanying notes are an integral part of these financial statements.
F-7
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
1. Nature of Business
The enactment in 1978 of the Public Utility Regulatory Policies Act
("PURPA") and the adoption of the regulations thereunder by the Federal
Energy Regulatory Commission ("FERC") provided incentives for the
independent development of power production facilities, such as
cogeneration, by requiring electric utilities to purchase power
generated by qualifying facilities.
Northeast Energy Associates, A Limited Partnership, ("NEA") and North
Jersey Energy Associates, A Limited Partnership, ("NJEA") (or together,
the "Partnerships") operate in the independent power industry. The
Partnerships were organized to develop, finance, construct, own, manage
and operate two 300 megawatt ("MW") natural gas-fueled cogeneration
facilities, one in Bellingham, Massachusetts and one in Sayreville, New
Jersey. The Partnerships have been granted permission by FERC to
operate the cogeneration facilities as qualifying facilities defined in
PURPA and as defined in federal regulations.
Through January 14, 1998, the general partner of each of the
Partnerships was Intercontinental Energy Corporation ("IEC"), a
Massachusetts corporation. IEC owned a one percent interest in each
partnership and the individual stockholders of the general partner
collectively owned the majority of the remaining partnership interests.
On January 14, 1998, all of the partner interests in the Partnerships
were acquired (Note 10).
The partners share profits and losses and have interests in assets and
liabilities and cash flows in proportion to their tax basis capital
accounts. Distributions to the partners may be made only after all
required funds and subfunds have been fully funded, as described in the
trust indenture (Note 5).
Cash Allocations Upon Disposition or Refinancing
In the absence of any dissolution events, the Partnerships shall
continue in existence until December 31, 2025 or thereafter, if so
determined by the majority of partners. Proceeds upon liquidation or
refinancing of partnership property would be apportioned on the
following basis:
1. Expenses of liquidation;
2. Third party debts and obligations;
3. To partners in proportion to their designated interests in the
Partnerships.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying combined financial statements include the accounts of
NEA and NJEA and are combined based on common ownership. All
transactions between NEA and NJEA have been eliminated in these
combined financial statements.
F-8
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
Cogeneration Facilities and Carbon Dioxide Facility
The cogeneration facilities and the carbon dioxide facility are stated
at cost. Cost includes initial acquisition costs increased by
subsequent development and construction costs, including developer fees
and construction management fees, interest expense and amortization of
project loan acquisition costs incurred during the construction period,
and continuing facility improvements. Capitalized facility costs are
being depreciated using the straight-line method over the estimated
useful life of each facility of 20 years.
Unamortized Financing Costs
Unamortized financing costs consist primarily of investment banking
fees, legal fees and other costs associated with the placement of
securities (Note 5). In May 1995, the Partnerships paid a $5,600,000
restructuring fee, out of excess cash flow, to the general partner in
connection with the refinancing (Note 5) equal to 1% of the total
refinancing. These costs are being amortized over the approximate
15-year term of the securities using the interest method. Unamortized
financing costs are net of accumulated amortization of $4,845,000 and
$7,008,000 at December 31, 1996 and 1997, respectively.
Other Fixed Assets
Other fixed assets consist primarily of furniture, office equipment and
leasehold improvements and are depreciated using the straight-line
method over estimated useful lives ranging from 3-7 years.
Inventories
Inventories consist of natural gas and fuel oil and are stated at the
lower of cost, determined on a first-in, first-out (FIFO) basis, or
market.
Interest Rate Swap Agreements
Notional principal amounts in contracts and related settlement gains
and losses on interest rate swap agreements are allocated to the
Partnerships based on the relative amounts of outstanding borrowings of
each partnership on the date on which the swap agreements were
contracted. Prior to the refinancing (Note 5), gains and losses, based
on the amount the Partnerships were entitled to receive or required to
pay for additional interest, were determined at each calendar
quarter-end based on the outstanding notional balance and the amount by
which the contractual fixed rate exceeded or was less than the
contractual variable rate. Such gains and losses were recognized as
adjustments to interest expense. Subsequent to the refinancing (Note
5), the net payments required pursuant to all swap agreements and the
change in the fair value of the swap agreements are recognized as
adjustments to interest expense. The fair value of the swap agreements
is recorded as a current liability. See Notes 5 and 9 for further
disclosure regarding interest rate swap agreements.
Natural Gas Hedging Instruments
Premiums paid for natural gas call options are deferred within other
current assets and are accounted for in conjunction with the underlying
natural gas purchases at which point the premiums are written off to,
and any resultant gains credited to, cost of power and steam sales.
Gains and losses on natural gas purchase swap agreements are recognized
as adjustments to cost of power and steam sales at monthly settlement
dates. Purchases of natural gas under forward purchase agreements are
accounted for as cost of power and steam sales at their contract price
at the time of delivery. See Note 9 for further disclosure regarding
natural gas hedging instruments.
F-9
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
Revenue Recognition
Revenue from power sales is recognized in accordance with Emerging
Issues Task Force Issue No. 91-6, "Revenue Recognition of Long-Term
Power Sales Contacts." Revenue is recognized based on power delivered
at rates stipulated in power sales agreements, except that revenue is
deferred to the extent that stipulated rates are in excess of amounts,
either scheduled or specified, in the agreements. The excess amounts
deferred are accumulated in energy banks and are reflected as amounts
due utilities for energy bank balances on the combined balance sheet.
Revenue from steam sales is recognized upon delivery of the steam.
Income Taxes
The partners are required to report their respective shares of the
Partnerships' taxable income or losses in their income tax returns and
are liable for any related taxes thereon. Accordingly, no provision for
income taxes is made in the combined financial statements of the
Partnerships.
The Partnerships' net assets and liabilities for financial reporting
purposes exceeded the net assets and liabilities for tax purposes by
approximately $41.6 million and $41.5 million at December 31, 1996 and
1997, respectively.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.
3. Cash and Cash Equivalents and Restricted Cash
The Partnerships consider all investments purchased with an original
maturity of three months or less to be cash equivalents. The
Partnerships invest excess cash in high grade money market accounts and
commercial paper with original maturities less than three months.
Accordingly, the investments are subject to minimal credit and market
risk and are considered by the Partnerships to be cash equivalents. At
December 31, 1996 and 1997, all of the Partnerships' cash equivalents
are classified as held-to-maturity and recorded at amortized cost,
which approximates fair value.
Restricted cash at December 31, 1996 and 1997 represents cash reserved
as collateral for letters of credit related to energy bank balances
(Note 6). This cash is invested with a bank in a fixed-rate investment
agreement. Subsequent to the acquisition on January 14, 1998 of all of
the partner interests in the Partnerships, the cash collateral
requirement related to the energy bank balances was terminated in
exchange for the guarantee of one of the acquiring entities (Note 10).
4. Cogeneration Facilities and Carbon Dioxide Facility
Cogeneration Facilities
Cogeneration facilities consist of costs incurred to develop and
construct two gas-fueled cogeneration plants with maximum output
capacities of any combination of electricity and steam equivalent to
approximately 600 MW in the aggregate.
F-10
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
Facility Sites
The facility owned by NEA is constructed on four parcels of land of
approximately 44 acres in Bellingham, Massachusetts. Three of the
parcels were acquired under various purchase and sale agreements. The
remaining parcel of land was acquired under a 26-year operating lease
agreement entered into in 1986 between NEA and a local developer. The
lease may be extended for another 25 years at the option of NEA. The
agreement provides for an annual lease payment of $60,000 from the date
of the agreement increasing annually thereafter by $12,000 (Note 6).
The facility owned by NJEA is constructed on two parcels of land of
approximately 49 acres acquired under various purchase and sale
agreements.
Power Sale Agreements
Commencing in 1986, NEA entered into five power sale agreements with
three major Massachusetts utilities to sell approximately 290 MW at
initial floor prices per kilowatt hour ("Kwh"), subject to adjustment
based on actual volumes of electricity purchased, escalation factors
and other conditions. Performance under certain of these power sale
agreements is secured by a second mortgage on the Bellingham facility.
In 1987, NJEA entered into an agreement with a major New Jersey utility
to sell 250 MW at an initial fixed price per Kwh subject to
adjustments, as defined in the agreement. These power sale agreements
have terms ranging from 20 to 30 years. All of the Partnerships' power
sales to utilities are generated through these arrangements. As such,
the Partnerships are directly affected by changes in the power
generation industry. Substantially all of the Partnerships' accounts
receivable are with utilities located in the Northeast portion of the
United States. The Partnerships do not require collateral or other
security to support their receivables. However, management does not
believe significant credit risk exists at December 31, 1997. Sales to
significant customers are as follows:
During the year ended December 31, 1995, revenue from two different
utilities totaled approximately $132.1 million and $118.3 million, or
approximately 47% and 42% of revenue, respectively.
During the year ended December 31, 1996, revenue from two different
utilities totaled approximately $122.3 million and $121.5 million, or
approximately 45% and 44% of revenue, respectively.
During the year ended December 31, 1997, revenue from two different
utilities totaled approximately $142.4 million and $123.6 million, or
approximately 46% and 40% of revenue, respectively.
Certain agreements require the establishment of suspense accounts
("energy banks") to record cumulative payments made by the utilities in
excess of avoided cost rates scheduled or specified in such agreements.
Some energy banks bear interest at various rates specified in the
agreements. A positive energy bank balance represents a liability of
the applicable Partnership to the applicable power purchaser which will
be reduced by subsequent sales of electric power to such power
purchaser to the extent that in later periods the avoided cost rates
scheduled or specified in such agreements rise above contract rates.
For certain agreements requiring the establishment of energy banks, the
Partnerships are required to provide collateral based on energy bank
balances (Note 6).
F-11
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
On November 25, 1997, the Massachusetts legislature passed a
comprehensive electric deregulation bill, the purpose of which is to
establish a comprehensive framework for the restructuring of the
electric utility industry. Additionally, industry efforts are also
underway in New Jersey. While the Partnerships' do not expect electric
utility industry restructuring to result in material adverse changes to
the Partnerships' Power Purchase Agreements, the impact of electric
utility industry restructuring on the companies that purchase power
from the Partnerships is uncertain.
Steam Sales Agreements and Carbon Dioxide Facility
In order for the Partnerships' facilities to maintain the status as
qualifying facilities under PURPA, the facilities are required to
generate five percent of total energy output as steam for sale to
unrelated third parties.
In 1989, NEA entered into a 25-year steam sales contract with a
processor and seller of carbon dioxide. Pursuant to this agreement, NEA
sells all the steam generated by the Bellingham facility at a price
which fluctuates based on changes in the price of a specified grade of
fuel oil.
This agreement can be extended at the option of the steam user. In
conjunction with this contract, NEA has constructed a carbon dioxide
facility and, in 1989, entered into a 15-year agreement to lease the
facility to the steam user. Base rent under the terms of the lease is
$100,000 per month, adjusted by the operating results of the carbon
dioxide facility for each month as outlined in the lease agreement.
Additionally, NEA pays the steam user $100,000 annually for
administrative services rendered related to the operation of the carbon
dioxide facility. NEA does not operate the carbon dioxide facility.
In 1989, NJEA entered into a 20-year steam sales contract with a steam
user adjacent to the Sayreville facility. Under the terms of this
agreement, NJEA sells a specified maximum quantity of steam at a floor
price which can increase based on changes in prices of coal. This
agreement automatically renews for two consecutive five year terms
unless either party gives notice not to renew two years before the
expiration of each of the prior terms.
Fuel Supply, Transportation and Storage Agreements
Natural gas is provided to the facilities primarily under long-term
contracts for supply, transportation and storage. The remaining fuel
requirements of the facilities are provided under short-term "spot"
arrangements. The long-term natural gas supply is provided under
contracts with ProGas Limited ("ProGas"), a Canadian gas marketing
company, and Public Service Electric and Gas Company ("PSE&G"), a
domestic retail gas distribution company. Transportation of the natural
gas is provided by various pipeline companies, including CNG
Transmission Company ("CNG"), Transcontinental Gas Pipe Line
Corporation ("Transco") and Algonquin Gas Transmission Company
("Algonquin"). Gas storage agreements provide contractual arrangements
for the storage of limited volumes of natural gas with third parties
for future delivery to the projects.
The ProGas contracts commenced in 1991. The initial terms of these
contracts of 15 years were extended an additional seven years effective
in 1994. Under the ProGas contracts, ProGas is required to arrange for
the aggregation, gathering and transportation of gas from Alberta,
Canada to the U.S. pipeline at Niagara, New York. The maximum total
volumes of gas to be delivered under these contracts are approximately
48,800 and 22,000 MMBtu per day for NEA and NJEA,
F-12
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
respectively. The contract price of the ProGas supply delivered to the
import point, inclusive of transportation costs to that point, is
determined with reference to a "base price" in 1990, redetermined
annually thereafter based on specified inflation indices. The PSE&G
contract commenced in 1991. Under the PSE&G agreement, PSE&G will sell
and deliver to NJEA up to 25,000 MMBtu per day of gas for a term of 20
years. The contract price of the PSE&G fuel is established monthly
using a contractually specified mechanism.
With the exception of the PSE&G arrangement, all of the Partnerships'
long-term contractual arrangements call for monthly "demand charge"
payments. These demand charge payments, which are to reserve certain
pipeline transportation capacity, are made regardless of the
facilities' specific fuel requirements in any month and regardless of
whether the facilities utilize the capacity reserved under the
contracts. These demand charges totaled approximately $49 million, $48
million and $46 million in 1995, 1996 and 1997, respectively, and total
payments under such contracts were approximately $98.3 million, $100.5
million and $112.5 million in 1995, 1996 and 1997, respectively,
inclusive of demand charges. Under 1997 pricing conditions, the demand
charge payments would be approximately $46 million under these
contracts for each of the next five years and approximately $723
million over the remaining life of these contracts. Total charges under
the contract with PSE&G, including transportation costs, during 1995,
1996 and 1997, were approximately $24.3 million , $32.4 million and
$28.1 million, respectively. In the event that the available capacity
under these agreements is not utilized by the operations of the
facilities, the Partnerships have the opportunity under certain of
these contractual agreements to sell unused capacity to third parties,
but have not yet done so.
NEA's facility also has the capability to burn #2 fuel oil. Fuel oil
was obtained and is stored on site for contingency supply for the
facility.
5. Loans Payable
In 1989, as amended in 1990, 1991 and 1992, the Partnerships, together
with the general partner, executed a project loan and credit agreement
with a group of banks for a maximum commitment of $600,000,000 for the
construction and development of the Bellingham and Sayreville
facilities and initial working capital and letters of credit facility.
On December 1, 1994, the Partnerships refinanced their existing
borrowings by means of a placement of securities to qualified
institutional investors as defined in Rule 144A of the Securities Act
of 1933 ("Rule 144A"). Borrowings outstanding are as follows:
December 31,
---------------------------
1996 1997
---- ----
8.43% Senior Secured Notes Due 2000 $95,482,000 $71,407,000
9.16% Senior Secured Notes Due 2002 31,500,000 31,500,000
9.32% Senior Secured Bonds Due 2007 215,740,000 215,740,000
9.77% Senior Secured Bonds Due 2010 171,640,000 171,640,000
------------ ------------
$514,362,000 $490,287,000
============ ============
F-13
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
The above securities were issued through a special purpose funding
corporation, IEC Funding Corp., established solely for the purpose of
issuing the securities, and are unconditionally guaranteed, jointly and
severally, by the Partnerships. Effective February 10, 1995, IEC
Funding Corp. filed a Registration Statement on Form S-4 with the
Securities and Exchange Commission for purposes of effecting a public
exchange offer whereby the securities listed above were exchanged for a
new issue of securities (the "Securities"). The Securities have terms
identical to the securities issued in accordance with Rule 144A.
Subsequent to the acquisition discussed in Note 10, IEC Funding Corp.
changed its name to ESI Tractebel Funding Corp.
Interest on the Securities is payable semiannually on each June 30 and
December 30, commencing December 30, 1994. Principal repayments, which
commenced on June 30, 1995, are made semiannually in amounts stipulated
in the trust indenture.
Future principal payments are as follows:
Year ending December 31,
------------------------
1998 $ 21,563,000
1999 23,511,000
2000 26,333,000
2001 20,160,000
2002 22,688,000
Thereafter 376,032,000
------------
$490,287,000
============
The Securities are not subject to optional redemption but are subject
to mandatory redemption in certain limited circumstances involving the
occurrence of an event of loss, as defined in the trust indenture, for
which the Partnerships fail to or are unable to restore a facility.
Additionally, the Partnerships may, at their option, repurchase all or
part of the Securities with proceeds received from the release of cash
collateral maintained as security for letters of credit (Note 6).
The proceeds of the Securities were used (a) to purchase the notes
outstanding under the original loan and credit agreement and (b) to
make loans to the Partnerships. In connection with these two
transactions, the notes outstanding under the loan and credit agreement
were surrendered and new notes of the Partnerships were issued to ESI
Tractebel Funding Corp. (formerly IEC Funding Corp.) in an aggregate
principal amount equal to the aggregate principal amount of the
Securities (the "New Notes") and the loan and credit agreement was
assigned to ESI Tractebel Funding Corp. (formerly IEC Funding Corp.)
and amended and restated (the "Amended and Restated Credit Agreement").
Borrowings are secured by a lien on, and a security interest in,
substantially all of the assets of the Partnerships. Under the Amended
and Restated Credit Agreement, the Partnerships are jointly and
severally required to make scheduled payments on the New Notes on dates
and in amounts identical to the scheduled payments of principal and
interest on the Securities. The Securities, the guarantees thereon
provided by the Partnerships and the New Notes are nonrecourse to the
partners of the Partnerships and are payable solely from the collateral
pledged as security.
F-14
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
Under the terms of the trust indenture governing the Securities, the
Partnerships are required to establish certain funds and subfunds,
which must be fully funded before any distributions can be made to
partners. The funding requirements of these funds are defined in the
trust indenture. Cash within these funds can be drawn currently if
funds in the Partnerships' other cash accounts are insufficient to meet
operational cash requirements. The order in which these funds may be
drawn is described in the trust indenture. Funds available for
distribution to partners as of December 31, 1997 have been paid.
The trust indenture contains certain restrictions on certain activities
of the Partnerships, including the incurrence of additional
indebtedness or liens, the payment of distributions to the partners,
the cancellation of power sale and fuel supply agreements, the use of
proceeds from the issuance of the Securities and the execution of
mergers, consolidations and sales of assets.
The trust indenture allows the Partnerships to enter into revolving
credit agreements of up to $20 million in order to provide for working
capital requirements. The Partnerships have entered into an initial
working capital facility of $15 million with a bank. Available
borrowings under the working capital facility are calculated based on
outstanding receivables and fuel inventories. The Partnerships are
required to pay an annual agency fee of $25,000 and quarterly
commitment fees at an annual rate of .25% on the unused portion of the
facility. At December 31, 1996 and 1997, no borrowings were outstanding
under this working capital facility. Subsequent to the acquisition on
January 14, 1998 of all of the partner interests in the Partnerships,
this working capital facility was terminated (Note 10).
Under the terms of the original loan and credit agreement, the
Partnerships were required to enter into interest rate swap agreements
("Swaps") with certain financial institutions, providing for payments
thereunder on a notional principal amount of indebtedness to be made by
the Partnerships at fixed interest rates in exchange for payments to be
made by such financial institutions at floating interest rates. Such
existing Swaps remained in effect after the issuance of the Securities.
In connection with the issuance of the Securities, the Partnerships
entered into counter swap agreements in order to hedge the obligations
of the Partnerships under such existing Swaps. As a result of the
foregoing arrangements, after giving effect to the net payments to be
made and received by the Partnerships pursuant to all of the Swaps, the
Partnerships' net payments pursuant to the Swaps were equivalent to a
fixed net interest rate of approximately 1.35% on the original
specified notional principal amount, which was scheduled to decline
periodically until the scheduled expiration of the Swaps in 1999. The
Partnerships are jointly and severally liable under these agreements.
The Partnerships' exposure to interest rate fluctuations could increase
in the event of nonperformance by the bank who is party to the interest
rate swap agreements; however, the Partnerships do not anticipate
nonperformance by the bank. See Note 9 for additional information
regarding interest rate swap agreements.
As a result of the refinancing described above, the original Swaps no
longer qualify as hedges and, therefore, must be recorded at fair
value. Changes in fair value are recognized in the combined statement
of operations. See Note 9 for information regarding fair value of
financial instruments.
F-15
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
6. Commitments and Contingencies
See Note 4 for information regarding additional commitments and
contingencies.
Energy Bank Collateral
Under the terms of the trust indenture, the Partnerships are required
to maintain a letter of credit facility to secure obligations for
energy bank balances under the various power purchase agreements (Note
4). During December 1994, the Partnerships entered into an agreement
with a bank for a letter of credit facility to issue up to an aggregate
amount of $82 million in letters of credit. This facility contains a
cross-default provision to the trust indenture, as well as a payment
default under the working capital facility (Note 5). The Partnerships
pay quarterly fees on this letter of credit facility at an annual rate
of .30% on outstanding letters of credit and unused commitments to
issue letters of credit. As of December 31, 1996 and 1997, the
Partnerships' obligation for letters of credit outstanding under this
facility is $68,656,000 and $67,656,000, respectively. The Partnerships
are required to provide cash collateral for the maximum amount of
obligations allowed under the terms of this facility. As of December
31, 1996 and 1997, the Partnerships reserved $69,156,000 in cash as
collateral for such obligations (Note 3). Subsequent to the acquisition
on January 14, 1998 of all of the partner interests in the
Partnerships, the cash collateral requirement was terminated in
exchange for the guarantee of one of the acquiring entities; also, the
letters of credit facility was replaced with letters of credit from
other financial institutions (Note 10).
Operation and Maintenance of the Cogeneration Facilities In 1989, the
Partnerships entered into two separate ten year operation and
maintenance agreements with the same contractor responsible for
constructing and installing the combined-cycle cogeneration plants for
both facilities for an aggregate annual consideration of approximately
$11,100,000 subject to changes in specified indices. The agreements
commenced during 1991 after the facilities became operational. The
Partnerships each have an option to enter into a successor operation
and maintenance agreement with the contractor for a ten year term
following the expiration of the term of the original agreement, on
either a cost plus payment basis or a fixed fee payment basis to be
negotiated at the time of the operation exercise.
Under the terms of these agreements, the Partnerships are required to
pay the operation and maintenance contractor a bonus payable annually
over the term of the agreement, based on operating performance for each
year ending on the anniversary of the respective commencement of
operations (September 1, 1991 for NJEA and October 1, 1991 for NEA).
The Partnerships incurred $5,375,000, $3,482,000 and $5,823,000 related
to this bonus in 1995, 1996 and 1997, respectively.
During 1993, the Partnerships entered into a revised ten year heat rate
bonus agreement with the operation and maintenance contractor. Under
the terms of this agreement, the total bonus to be earned over the ten
year period is $11 million, subject to the continued satisfaction of
specified minimum performance standards. The agreement provides that
this amount will be paid to the contractor over the first five years of
the agreement. The agreement also provides that amounts paid under the
former heat rate bonus agreement during 1992 would be applied as
payments under the revised agreement. Total payments made under this
agreement were $1,854,000 in each of 1995, 1996 and 1997. Amounts
expensed under this heat rate bonus agreement were $1,060,000 in each
of 1995, 1996 and 1997.
F-16
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
Operating Lease
Lease payments under the operating lease for the land in Bellingham,
Massachusetts (Note 4) are as follows:
Year ending December 31,
------------------------
1998 $ 189,000
1999 201,000
2000 213,000
2001 225,000
2002 237,000
Thereafter 2,760,000
------------
$ 3,825,000
============
During 1995, 1996 and 1997, NEA paid and expensed $153,000, $165,000
and $177,000, respectively, under this agreement.
7. Employee Savings Plan
Effective January 1, 1991, the general partner (IEC) adopted a defined
contribution employee savings plan qualifying under Section 401(k) of
the Internal Revenue Code. Pursuant to the plan, the general partner
fully matches contributions made by eligible employees to the plan up
to 5% of an employee's base compensation. Contributions made by the
general partner become fully vested after four years of continuous
service. In addition, employees may contribute up to an additional 5%
of base compensation which is not matched by the general partner.
During 1995, 1996 and 1997, the Partnerships were charged $78,000,
$90,000 and $156,000, respectively, for their shares of contributions
made by the general partner to this plan (Note 8).
8. Other Related Party Transactions
Subsequent to the commencement of operations of the Partnerships, the
general partner began to pay certain expenses as a convenience for the
Partnerships. These expenses are reimbursed to the general partner at
cost. The following represents the activity between the Partnerships
and the general partner for the years ended December 31, 1995, 1996 and
1997:
F-17
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- -------------------------------------------------------------------------------
For the year ended December 31, 1995: NEA NJEA
--- ----
Expenses paid by the general partner
Payroll and related expenses $1,053,000 $878,000
Travel 76,000 76,000
Office space and utilities 126,000 125,000
Professional fees, insurance and other 424,000 413,000
---------- ---------
1,679,000 1,492,000
Payments to the general partner 1,457,000 1,457,000
---------- ---------
Payments in excess of expenses (222,000) (35,000)
Due from (to) general partner, December 31, 1994 133,000 13,000
---------- ---------
Due from (to) general partner, December 31, 1995 ($89,000) ($22,000)
========== =========
For the year ended December 31, 1996:
Expenses paid by the general partner
Payroll and related expenses $1,364,000 $1,311,000
Travel 95,000 95,000
Office space and utilities 128,000 128,000
Professional fees, insurance and other 827,000 830,000
---------- ----------
2,414,000 2,364,000
Payments to the general partner 2,541,000 2,490,000
---------- ----------
Payments in excess of expenses 127,000 126,000
Due from (to) general partner, December 31, 1995 (89,000) (22,000)
---------- ----------
Due from (to) general partner, December 31, 1996 $ 38,000 $ 104,000
========== ==========
F-18
For the year ended December 31, 1997: NEA NJEA
--- ----
Expenses paid by the general partner
Payroll and related expenses $1,402,000 $1,332,000
Travel 88,000 88,000
Office space and utilities 168,000 168,000
Professional fees, insurance and other 934,000 816,000
---------- ----------
2,592,000 2,404,000
Payments to the general partner 2,483,000 2,414,000
---------- ----------
Payments in excess of expenses (109,000) 10,000
Due from (to) general partner, December 31, 1996 38,000 104,000
---------- ----------
Due from (to) general partner, December 31, 1997 $ (71,000) $ 114,000
=========== ==========
9. Financial Instruments
The Partnerships have made use of derivative financial instruments to
hedge their exposure to fluctuations in both interest rates and the
purchase price of natural gas.
Under the project loan and credit agreement, the Partnerships were
required to enter into fixed interest rate swap agreements as a means
of managing exposure to the variable rate interest of the original
Partnerships borrowings. In conjunction with the refinancing, the
Partnerships entered into counter swap agreements so that the
Partnerships would no longer be exposed to changes in interest rates
(Note 5).
The prices received by the Partnerships for power sales under their
long-term sales contracts do not move precisely in tandem with the
prices paid by the Partnerships for natural gas. In order to mitigate
the price risk associated with purchases of natural gas, the
Partnerships may, from time to time, enter into certain hedging
transactions either through public exchanges such as the NYMEX, or by
means of over-the-counter transactions with specific counterparties.
The Partnerships hedge purchases of natural gas through the use of (a)
natural gas call options that give the Partnerships the right, but not
the obligation, to purchase specified quantities of natural gas at a
pre-determined price; (b) natural gas purchase swap agreements that
require the Partnerships to pay a price, fixed absolutely or within a
specified range, in return for a variable price on a notional specified
quantity of natural gas; and (c) forward purchases of natural gas.
The Partnerships control the credit risk arising from these instruments
through credit approvals, limits and monitoring procedures. There are
no significant concentrations of credit risk. The Partnerships do not
normally require collateral or other security to support financial
instruments with credit risks.
F-19
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
The following table sets forth the contract or notional amounts of
these financial instruments. While indicating the size of the
transaction entered into, the amounts do not represent the
Partnerships' exposure to loss in the event of nonperformance by the
counterparties involved. The Partnerships do not anticipate
nonperformance by the counterparties.
Contract or Contract or
notional amount notional amount
at December 31, at December 31,
1996 1997
------------------------- ---------------------------
$ MMBtu $ MMBtu
----- ----- ----- -----
Interest rate swap agreements 20,335,000 - 12,940,000 -
Gas purchase swap agreements - 28,600,000 - 21,920,000
Gas forward purchases - 418,000 - -
The net effect on interest expense due to the interest rate swap
agreements and the net gain/(loss) included in cost of power and steam
sales resulting from the gas purchase options, swap agreements and
forward purchases is as follows:
For the year ended December 31,
-------------------------------------------
1995 1996 1997
---- ---- ----
Net effect on interest expense -
(decrease) increase $(486,000) $ 137,000 $ 103,000
Net (loss)/gain included in cost of
power and steam sales (448,000) 5,246,000 3,990,000
The estimated fair value and related carrying amounts of certain
financial instruments is as follows:
December 31, 1996 December 31, 1997
----------------- -----------------
Related Related
Fair carrying Fair carrying
value amount value amount
$ $ $ $
----- -------- ----- -------
Loans payable (564,075,000) (514,362,000) (526,010,000) (490,287,000)
Restricted cash 69,156,000 69,156,000 69,156,000 69,156,000
Interest rate swap agreements (2,022,000) (2,022,000) (889,000) (889,000)
Gas purchase swap agreements 1,671,000 - 2,527,000 -
Gas forward purchases (143,000) - - -
The estimated fair values may not be representative of actual values of
the financial instruments that could have been realized as of year end
or that will be realized in the future.
F-20
Northeast Energy Associates, A Limited Partnership, and
North Jersey Energy Associates, A Limited Partnership
Notes to Combined Financial Statements
- --------------------------------------------------------------------------------
The following methods and assumptions were used to estimate the fair
values of certain instruments:
Loans payable - The fair value of loans payable at December 31, 1996
was estimated by an independent third party valuation based on the
fixed nature of the loans, the credit risk associated with such loans
and the current borrowing environment available to the Partnerships.
The estimated fair value of the loans payable at December 31, 1997 has
been determined based upon the borrowing rate (8%) currently available
to the Partnerships for debt instruments with similar terms and average
maturities.
Restricted cash - The fair value of restricted cash is estimated based
upon the fixed yield and term of the investment and rates currently
available to the Partnerships for deposits of similar maturities.
Interest rate swap agreements - The fair value of interest rate swap
agreements is the estimated amount that the banks would receive to
terminate the swap agreements, taking into account current interest
rates and the creditworthiness of the swap counterparties.
Natural gas hedging instruments - The fair value of natural gas hedging
instruments is based upon the amounts the Partnerships would be
entitled to receive or required to pay if the contracts were terminated
at the reporting date, taking into account the forward prices of
natural gas on the reporting date, the fixed purchase prices of the
contracts and the exercise dates of the contracts.
10. Subsequent Events
On January 14, 1998, pursuant to the purchase agreement dated as of
November 21, 1997, all of the partner interests in the Partnerships
were acquired by Tractebel, S.A. and FPL Group, Inc., through their
wholly owned subsidiaries, for approximately $533 million in cash and
the assumption of the Partnerships' outstanding debt. The acquisition
will be accounted for under the purchase method; accordingly, the
carrying value of the assets acquired and liabilities assumed of the
Partnerships will be adjusted based upon the final purchase price
allocation. Concurrent with and related to the acquisition of the
Partnerships, IEC Funding Corp. was also acquired and its name changed
to ESI Tractebel Funding Corp. Subsequent to the acquisition, the
working capital facility was terminated and the letters of credit
facility and the Debt Service Reserve Fund were replaced with new
letter of credit arrangements (Notes 5 and 6) and the cash collateral
requirement related to the energy bank balances was eliminated in
exchange for the guarantee of one of the acquiring entities (Note 6).
F-21
APPENDIX A
DEFINED TERMS
The following are summaries of some of the definitions used in certain
of the principal documents and in this Prospectus. This Appendix is qualified in
its entirety by reference to the project documents for the complete terms and
definitions.
"Accommodation Agreement" means the Accommodation Agreement dated as of
June 28, 1989, among NEA, Commonwealth, Boston Edison and Montaup.
"Acquisition Date" means January 14, 1998, the date of the consummation
of the Acquisitions.
"Acquisitions" means the acquisition by NE LP and NE LLC of all of the
partnership interests in NEA and NJEA and the acquisition by ESI Funding and
Tractebel Power of seventy-five percent (75%) of the outstanding capital stock
of ESI Tractebel Funding pursuant to the Purchase Agreement.
"Additional Project Securities" means any Debt of ESI Tractebel Funding
issued, subject to certain conditions set forth in the Project Indenture, to
provide a source of funds for (i) Required Improvements, (ii) cash collateral to
support Energy Bank Obligations (or to secure obligations of the Partnerships
under the Project Letter of Credit Facility with respect to Project Letters of
Credit issued to secure such Energy Bank Obligations) arising as a result of
Power Purchase Agreements (or amendments thereto) entered into after November
15, 1994 (iii) payment of fees and costs associated with the issuance of
Additional Project Securities, or (iv) funding the Debt Service Reserve Fund to
the extent that the balance in such Fund is less than the Debt Service Reserve
Requirement.
"Administrative Services Agreement" means the Administrative Services
Agreement, dated as of November 21, 1997, by and between NE LP and ESI GP.
"Administrative Services Fee" means a fee, payable monthly, equal to
$600,000 per annum, adjusted annually based on a producer price index paid by NE
LP to ESI LP as compensation for the services it performs pursuant to the
Administrative Services Agreement.
"Affiliate," as used in the Project Indenture, means, as to any Person,
any other Person directly or indirectly controlling or controlled by or under
direct or indirect common control with such specified Person. For purposes of
this definition, "control" (including, with correlative meanings, the terms
"controlling," "controlled by" and "under common control with"), as used with
respect to any Person, means the possession, directly or indirectly, of the
power to direct or cause the direction of the management or policies of such
Person, whether through the ownership of voting securities, by agreement or
otherwise; provided that the beneficial ownership of 20% or more of the Voting
Stock of a Person shall be deemed to be control.
"Aggregate Amortization Reserve Amount" means, as of any date of
determination, the sum of the Amortization Reserve Amounts as of such date in
respect of all items of Permitted Purchase Money Indebtedness and Permitted
Unsecured Indebtedness then outstanding.
"Algonquin" means Algonquin Gas Transmission Company, a Delaware
corporation.
"Avoided Cost Security" means the security granted, pursuant to the NEA
Second Mortgage, with respect to all amounts paid under the respective Power
Purchase Agreements for the NEA Project in excess of the particular mortgagee's
actual Avoided Costs, with interest thereon at the prime rate of The First
National Bank of Boston, N.A. in effect from time to time.
"Avoided Costs" means, the incremental costs to an electric utility of
electric energy or capacity or both which, but for the purchase from a
qualifying facility, such utility would generate itself or purchase from some
other source.
"Back-up Letter of Credit" as used in the Project Indenture means an
irrevocable standby letter of credit (a) issued by a commercial bank whose
long-term obligations are rated (or whose bank holding company has long-term
obligations rated) at least "A" by S&P, "A2" by Moody's or "A" by Fitch (or an
equivalent rating by another nationally recognized credit rating agency of
similar standing if two or more of such corporations are not in the business of
rating long-term obligations of commercial banks), (b) in form reasonably
acceptable to the Project Trustee, (c) with a minimum term of one (1) year (or
shorter period ending on or after the Stated Maturity of the Project
Securities), (d) for the benefit of the Project Letter of Credit Banks, (e)
which shall not be a Debt of either ESI Tractebel Acquisition or either
Partnership and shall not be secured by or otherwise encumber any of the Project
Collateral and (f) providing for the amount thereof to be available to the
Project Letter of Credit Banks in multiple drawings, including a drawing by the
Project Letter of Credit Banks in multiple drawings, including a drawing by the
Project Letter of Credit Banks in multiple drawings, including a drawing by the
Project Letter of Credit Banks (or Project Trustee or the Collateral Agent on
behalf of the Project Letter of Credit Banks) upon the receipt of notice from
the Project Letter of Credit Banks (or the Project Trustee or the Collateral
Agent) of any Event of Default and, until such time as a Back-up Letter of
Credit is not required, a drawing by the Project Letter of Credit Banks (or the
Project Trustee or the Collateral Agent on behalf of the Project Letter of
Credit Banks) at any time within 30 days prior to the expiration of such letter
of credit for the full face amount thereof in the event such letter of credit is
not renewed or substituted with one or more other Back-up Letters of Credit at
such time, conditioned in each case only upon presentment of sight drafts
accompanied by the applicable certificate in the form attached to such letter of
credit (and reasonably acceptable in form to the Project Letter of Credit Banks
and either the Project Trustee or the Collateral Agent).
"BankBoston" means BankBoston, N.A.
"BOC Gases" means the BOC Gases Division of the BOC Group, Inc., a
Delaware corporation.
"Bond Guaranty" means the guaranty to be provided on the Closing Date
by NE LP in favor of the Trustee, guaranteeing the obligations of ESI Tractebel
Acquisition under the Indenture.
"Bond Loan" means ESI Tractebel Acquisition's loan to NE LP of proceeds
received by ESI Tractebel Acquisition from the sale of the Securities.
"Boston Edison" means Boston Edison Company, a Massachusetts
corporation.
"Boston Edison I Power Purchase Agreement" means the Power Purchase
Agreement dated as of April 1, 1986, as amended on June 8, 1987 and June 21,
1989, between NEA and Boston Edison.
"Boston Edison II Power Purchase Agreement" means the Power Purchase
Agreement dated as of January 28, 1988, as amended, between NEA and Boston
Edison.
"Boston Edison Interconnection Agreement" means the Amended and
Restated Interconnection Agreement dated as of September 24, 1993, between
Boston Edison and NEA.
A-2
"Broad Street" means Broad Street Contract Service's, Inc.
"Btu" means British thermal units, a unit of energy.
"Capital Expenditures" as defined in the Project Indenture, means for
any period, expenditures (including the aggregate amount of obligations in
respect of Capital Leases (as defined in the Project Indenture) incurred during
such period) made during such period by either Partnership to acquire or
construct fixed assets, including, without limitation, plant, equipment and
fixtures (including renewals, improvements and replacements, but excluding
repairs) during such period computed in accordance with GAAP.
"Carbon Dioxide Plant" means the carbon dioxide production facility
owned by NEA and located adjacent to the NEA Project on the NEA Site and all
equipment and facilities ancillary thereto.
"Carbon Dioxide Sales Agreements" means those agreements between NECO
and BOC Gases, and NECO and Praxair, respectively, for the purchase and sale of
carbon dioxide.
"Cash Collateral Proceeds" means the cash collateral (and investments
thereof) deposited by the Partnerships to secure the Partnerships' obligations
to reimburse under the Project Letter of Credit Facility.
"Change of Control" means the occurrence of any of the following: (i)
the sale, lease, transfer, conveyance or other disposition (other than by way of
merger or consolidation) in one or a series of related transactions, of all or
substantially all of the assets of NE LP, NE LLC, NEA or NJEA to any "person" or
group (as each such term is used in section 13(d)(3) and 14(d)(2) of the
Exchange Act) other than the Sponsors or their Related Parties; (ii) the
adoption of a plan relating to the liquidation or dissolution of NE LP, NE LLC,
NEA or NJEA (other than as permitted by the Indenture); (iii) the consummation
of any transaction or series of related transactions (including without
limitation, any merger or consolidation) the result of which is that any person
or group (as defined above), other than the Sponsors and their Related Parties,
becomes the "beneficial owner" (as such term is defined in Rule 13d-3 and Rule
13d-5 under the Exchange Act, except that a person or group shall be deemed to
have "beneficial ownership" of all securities that such person or group has the
right to acquire, whether such right is currently exercisable or is exercisable
only upon the occurrence of a subsequent condition), directly or indirectly, of
more than 50% of the voting power of any general partner of NE LP, NEA or NJEA
or of the voting power of the managing member of the NE LLC by way of merger or
consolidation or otherwise other than a transaction involving an acquisition of
FLP Group or Tractebel; (iv) the consummation of any transactions or series of
related transactions the result of which is that any person or group of persons
(as defined above) other than the Sponsors and the Related Parties owns,
directly or indirectly, more of the economic and voting interests of the
Sponsors, NE LP, NE LLC, NEA or NJEA or of the voting power of the managing
member of NE LLC than do the FLP Group and Tractebel; or (v) the consummation of
any transaction or series of related transactions the result of which is that
any person or group (as defined above) other than the Sponsors and the Related
Parties owns, directly or indirectly more of the voting power of any general
partner of NE LP, NEA, or NJEA than do the Sponsors and their Related Parties;
provided that, notwithstanding the foregoing, a Change of Control will not occur
if Moody's and S&P confirm that the then existing ratings of the New Securities
will not be lowered as a result of any of the foregoing events.
"Clean Air Act" means the Federal Clean Air Act of 1955, as amended.
"Closing Date" means February 19, 1998, the date the Old Securities
were issued and delivered to Goldman.
A-3
"CNG" means CNG Transmission Corporation, a Delaware corporation.
"Collateral Agency Agreement" means the Collateral Agency Agreement,
dated as of December 1, 1994, as amended, among the Collateral Agent, the
Project Trustee, IEC Funding Corp. (now ESI Tractebel Funding), the Swap Banks,
the Working Capital Banks and the Partnerships.
"Collateral Agent" when used in connection with the Project Securities,
means State Street Bank, as collateral agent pursuant to the Collateral Agency
Agreement and when used in connection with the Securities, means State Street
Bank, as collateral agent under the Pledge Agreements.
"Commission" means the United States Securities and Exchange
Commission.
"Commonwealth" means Commonwealth Electric Company, a Massachusetts
corporation.
"Commonwealth I Power Purchase Agreement" means the Power Sale
Agreement between Commonwealth and NEA dated as of November 26, 1986, and
amended as of August 15, 1988 and as further amended as of January 1, 1989.
"Commonwealth II Power Purchase Agreement" means the Power Sale
Agreement between Commonwealth and NEA dated as of August 15, 1988, and amended
as of January 1, 1989.
"Commonwealth Power Purchase Agreements" means, collectively, the
Commonwealth I Power Purchase Agreement and the Commonwealth II Power Purchase
Agreement.
"Conrail" means Consolidated Rail Corporation.
"Daily NEA Quantity" means 48,817 Dth of natural gas.
"Daily NJEA Quantity" means 22,019 Dth of natural gas.
"Debt" of any Person, as defined in the Project Indenture, means (i)
all obligations of such Person for borrowed money, (ii) all obligations of such
Person evidenced by bonds, debentures, notes or other similar instruments, (iii)
all obligations of such Person to pay the deferred purchase price of property or
services, (iv) all obligations under capital leases of such Person, (v) all Debt
of others secured by a Lien on any asset of such Person, whether or not such
Debt is assumed by such Person (vi) all Debt of others to the extent guaranteed
by such Person, (vii) all obligations under letters of credit issued for the
account of such Person, (viii) all obligations of such Person under trade or
bankers' acceptances and (ix) all obligations of such Person under agreements
providing for interest rate swaps, collars or caps.
"Debt Service Account," as defined in the Indenture, means the account
entitled "Debt Service Account" established and maintained by the Trustee
pursuant to the Indenture.
"Debt Service Coverage Ratio," as defined in the Project Indenture,
means the ratio of (i) the Project Revenues received directly by NE LP and NE
LLC during the 12-month period preceding the date as of which such ratio is
calculated (net of any operating expenses paid by any of the Securities, NE LP
and NE LLC during such period) to (ii) the scheduled debt service payments
(including principal, interest, premium, penalties and fees) on the Securities
and all other indebtedness (other than any Permitted Indebtedness) of ESI
Tractebel Acquisition, NE LP and NE LLC during such 12-month period, (provided
that, for purposes of this calculation, the corresponding payments in respect of
the Bond Loans and the Securities shall be deemed to constitute only one
payment).
A-4
"Debt Service Reserve Fund," as defined in the Project Indenture, means
the Fund entitled "Debt Service Reserve Fund" established and maintained by the
Project Trustee pursuant to the Project Indenture.
"Debt Service Reserve Requirement," as defined in the Project
Indenture, means, as of any Monthly Transfer Date, an amount equal to 50% of the
aggregate regularly scheduled interest, principal and fee payments to be made by
the Partnerships in respect of the Project Notes (for application to the payment
of principal, interest and fees of the Project Securities and any Additional
Project Securities) during the period commencing on (and including) such Monthly
Transfer Date and ending on (but excluding) the twelfth (12th) Monthly Transfer
Date thereafter; provided that the amount of the Debt Service Reserve
Requirement as of the Closing Date and as of the date of issuance of any
Additional Project Securities and for the period thereafter until the next
succeeding Monthly Transfer Date shall be equal to the Debt Service Reserve
Requirement calculated as of the Closing Date the date of issuance of any
Additional Project Securities or such next succeeding Monthly Transfer Date, as
the case may be.
"Dekatherm" or "Dth" means one MMBtu.
"Disqualified Stock", as defined in the Indenture, means any Capital
Stock that, by its terms (or by the terms of any security into which it is
convertible, or for which it is exchangeable, at the option of the holder
thereof), or upon the happening of any event, matures or is mandatorily
redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at
the option of the holder thereof, in whole or in part, on or prior to the date
that is 91 days after the date on which the Securities mature; provided,
however, that any Capital Stock that would constitute Disqualified Stock solely
because the holders thereof have the right to require ESI Tractebel Acquisition
to repurchase such Capital Stock upon the occurrence of a Change of Control
shall not constitute Disqualified Stock if the terms of such Capital Stock
provide that ESI Tractebel Acquisition may not repurchase or redeem any such
Capital Stock pursuant to such provisions unless such repurchase or redemption
complies with the covenant described under "Description of Securities."
"Distributable Percentage", as defined in the Project Indenture, means,
at any date, (i) 100% if the Debt Service Coverage Ratio for the Rolling Prior
Year is greater than or equal to 1.40:1, (ii) 75% if the Debt Service Coverage
Ratio for the Rolling Prior Year is less than 1.40:1 but greater than or equal
to 1.35:1, (iii) 50% if the Debt Service Coverage Ratio for the Rolling Prior
Year is less than 1.35:1 but greater than or equal to 1.30:1 and (iv) 25% if the
Debt Service Coverage Ratio for the Rolling Prior Year is less than 1.30:1 but
greater than or equal to 1.25:1.
"Distribution Account", as defined in the Indenture, means the account
entitled "Distribution Account" maintained by the Trustee pursuant to the
Indenture.
"Dollars" and "$" means lawful money of the United States.
"DTC" means The Depository Trust Company.
"DTE" means Department of Telecommunications and Energy.
"Energy Bank" or "Energy Bank Obligations" means an account recording
the liability of a Partnership to a Power Purchaser representing cumulative
payments made to such Partnership by such Power Purchaser under the applicable
Power Purchase Agreement in excess of such Power Purchaser's Avoided Costs,
determined in accordance with such Power Purchase Agreement.
A-5
"Energy Bank Letters of Credit" means, collectively, any letter or
letters of credit for the benefit of the Power Purchasers to secure the Energy
Bank Obligations.
"Environmental Law" means any and all Government Rules relating to
human health or the environment, or the release of Hazardous Materials into the
indoor or outdoor environment including, without limitation, ambient air,
surface water, groundwater, wetlands, land or subsurface strata or otherwise
relating to the use of Hazardous Material, whether now or hereafter in effect.
Environmental Laws shall include, without limitation, the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended, the
Toxic Substances Control Act, as amended, the Hazardous Materials Transportation
Act, as amended, the Resource Conservation and Recovery Act, as amended, the
Clean Water Act, as amended, the Safe Drinking Water Act, as amended, the Clean
Air Act, as amended, the Occupational Safety and Health Act, as amended, and all
analogous laws promulgated or issued by any state or other Governmental
Authority.
"EPA" means the Environmental Protection Agency of the United States.
"ESI" or "ESI Energy" means ESI Energy, Inc., a Florida corporation.
"ESI Acquisition Funding" means ESI Northeast Energy Acquisition
Funding, Inc., a Florida corporation.
"ESI Funding" means ESI Northeast Energy Funding, Inc., a Florida
corporation.
"ESI GP" means ESI Northeast Energy GP, Inc., a Florida corporation.
"ESI LP" means ESI Northeast Energy LP, Inc., a Florida corporation.
"ESI Tractebel Acquisition" means ESI Tractebel Acquisition Corp., a
Delaware corporation.
"ESI Tractebel Funding" means ESI Tractebel Funding Corp., a Delaware
corporation, formerly known as "IEC Funding Corp."
"Event of Loss" means any compulsory transfer or taking or transfer
under threat of compulsory transfer or taking of all or any material part of
either Project by any Government Authority, or any event which causes all or any
material portion of either Project by any Government Authority, or any event
which cause all or any material portion of either Project to be damaged,
destroyed or rendered unfit for normal use for any reason whatsoever.
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"Exchange Offer" means the anticipated offer by ESI Tractebel
Acquisition to exchange the New Securities for an equal principal amount of the
Old Securities.
"Extended Gas Service" means the sale and delivery of gas to NJEA by
PSE&G for days on which the mean daily temperature for Newark, New Jersey is
between 22(degree)F and 14(degree)F.
"FERC" means the United States Federal Energy Regulatory Commission.
"Fluor Daniel" means Fluor Daniel Inc., a California corporation.
"Fluor Daniel Agreement" means the Design/Build Contract dated as of
June 28, 1989 between NEA and Fluor Daniel.
A-6
"FPA" means the Federal Power Act, as amended.
"FPL" means Florida Power & Light Co., a Florida corporation.
"FPL Energy" means FPL Energy, Inc., a Florida corporation.
"FPL Group" means FPL Group, Inc., a Florida corporation.
"FPL Group Capital" means FPL Group Capital Inc., a Florida
corporation.
"FPL Group Capital Guaranty" or "FPL Capital Guarantee" means a
guaranty or an agreement made by FPL Group Capital in to reimburse Energy Bank
Letter of Credit Banks and/or Substitute Letter of Credit Banks, issued pursuant
to the Reimbursement Agreement.
"Fuel Consultant" means Benjamin Schlesinger and Associates, Inc.
"Fuel Consultant's Report" means the report prepared by the Fuel
Consultant included in Appendix C.
"Fuel Management Agreements" means, collectively, the NEA Fuel
Management Agreement and the NJEA Fuel Management Agreement.
"Fuel Management Fees" means the monthly fees required to be paid by
NEA and NJEA to the Fuel Manager pursuant to the Fuel Management Agreements.
"Fuel Manager" means ESI Northeast Fuel Management, Inc., a Florida
corporation.
"Funds" means the funds established and maintained by the Project
Trustee pursuant to the Project Indenture.
"Gas Transmission Reserve Fund" means the Fund entitled "Gas
Transmission Reserve Fund" established and maintained by the Project Trustee
pursuant to the Project Indenture.
"Gas Transmission Reserve Requirement" means (a) as of any date
occurring within the fifteen month period preceding the earliest expiration date
of the Transco Agreements and which precedes the earliest expiration date of the
Transco Agreements by a period that includes not less than three Monthly
Transfer Dates, $5,300,000, (b) as of any other date thereafter, $10,600,000 and
(c) prior to the date determined pursuant to clause (a), zero; provided that as
of and subsequent to any extension or replacement of the Transco Agreements by
agreements expiring on or after the final maturity date of the Project
Securities and satisfying certain other conditions specified in the Project
Indenture, the Gas Transmission Reserve Requirement shall be zero. The Gas
Transmission Reserve Requirement has been determined based on the assumption
that each Transco Agreement will expire on October 31, 2006, and will not be
extended, in whole or in part, beyond such date. In the event that either or
both Transco Agreements are extended or replaced by agreements satisfying
certain conditions specified in the Project Indenture, the Gas Transmission
Reserve Requirement will be adjusted pursuant to a formula specified in the
Project Indenture.
"General Partner" means NE LP.
"Goldman" means Goldman, Sachs & Co.
A-7
"Government Approval" means (i) any authorization, consent, approval,
license, ruling, permit, certification, exemption, filing, variance, order,
judgment, decree or publication of, by or with, (ii) any notice to, (ii) any
declaration of or with or (iv) any registration by or with, any Government
Authority required to be obtained or made by ESI Tractebel Acquisition, NE LP,
ESI Tractebel Funding or a Partnership or, where the context requires, by any
other Person party to a Project Document.
"Government Authority" means any United States federal, state,
municipal, local, territorial or other governmental subdivision, department,
commission, board, bureau, agency, regulatory authority, instrumentality,
judicial or administrative body, domestic or foreign.
"Government Rule" means any statute, law, regulation, ordinance, rule,
judgment, order, decree, permit, concession, grant, franchise, code, license,
directive, guideline, policy or rule of common law, requirement of, or other
governmental restriction or any judicial or administrative order, consent decree
or judgement or similar form of decision of or determination by, or any
interpretation or administration of any of the foregoing by, any Government
Authority, whether now or hereafter in effect.
"GSR Deficiency", as defined in the Project Indenture, is now zero.
"Guaranty", as defined in the Project Indenture, by any Person means
any guaranty, surety, bond or other obligation, contingent or otherwise, of such
Person directly or indirectly guaranteeing in any manner any Debt or other
obligation of any other Person and, without limiting the generality of the
foregoing, any obligation, direct or indirect, contingent or otherwise, of such
Person: (i) to purchase or pay (or advance or supply funds for the purchase or
payment of) such Debt or other obligation (whether arising by virtue of
Partnership arrangements, by agreement to keep well, to purchase assets, goods,
bonds or services, to take-or-pay, or to maintain financial statement conditions
or otherwise), (ii) entered into for the purpose of assuring in any other manner
the obligee of such Debt or other obligation of the payment thereof or to
protect such obligee against loss in respect thereof (in whole or in part) or
(iii) to reimburse any Person for the payment by such Person under any letter of
credit, surety, bond or other guaranty issued for the benefit of such other
Person, but excluding (x) endorsements for collection or deposit in the ordinary
course of business, or (y) indemnity or hold harmless provisions included in
contracts entered into in the ordinary course of business.
"Hazardous Material", as defined in the Project Indenture, means: (i)
any petroleum or petroleum products, flammable explosives, radioactive
materials, asbestos in any form that is or could become friable, urea
formaldehyde foam insulation and transformers or other equipment that contain
dielectric fluid containing polychlorinated biphenyls (PCBs), (ii) any chemicals
or other materials or substances which are now or hereafter become defined as or
included in the definition of "hazardous substances," "hazardous wastes,"
"hazardous materials," "extremely hazardous wastes," "restricted hazardous
wastes," "toxic substances," "toxic pollutants," "contaminants," "pollutants" or
words of similar import under any Environmental Law and (iii) any other chemical
or other material or substance, exposure to which is now or hereafter
prohibited, limited or regulated as such under any Environmental Law including
the Resource Conservation and Recovery Act, 42 U.S.C. Section 6901 et seq., the
Comprehensive Environmental Response Compensation and Liability Act, 42 U.S.C.
Section 6901 et seq., or any similar state statute.
"Hercules" means Hercules Incorporated, a Delaware corporation.
"HRSG" means a heat recovery steam generator.
"IEC" means Intercontinental Energy Corporation, a Massachusetts
corporation, the former general partner of each of the Partnerships.
A-8
"IEC Funding Corp." means the corporation now referred to as ESI
Tractebel Funding Corp., a Delaware corporation.
"IECURC" means IEC Urban Renewal Corporation, a New Jersey corporation
wholly-owned by NJEA.
"Import Point" means the point of interconnection between the
TransCanada pipeline and CNG's pipeline at Niagara Falls, Ontario/Niagara Falls,
New York.
"Indenture" means the Trust Indenture dated as of the Closing Date,
among ESI Tractebel Acquisition, NE LP, NE LLC and the Trustee providing for the
issuance of the Securities.
"Independent Engineer" means Sargent & Lundy, L.L.C., an Illinois
limited liability company, or its successors.
"Independent Engineer's Report" means the Report prepared by the
Independent Engineer and included as Appendix B in this Prospectus.
"Independent Gas Consultant" means Benjamin Schlesinger and Associates,
or its successors.
"Insurance Proceeds" means all amounts and proceeds (including
instruments) in respect of the proceeds of any casualty insurance policy or
title insurance policy, except proceeds of delayed opening or business
interruption insurance.
"Interest Fund," as defined in the Project Indenture, means the
Interest Fund established and maintained by the Project Trustee pursuant to the
Project Indenture.
"ISO Conditions" means a temperature of 59 degrees and an atmospheric
pressure of 29.92 inches of mercury absolute (i.e. sea level).
"Issuer and Partner Pledge Agreement" means the Pledge Agreement by
ESI Tractebel Acquisition, NE LP and NE LLC to the Collateral Agent, for the
benefit of the Collateral Agent, the Trustee and the holders of the Securities.
"JCP&L" means Jersey Central Power & Light Company, a New Jersey
corporation.
"JCP&L Power Purchase Agreement" means the Power Purchase Agreement
dated as of October 22, 1987, between NJEA and JCP&L, as amended.
"Kilowatt" or "KW" means one thousand watts.
"Kilowatt-hours" or "kWh" means a unit of electrical energy equal to
one kilowatt of power supplied or taken from an electric circuit steadily for
one hour.
"Lien", as defined in the Project Indenture, means, with respect to any
property of any Person, any mortgage, lien, pledge, charge, lease, easement,
servitude, right of others or security interest or encumbrance of any kind in
respect of such property of such Person.
"Long-term Gas Arrangements" means, collectively, the Long-term Gas
Supply Agreements, the Long-term Gas Transportation Agreements and the Long-term
Gas Storage Agreements.
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"Long-term Gas Storage Agreements" means the NEA Gas Storage Agreement
and the NJEA Gas Storage Agreement.
"Long-term Gas Supply Agreements" means the NEA ProGas Agreement, the
NJEA ProGas Agreement and the PSE&G Contract.
"Long-term Gas Transportation Agreements" means the NEA Gas
Transportation Agreements and the NJEA Gas Transportation Agreements.
"Loss Proceeds" means all Insurance Proceeds, all condemnation awards,
settlement payments and other amounts (other than proceeds of delayed opening or
business interruption insurance or similar items) received or payable in respect
of any Event of Loss.
"Major Overhaul Expenses" means expenses not covered by any operations
and maintenance contractor and which are incurred by a Partnership in connection
with scheduled major overhauls of a project in accordance with the maintenance
recommendations of the applicable manufacturer or vendor pursuant to the Project
Indenture.
"Major Overhaul Reserve Fund" means the Fund entitled "Major Overhaul
Reserve Fund" established and maintained by the Project Trustee pursuant to the
Project Indenture.
"Management Costs" means the management fee payable to NE LP, which fee
shall be comprised of four components, without duplication: (i) third-party
costs certified as being reasonably allocable to either or both of the Projects
or either or both of the Partnerships or ESI Tractebel Funding (including but
not limited to any rent, independent legal, consulting and accounting fees and
expenses that are certified as such), (ii) general and administrative expenses
of NE LP reasonably allocable to either or both of the Projects or either or
both of the Projects or either or both of the Partnerships or ESI Tractebel
Funding, (iii) compensation (including salary and related benefits) of
individuals that are not related by blood or marriage to the Original Project
Sponsors certified as being reasonable allocable to either or both of the
Projects or either or both of the Partnerships or the company and (iv) for each
calendar year commencing with the year in which the Closing Date shall occur, an
amount equal to $3,500,000, $1,500,000 of which shall constitute the
Subordinated Management Fee (each such amount inflated annually commencing on
January 1, 1995, in accordance with the Project Indenture, and adjusted ratably
for each partial calendar year in which the Project Securities shall be
outstanding).
"MBtu" means one thousand Btus.
"Mcf" means one thousand cubic feet of gas at 60 degrees F and at a
pressure of 14.73 pounds per square inch absolute.
"Medway Substation" means the Medway Substation of Boston Edison,
located in Medway, Massachusetts.
"Megawatt" or "MW" means one million watts.
"Megawatt hour" or "MWH" means one thousand kilowatt-hours.
"MMBtu" means one million Btus.
"Montaup" means Montaup Electric Company, a Massachusetts corporation.
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"Montaup Power Purchase Agreement" means the Power Purchase Agreement
dated as of October 17, 1986, as amended on June 28, 1989, between NEA and
Montaup.
"Monthly MOR Contribution Amount," as defined in the Project Indenture
means, for each Monthly Transfer Date commencing with the first such date in
calendar year 2001 (a) the applicable amount set forth in the Project Indenture
as the aggregate required contribution to the Major Overhaul Reserve Fund for
the calendar year of such Monthly Transfer Date (as such schedule may be
revised, as set forth therein, by the Independent Engineer in the event that
either O&M Agreement is amended or replaced to provide for the payment by a
third party operator for either Project of all or a portion of any Major
Overhaul Expenses) divided by (b) 12 (or, in the case of the calendar year in
which the final maturity date for the Project Securities occurs, the number of
Monthly Transfer Dates occurring in such calendar year prior to such date).
"Monthly Transfer Date," as defined in the Project Indenture means the
first business day of each calendar month.
"Monthly Transfer Period" means the period commencing on (and
including) a Monthly Transfer Date and ending on (but excluding) the immediately
succeeding Monthly Transfer Date.
"Moody's" means Moody's Investors Service, Inc.
"MOR Deficiency," as defined in the Project Indenture, means, as of any
date of determination subsequent to the first Monthly Transfer Date in calendar
year 2001, the excess, if any, of (a) the aggregate Monthly MOR Contribution
Amounts for all prior Monthly Transfer Dates over (b) the excess (if any) of (i)
the aggregate amount of all prior transfers to the Major Overhaul Reserve Fund
over (ii) the aggregate amount of all withdrawals from the Major Overhaul
Reserve Fund made on or prior to such date of determination other than pursuant
to the Project Indenture; provided, that the amount of any MOR Deficiency (i)
shall be reduced by the amount of Major Overhaul Expenses previously paid by the
Partnerships from funds other than disbursements from the Major Overhaul Reserve
Fund, (ii) shall be subject to adjustment as provided in the Project Indenture
and (iii) shall be equal to zero as of any date of determination prior to the
first Monthly Transfer Date in calendar year 2001.
"MOU" means Memorandum of Understanding.
"NationsBank" means NationsBank of Texas.
"NE LLC" means Northeast Energy, LLC, a Delaware limited liability
company.
"NE LP" means Northeast Energy, LP, a Delaware limited partnership.
"NE LP Partnership Agreement" means the Agreement of Limited
Partnership of Northeast Energy, LP, dated as of November 21, 1997, by and among
ESI GP, ESI LP, Tractebel GP and Tractebel LP.
"NEA" means Northeast Energy Associates, A Limited Partnership, a
Massachusetts limited partnership.
"NEA Additional Properties Mortgage" means the Amended and Restated
Mortgage, Assignment of Rents, Security Agreement and Fixture Filing (Additional
Properties) granted by NEA to the Collateral Agent with respect to certain real
estate owned by NEA adjacent to the NEA Site.
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"NEA Fuel Management Agreement" means the Fuel Management Agreement,
dated as of January 20, 1998 (effective retroactively to January 14, 1998) by
and between the Fuel Manager and NE LP, assigned by NE LP to NEA on January 20,
1998.
"NEA Fuel Management Fee" means $450,000, as compensation for certain
fuel management services for the NEA Project pursuant to the NEA Fuel Management
Agreement.
"NEA Gas Agreements" means the NEA ProGas Agreement, the NEA Gas
Transportation Agreements and the NEA Gas Storage Agreement.
"NEA Gas Storage Agreement" means the Service Agreement Applicable to
the Storage of Natural Gas Under Rate Schedule GSS-II dated as of September 30,
1993, between CNG and NEA, as amended by the parties and in respect of changes
in FERC approved tariffs.
"NEA Gas Supply Agreement" means the NEA ProGas Agreement.
"NEA Gas Transportation Agreements" means collectively, the Firm
Transportation Service Agreement dated as of February 28, 1994, among CNG, NEA,
ProGas and ProGas U.S.A., Inc., the Firm Gas Transportation Agreement (Rate
Schedule X-320) dated February 27, 1991, between Transco and NEA, the Rate
Schedule X-35 Firm Gas Transportation Agreement dated October, 1993, between
Algonquin and NEA and the Service Agreement for Rate Schedule FTS-5 dated
February 16, 1994, between Texas Eastern and NEA, each as amended by the parties
and in respect of changes in FERC approved tariffs.
"NEA O&M Agreement" means the Second Amended and Restated Operations
and Maintenance Agreement dated as of June 28, 1989, between NEA and the
Operator (as successor to Westinghouse Electric).
"NEA O&M Fee" means the monthly fee required to be paid by NEA to the
Operator pursuant to the NEA O&M Agreement.
"NEA Partnership Agreement" means the Amended and Restated Agreement of
Limited Partnership of Northeast Energy Associates, A Limited Partnership, dated
as of November 21, 1997 by and between NE LP and NE LLC.
"NEA Power Purchase Agreements" means the Boston Edison I Power
Purchase Agreement, the Boston Edison II Power Purchase Agreement, the
Commonwealth I Power Purchase Agreement, the Commonwealth II Power Purchase
Agreement and the Montaup Power Purchase Agreement.
"NEA Power Purchasers" means Boston Edison, Commonwealth and Montaup.
"NEA ProGas Agreement" means the Gas Purchase Contract dated as of May
12, 1988, between NEA and ProGas, as amended.
"NEA Project" means the nominal 300 MW natural gas-fired combined cycle
cogeneration facility owned by NEA located on the NEA Site, including all
electrical and steam generating components, and all electrical, steam and
natural gas interconnection facilities and structures, associated materials,
handling and environmental equipment and ancillary structures, equipment and
systems.
"NEA Project Documents" means, individually and collectively, certain
existing agreements and documents specified in the Project Indenture (which
include the NEA Power Purchase Agreements, the
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NEA Gas Agreements, the NEA Steam Sales Agreement and the NECO Lease), as any of
the same may from time to time be amended, modified or supplemented together
with all Additional Project Documents (as defined in the Project Indenture) to
which NEA is a party or which relate to all or any part of the NEA Project as to
the Carbon Dioxide Plant.
"NEA Project Mortgage" means the Amended and Restated Mortgage,
Assignment of Rents, Security Agreement and Fixture Filing granted by NEA to the
Collateral Agent with respect to the NEA Site and all related improvements and
fixtures thereon owned by NEA.
"NEA Second Mortgage" means the Mortgage, Assignment of Rents, Security
Agreement and Fixture Filing dated as of June 28, 1989, by NEA in favor of
Boston Edison, Commonwealth and Montaup securing the performance by NEA of its
obligations under each of the NEA Power Purchase Agreements.
"NEA Site" means the approximately 44-acre site on the upper Charles
River in the town of Bellingham, Massachusetts, on which the NEA Project and the
Carbon Dioxide Plant are located.
"NEA Steam Sales Agreement" means the Amended and Restated Steam Sales
Agreement dated as of December 21, 1990, between NEA and NECO.
"NECO" means NECO-Bellingham, Inc., a special-purpose subsidiary of a
privately held company based in Houston.
"NECO Lease" means the Amended and Restated Lease dated as of December
21, 1990, between NEA and NECO.
"NEPOOL" means the New England Power Pool.
"NEPOOL Agreement" means the NEPOOL Agreement dated September 1, 1971.
"Net Electrical Capability" means the sum of the nameplate rating of
the generators for each Project, as designated by the manufacturer and expressed
in megawatts, less allowance for station service, at which such Project is
designed to operate continuously in a reasonable and prudent manner under ISO
conditions in accordance with good utility practice.
"New Securities" means the bonds to be exchanged by ESI Tractebel
Acquisition in exchange for Old Securities pursuant to the Exchange Offer.
"New NEA O&M Agreement" means the Operation and Maintenance Agreement,
dated as of November 21, 1997, by and between NE LP and the New Operator,
subsequently assigned by NE LP to NEA.
"New NEA O&M Fee" means the monthly fee required to be paid by NEA to
the New Operator pursuant to the New NEA O&M Agreement.
"New NJEA O&M Agreement" means the Operation and Maintenance Agreement,
dated as of November 21, 1997, by and between NE LP and the New Operator,
subsequently assigned by NE LP to NJEA.
"New NJEA O&M Fee" means the monthly fee required to be paid by NJEA to
the New Operator pursuant to the New NJEA O&M Agreement.
A-13
"New O&M Agreements" means the New NEA O&M Agreement and the New NJEA
O&M Agreement.
"New O&M Fees" means the fees as compensation for the operation and
maintenance services for the Projects under the New O&M Agreements.
"New Operator" means ESI Operating Services, Inc., a Florida
corporation.
"1990 Amendments" means the 1990 Amendments to the Federal Clean Air
Act of 1955.
"NJBPU" means the New Jersey Board of Public Utilities.
"NJEA" means North Jersey Energy Associates, A Limited Partnership, a
New Jersey limited partnership.
"NJEA Fuel Management Agreement" means the Fuel Management Agreement,
dated as of January 20, 1998 (effective retroactively to January 14, 1998) by
and between the Fuel Manager and NE LP, assigned by NE LP to NJEA on January 20,
1998.
"NJEA Fuel Management Fee" means $450,000, as compensation for certain
fuel management services for the NJEA Project pursuant to the NJEA Fuel
Management Agreement.
"NJEA Gas Agreements" means, collectively, the NJEA ProGas Agreement,
the PSE&G Contract, the NJEA Gas Transportation Agreements and the NJEA Gas
Storage Agreement.
"NJEA Gas Storage Agreement" means the Service Agreement Applicable to
the Storage of Natural Gas Under Rate Schedule GSS-II dated as of September 30,
1993, between CNG and NJEA.
"NJEA Gas Supply Agreements" means, collectively, the NJEA ProGas
Agreement and the PSE&G Contract.
"NJEA Gas Transportation Agreements" means collectively, the Firm
Transportation Service Agreement dated as of February 28, 1994, among CNG, NJEA,
ProGas and ProGas U.S.A., Inc., the Firm Gas Transportation Agreement (Rate
Schedule X-319) dated February 27, 1991, between Transco and NJEA and the
Service Agreement for Rate Schedule FTS-5 dated February 16, 1994, between Texas
Eastern and NJEA, each as amended by the parties and in respect of changes in
FERC approved tariffs.
"NJEA O&M Agreement" means the Amended and Restated Operations and
Maintenance Agreement dated as of June 28, 1989, between NJEA and the Operator
(as successor to Westinghouse Electric).
"NJEA O&M Fee" means the monthly fee required to be paid by NJEA to the
Operator pursuant to the NJEA O&M Agreement.
"NJEA Partnership Agreement" means the Amended and Restated Agreement
of Limited Partnership of North Jersey Energy Associates, A Limited Partnership,
dated as of November 21, 1997 by and between NE LP and NE LLC.
"NJEA Power Purchase Agreement" means the JCP&L Power Purchase
Agreement.
"NJEA Power Purchaser" means JCP&L.
A-14
"NJEA ProGas Agreement" means the Gas Purchase Contract dated as of May
12, 1988, between NJEA and ProGas, as amended.
"NJEA Project" means the nominal 300 MW natural gas-fired combined
cycle cogeneration facility owned by NJEA and located on the NJEA Site,
including all electrical and steam generating components, and all electrical,
steam and natural gas interconnection facilities and structures, associated
materials handling and environmental control equipment and ancillary structures,
equipment and systems.
"NJEA Project Documents" means, individually and collectively, certain
existing agreements and documents specified in the Project Indenture (which
include the JCP&L Power Purchase Agreement, the NJEA Gas Agreements and the NJEA
Steam Sales Agreement), as any of the same may from time to time be amended,
modified or supplemented, together with all Additional Project Documents (as
defined in the Project Indenture) to which NJEA is a party or which relate to
all or any part of the NJEA Project.
"NJEA Project Mortgage" means the Amended and Restated Indenture of
Mortgage, Assignment of Rents, Security Agreement and Fixture Filing, dated as
of December 1, 1994, granted by NJEA to the Collateral Agent with respect to the
NJEA Site and all related improvements and fixtures thereon owned by NJEA.
"NJEA Site" means the approximately 49-acre site in the Borough of
Sayreville, New Jersey, on which the NJEA Project is located.
"NJEA Steam Sales Agreement" means the Industrial Steam Sales Contract
dated as of June 5, 1989, as amended, between NJEA and Hercules.
"Non-Material Project Document", as defined in the Project Indenture,
means any Project Document (x) which shall be for a term (including any
extensions provided therein, other than those that are optional to the
applicable Partnership) not longer than 1 year or (y) under which such
Partnership shall have obligations not in excess of $1,000,000, excluding,
however, (a) any contract or agreement providing, directly or indirectly, for
monetary or nonmonetary obligations of the Partnership the performance of which
could reasonably be expected to have a material adverse effect and (b) any
contract or agreement providing for the acquisition by either Partnership of
property, or the delivery to the Partnership of services, that if no obtained
could reasonably be expected to have material adverse effect (taking into
consideration all available alternatives). For purposes of this definition,
indemnity or similar obligations of a Partnership subject to a maximum dollar
amount shall be limited to such amount, and, subject to any such limitation,
shall be computed at the maximum amount thereof which could, at the time such
agreement is entered into, reasonably be expected to become due and payable.
"Note" means the note issued by NE LP to ESI Tractebel Acquisition to
evidence NE LP's obligation to repay the Bond Loan.
"NOx" means oxides of nitrogen.
"NYMEX" means the New York Mercantile Exchange.
"O&M Agreements" means the NEA O&M Agreement and the NJEA O&M
Agreement, as applicable, (including any extensions or modifications thereof).
"OASIS" means an open-access same-time information system, as defined
in FERC Order No. 889.
A-15
"Offering" means the offering of the Old Securities described herein.
"Operating Expenses," as defined in the Project Indenture means, for
any period, the sum of the following costs and expenses (without duplication)
paid or required to be paid during such period (or, in the case of any future
period, projected to be paid or payable in such period): (a) the operating and
maintenance expenses of the Projects including, without limitation, (i) amounts
due from the applicable Partnership under any operations and maintenance
agreement in respect of the operation and maintenance of either Project, (ii)
fuel procurement, storage, transportation, management and associated costs for
the Projects and costs of any fuel hedging arrangements, (iii) premiums for
insurance including, without limitation, insurance required to be maintained
pursuant to the Project Indenture or pursuant to any Project Document, (iv)
franchise, licensing, excise, property and other similar taxes (other than
federal and state income taxes and any other taxes imposed upon, or measured by,
income or receipts, unless any such tax shall be imposed on the Partnerships
solely by reason of the adoption of a Government Rule or the amendment of an
existing Government Rule subsequent to the closing date with respect to the
offering of the Project Securities) payable by or on behalf of the Partnerships,
(v) all taxes payable by ESI Tractebel Funding, (vi) utilities, supplies and
other services acquired in connection with the operation or maintenance of the
Projects, (vii) maintenance costs with regard to the Projects, including the
rebuilding, repair or replacement of any Project in connection with an Event of
Loss (to the extent such costs are not paid from funds on deposit in the Major
Overhaul Reserve Fund or the Capital Expenditure Fund), (viii) costs and fees
incurred in connection with obtaining and maintaining in effect the Government
Approvals relating to a Project, (ix) costs of the Partnerships and ESI
Tractebel Funding relating to the settlement of pending or threatened litigation
or other claims relating to a Project or any related fines, penalties, judgments
and other costs (including, without limitation, legal fees and expenses)
associated with such litigation or other claims, (x) rental expense of the
Partnerships relating to the rental of any property associated with the
Projects, (xi) fees and expenses of consultants and experts retained by or
required to be paid by either of the Partnerships or ESI Tractebel Funding,
including, without limitation, the Independent Experts, attorneys and
accountants, (xii) indemnification payments made by either of the Partnerships
or ESI Tractebel Funding to any Person pursuant to any bona fide obligation
necessarily and reasonably incurred in connection with the operation or
financing (including any financing contemplated pursuant to the Project
Indenture) of the Projects and owed by such Partnership to such Person and
(xiii) Management Costs (provided that the amount of Management Costs referred
to in clause (iv) of the definition thereof payable as an Operating Expense
during any Monthly Transfer Period shall not exceed the sum of (A) the quotient
of (x) the then applicable annual amount of such Management Costs over (y) 12
or, if applicable, the number of Monthly Transfer Periods in any partial year in
which the Project Securities shall be outstanding and (B) the amount of
Management Costs that were permitted to be paid as operating expenses pursuant
to this proviso in any prior Monthly Transfer Period but not previously paid;
provided further that, for purposes of the foregoing proviso, a portion of the
amount determined pursuant to clause (A) for each Monthly Transfer Period shall
be allocated ratably to the Subordinated Management Fee and amounts determined
pursuant to clause (B) shall be allocated to the Subordinated Management Fee to
the extent unpaid amounts are attributable to deficiencies in the Subordinated
Management Fee Subfund of the Operating Fund); plus (b) fees and expenses of the
Project Trustee and the Collateral Agent, plus (c) costs relating to the
issuance of any Project Securities, including, without limitation, any exchange
offer and any registration statement in respect of the Project Securities or any
other costs incurred by ESI Tractebel Funding and the Partnerships in connection
with the performance of any further assurance obligations hereunder and under
the Project Indenture and the Project Security Documents; plus (d) amounts
payable by the Partnerships in respect of guaranties permitted under the Project
Indenture; plus (e) amounts payable to any entity (other than an affiliate of NE
LP), either in the form of dividends or management or similar fees or
reimbursement of expenses (in each case in reasonable amounts) that owns any of
the outstanding capital stock of ESI Tractebel Funding, provided that all of the
foregoing costs and expenses shall be determined on a cash basis and shall not
include depreciation, amortization or other non-cash items.
A-16
"Operator" means Westinghouse Services.
"Original Banks" means the financial institutions party to the Original
Project Credit Agreement.
"Original Project Credit Agreement" means the Project Loan and Credit
Agreement dated as of June 28, 1989, as amended, among the Partnerships as
borrowers, IEC, The Chase Manhattan Bank as issuing bank and as agent for the
Original Banks, The Bank of New York (as successor to Irving Trust Company) as
co-agent and the Original Banks.
"Original Project Indenture" means the Trust Indenture, dated as of
November 15, 1994, among each of the Partnerships, IEC Funding Corp. (now ESI
Tractebel Funding), and the Project Trustee, as supplemented by the First
Supplemental Trust Indenture, dated as of November 15, 1994.
"Original Project Notes" means the notes issued by the Partnerships to
the Original Banks pursuant to the Original Project Credit Agreement.
"Original Project Securities" means the 8.43% Senior Secured Notes Due
2000, the 9.16% Senior Secured Notes Due 2002, the 9.32% Senior Secured Bonds
Due 2007 and the 9.77% Senior Secured Bonds Due 2010. The Original Project
Securities were exchanged for Project Securities in May 1995.
"Partial Transportation Extension Event" means the occurrence of the
following with respect to a Transco Agreement: (a) either (i) the extension of
the term of such Transco Agreement on terms and conditions which would
constitute a Transco Extension Event but for the fact that (A) the term of such
Transco Agreement (as so extended) is scheduled to expire prior to the final
maturity date of the Project Securities and/or (B) the maximum daily quantity to
be transported pursuant to such Transco Agreement is less than that in effect
under such Transco Agreement on December 1, 1994 or (ii) the execution by either
Partnership and one or more third parties of one or more gas transportation
agreements providing for firm gas transportation service to such Partnership by
such third party(ies) which would constitute a Transco Substitution Event but
for the fact that (x) the term of such agreement is scheduled to expire prior to
the final maturity date of the Project Securities and/or (y) the maximum daily
quantity to be transported pursuant to such agreement(s) is less than that in
effect for the applicable Transco Agreement on December 1, 1994; and (b) the
receipt by the Project Trustee of a certificate of the Independent Gas
Consultant to the effect of (a) above.
"Partners" means, collectively, NE LP and NE LLC.
"Partnership Distribution Fund" means the Fund entitled "Partnership
Distribution Fund" established and maintained by the Project Trustee pursuant to
the Project Indenture.
"Partnership Suspense Fund" means the Fund entitled "Partnership
Suspense Fund" established and maintained by the Project Trustee pursuant to the
Project Indenture.
"Partnerships" means NEA and NJEA.
"Peak Gas Service Credit" means the demand charge paid by PSE&G to NJEA
in exchange for the right to retain NJEA's gas supplies on days when the mean
daily temperature forecast for Newark, New Jersey drops below certain levels.
"Permitted Purchase Money Indebtedness," as defined in the Project
Indenture, means purchase money or lease obligations incurred to finance items
of equipment not comprising an integral part of
A-17
either Project (and obligations in respect of Debt incurred to refinance any
such obligations), provided that (a) if such obligations are secured, they are
secured only by Liens upon the equipment being financed and (b) such obligations
do not in the aggregate have annual scheduled interest, principal, lease and
purchase price installment payments in excess of $5,000,000.
"Permitted Unsecured Indebtedness" means unsecured Debt in an aggregate
outstanding principal amount at no time greater than $10,000,000.
"Person" means any individual, sole proprietorship, corporation,
partnership, joint venture, limited liability company, trust, unincorporated
association, institution, Government Authority or any other entity.
"PJM" or "PJM Interconnected Power Pool" means the Pennsylvania/New
Jersey/Maryland interconnected Power Pool.
"PJM Agreement" means the PJM Agreement dated September 26, 1956, as
amended.
"Pledge Agreements" means the Sponsor Pledge Agreement and the Issuer
and Partner Pledge Agreement.
"Policy Act" means the Energy Policy Act of 1992.
"PORTAL" means the Private Offerings, Resales and Trading Through
Automatic Linkages of the National Association of Securities Dealers, Inc.
"Power Purchase Agreements" means individually and collectively, the
Boston Edison I Power Purchase Agreement, the Boston Edison II Power Purchase
Agreement, the Commonwealth I Power Purchase Agreement, the Commonwealth II
Power Purchase Agreement, the Montaup Power Purchase Agreement and the JCP&L
Power Purchase Agreement, and any Additional Project Document (as defined in the
Project Indenture) (other than a Non-Material Project Document) providing for
the sale of electric energy or capacity from the Projects.
"Power Purchasers" means Boston Edison, Commonwealth, JCP&L and Montaup
and any other Person (other than the Partnerships) party to a Power Purchase
Agreement.
"Praxair" means Praxair, Inc., the successor to Liquid Carbonic Carbon
Dioxide Corporation.
"Principal Fund" means the Fund entitled "Principal Fund" described in,
and pursuant to the Project Indenture.
"ProGas" means ProGas Limited, an Alberta corporation.
"ProGas Agreement Expiration Date" means, with respect to each ProGas
Agreement, the later of (a) November 1, 2006 and (b) the scheduled expiration
date of such ProGas Agreement after giving effect to any Partial ProGas
Extension Events.
"ProGas Agreements" means the NEA ProGas Agreement and the NJEA ProGas
Agreement.
"Project Accounts" means the accounts entitled "Project Accounts"
maintained and used by the Project Trustee.
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"Project Collateral," defined as "Collateral" in the Project Indenture,
means, collectively, all of the collateral mortgaged, pledged or assigned to the
Collateral Agent by any of ESI Tractebel Funding, each Partnership, NE LP, ESI
Funding and Tractebel Power, in each case pursuant to the granting and assigning
clauses of the applicable Project Security Documents.
"Project Credit Agreement" means the Amended and Restated Project Loan
and Credit Agreement, dated as of December 1, 1994, by and among ESI Tractebel
Funding and each of the Partnerships.
"Project Documents" means, collectively, the NEA Project Documents and
the NJEA Project Documents.
"Project Guaranty" means the guaranty agreement, by and among the
Project Trustee, NEA and NJEA, guaranteeing the obligations of ESI Tractebel
Funding under the Project Indenture.
"Project Indebtedness," as used in this Prospectus means, collectively,
the existing Debt of the Partnerships and ESI Tractebel Funding in connection
with the Project Securities, the existing Debt of the Partnerships in connection
with the Sanwa Credit Agreement and the existing Debt of the Partnerships under
the Swaps.
"Project Indenture" means the Trust Indenture dated as of November 15,
1994, entered into by ESI Tractebel Funding, the Partnerships and the Project
Trustee providing for the issuance of the Project Securities, as supplemented by
a First Supplemental Trust Indenture, dated as of November 15, 1994, and as
amended and supplemented by the Second Supplemental Trust Indenture dated as of
January 14, 1998.
"Project Letter of Credit Banks" means the financial institutions from
time to time parties to a Project Letter of Credit Facility.
"Project Letter of Credit Facility" means any agreement or agreements
from time to time in effect among the Partnerships and the Project Letter of
Credit Banks, and any replacements thereof which satisfies the requirements
under the Power Purchase Agreements, the Fluor Daniel Agreement and the
Prestwich Lease providing for the issuance of the Project Letters of Credit. No
Letters of Credit are currently outstanding in connection with the Fluor Daniel
Agreement or the Prestwich Lease.
"Project Letters of Credit" means the Letters of Credit securing the
Partnerships' obligations.
"Project Loans" means the loan made by ESI Tractebel Funding to each of
the Partnerships in connection with the Project Credit Agreement and the Project
Indenture.
"Project Notes" means (a) the promissory notes of the Partnerships
issued to ESI Tractebel Funding on December 1, 1994 pursuant to the Project
Credit Agreement, which notes were issued (x) to amend and restate the Original
Project Notes and (y) to evidence the Project Loans together with (b) any
promissory notes issued by the Partnerships to ESI Tractebel Funding subsequent
to December 1, 1994 in accordance with the terms of the Project Credit
Agreement.
"Project Partnership Agreements" means, collectively, the NEA
Partnership Agreement and the NJEA Partnership Agreement.
"Project Revenues," as defined in the Project Indenture means, for any
period, the sum of the following (without duplication) received by either of the
Partnerships, or credited to the account of either of the Partnerships as
described in clause (iii) below, on a cash basis during such period: (i) all
revenues
A-19
under the Power Purchase Agreements and the Steam Sales Agreements plus (ii) all
other revenues, whether from the sale of electrical capacity or electricity,
thermal energy or by-products of the operations of the Projects or otherwise
plus (iii) investment earnings on amounts in the Funds and on the investment of
the Cash Collateral Proceeds (and any substitute collateral for the Project
Letter of Credit Facility), but only to the extent such investment earnings have
been transferred to the Revenue Fund plus (iv) the proceeds of any business
interruption insurance and other payments received for interruption of
operations (excluding any proceeds of any physical damage or liability
insurance) plus (v) refunds of deposits plus (vi) all rental and other payments
received by either of the Partnerships from the lease or sale of any portion of
either or both of the Project Sites plus (vii) all other income, proceeds or
receipts, howsoever earned or received by either of the Partnerships during such
period plus (viii) Cash Collateral Proceeds (and any substitute collateral for
the Project Letter of Credit Facility) transferred to the Revenue Fund as a
result of any reduction in the Energy Bank Obligations. Project Revenues shall
exclude, to the extent otherwise included, (a) proceeds of the Project
Securities (including any such proceeds advanced to the Partnerships pursuant to
the Project Credit Agreement), (b) proceeds of borrowings under the Working
Capital Facility or any other permitted Debt, (c) Cash Collateral Proceeds (and
any substitute collateral for the Project Letter of Credit Facility) released
from the security of the Project Letter of Credit Banks or the Power Purchasers,
as the case may be, which are not the result of any reduction in the Energy Bank
Obligations and (d) Loss Proceeds.
"Project Secured Parties" include the holders of the Project Securities
(represented by the Project Trustee), the Sanwa Working Capital Banks, the Swap
Banks, if any, the Collateral Agent and the Project Trustee.
"Project Securities" means, collectively, the 2000 Project Notes, the
2002 Project Notes, the 2007 Project Bonds and the 2010 Project Bonds issued by
ESI Tractebel Funding under the Project Indenture.
"Project Security Documents" means the mortgages and other security
agreements pursuant to which the Partnerships, ESI Tractebel Funding and NE LP
grant liens to the Collateral Agent for the benefit of the Project Secured
Parties.
"Project Sites" means, collectively, the NEA Site and the NJEA Site.
"Project Trustee" means State Street Bank and Trust Company in its
capacity as trustee under the Project Indenture.
"Projections" means certain projections of the Projects' revenues and
the costs associated therewith including certain assumptions by NE LP.
"Projects" means, collectively, the NEA Project and the NJEA Project.
"Prudent Utility Practices" means the practices, methods and standards
generally followed by the independent power and electric utility industry with
respect to the design, construction, operation and maintenance of electric
generating equipment of the type applicable to the Projects, and which
practices, methods and standards generally conform to operation and maintenance
standards recommended by the applicable Project's equipment suppliers and
manufacturers.
"PSE&G Contract" means the Gas Purchase and Sales Agreement dated as
of May 4, 1989, as amended, between NJEA and PSE&G.
"PTFs" means pool transmission facilities.
A-20
"PSE&G" means Public Service Electric and Gas Company, a New Jersey
corporation.
"PUHCA" means the Public Utility Holding Company Act of 1935, as
amended.
"Purchase Agreement" means the Purchase Agreement, dated as of November
21, 1997, by and among the Sellers, the Partners, ESI Funding and Tractebel
Power for the acquisition of all of the partnership interests in the
Partnerships.
"PURPA" means the Public Utility Regulatory Policies Act of 1978, as
amended, and the regulations promulgated thereunder.
"QF" or "Qualifying Facility" means a "qualifying cogeneration
facility" in accordance with PURPA and the rules and regulations of FERC under
PURPA relating thereto.
"Qualifying Facility Power Purchase Rate" means the energy rate filed
from time to time by each of the NEA Power Purchasers and approved by the
Massachusetts Department of Public Utilities.
"Quarterly Tax Payment Dates" means, collectively, January 15, April
15, June 15 and September 15 of each calendar year or, in the event that any tax
payments contemplated by the definition of "Tax Requirements" shall become due
on any date or dates other than those provided for immediately above, any such
other date or dates on which such tax payments shall be due.
"Registration Rights Agreement" means the Registration Rights Agreement
dated as of the Closing Date, among ESI Tractebel Acquisition, NE LP and
Goldman.
"Regulation S" means Regulation S under the 1933 Act.
"Reimbursement Agreement" means the Reimbursement Agreement, dated as
of November 21, 1997 by and among FPL Group Capital, Tractebel Power and NE LP.
"Required Improvements" means improvements required to comply with any
change in applicable Environmental Laws or other Government Rules (or
interpretations thereof), or to maintain the status of a Project as a QF.
"Restricted Payments," as defined in the Project Indenture, means: (a)
(i) the declaration or payment of distributions or dividends by, or the
occurrence of any liability to make any such payment or distribution on account
of, either Partnership in cash, property, obligations or other securities on, or
(ii) other payments or distributions on account of, or (iii) the purchase,
redemption, retirement or other acquisition of, or (iv) the setting apart of
money for a sinking or other analogous fund for the purchase, redemption,
retirement or other acquisition of, any Partnership (whether general or limited)
interest (or any share capital of any class or any preferred stock issued by any
Permitted Successor (as defined in the Project Indenture), including redeemable
preferred shares, or any warrant, option or other right to acquire such share
capital or preferred stock, but excluding dividends or other distributions
payable solely in ordinary common shares of such Permitted Successor (as defined
in the Project Indenture)); and (b) any payment of the principal of or interest
on any subordinated indebtedness; and (c) the making of any loans or advances
from either Partnership or ESI Tractebel Funding to any Related Party (other
than certain permitted Debt contemplated by the Project Indenture).
"Revenue Fund" means the Fund entitled "Revenue Fund" established and
maintained by the Project Trustee pursuant to the Project Indenture.
A-21
"Rolling Prior Year" means, (i) as of December 1, 1994 and any date
occurring prior to the delivery to the Project Trustee of financial statements
of the Partnerships for any fiscal quarter ending after December 1, 1994, the
most recent period of four consecutive fiscal quarters of the Partnerships ended
prior to such date, treated as a single accounting period and (ii) as of any
other date, the most recent period of four consecutive fiscal quarters of the
Partnerships ended prior to such date (or shorter period commencing on December
1, 1994), treated as a single accounting period, with respect to which financial
statements shall have been delivered to the Project Trustee.
"Rule 144A" means Rule 144A under the 1933 Act.
"S&P" means Standard & Poor's Ratings Services, a division of McGraw
Hill.
"Sanwa Bank" means The Sanwa Bank, Limited, New York Branch.
"Sanwa Credit Agreement" means the Credit Agreement, dated as of
December 1, 1994, by and among the Partnerships, Sanwa Bank as issuing bank and
as agent, and the other banks named therein.
"Sanwa Letter of Credit Banks" means the financial institutions from
time to time parties to the Sanwa Letter of Credit Facility,
"Sanwa Letters of Credit" means the letters of credit issued by the
Sanwa Letter of Credit Banks to secure the Partnerships' Energy Bank
Obligations.
"Sanwa Working Capital Banks" means the financial institutions from
time to time parties to the Sanwa Working Capital Facility.
"Sanwa Working Capital Facility" means the Working Capital Facility
provided by the Sanwa Working Capital Banks pursuant to the Sanwa Credit
Agreement.
"Sargent & Lundy" means Sargent & Lundy, L.L.C., an Illinois limited
liability company.
"SEC" means the United States Securities and Exchange Commission.
"Second Supplemental Indenture" means the Second Supplemental Trust
Indenture dated as of January 14, 1998.
"Sellers" means those Sellers identified on Schedule I to the Purchase
Agreement.
"Sponsor Pledge Agreement" means the pledge agreement by ESI GP, ESI
LP, Tractebel GP, Tractebel LP, Tractebel Power and ESI Funding to the
Collateral Agent for the benefit of the Collateral Agent, the Trustee and the
holders of the Securities.
"Sponsors" means ESI Energy, Inc. and Tractebel Power, Inc.
"Spot Gas" means any natural gas purchased by either Partnership
pursuant to (a) arrangements and agreements having a term of one year or less,
(b) either ProGas Agreement subsequent to the ProGas Agreement Expiration Date
with respect thereto (i.e., during the period over which such ProGas Agreement
shall be extended on terms not constituting a Partial ProGas Extension Event) or
(c) any arrangements and agreements entered into after the date hereof and
covering a period subsequent to the earliest ProGas Agreement Expiration Date
and having a term greater than one year in duration.
A-22
"State Street Bank" means State Street Bank and Trust Company, a
Massachusetts banking corporation.
"Steam Sales Agreements" means, collectively, the NEA Steam Sales
Agreement and the NJEA Steam Sales Agreement.
"Subfunds" means the subfunds established and maintained by the Project
Trustee pursuant to the Project Indenture.
"Subordinated Debt" means all Debt of the Partnerships or ESI Tractebel
Funding subordinated in right of payment to the Project Securities in accordance
with certain requirements specified in the Project Indenture.
"Subordinated Management Fee" means, for each calendar year commencing
with the year in which the closing date occurs a portion of the Management Costs
referred to in clause (iv) of the definition thereof in an amount equal to
$1,500,000 (inflated annually commencing on January 1, 1999 and adjusted ratably
for each partial calendar year in which the Project Securities are outstanding).
"Substitute Debt Service Coverage Ratio" means, for any period, the
ratio of (a) the sum of (i) Operating Cash Flow for such period plus (ii) the
balance held in the Partnership Suspense Fund as of the date of determination of
the Substitute Debt Service Coverage Ratio to (b) Mandatory Debt Service for
such period.
"Substitute Letter of Credit" means an irrevocable standby letter of
credit (a) issued by a commercial bank whose long-term unsecured debt
obligations are rated (or whose bank holding company has long-term unsecured
debt obligations rated) at least "A" by S&P, "A2" by Moody's or "A" by Fitch (or
an equivalent rating by another nationally recognized credit rating agency of
similar standing if two or more of such corporations are not in the business of
rating long-term obligations of commercial banks) at the time of issuance, (b)
in a form reasonably acceptable to the Project Trustee, (c) with a minimum term
of one year (or shorter period ending on or after the final maturity date of the
Project Securities), (d) for the benefit of the Project Trustee, (e) which shall
not be a Debt of either ESI Tractebel Funding or either Partnership and shall
not be secured by or otherwise encumber any of the Project Collateral and (f)
providing for the amount thereof to be available to the Project Trustee in
multiple drawings, including a final drawing at any time within 30 days prior to
the expiration of such letter of credit for the full face amount thereof in the
event such letter of credit is not renewed or substituted with one or more other
Substitute Letters of Credit at such time, conditioned only upon presentation of
sight drafts accompanied by the applicable certificate in the form attached to
such letter of credit (and reasonably acceptable in form to the Project
Trustee).
"Substitute Letter of Credit Bank" means BankBoston, Bank Brussels
Lambert or any other financial institutions providing a Substitute Letter of
Credit.
"Swap Banks" means the financial institutions that are parties to the
Swaps.
"Swaps" means (i) the interest rate exchange agreements entered into by
the Partnerships with various financial institutions in connection with the
Original Project Credit Agreement and (ii) the interest rate exchange agreements
entered into by the Partnerships on December 1, 1994, in connection with the
issuance of the Original Project Securities.
"Tax Requirements," as defined in the Project Indenture, means, for
each Quarterly Tax Payment Date, the aggregate amount of Federal, New Jersey (in
the case of a partner of NJEA) and Massachusetts
A-23
(in the case of a partner of NEA) income taxes (including estimated tax payments
thereof) estimated to be payable by the partners on such Quarterly Tax Payment
Date, computed based upon and in accordance with the following assumptions: (a)
each partner shall be considered an unmarried individual without dependents
subject to tax on all income at the highest marginal rate of Federal and, as
applicable, New Jersey and/or Massachusetts income taxes whose only asset and
only source of income, gain, loss, deduction or credit is the Partnership(s)
(taking into account net operating loss, capital loss and any other loss or
credit carryforwards or carrybacks that would be available to such partner, and
that arise solely as a result of the income, gains, losses, deductions and
credits of the Partnerships and the deductibility of state income taxes for
Federal income tax purposes); (b) all income of the Partnerships subject to
Massachusetts income tax shall be treated as ordinary income, interest income,
dividend income or net capital gain in accordance with the relevant provisions
of Massachusetts income tax law; and (c) except as otherwise contemplated
pursuant to the next succeeding sentence, each partner pays its taxes for a
given calendar year in quarterly installments on the applicable Quarterly Tax
Payment Date; provided, that any such computation shall not give effect to, and
the term "Tax Requirements" shall not include, any income taxes payable as a
result of a dissolution of one or both Partnerships to the extent that such
income taxes exceed the amount of income taxes which would have been payable if
such dissolution had not occurred. The Tax Requirements, as of any date of
determination (the "Tax Determination Date"), shall be increased or reduced, as
the case may be, to reflect any difference between (x) the Tax Requirements for
any preceding Quarterly Tax Payment Date as originally computed (after giving
effect to any previous increase or reduction relating thereto) and (y) the Tax
Requirements for such preceding Quarterly Tax Payment Date as recomputed at the
Tax Determination Date to reflect any change in the original computation,
including, on an annual basis, any differences between any estimates of
Partnership income and expenses for any fiscal year (or any period during such
fiscal year) utilized in such computations and the actual Partnership income and
expenses for such fiscal year. In the case of a reduction that exceeds the Tax
Requirements amount calculated before giving effect to such reduction, each
subsequent Tax Requirements amount shall be reduced to the extent of such excess
until such excess has been fully offset against subsequent Tax Requirements. At
any time during which either NJEA, NEA or any Permitted Successor (as defined in
the Project Indenture) is itself an entity subject to Federal or, in the case of
NJEA, New Jersey, or in the case of NEA, Massachusetts, income or franchise or
similar taxes, the Tax Requirements attributable to NJEA, NEA or such Permitted
Successor (as defined in the Project Indenture), as the case may be, shall be
reduced by the amount of such Federal, New Jersey and Massachusetts taxes
payable by NJEA, NEA or such successor entity; provided, however, that in the
case of any such tax payable to New Jersey or Massachusetts, no such reduction
to the applicable Tax Requirements shall occur if the entity on which the tax is
imposed is treated as a pass-through entity in such jurisdiction.
"Texas Eastern" means Texas Eastern Transmission Line Corporation, a
Delaware corporation.
"Tractebel Belgium" means Tractebel S.A., a company organized under the
laws of Belgium.
"Tractebel GP" means Tractebel Northeast Generation GP, Inc., a
Delaware corporation.
"Tractebel LP" means Tractebel Associates Northeast LP, Inc., a
Delaware corporation.
"Tractebel Power" means Tractebel Power, Inc., a Delaware corporation.
"Tractebel" means Tractebel, Inc., a Delaware corporation.
"TransCanada" means Trans Canada Pipelines Limited, an Ontario
corporation.
"Transco" means Transcontinental Gas Pipe Line Corporation, a Delaware
corporation.
A-24
"Transco Agreement Expiration Date" means, with respect to each Transco
Agreement, the later of (a) October 31, 2006, and (b) the scheduled expiration
date of such Transco Agreement after giving effect to any Partial Transportation
Extension Events with respect to such Transco Agreement (it being understood
that, in the event of the continuance of such Transco Agreement on terms not
constituting a Partial Transportation Extension Event, the scheduled expiration
date of such Transco Agreement for purposes of this clause (b) shall be deemed
to be the last day through which such Transco Agreement was extended on terms
constituting a Partial Transportation Extension Event.
"Transco Agreements" means the Firm Gas Transportation Agreement for
Rate Schedule X-320 dated February 27, 1991 between Transco and NEA and the Firm
Gas Transportation Agreement for Rate Schedule X-319 dated February 27, 1991
between Transco and NJEA.
"Transco Extension Event" means the occurrence of each of the following
with respect to a Transco Agreement: (a) the extension of the term of such
Transco Agreement resulting in a scheduled expiration date therefor that is on
or after the final maturity date of the Project Securities and otherwise on
substantially the same terms and conditions contained in such agreement on
December 1, 1994, except for any changes to the charges for transportation
service applicable to the period of any such extension; and (b) the receipt by
the Project Trustee of a certificate of the Independent Gas Consultant to the
effect of (a) above.
"Transco Substitution Event" means the occurrence of each of the
following: (a) the execution by each Partnership and one or more third parties
of one or more gas transportation agreements providing for firm gas
transportation service to the Partnerships by such third party(ies) in
substitution of the firm transportation service provided to the Partnerships by
Transco under the Transco Agreements, which substitute firm gas transportation
service shall (i) be furnished during the period form the expiration date of the
Transco Agreements through a date no earlier than the final maturity date of the
Project Securities, (ii) cover volumes of gas for each Partnership not less than
those covered on December 1, 1994 under the Transco Agreements to which such
Partnership is (or was) party, and (iii) be on terms generally no less favorable
to each Partnership than those contained on December 1, 1994 in the Transco
Agreement to which such Partnership is (or was) party, except for changes to the
charges for transportation service; and (b) the receipt by the Project Trustee
of a certificate of the Independent Gas Consultant to the effect of (a) above
(other than with respect to (a)(iii) above).
"Trustee" means State Street Bank and Trust Company in its capacity as
trustee under the Indenture.
"Voting Stock" as defined in the Project Indenture means the Capital
Stock of any Person as of any date that such Person is at the time entitled to
vote in the election of the Board of Directors of such Person.
"Westinghouse Electric" means Westinghouse Electric Corporation, a
Pennsylvania corporation.
"Westinghouse Services" means Westinghouse Operating Services Company,
a Delaware corporation and a subsidiary of Westinghouse Electric.
"Working Capital Banks" means the financial institutions from time to
time parties to a Working Capital Facility.
"Working Capital Facility" means any agreement or agreements from time
to time in effect among the Partnerships and the Working Capital Banks providing
for the availability of working capital loans to the Partnerships in an
aggregate principal amount not to exceed $20 million.
A-25
"Working Capital Fund" means the Fund entitled "Working Capital Fund"
established and maintained by the Project Trustee pursuant to the Project
Indenture.
"Working Capital Loans" means loans provided under the Working Capital
Facility.
A-26
APPENDIX B
Bellingham and Sayreville Cogeneration Facilities
Due Diligence Review
Prepared for
ESI Energy, Inc. and
Tractebel Power, Inc.
SL-5171
February 12, 1998
55 East Monroe Street
Chicago, IL 60603-5780 USA
B-1
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SL-5171
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Bellingham and Sayreville Cogeneration Facilities
Due Diligence Review
Contents
Section Page
- ------- ----
ES EXECUTIVE SUMMARY.................................................................................. ES-1
Technical Review of the Cogeneration Facilities.................................................. ES-2
Technical Review of the Bellingham Carbon Dioxide Plant.......................................... ES-3
Plant Performance Review......................................................................... ES-3
Operation and Maintenance Review................................................................. ES-4
Pro Forma Financial Statement Review............................................................. ES-4
Permitting and Compliance Review................................................................. ES-5
1 INTRODUCTION....................................................................................... 1-1
Ownership Structure.............................................................................. 1-1
The Sites........................................................................................ 1-2
The Cogeneration Plants.......................................................................... 1-3
The Bellingham Carbon Dioxide Plant.............................................................. 1-4
Auxiliary Plant Services......................................................................... 1-5
Objective of Review and Methodology.............................................................. 1-6
Summary.......................................................................................... 1-7
- -------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-2
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SL-5171
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Contents (cont.)
Section Page
- ------- ----
2 TECHNICAL REVIEW OF THE COGENERATION FACILITIES..................................................... 2-1
Westinghouse 501D5 Combustion Turbines............................................................ 2-1
Design Basis................................................................................. 2-1
Operation and Maintenance.................................................................... 2-2
Heat Recovery Steam Generators.................................................................... 2-4
Design Basis................................................................................. 2-4
Operation and Maintenance.................................................................... 2-5
Westinghouse Steam Turbines....................................................................... 2-7
Design Basis................................................................................. 2-7
Operation and Maintenance.................................................................... 2-7
Air-Cooled Condenser/Air Removal System........................................................... 2-8
Design Basis................................................................................. 2-8
Operation and Maintenance.................................................................... 2-8
Balance-of-Plant Equipment........................................................................ 2-9
Condensate System............................................................................ 2-9
Boiler Feedwater System...................................................................... 2-9
Demineralized Water Treatment System......................................................... 2-10
Fire Protection System....................................................................... 2-10
Zero Discharge Wastewater Treatment System................................................... 2-11
Summary...................................................................................... 2-12
Electrical Components and Systems................................................................. 2-12
Bellingham Cogeneration Facility............................................................. 2-12
Sayreville Cogeneration Facility............................................................. 2-15
Plant Control System......................................................................... 2-17
- --------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-3
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SL-5171
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Contents (cont.)
Section Page
- ------- ----
Architectural/Civil/Structural Components and Systems...................................... 2-19
General Features of Both Facilities................................................... 2-19
Bellingham Cogeneration Facility...................................................... 2-20
Sayreville Cogeneration Facility...................................................... 2-22
Summary.................................................................................... 2-23
3 TECHNICAL REVIEW OF THE BELLINGHAM CARBON DIOXIDE PLANT.......................................... 3-1
Process Description and Design............................................................. 3-1
Operation and Maintenance History.......................................................... 3-2
Condensate Return Pump................................................................ 3-3
CO2 Oil Separator..................................................................... 3-4
Summary.................................................................................... 3-5
4 PLANT PERFORMANCE REVIEW......................................................................... 4-1
Capacity, Generation, and Heat Rate........................................................ 4-1
1991 Plant Acceptance Tests........................................................... 4-1
Operating Guarantees.................................................................. 4-2
Operating Performance................................................................. 4-3
Availability............................................................................... 4-4
Industry Averages..................................................................... 4-4
Station Performance................................................................... 4-5
Summary.................................................................................... 4-8
- --------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-4
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SL-5171
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Contents (cont.)
Section Page
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5 OPERATION AND MAINTENANCE REVIEW.................................................................... 5-1
Existing O&M Agreements....................................................................... 5-1
Bellingham Facility...................................................................... 5-2
Sayreville Facility...................................................................... 5-3
Nonfuel O&M Expenses.......................................................................... 5-4
Summary....................................................................................... 5-8
6 PRO FORMA FINANCIAL PROJECTIONS REVIEW.............................................................. 6-1
Operational Assumptions....................................................................... 6-2
Capacity................................................................................. 6-2
Availability............................................................................. 6-5
Heat Rate as Fuel Consumption per Kilowatt-Hour.......................................... 6-6
Power Generation Revenues..................................................................... 6-7
Power Sales Prices....................................................................... 6-7
Energy Banks............................................................................. 6-7
Gross Steam Production Income............................................................ 6-8
Project Operating Costs.................................................................. 6-8
Financing Costs.......................................................................... 6-9
Reserve Accounts......................................................................... 6-10
Base-Case Results............................................................................. 6-11
Sensitivity Analyses.......................................................................... 6-11
Sensitivity Case A: Increased Spot Gas Prices............................................ 6-11
Sensitivity Case B: Increased Inflation Rate............................................. 6-11
- --------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-5
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Contents (cont.)
Section Page
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Sensitivity Case C: Lower Station Availability....................................... 6-11
Sensitivity Case D: Lower Fuel Efficiency............................................ 6-12
Sensitivity Case E: No Merchant Power Sales.......................................... 6-12
Summary ................................................................................ 6-12
7 PERMITTING AND COMPLIANCE REVIEW.............................................................. 7-1
Bellingham Cogeneration Facility.......................................................... 7-1
Energy and Utility Approvals and Requirements........................................ 7-1
Environmental Impact Report.......................................................... 7-2
Soil and Groundwater Contamination................................................... 7-3
Air Pollution Control Permits........................................................ 7-3
Other Air Pollution Control Requirements............................................. 7-5
Noise Guidelines Compliance.......................................................... 7-6
Airspace Obstruction Approval........................................................ 7-7
Wastewater Discharges................................................................ 7-7
Water Withdrawal Permits............................................................. 7-8
Solid and Hazardous Waste Disposal................................................... 7-8
Chemical and Petroleum Storage....................................................... 7-9
Oil and Chemical Spill Response...................................................... 7-10
Wetlands and Floodplain Permits...................................................... 7-11
Zoning Approvals..................................................................... 7-12
Building Permits..................................................................... 7-13
Right-of-Way Permits................................................................. 7-13
Future Environmental Regulations..................................................... 7-13
CO2 Plant - Air Permit............................................................... 7-14
- --------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-6
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SL-5171
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Contents (cont.)
Section Page
- ------- ----
CO2 Plant - Chemical Spill Response.................................................. 7-15
Sayreville Cogeneration Facility.......................................................... 7-15
Energy and Utility Approvals and Requirements........................................ 7-15
Soil and Groundwater Contamination................................................... 7-16
Air Pollution Control Permits........................................................ 7-16
Noise Levels......................................................................... 7-19
Airspace Obstruction Approval........................................................ 7-19
Wastewater Discharges................................................................ 7-19
Water Withdrawal Permits............................................................. 7-21
Solid and Hazardous Waste Disposal................................................... 7-21
Chemical and Petroleum Storage....................................................... 7-22
Oil and Chemical Spill Response...................................................... 7-22
Wetlands and Stream Encroachment Permits............................................. 7-22
Zoning Approvals and Building Permits................................................ 7-23
Future Environmental Regulations..................................................... 7-23
Summary ................................................................................ 7-24
Appendixes
A Financial Projections for Base Case
B Financial Projections for Sensitivity Cases
- -------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-7
ES-1
SL-5171
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EXECUTIVE SUMMARY
Sargent & Lundy L.L.C. (Sargent & Lundy) has performed a due diligence review of
the Bellingham and Sayreville cogeneration facilities to provide an independent
assessment of the facilities' design bases, the quality of the facilities as
constructed, the operation and maintenance practices and budgets, the
performance history, the pro forma financial statements, and the environmental
permitting and compliance history. The Bellingham and Sayreville facilities are
two nominal 300-megawatt combined-cycle power plants developed by
Intercontinental Energy Corporation and acquired by Northeast Energy, L.P. and
Northeast Energy, L.L.C. The facilities are located in Bellingham,
Massachusetts, and Sayreville, New Jersey. The plants are similar in design and
construction and are currently being operated and maintained by Westinghouse
Electric Corporation under similar contractual arrangements. Each facility
consists of a cogeneration plant, together with site improvements,
administrative and other process-related buildings, and all necessary
interconnections. The Bellingham facility also includes a carbon dioxide (CO2)
plant that produces food-grade CO2.
Through our independent assessment, Sargent & Lundy is able to render the
following opinions:
o The facilities have been well constructed in accordance with
generally accepted engineering practices and are fully capable of
performing in accordance with the operating and financial
projections.
o The technology used for the projects is sound, is commercially
proven, and should provide an additional 20 years of service or
longer with proper operations and maintenance practices.
o An acceptable operation and maintenance program, including
provisions for planned major maintenance, has been established.
o The plants are clean, well operated, and well maintained. After
the current O&M agreements with Westinghouse expire, the facilities
will be operated and maintained by ESI Operating Services, Inc., an
affiliate of one of the new owners. ESI Operating Services, Inc. is
fully capable of operating and maintaining these combined-cycle
power plant facilities.
o Both plants have been operating for over six years, with higher
than guaranteed net capacities and lower than guaranteed plant heat
rates. The availabilities of the plants have exceeded guaranteed
levels and are higher than industry averages.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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o Each facility's electrical and steam production and overall
performance to date is consistent with the design of each facility.
The facilities are operating as baseload power plants. Through
1997, the Bellingham and Sayreville plants have achieved average
availability factors of 96% and 93.3%, respectively.
o The plants have in the past and are capable in the future of
meeting the requirements of the existing power purchase agreements.
o The pro forma projections reflect demonstrated plant performance
and include conservative estimates of future performance of the
facilities. The estimates of technical performance and of the
expenses for operations and maintenance of the facilities and other
similar operating assumptions used in the projections represent
conservative estimates and assumptions in light of the
circumstances of the projects. The budgets provide sufficient funds
for routine and major maintenance practices used in the industry to
minimize degradation of power output and heat rate. We expect that
maintenance expenses will be within the limits anticipated in the
budgets.
o Under the base-case assumptions, the pro forma financial
projections show a minimum debt service coverage ratio for the
Bonds of 2.25 times and an average debt service coverage ratio of
2.88 times over the life of the Bonds. The debt service coverage
ratios remain relatively stable over a broad range of
sensitivities.
o The facilities meet the environmental requirements of all
regulatory agencies, including those for Qualifying Facilities and
those required by the environmental permits, and we expect that
they will continue to do so in the future.
The significant findings of the review are presented by section in the following
summaries.
TECHNICAL REVIEW OF THE COGENERATION FACILITIES
General reviews of the design bases, construction, operation, and maintenance of
the Bellingham and Sayreville cogeneration plants were performed, including
reviews of design standards, drawings, and specifications. Walkdowns of each
facility were also performed to establish the present condition, and interviews
of key plant operations and maintenance personnel were conducted. Based on the
technical review, the facilities have been well constructed in accordance with
generally accepted engineering practices.
The conditions noted at each facility were usual for operating plants and should
not affect the long-term operability or maintainability of the units. Some
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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conditions do exist that require minor repair or modification, and the plant
personnel are aware of these conditions and have made or are making plans to
perform the required work. The costs associated with these repairs or
modifications are not significant and are within the amounts included in the
operation and maintenance budgets.
The plants have been successfully operated and maintained by Westinghouse
Electric Corporation since startup, and continued good operation and maintenance
practices by the owners should provide reliable long-term service from both
plants allowing the plants to meet their operating and financial projections.
TECHNICAL REVIEW OF THE BELLINGHAM CARBON DIOXIDE PLANT
The CO2 plant has been in operation since 1991 producing and marketing a
food-grade product. For the past 55 months, the plant has been operating
virtually 100% of the time, producing in excess of the design guaranteed
production quantities of food-grade CO2. This record is a result of a concerted
effort by the plant personnel to identify and eliminate the source of corrosion
that occurred during the startup operation and to establish new predictable
process operating parameters. Based on the consistency of current operations,
the CO2 plant should continue operating at its design parameters and within
projected operation and maintenance costs.
PLANT PERFORMANCE REVIEW
The performance and reliability test procedures, performance test correction
curves, operation and maintenance agreements, monthly generation reports, outage
reports, and other documents were reviewed to determine whether the guaranteed
performance parameters are being met and used correctly in projecting the future
performance of the plants. The demonstrated capacity and heat rate of each plant
have shown little anneal variance, and each plant has consistently achieved the
contract performance guarantees. The average yearly availabilities for both
plants are consistently higher than the industry average for newer
combined-cycle plants. Finally, the Bellingham CO2 plant has also demonstrated
its capability to produce the design quantity and quality of CO2 and to utilize
the necessary amount of steam to fulfill the cogeneration plant's Qualifying
Facility requirements. The historical performance of the plants should result in
a reasonably accurate forecast of future plant performance.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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OPERATION AND MAINTENANCE REVIEW
The Operation and Maintenance (O&M) budget estimates for the Bellingham and
Sayreville facilities were assessed in light of the operating history of the two
plants and industry experience. The purpose of this assessment was to determine
whether the O&M budget estimates are adequate, conservative and consistent with
expected performance characteristics.
The review of the O&M budget estimates for the Bellingham and Sayreville
facilities indicates that the budgets represent reasonable estimates and
assumptions. The budgets provide sufficient funds for routine and major
maintenance practices used in the industry to minimize degradation of power
output and heat rate. The minor corrective actions suggested in this report,
such as routine painting, HRSG tubing inspection and repair, and HRSG foundation
pier inspection and repair, can all be implemented within this budget. Based on
the review of the existing O&M agreements, the specified payments to the
operator should be sufficient to support expected plant performance, and the
liquidated damages for fuel consumption and steam output should be sufficient to
maintain expected net income. The liquidated damages for electrical output
mitigate lost income in the event of reduced plant output and, together with the
bonus provisions, provide an economic incentive to the operator to maintain or
exceed the output guarantee. Once the existing O&M agreements expire, the owner
will bear additional risk for plant performance since the liquidated damage and
bonus incentive will no longer exist. Since the new entity performing the O&M
activities is an affiliate of one of the new owners, the new operator will have
a greater incentive to maintain or improve on the high levels of performance
achieved in the past.
PRO FORMA FINANCIAL STATEMENT REVIEW
The annual debt service coverage ratios for the base case and sensitivity cases
presented by Northeast are shown in the following table. These coverage ratios
represent cash distributions to Northeast divided by scheduled annual debt
service on the Bonds.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Annual Bond Debt
Service Coverage Ratios
Minimum Average
----------------------------- ---------------------
Base Case 2.25 x 2.88 x
Sensitivity Case A 2.21 x 2.87 x
Sensitivity Case B 2.17 x 2.80 x
Sensitivity Case C 2.05 x 2.65 x
Sensitivity Case D 1.88 x 2.33 x
Sensitivity Case E 1.37 x 2.59 x
The debt service coverage ratios under the base case and sensitivity cases
remain relatively stable over a broad range of sensitivities around the key
parameters discussed in this report.
Based on a review of the structure of the pro formas and a detailed review of a
sample of the more significant calculations, the financial model appears
accurate and in accordance with industry practice, and the pro forma financial
projections are reasonable forecasts of the future financial performance of the
projects.
PERMITTING AND COMPLIANCE REVIEW
Based on the environmental permitting and compliance review of the Bellingham
and Sayreville cogeneration facilities, the following conclusions were reached:
o All of the permits and approvals currently required for
construction and operation of the plants have been obtained.
o The plants have been operating in compliance with all of their
permit conditions, except for minor exceedances of NOX emission
limits at Sayreville, which have been adequately addressed.
o Based on the physical walkdowns of the facilities, interviews with
key plant personnel, and reviews of documents and records, the
plants should be able to operate in compliance in the future based
on the procedures and equipment now in place.
o The plants have been operating in compliance with qualifying
facility requirements as defined under the Public Utilities
Regulatory Policies Act.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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o The four environmental releases, a fuel oil spill and three
chemical spills at Bellingham, were promptly and effectively
resolved and actions were taken to prevent future occurrences.
Additional remediation of the oil spill at Bellingham is required.
This remediation continues to be the responsibility of
Westinghouse. To date, Westinghouse has diligently pursued closure
of this issue, and the remediation effort has apparently been
satisfactory to the relevant environmental authorities. There
should be no additional impacts to the operation of the facilities
because of these spills.
o The plants are required to obtain Title V Operating Permits, and
the owner is actively pursuing issuance of the permits. There is no
reason to believe the plants will be adversely affected by the
permits.
Due to the existing systems already in place, the facilities are generally well
designed to meet any expected requirements from future environmental
regulations.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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SARGENT & LUNDY, by
/s/ J. G. Gatz /s/ C. A. Radek
- --------------------------------------- ----------------------------------------------
J. G. Gatz C. A. Radek
Project Manager Structural Engineer
Power Generation Systems Division Structural & Civil Division
/s/ D. R. Harvin /s/ L. A. Valerio
- --------------------------------------- ----------------------------------------------
D. R. Harvin L. A. Valerio
Financial Analyst Senior Electrical Engineer
Project Financial Services Division Mechanical Project Engineering Division
/s/ R. J. Kerhin /s/ H. H. Wisch
- --------------------------------------- ----------------------------------------------
R. J. Kerhin H. H. Wisch
Quality Control Specialist Combustion Turbine Specialist
Materials Engineering Division Mechanical Project Engineering Division
/s/ R. S. Light
- ---------------------------------------
R. S. Light
Senior Environmental Engineer
Air & Water Quality Division
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Section 1
INTRODUCTION
The two nominal 300 megawatt (MW) combined-cycle power plant facilities are
located in Bellingham, Massachusetts, and Sayreville, New Jersey, on sites that
are owned in fee simple. The locations of the facilities are shown in Exhibit
1-1. The two cogeneration plants are similar in design and construction and are
currently being operated and maintained by Westinghouse Electric Corporation
(Westinghouse) under similar contractual arrangements. Each facility consists of
a cogeneration plant, together with site improvements, administrative and other
process related buildings, and all necessary interconnections. The Bellingham
facility also includes a carbon dioxide (CO2) plant that produces food-grade
CO2.
OWNERSHIP STRUCTURE
The facilities were developed by Intercontinental Energy Corporation (IEC),
which held a 1% general partnership interest in Northeast Energy Associates
(NEA) and limited partnership interests. The facilities were acquired by
Northeast Energy, L.P. (Northeast) and Northeast Energy, L.L.C. (NE, L.L.C.), a
wholly-owned subsidiary of Northeast. Northeast purchased IEC's 1% general
partnership interest as well as all of the limited partnership interests in NEA
except for a 1% limited partnership interest purchased by NE, L.L.C.
Fifty percent of Northeast is owned and controlled, through wholly-owned
subsidiaries, by ESI Energy, Inc. (ESI). ESI has 31 projects in its portfolio,
including natural gas, geothermal and wind facilities, and is one of the largest
independent power companies in the United States of America. ESI is an indirect
wholly-owned subsidiary of FPL Group, Inc. (FPL Group), a holding company whose
stock is traded on the New York Stock Exchange. FPL Group's total assets as of
June 30, 1997, exceeded $12.7 billion and its revenue and net income for its
fiscal year ended 1996 exceeded $6 billion and $579 million, respectively.
FPL Group is also the parent company of Florida Power & Light Company (FPL), one
of the largest investor-owned utilities in the United States. FPL serves
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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approximately 3.6 million customers within a service area that includes most of
the eastern and southern regions of the state of Florida. FPL has experience in
operating cost-effective generation while maintaining high plant availability.
The other fifty percent of Northeast is owned and controlled, through
wholly-owned subsidiaries, by Tractebel Power, Inc. (TPI). TPI is a wholly-owned
subsidiary of Tractebel Inc. (Tractebel), which in turn is a wholly-owned
subsidiary of Tractebel, S.A. a major energy and industrial group founded in
1895 and based in Brussels, Belgium (Tractebel Belgium). Tractebel Belgium, with
annual revenues of approximately $10 billion in its fiscal year ended December
31, 1996, is a world leader in the electric power generation and transmission
industry and produces approximately 23,000 MW globally. Tractebel Belgium's two
primary U.S. operating subsidiaries are TPI and Tractebel Energy Marketing, Inc.
TPI concentrates on acquiring, developing, and operating independent power
facilities in North America and, together with its subsidiaries, currently owns
14 power projects in the United States. Tractebel Power Operations, Inc., a
subsidiary of TPI, provides administration and operations and maintenance
services for 13 of the projects.
THE SITES
The Bellingham facility is located on an industrially zoned 44-acre site in the
town of Bellingham, Massachusetts, near the upper Charles River. The site is
readily accessible from Interstate Route 495 and by a railroad line belonging to
Consolidated Rail Corporation (Conrail). The facility is close to Boston Edison
Company's Medway substation and less than a mile from a 345-kilovolt (kV) power
line through which the plant is interconnected with Boston Edison Company,
Commonwealth Electric Company, and Montaup Electric Company. The Algonquin Gas
Transmission Company (Algonquin) gas pipe runs within the site boundary.
The Sayreville facility is located on an industrially zoned 49-acre site in the
borough of Sayreville, New Jersey. The site is easily accessible by the Garden
State Parkway, the New Jersey Turnpike, and a Conrail railroad line. A
Transcontinental Gas Pipe Line Corporation (Transco) natural gas pipeline runs
within 200 yards of the site, and the facility is interconnected with Jersey
Central Power & Light Company (JCP&L) through a one-mile power line.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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A photograph of the Bellingham Cogeneration Facility and the site plot plan are
presented in Exhibits 1-2 and 1-3, respectively, and a photograph of the
Sayreville Cogeneration Facility and the site plot plan are presented in
Exhibits 1-4 and 1-5, respectively.
THE COGENERATION PLANTS
Each cogeneration plant, nominally rated at 300 MW, consists of the following
major equipment:
o Two Westinghouse 501D5 combustion turbines and associated electric
generators and transformers
o Two unfired heat recovery steam generators (HRSGs)
o One Westinghouse steam turbine and associated electric generator
and transformer
o One air-cooled steam condenser
o Balance-of-plant equipment consisting of a condensate system,
deaerator, boiler feedwater system, high- and low-pressure steam
systems, demineralizer system, and fire protection system
A zero discharge wastewater treatment system is installed at Bellingham.
Westinghouse has recently provided 21 501D5 combustion turbines for simple-cycle
and combined-cycle power plants with a total generation of 2570 MW. The
Westinghouse scope for these power plants ranged from equipment supply only to
complete turnkey installations. Approximately 235 combustion turbines of the 501
series are currently in service, of which 85 are 501D5 units.
At each facility, the combustion and steam turbines and their associated
auxiliary equipment are located within a building. Two bridge-type cranes are
installed to service the combustion and steam turbines for maintenance.
Natural gas is the primary fuel for both Bellingham and Sayreville. Natural gas
is supplied to the sites via pipelines. The environmental permits for the
Bellingham facility provide for the combustion turbines to fire low-sulfur No. 2
fuel oil for a maximum of 1440 turbine-operating hours per year.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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The exhaust gases from the combustion turbines pass through the HRSGs, providing
heat to generate steam, and then exhaust into the atmosphere through a common
chimney. The chimney has one liner at Bellingham and two liners at Sayreville.
The steam generated in the HRSGs is used to generate power in the steam
turbines, for NOX control, and for process steam used in the carbon dioxide
plant at Bellingham and for sale to Hercules Incorporated (Hercules) at
Sayreville.
Plant exhaust gas emissions are continuously monitored. The emissions are
controlled by restrictions on contaminants in the fuel supply, by the combustion
turbine combustor basket design, and by steam injection for NOX control.
At Bellingham, the facility interconnects with a 345-kV power line collectively
owned by Boston Edison Company, Commonwealth Electric Company, and Northeast
Utilities. Boston Edison Company, Commonwealth Electric Company, and Montaup
Electric Company collectively purchase all of the power generated, generally, on
a pro rata basis. In addition, approximately 4 MW of power is provided directly
to the carbon dioxide plant. At Sayreville, the facility interconnects with a
230-kV line owned by JCP&L, which currently purchases all of the power
generated.
THE BELLINGHAM CARBON DIOXIDE PLANT
The Bellingham carbon dioxide plant is designed to produce 350 tons per day of
food-grade CO2. The plant is located adjacent to the cogeneration plant on the
Bellingham site. The control room and office area, electrical equipment, CO2
purification equipment, and a 5-ton overhead maintenance crane are housed in a
multifunction prefabricated steel building. Most of the process equipment is
located outdoors.
Carbon dioxide is recovered from the exhaust gas produced by the combustion
turbines in the cogeneration plant using an amine technology developed by Dow
Chemical Company and acquired by Fluor Daniel. This proprietary technology was
developed to recover carbon dioxide from exhaust gases containing low volumes of
carbon dioxide and high volumes of oxygen. The exhaust gas at Bellingham
contains approximately 3% by volume of carbon dioxide and 12% oxygen. From 10%
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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to 15% of the exhaust gas produced by the combustion turbines is diverted to the
carbon dioxide plant. The remainder of the exhaust gas is emitted to the
atmosphere through the chimney.
The recovered carbon dioxide is purified and liquefied using standard industry
technology. The liquid carbon dioxide is stored in eight 200-ton storage tanks
from which it is loaded into trucks for distribution. The site also has the
capability of loading CO2 into rail cars for distribution.
AUXILIARY PLANT SERVICES
At Bellingham, railroad service is supplied by a connection to an existing
Conrail line that accesses one corner of the site. Process water is supplied
from three dedicated offsite wells and augmented when required by two onsite
wells. Storage for 2,500,000 gallons of water is provided in a single tank, in
addition to a 1,000,000-gallon raw water tank that contains a reserve water
supply for fire protection.
Fuel oil is stored in a single 2,500,000-gallon tank with the necessary
spill-prevention protection and ancillary loading and unloading facilities.
At Sayreville, raw water, in an amount equal to the steam exported to Hercules
plus 15%, is supplied from the Hercules private water supply system. Additional
process and potable water is supplied from the municipal water system.
Offices for the administrative and operations and maintenance personnel and a
workshop are included within the turbine building of each facility.
OBJECTIVE OF REVIEW AND METHODOLOGY
The objective of this review was for Sargent & Lundy L.L.C. (Sargent & Lundy) to
provide an independent assessment of the facilities' design bases, the quality
of the facilities as constructed, the operation and maintenance (O&M) practices
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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and budgets, the performance history, the pro forma financial statements, and
the environmental permitting and compliance history for the Bellingham and
Sayreville cogeneration facilities.
Sargent & Lundy performed a walkdown of the facilities, interviewed the key
plant personnel, and reviewed the following documentation to accomplish this
objective in an effective manner:
o Plant design documents including--
-- site drawings
-- general arrangement drawings
-- heat, mass, and water balances
-- process flow and piping & instrumentation diagrams
-- electrical single-line diagrams
-- major electrical, mechanical and structural specifications, and physical
drawings
o Plant operation and maintenance records including--
-- historical capacity, heat rate, and availability information
-- historical power generation, steam generation, fuel consumption, and
planned maintenance hours
-- operating conditions of major plant components and systems
forced outages and deratings and corrective actions taken
-- qualifying facility compliance records
o Plant contractual agreements including--
-- power purchase agreements steam sales agreements gas supply agreements
-- O&M agreements
o Pro forma financial projections
o Applicable environmental requirements including--
-- energy and utility approvals and requirements
-- air and water pollution control permits
-- waste disposal permits and requirements
-- various other environmental permitting requirements
- --------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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o Plant environmental records including--
-- permit applications and permits received
-- environmental records and reports prepared as required by the
permitting agencies
-- environmental compliance issues and corrective actions taken
In performing the review of past performance, Sargent & Lundy focused on the
first six years of operation from September 1991 through September 1997.
SUMMARY
Sargent & Lundy was provided access to the facilities, the key plant personnel,
and the necessary documentation to provide an independent assessment of the
Bellingham and Sayreville cogeneration facilities and a review of cash flow
available to cover debt service on the Bonds. Based on this review, we are able
to render the following opinions:
o The facilities have been well constructed in accordance with
generally accepted engineering practices and are fully capable of
performing in accordance with the operating and financial
projections.
o The technology used for the projects is sound, commercially
proven, and should provide an additional 20 years of service or
longer with proper operations and maintenance practices.
o An acceptable operation and maintenance program, including
provisions for planned major maintenance, has been established.
o The plants are clean, well operated, and well maintained. After
the current O&M agreements with Westinghouse expire, the facilities
will be operated and maintained by ESI Operating Services, Inc., an
affiliate of one of the new owners. ESI Operating Services, Inc. is
fully capable of operating and maintaining these combined-cycle
power plant facilities.
o Both plants have been operating for over six years, with higher
than guaranteed net capacities and lower than guaranteed plant heat
rates. The availabilities of the plants have exceeded guaranteed
levels and are higher than industry averages.
o Each facility's electrical and steam production and overall
performance to date is consistent with the design of each facility.
The facilities are operating as baseload power plants. Through
1997, the Bellingham and Sayreville plants have achieved average
availability factors of 96% and 93.3%, respectively.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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o The plants have in the past and are capable in the future of
meeting the requirements of the existing power purchase agreements.
o The pro forma projections reflect demonstrated plant performance
and include conservative estimates of future performance of the
facilities. The estimates of technical performance and of the
expenses for operations and maintenance of the facilities and other
similar operating assumptions used in the projections represent
conservative estimates and assumptions in light of the
circumstances of the projects. The budgets provide sufficient funds
for routine and major maintenance practices used in the industry to
minimize degradation of power output and heat rate. We expect that
maintenance expenses will be within the limits anticipated in the
budgets.
o Under the base-case assumptions, the pro forma financial
projections show a minimum debt service coverage ratio for the
Bonds of 2.25 times and an average debt service coverage ratio of
2.88 times over the life of the Bonds. The debt service coverage
ratios remain relatively stable over a broad range of
sensitivities.
o The facilities meet the environmental requirements of all
regulatory agencies, including those for Qualifying Facilities and
those required by the environmental permits, and we expect that
they will continue to do so in the future.
This report presents the results of the review on which we based these opinions.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Section 2
TECHNICAL REVIEW OF THE COGENERATION FACILITIES
The design bases, construction, operation, and maintenance of the major
components and systems of the Bellingham and Sayreville cogeneration facilities
were reviewed. The following components and systems were included in this
review:
o Westinghouse 501D5 combustion turbines
o Heat recovery steam generators (HRSGs)
o Westinghouse steam turbines
o Air-cooled condenser/air removal system
o Balance-of-plant equipment
o Electrical components and systems
o Architectural/civil/structural components and systems
The technical review of the Bellingham carbon dioxide plant is presented in
Section 3.
WESTINGHOUSE 501D5 COMBUSTION TURBINES
Design Basis
Each plant utilizes two Westinghouse 501D5 combustion turbine-generators for
power generation and to provide high-temperature exhaust gas to the HRSGs for
steam production. Each Westinghouse 501D5 combustion turbine consists of a
high-efficiency 19-stage axial compressor, a combustion cylinder with 14
combustors interconnected in a circular array parallel to the rotor axis, and a
4-stage reaction turbine. The principal fuel for the Bellingham and Sayreville
combustion turbines is natural gas, although the Bellingham facility has been
designed for the combustion turbines to fire low-sulfur No. 2 fuel oil.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Westinghouse has supplied 85 combustion turbines of this design since 1981, and
the 501D5 combustion turbine has no inherent design defects. The 501D5
combustion turbine is a sound, commercially proven technology, based on over 40
years of Westinghouse design and manufacturing experience.
The combustion turbines installed at the Bellingham and Sayreville plants were
manufactured in 1990 by Mitsubishi Heavy Industries, Ltd. (MHI) in Takasago,
Japan, where Westinghouse-designed combustion turbines have been produced under
license for more than 25 years.
Operation and Maintenance
All four combustion turbines are normally operated in continuous service, and
therefore, the combustion turbines have not experienced many startup-shutdown
cycles. The combustion turbines are normally brought offline only for scheduled
maintenance or routine compressor water-washing to maintain power output and
efficiency. The Bellingham combustion turbines normally operate at baseload
power. The Sayreville combustion turbines normally operate at baseload
temperature, but with reduced airflow and power due to the terms of the existing
power purchase agreement (PPA) with JCP&L wherein JCP&L purchases approximately
250 MW of output.
The monthly availabilities for both plants are consistently higher than industry
average availabilities. Since plant commissioning, the Bellingham units have
experienced 58 forced outages, and the Sayreville units have experienced 19
forced outages. All but two of the forced outages were minor and of relatively
short duration, as discussed in Section 4. The plant O&M personnel took prompt
effective corrective actions to resolve the problems.
At Bellingham, a major forced outage of Combustion Turbine Number 1 (No. 1)
occurred in December 1992. The combustion turbine incurred extensive mechanical
damage when a failed transition piece released debris into the turbine flow
path, destroying all four stages. The combustion turbine was rebuilt and
returned to baseload service in 28 days. The origin of the transition piece
failure was a minor crack that occurred in the rear support as the result of a
marginal shop weld. All suspect transition pieces were replaced with redesigned
versions or with transition pieces having significantly improved welds.
Operating procedures and personnel training were also enhanced immediately.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Based on the results of annual inspections over the past six years, there have
been no indications of cracks. The affected combustion turbine has since
operated at full design capacity, and this problem is considered to be
successfully resolved.
Since the rotor of this combustion turbine was replaced in December 1992
following the transition piece failure, this combustion turbine has experienced
turbine-end vibration problems. In a typical excursion, vibration amplitudes
increase substantially without notice and without a corresponding change in
phase angle. Within 30 to 60 minutes of the beginning of the vibration
excursion, the combustion turbine must be tripped. Normal restart can then be
initiated immediately, and the problem does not recur for several days or weeks.
Several such excursions may occur during a year. Although running vibration
remains at acceptable amplitudes of 2.0 to 2.5 mils, amplitudes increase during
such events. This phenomenon has been the subject of numerous studies, and the
major inspection scheduled for May 1998 may reveal the root cause of the
vibration, which is currently believed to be a rub.
In August 1993, a third-stage turbine blade failed in the Sayreville No. 1
combustion turbine. The resultant damage required the replacement of all third-
and fourth-stage turbine components. The root cause for this failure has not
been completely established, but is believed to be either a defective blade or
corrosion. There are no other known failures of this blade design. All
replacement blades were coated to prevent future corrosive attack. Since the
event, this combustion turbine has been operated at required power without
incident, and this problem is considered to be successfully resolved.
In summary, the Westinghouse combustion turbines installed at Bellingham and
Sayreville have performed well and have contributed to higher-than-average
availabilities. All but two of the forced outages that have occurred were minor,
and O&M personnel took prompt effective corrective actions to resolve the
problems that caused the outages. The root causes of the two major outages have
been addressed, and the units have been operated as required without further
incidents. With continued good operation and maintenance practices, the
combustion turbines should provide reliable long-term service.
- -------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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HEAT RECOVERY STEAM GENERATORS
Design Basis
The heat recovery steam generators (HRSGs) installed at both plants were
designed and manufactured by Nooter/Eriksen Cogeneration Systems, Inc.
(Nooter/Eriksen). Nooter/Eriksen has designed and built over 100 HRSGs and is
well known in the power industry as a quality supplier of this type of
equipment. Each combustion turbine is fitted with one HRSG at its exhaust, which
recovers heat from the exhaust gas to produce steam from treated, deaerated
boiler feedwater at fixed pressures. The steam produced in each HRSG is mainly
used in the steam turbine for power production. In addition, steam is used for
injection into the combustion turbine combustors for NOX emissions control and
for process steam export. Each of the HRSGs has a two-pressure configuration and
a top-supported, natural-circulation, water tube design. Each of the HRSGs is
rated at the following steam conditions:
Design Operating Design
Pressure Pressure Temperature
--------- ---------- -----------
High-pressure (HP) steam 1145 psig 985 psig 938(0)F
Low-pressure (LP) steam 185 psig 85-90 psig 400(0)F
The heating surface of each HRSG is enclosed in a gas-tight outer casing with
internal insulation covered by floating internal liners. The HRSGs have
provisions to maintain the steam system in a warm condition overnight to enable
hot restart. Primary steam flow at the design point is 340,660 lb/hr at 945 psig
and 938(Degree)F. Side seals exist at every third row throughout the HRSG to
maintain performance. The superheaters, evaporators, and economizers are fully
drainable.
Operation and Maintenance
The HRSGs at both plants are operated below their rated pressure. Initially,
there were several minor outages associated with valve leaks and heat tracing.
These problems were resolved. In 1994, tube leaks were discovered in the
low-pressure (LP) evaporator at Sayreville. The HRSG boiler tubes have
experienced some internal erosion/corrosion that has resulted in tube leaks.
Laser optic inspections of the inside diameter of the boiler tubes were
performed by QUEST Integrated, Inc. in 1996. These inspections showed that the
majority of the flow-assisted corrosion (FAC) was located in the upper elbows
and small portions of the vertical straight tubes on the hot side of the LP
evaporator.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-26
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The root cause of this phenomenon has not been determined but may be a
combination of the following factors:
* flow-related design problems
* low carbon steel material
* boiler water chemistry
* operating parameters
Westinghouse has striven to address all of these factors.
To address the flow-related aspects, 10 taps have been installed on each HRSG,
and Deltak has been contracted to perform a flow analysis of the system.
Based on similar experience in the industry, Westinghouse has elected to replace
the most susceptible tubing, and over 500 three-foot long sections of tubing
have been replaced. Most of this work was performed during the October 1997
outage. A 3-foot section consisting of the elbow and adjacent SA 178 carbon
steel tubing was replaced with SA 213 Grade T 22 tubing. This new tubing
contains 2-1/4% chromium and 1% molybdenum, which has been shown to have
approximately 40 times the resistance to FAC than carbon steel. In addition, the
initial wall thickness of the 2-inch outer diameter tubes was 0.105 inch but the
replacement tubes have a wall thickness of 0.220 inch. Since this method of
repair has been successfully implemented at other facilities, Westinghouse
believes that this additional tube wall thickness plus the corrosion resistance
of the T 22 material will eliminate any further problems in these areas. While
it is not known whether other tubes might be susceptible in the future,
Westinghouse intends to perform ongoing inspections to identify and resolve any
future occurrences of this problem.
Concerning boiler water chemistry, the oxygen scavenger used at Sayreville is
more corrosive than that used at Bellingham. Due to Food and Drug Administration
(FDA) requirements at the steam host, Hercules, the same
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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scavenger used at Bellingham cannot be used at Sayreville. The different water
chemistry may contribute to the problem.
Finally, the units at Sayreville operate below capacity, and therefore, the LP
boiler operates at a higher temperature. The fluid in the area experiencing FAC
may actually be a two-phase fluid instead of water, which would dramatically
increase FAC.
In conclusion, while the root cause of the leaks has not been determined, the
replacement of over 500 susceptible elbows should eliminate the problem since
this method of repair has been successfully implemented at other facilities. The
plant operators recognize that continued surveillance is required, and it is
possible that a similar replacement may be required on the cold side of the LP
evaporators.
The cyclones that remove moisture from the steam entering the steam drum have
significant wear also probably as a result of FAC. Thirteen cyclones were
removed for repair or replacement due to holes at the first turn where the fluid
exits from the baffle. The current method of repair is to weld a piece of 2-1/4%
chromium and 1% molybdenum sheet metal to the worn area and place the cyclones
back into service. This repair appears to be successful, but the repair must be
performed to all 88 cyclones.
The HRSGs at Bellingham have not experienced any similar FAC. Either because of
the different operating parameters or boiler water chemistry, there is little
wear in the tubes of the Bellingham HRSGs. At Bellingham, the cold end of the
high-pressure evaporator has deposits from the boiler water, which have caused a
few leaks. These deposits require cleaning during the outages. With continued
good operation and maintenance practices, the HRSGs at both facilities should
provide reliable long-term service.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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WESTINGHOUSE STEAM TURBINES
Design Basis
Each of the two plants uses one Westinghouse steam turbine to convert the steam
produced by the two HRSGs into mechanical energy, which is then used to create
electrical power in the generator connected to the steam turbine. The steam
turbine at each of the plants is a Westinghouse single-flow, single-casing,
nonreheat design with an upward exhaust. The maximum capacity of the Bellingham
steam turbine is 108,290 kilowatts (kW) at 935 psig and 915(degree)F, and the
maximum capacity of the Sayreville steam turbine is 101,740 kW at 928 psig and
934(degree)F. Sayreville exports a significant quantity of steam to Hercules,
while a lesser quantity is used by the Bellingham CO2 plant. The condenser
backpressure is 2.5 in. HgA at each site. Low-pressure steam is admitted to the
steam turbine at approximately 80 psig and 405(0)F, and steam for combustion
turbine NOX control is extracted from the steam turbine at approximately 325
psig and 700(0)F. Westinghouse has designed and manufactured hundreds of steam
turbines of similar configuration and size, and is generally viewed in the power
industry as a high-quality supplier of steam turbine-generator units.
Operation and Maintenance
On the days of the site visits, all units were observed to be operating at
normal power output. The operators advised that the condenser pressure is
consistently maintained below the steam turbine exhaust pressure alarm and trip
points.
Based on the outage reports for both plants, no major forced outages have been
caused by the steam turbine-generators and related auxiliary equipment during
the September 1991 through September 1997 period. At Bellingham, 14 minor forced
outages occurred during the period due to the steam turbine. At Sayreville,
there were 4 minor forced outages during the same period. These outages were
associated with minor problems such as flange gasket leaks and valves sticking
closed. With continued good operation and maintenance practices, these steam
turbines should provide reliable long-term power generation.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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AIR-COOLED CONDENSER/AIR REMOVAL SYSTEM
Design Basis
The air-cooled condensers installed at the Bellingham and Sayreville plants
accept steam from the steam turbine exhaust and condense the steam to water by
distributing the steam through finned tubes that are cooled by fans providing
air flow across the tubes. All condensate is directed to the condensate tank
and, from there, is pumped to the plant feedwater system. The air-cooled
condensers are each comprised of 16 bays arranged in a four-row A-frame
configuration mounted on a steel support structure. Each bay is served by a
two-speed electric motor-driven fan that provides convective upward airflow
across the fin tubes. The fans are a multi-blade, axial flow design and are
driven by individual motors and gearboxes. An air ejection system is provided to
remove noncondensibles from the condenser and connected systems during operation
and before condenser startup. The ejector system consists of two single-stage
hogging and twin-element, two-stage holding steam jet ejectors. Under normal
operating conditions, only one of the two holding ejector elements is required
for maintaining vacuum. These condensers were designed and built by GEA Power
Cooling Systems, a well-known supplier of air-cooled condensers that has
installed over 80 units of similar designs since 1939.
Operation and Maintenance
Each site had one inoperative fan during the site visit; however, Westinghouse
advised that all fans will be operating by spring 1998. While one inoperative
fan is not a problem during winter, each site has been known to lose 5 to 10 MW
of output due to high back-pressure when ambient temperatures exceed
90(degree)F. Available engineering weather data, from various government data
sources, indicate that the dry bulb temperature in Massachusetts will equal or
exceed 90(Degree)F, on the average, 0.7% of the hours in a year (62 hours per
year) and that the dry bulb temperature in New Jersey will equal or exceed
90(degree)F, on the average, 1.3% of the hours in a year (114 hours per year).
The air-cooled condensers are well maintained, being cleaned as necessary to
maintain performance. From September 1991 to September 1997, there have been no
air-cooled condenser-related forced outages at
- -------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-30
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Bellingham and only one minor outage at Sayreville due to a faulty gasket. With
continued proper operation and maintenance practices, the air-cooled condenser
and air removal system should provide reliable long-term service.
BALANCE-OF-PLANT EQUIPMENT
Condensate System
Identical condensate system designs are used at the Bellingham and Sayreville
plants. At each site, condensate from the air-cooled condenser and makeup from
the vacuum deaerator flows by gravity to the condensate receiver tank. A
condensate pump supplies condensate through two 50% capacity, plate-type
condensate preheaters. The condensate pumps are 300-horsepower (hp)
self-lubricated, four-stage impeller units manufactured by Byron Jackson. Two
100% capacity condensate pumps and two 100% capacity makeup pumps are used in
this design, with one pump in the standby mode during normal operation. The
design of the condensate systems at both plants is consistent with accepted
power industry practices.
The condensate pumps and deaerator were observed to be operating at their normal
conditions at both plants. One minor forced outage occurred at Sayreville in
1993 due to a steam leak in the deaerator system. No major forced outages have
occurred during the September 1991 through September 1997 period due to any of
the equipment in the condensate systems at either plant.
Boiler Feedwater System
A feedwater pump delivers high-pressure and low-pressure feedwater from the
deaerator to the HRSG steam drums, the fuel gas heaters, and the NOX steam
desuperheaters. Hot condensate from the deaerator storage tank transfers heat to
the condensate entering the deaerator before the condensate enters the feed pump
suction. Two 100% capacity motor-driven feedwater pumps are used, with one in
the standby mode during normal operation. The boiler feed pumps were
manufactured by Ingersoll-Rand. The pumps are designed with force-fed
lubrication and are driven by 2000-hp motors. The design of the feedwater system
at both plants is consistent with accepted power industry practices.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-31
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One minor outage occurred at Bellingham in 1993 due to a clogged boiler feed
pump strainer, and one minor outage occurred at Sayreville due to an instrument
air loss to the boiler feedwater stop valve. No major forced outages have
occurred during the September 1991 through September 1997 period due to any of
the equipment in the feedwater systems at either plant.
Demineralized Water Treatment System
The demineralized water treatment systems at Bellingham and Sayreville provide
treated water to the condensate storage tank for cycle makeup. At Bellingham,
wastewater from the neutralization tank is supplied to the zero discharge system
for recycling. At Sayreville, wastewater is discharged to the local municipal
treatment plant. Two purification trains are used at Bellingham, and three
trains are used at Sayreville. The Sayreville plant has higher makeup water
requirements because Hercules, the steam host, does not return condensate but
rather supplies 115% raw water, which must be demineralized. The demineralizer
system at Bellingham has a capacity of 520 gallons per minute (gpm) net per
train. The system provides 748,800 gallons per train per day to demineralized
water storage. The Sayreville system capacity is 460 gpm net per train. The
system provides 662,400 gallons per train per day. All major pumps in this
system are provided with 100% capacity standby pumps for redundancy.
The major equipment in the demineralized water treatment system was observed to
be well maintained and operating properly on the days of the inspections. No
forced outages have occurred during the September 1991 through September 1997
period due to the demineralized water treatment systems at either plant.
Fire Protection System
The fire protection system designs for the Bellingham and Sayreville plants are
based on National Fire Protection Association (NFPA) standards; other
industry-accepted standards; and good, sound engineering practices. The fire
protection systems should provide adequate protection of property to the owner
and adequate protection of life to the operators and the community.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-32
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The fire protection systems at both the Bellingham and Sayreville plants consist
of the following subsystems:
* A water supply system for the fire hydrants, hose stations, and
sprinkler systems in the general areas of the plant.
* A Halon 1301 flooding system for various enclosed turbine
packages, control rooms, and equipment rooms. A supply of Halon
1301 is stored at the site for future use.
* Smoke detectors and temperature-sensing devices located throughout
the plant that initiate the fire protection system and shut down
the HVAC system in the event of a fire.
* A foam fire protection system for the fuel oil storage area at
Bellingham. Only the Bellingham plant stores fuel oil.
The fire protection systems and equipment are installed according to NFPA
standards and other industry-accepted standards. The systems and equipment
showed no deviation from the standards used for their design.
The Bellingham and Sayreville fire protection systems should provide the
necessary protection for the personnel and property provided that plant
personnel continue to perform the required periodic maintenance and testing for
the systems on a regular and timely basis, and any fire protection system issues
that would result in system inoperability are quickly and efficiently resolved.
The plant personnel have demonstrated their ability to maintain the fire
protection systems in an appropriate condition.
Zero Discharge Wastewater Treatment System
The wastewater treatment system at Bellingham is a zero discharge system. The
zero discharge system collects and processes aqueous wastes from boiler
blowdown, oily waste drains, and filter backwash drains and demineralizer wastes
from the neutralization tank. The wastes are delivered intermittently and are
processed through two subsystems: the backwash filter subsystem and the
evaporator system. The treated water is then recycled to the raw water tank. All
major pumps in this system are provided with 100% capacity standby pumps to
provide redundancy. The design of the zero discharge system is consistent with
accepted industry practices.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-33
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All of the major equipment in the zero discharge system was observed to be well
maintained and functioning properly on the days of the plant inspections. No
forced outages have occurred due to the zero discharge system at Bellingham.
Summary
The design of the balance-of-plant systems installed at the Bellingham and
Sayreville cogeneration facilities is consistent with accepted power industry
practices. None of the balance-of-plant systems have contributed to major
outages at either of the facilities. With continued proper operation and
maintenance practices, the systems should provide reliable long-term service.
ELECTRICAL COMPONENTS AND SYSTEMS
Bellingham Cogeneration Facility
Electric power from the Bellingham plant is produced by three identical
generators rated at 129.06 MW at 0.9 power factor. The steam turbine-generator
produces less power due to the capacity of the turbine; nevertheless, the
generator sizes are identical for simplicity, interchangeability of spare parts,
and other similar reasons. The power is generated at a nominal 13.8-kV level and
is carried over 6000-ampere (A) isolated-phase bus ducts to the main step-up
transformers sized at the oil-air/forced air (OA/FA) ratings of 100/133
megavolt-amperes (MVA). These transformers raise the generated voltage to 345
kV, which is the voltage level of the single-circuit transmission line that
delivers the power to the Boston Edison Company (BECO), Commonwealth Electric
Company (CEC), and Eastern Utilities Associates Service Corporation (EUA) grids.
The transmission line ties in to the 345-kV transmission line between EUA's
Sherman Road substation and BECO's West Medway substation approximately 0.45
mile from the plant.
Neatly arranged takeoff towers support the overhead lines and arresters that tie
the high-voltage bushings of the main step-up transformers to the 345-kV
air-insulated disconnect switches that can electrically isolate each unit under
an offline condition. An air-to-gas terminal bushing at the disconnect switch
allows the transition of the air-
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-34
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insulated overhead line to the compact, six-breaker, gas-insulated ring bus. The
gas-insulated ring bus was used principally because of the switchyard space
limitation.
The sulfur hexafluoride (SF6) gas-insulated switchyard consists of six 1200-A
gas-insulated, dead-tank-design circuit breakers in a ring bus configuration
with three sections used for the incoming generator power lines, one section for
the outgoing transmission line, and two sections used for the two auxiliary
transformers. The auxiliary transformers provide station auxiliary power during
startup and normal operating conditions. Motorized disconnect switches are used
on each side of the circuit breakers.
Gas-to-air terminals are provided near the transmission line dead-end tower for
the transition back to air insulation from the gas-insulated substation.
Disconnect switches are provided in series both on the gas side of the bushing
and on the air side for isolation. The air-side disconnect is manually operated
and under the control of BECO for isolating the plant from the grid under
offline conditions.
If the single transmission line leaving the plant is disabled, the Bellingham
plant would be isolated from the 345-kV grid, requiring the plant to be either
taken off line or to "island." Islanding means reducing the power output from
the generator to the level needed to supply only the plant's auxiliary loads.
The plant is designed to continuously "island"; however, once shut down, the
plant cannot be restarted until the 345-kV grid power is available. There is no
diesel generator or in-plant power source to provide a black-start capability.
Vital 125-Vdc power is provided through two 1650-A-hr station batteries to allow
a safe and orderly shutdown of equipment if all other power is lost.
To ensure that emergency electrical power is available for housekeeping loads
and for some of the essential long-term loads, a tie in to Massachusetts
Electric Company is provided via a 13.8-kV overhead line. The loads supplied
from this source through a 1,000-kVA transformer are connected to one of two
independent motor control centers provided for that purpose.
- -------------------------------------------------------------------------------
This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-35
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The normal source of power for the auxiliary loads is from two full-sized
auxiliary transformers that are connected to the 345-kV system at the
gas-insulated substation. Each of these transformers, which have an OA/FA rating
of 12/16 MVA, can run all of the auxiliaries with the second transformer
out-of-service.
The auxiliary power arrangement consists of two 4.16-kV switchgear buses rated
for 250 MVA. Branch circuit breakers of 1200 A feed two 4.16-kV motor controller
buses and four 4.16-kV to 480-V double-ended substations with OF/FA ratings of
2000/2667 kVA. A single feed runs to the CO2 plant. Each of the auxiliary
transformers is connected to its correspondent switchgear through 3000-A circuit
breakers. Both switchgear are interconnected through a 3000-A tie circuit
breaker. The 480-V motor control centers, low-voltage panels, batteries, and
inverters are all logically intertied to equipment that is well arranged for
reliability and safe operation of the plant.
The electrical design of the Bellingham plant has been well thought out and
properly installed. A few minor issues, such as uncovered cable trays in exposed
outdoor areas and corrosion on the electrical junction boxes in the zero
discharge system area, were noted; however, these items do not degrade plant
performance. The plant personnel currently have an ongoing plan to replace and
relocate affected junction boxes. Nothing observed at the plant would be
considered a design or construction flaw or a violation of applicable permits or
building codes.
Visual inspection of the electrical equipment showed the equipment to be well
maintained with signed and dated inspection tags on the equipment. Good
housekeeping practices were evident, with the switchgear, control room, and
instrument areas being notably clean.
In December 1993, the generator of Combustion Turbine No. 1 at Bellingham was
shut down and the rotor was removed to locate and eliminate a ground on the
generator field windings that had been appearing on the field ground detector.
When the rotor was removed, the inspection showed that the slot wedges in the
stator were loose and required replacing. The field ground was caused by a
broken baffle spring.
The original steel axial baffle springs, which are located under both the
exciter and turbine end retaining rings, were replaced with a new and superior
nonmetallic type, and the wedges were subsequently replaced during the spring
1994 outage. These machine upgrades were implemented on the other two units
during the spring 1996 outage.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-36
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Other outages due to electrical problems were not extraordinary and were likely
the result of the early startup problems often associated with a new plant. The
latest oil sample analysis reports for all of the oil-filled transformers showed
satisfactory condition and normal aging. All indications showed the plant to be
properly maintained and well operated.
Sayreville Cogeneration Facility
Electric power from the Sayreville plant is produced by three identical
generators rated at 129.06 MW at 0.9 power factor. The steam turbine-generator
produces less power due to the capacity of the turbine; nevertheless, the
generator sizes are identical for simplicity, interchangeability of spare parts,
and other similar reasons. The power is generated at a nominal 13.8-kV level and
is carried over 6000-A isolated-phase bus ducts to the main step-up transformers
sized at the forced-oil-and-air (FOA) rating of 133 MVA. These transformers
raise the generated voltage to 230 kV, which is the voltage level of the
double-circuit transmission line that delivers the power to the Jersey Central
Power and Light Company (JCP&L) grid over a common transmission right-of-way
with both circuits on common poles. After exiting the site, one line is routed
to the Raritan River Substation and the other to the Atlantic Substation.
Each main power transformer has a single 230-kV, 1200-A, SF6 gas-insulated
circuit breaker associated with it. An overhead line supported from a dead-end
tower at the turbine building is tapped down to the transformer bushing and
arrester. The line connects to another tower located over the circuit breaker
where the line drops down into the circuit breaker bushing. Each circuit breaker
is tied to an in-line disconnect switch that is connected to one of two rigid
buses that exit the plant property and connects into a four 230-kV, 2000-A, SF6
gas-insulated circuit breaker ring bus configuration that is owned and
maintained by JCP&L.
Power into the plant for startup and generated power out is metered at the JCP&L
switchyard tie-in point. Except for the double-circuit 230-kV transmission
lines, there is no other offsite power source available. The plant is
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
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designed to operate in an islanding mode during which time the plant supplies
power only to its own auxiliaries; however, once the plant is shut down, it
requires power from the 230-kV grid to restart. There is no black-start diesel
generator or other onsite power source available for starting up the plant.
Battery power is available to allow a safe and orderly shutdown of equipment if
all other power is lost.
The normal source of power for the auxiliary loads is supplied by two full-sized
auxiliary transformers. Each of these transformers, which have an OA/FA rating
of 12/16 MVA, can run all of the auxiliaries with the second transformer out of
service. The transformers are connected to the 230-kV air-insulated substation
by 1,200-A circuit switchers. Circuit switchers are devices that do not have the
full interrupting rating of a circuit breaker. Circuit switchers can break a
high-voltage circuit that is energized, and they can interrupt a transformer
low-voltage ground fault because the 4-kV system is resistance grounded, which
limits the amount of ground fault current available. Relaying also is provided
to trip the circuit switchers if the transformers become overloaded.
The auxiliary power arrangement consists of two 4.16-kV switchgear buses rated
at 250 MVA. Branch circuit breakers of 1200 A feed two 4.16-kV motor controller
buses and four 4-kV to 480-V double-ended substations with OF/FA ratings of
2000/2667 kVA. Each of the auxiliary transformers is connected to its
corresponding switchgear through 3000-A circuit breakers. Both switchgear are
interconnected through a 3000-A tie circuit breaker. The 480-V motor control
centers, low-voltage panels, batteries, and inverters all are logically
intertied to equipment that appears to be well arranged for reliability and safe
operation of the plant.
The electrical design of the Sayreville plant has been well thought out and
properly installed. A few minor issues, such as uncovered cable trays and heat
tracing tapes in exposed outdoor areas, were noted; however, these items do not
degrade plant performance. Nothing observed at the plant would be considered a
design or construction flaw or a violation of applicable permits or building
codes.
Because of the December 1993 incident concerning the steel axial baffle springs
of the Combustion Turbine No. 1 generator at Bellingham, the original steel
axial baffle springs at Sayreville were also replaced with the nonmetallic type.
The upgrade of the steam turbine generator, including replacement of the stator
wedges, was
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released to any third party without the prior written consent of S&L. Copyright
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performed during the fall 1994 outage. The Combustion Turbine No. 2
generator upgrade was performed during the fall 1996 outage, and the Combustion
Turbine No. 1 generator upgrade was performed during the fall 1997 outage.
With the exception of the high-voltage switchyard, the Sayreville electrical
components and systems are almost identical to those at the Bellingham plant.
Several of the early outages were attributable to relay and instrumentation
startup-type trips. The latest oil sample analysis reports for all of the
oil-filled transformers showed satisfactory condition and normal aging. All
indications showed the plant to be properly maintained and well operated.
Plant Control System
The control systems for each of the Bellingham and Sayreville plants is a
Westinghouse Distributed Processing Family (WDPF) controller with completely
redundant drops, data highways, and operator stations. There are three stations
located in the control room, each consisting of touch screen monitors and a
keyboard for nonautomatic control. The touch screens monitor plant conditions
through a series of graphic displays of plant processes and allow the mode of
control to be switched between automatic and manual. Manual control of equipment
is performed using the keyboard. The systems are interconnected with
Westinghouse's engineering facility in Orlando, Florida, so that any problems
can be quickly diagnosed and engineering support can be provided. This
interconnection was most used during the initial operation of the plants and has
not been used lately.
The control systems would generally be classified as state-of-the-art. Most of
the operators have worked at the plants since initial startup and their
knowledge of the systems and evidence of formal training was noteworthy.
At Bellingham, the WDPF control system was upgraded in 1996 from a level 6.5.2
system to a level 7.2. This upgrade significantly reduced processing time,
allowing the system to update information faster and to react to changing plant
conditions faster. The upgrade ensures that process data points are not dropped
due to processor overloading. Based on information provided at the plant, the
cost for this upgrade was approximately $200,000.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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There is presently no plan to install this control upgrade at Sayreville since
the Sayreville control system did not experience the same processor overload
problem experienced with the Bellingham control system. The current availability
of parts and technical support should be analyzed to determine whether there is
any merit to implementing this upgrade at Sayreville.
A heat rate monitoring system is installed in the control room at Bellingham.
The applicable data gathered by the control system are manually inputted by the
operator to calculate the heat rate.
A vertical mimic control board is also located in each of the control rooms for
breaker and disconnect control of the circuit breakers. Pistol-grip-type control
switches with targets and lights are mounted on the mimic board for switching
the breakers. An automatic synchronization system is normally used for closing
these breakers, but manual synchronizing can also be accomplished if required by
the operator.
The control system is highly automated with excellent information available to
the operator and others desiring current and/or historical system conditions.
ARCHITECTURAL/CIVIL/STRUCTURAL COMPONENTS AND SYSTEMS
General Features of Both Facilities
The Bellingham and Sayreville facilities are very similar with regard to the
architectural, civil, and structural design except for the following features:
* The Bellingham Cogeneration facility includes a carbon dioxide
plant.
* The Bellingham plant has oil burning capabilities with the
required fuel oil handling and storage facilities.
* The Bellingham plant utilizes a common concrete chimney with a
single liner to service both units while the Sayreville plant has
two liners inside a common concrete chimney with one dedicated to
each unit.
* At Bellingham, ductwork from the HRSG outlet is directed to the
chimney and to the CO2 plant, which is not present at Sayreville.
The Sayreville ductwork from the HRSG outlets are routed directly
to the chimney.
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released to any third party without the prior written consent of S&L. Copyright
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* The Sayreville design has the necessary features, including an
elevator to provide handicapped persons access to the office
areas. The Bellingham plant is not designed for handicapped
access.
* The foundation designs are somewhat different since the soil
conditions are different at the two sites.
Other differences in the designs of the two facilities are insignificant from an
architectural/civil/structural standpoint.
Both facilities were designed in accordance with good engineering practices and
the latest codes and standards in effect at the time of design. A review of
drawings revealed the design of the foundations and structures is consistent
with the approaches outlined in the civil and architectural design basis
documents that were prepared for the projects. The design conditions, structural
loadings, and construction materials are consistent with those used in the
industry for facilities of this type. The foundation designs were observed to be
generally consistent and comparable with those used at other similar facilities.
Field walkdowns were performed at each site. In general, the condition of the
structures was good and consistent with the age of the facilities. The steel and
concrete are beginning to show signs of aging that were not present when a
similar assessment was performed in 1994. The conditions noted at each facility
were not unusual for an operating plant and should not affect the long-term
operability or maintainability of the units. Some conditions do exist that
require repair or modification, and the plant personnel are aware of these
conditions and have made or are making plans to perform the required work.
Bellingham Cogeneration Facility
Steel/Superstructure
The indoor and outdoor steel structures are a combination of galvanized and
painted steel. The interior steel was in good condition whether of galvanized or
painted construction. The outdoor galvanized steel appeared to be in good
condition with only some mild staining or rusting noted in places. The outdoor
painted steel was in acceptable condition, but some areas are beginning to peel,
rust, or corrode such that cleaning and painting would
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
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be prudent. None of the rusting noted, however, was to an extent that would
warrant immediate action. The cleaning and painting required can be achieved
through a planned maintenance program that targets the most heavily corroded
areas.
No significant warping or damage to any structural member was observed at the
site.
The ductwork to the carbon dioxide plant was reported to be in good condition.
Yearly inspections of the ductwork have revealed the occurrence of some minor
surface corrosion. This minor corrosion is typical for this type of ductwork. A
historic problem with the ductwork was reported as major rusting and scaling of
the interior walls. This problem was eliminated by installing drains in the
ductwork next to the chimney. Since the installation of the drains, the major
rusting and scaling has ceased.
The combustion turbine enclosures and the turbine hall are constructed of
insulated metal siding with a metal wall liner panel that is perforated to
deaden the sound from the equipment. This siding appeared to be in good
condition, as was all other plant siding except that for the water treating
building.
Concrete and Foundations
Concrete structures were in a generally acceptable condition with some minor
cracking of foundations and floor slabs noted at places. The cracking was
consistent with the age of the structures and was minor at all areas except the
HRSG foundations. No excessive settlement of any structure was observed.
Concerning the HRSG foundations, the plant personnel plan on repairing the
foundation piers that are currently cracked, removing all tack welds between
plates, and greasing all bearing plates. These measures should reestablish the
original design conditions and help prevent further difficulties.
Other Items
As noted in inspections performed in 1994, the drainage of the site appears to
be adequate to prevent flooding of the site and to maintain adequate operation
of the facility during heavy rainfall.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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In general, the structures appear to meet the design requirements of the NFPA
code for the transformer foundations and the protection of the adjacent
structures.
To date, the concrete chimney has not been inspected. Based on the age of the
chimney and the aggressive environment that exists inside, the plant personnel
should conduct an inspection within the next two years. Afterwards, regular
inspections of the interior and exterior of the chimney should be conducted.
Inspection of the chimney will help identify problems with the liner materials
and the concrete shell that can develop due to the effects of leaking flue gas.
Sayreville Cogeneration Facility
Steel/Superstructure
Similar to the Bellingham Cogeneration Facility, the indoor and outdoor steel
structures at Sayreville are a combination of galvanized and painted steel. The
condition of the steel was similar to that at Bellingham. Cleaning and painting
of the more heavily corroded areas is recommended as part of normal maintenance
activities.
No significant warping or damage to any structural member was observed at the
site.
The Sayreville building siding was of similar construction to the Bellingham
siding. No significant problem areas were noted.
Concrete and Foundations
Concrete structures were in a generally acceptable condition with some minor
cracking of foundations and floor slabs noted at places. The cracking was
consistent with the age of the structures and was minor at all areas.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Similar to the Bellingham facility, some of the HRSG foundations are cracked.
For the cracked HRSG foundations, the plant personnel are aware of the adverse
conditions and have instituted repairs to some piers. They are planning to
repair the other cracked piers and grease the base plates to eliminate the
problem.
Other Items
The drainage of the site appears to be adequate to prevent flooding of the site
and to maintain adequate operation of the facility during heavy rainfall.
In general, the structures appear to meet the design requirements of the NFPA
code for the transformer foundations and the protection of the adjacent
structures.
The concrete chimney has been inspected twice. Each report summarized the
chimney as being in good condition. Some foamglass block tiles were noted as
missing at the breeching, and this condition is being monitored by the plant
personnel. The plant personnel intend to replace the missing tiles in the future
and to perform future inspections to assess the condition of the chimney.
SUMMARY
General reviews of the design bases, construction, operation, and maintenance of
the Bellingham and Sayreville cogeneration plants were performed including
reviews of design standards, drawings, and specifications. Walkdowns of each
facility were also performed to establish the present condition, and interviews
of key plant operations and maintenance personnel were conducted. Based on the
technical review, the facilities have been well constructed in accordance with
generally accepted engineering practices.
The conditions noted at each facility were usual for operating plants and should
not affect the long-term operability or maintainability of the units. Some
conditions do exist that require minor repair or modification, and the plant
personnel are aware of these conditions and have made or are making plans to
perform the required
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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work. The costs associated with these repairs or modifications are not
significant and are within the amounts included in the operation and maintenance
budgets.
The plants have been successfully operated and maintained by Westinghouse
Electric Corporation since startup, and continued good operation and maintenance
practices by the owners should provide reliable long-term service from both
plants allowing the plants to meet their operating and financial projections.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Section 3
TECHNICAL REVIEW OF THE BELLINGHAM CARBON DIOXIDE PLANT
The Bellingham Carbon Dioxide (CO2) plant is located on property adjacent to the
cogeneration plant. The CO2 plant is fed by a slip stream of 10% to 15% of the
combustion turbine exhaust gases. The inlet duct that conducts this slip stream
to the CO2 plant is equipped with dampers so that the CO2 plant can be supplied
from either or both of the combustion turbines. The CO2 plant can operate at
rated capacity with the exhaust gas from one combustion turbine. The CO2 plant
is based on amine technology developed by Dow Chemical Company and acquired by
Fluor Daniel. This technology was developed to recover carbon dioxide from
exhaust gases containing low volumes of carbon dioxide and high volumes of
oxygen. This plant is designed to recover CO2 from the exhaust gas, producing
350 tons per day of food-grade CO2.
During the limited periods when the combustion turbines are fired on fuel oil,
the CO2 plant must be shut down due to inherent contaminants in the No. 2 fuel
oil. However, the duct design and shutoff dampers allow the CO2 plant to operate
at rated capacity with one combustion turbine operating on natural gas.
All process water needed for the CO2 plant is recovered from the incoming
exhaust gas. Excess water is either vented to the atmosphere as part of the
process or is disposed of off site with the degraded monoethanolamine (MEA)
solution from the reclaimer.
PROCESS DESCRIPTION AND DESIGN
Exhaust gas from the cogeneration plant enters a direct-contact cooler where it
is cooled by a countercurrent flow of water. The exit gas is compressed by a
2500-hp blower and enters the bottom of the absorber. The gas flows up through
the absorber-packed beds where it comes in contact with a countercurrent flow of
MEA solution. This contact results in absorption of the CO2 into the MEA
solution. The CO2 is stripped from the rich MEA solution in the reboilers and
also from the countercurrent flow of the hot gas vapors from the reboilers.
Low-pressure steam from the cogeneration plant is used to vaporize the solution
in the reboilers.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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The saturated carbon dioxide gas stream from the top of the stripper is then
passed through a series of heat exchangers, knock-out drums, drying media, and
filter media to remove moisture and impurities. Then the CO2 gas stream is
compressed and liquefied and stored at 217 psig and -17(Degree)F in eight
individual 200-ton storage tanks.
The CO2 plant is constructed with a high degree of redundancy and parallel
systems for availability and maintainability. The CO2 is purified and liquefied
using standard commercial items, and no unusual maintenance problems have been
experienced or are anticipated with this equipment.
This facility has been designed in agreement with the structural considerations
for the cogeneration plant. The available design documentation was reviewed, and
the design has been performed in accordance with generally accepted engineering
practices. The structures were designed by Fluor Daniel using materials and
conditions similar to those used in the cogeneration plant. The design of the
site civil features is consistent with the design for the cogeneration plant.
A field walkdown of the site indicated that the structures are in good condition
and show no signs of damage. There is no cracking visible in any of the concrete
structures, and no visible settlement of any of the structures was noted.
OPERATION AND MAINTENANCE HISTORY
The CO2 plant has been in operation since 1991 producing and marketing a
food-grade product. During the first year of operation, plant production was
somewhat curtailed due to limitations in operating parameters, equipment
modifications, and system shutdowns. This experience is consistent with the
startup of a new and complex processing facility. During this period, the plant
was able to meet contractual commitments for steam consumption.
In the first year of operation, there were excursions in the iron and
heat-stable salt measurements. As a result, there was a concern that corrosion
was taking place in the CO2 system. A program was initiated in June 1992 to
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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monitor the wall thickness of the absorber and stripper vessels. During a
subsequent review of wall thickness measurements generated during a January 1993
monitoring effort, excessive corrosion of one section of the absorber was
identified. The system was brought off line, and on internal inspection,
excessive corrosion and failure of the lower level internals,
non-pressure-retaining parts, was identified. A corrective action was
implemented to replace the internals with stainless steel material and install a
stainless steel liner on the lower area affected by uninhibited wet CO2 gas.
Before restarting, a consultant, Mr. John McCullough, established new process
operating parameters (passivation) for startup and continuous operation.
Internal examination and wall thickness measurements of the absorber and
stripper have been performed yearly since the modifications. The observations
and measurements taken during the recent scheduled outages confirm that the
corrective actions implemented in March 1993, including the modified operation
procedures, properly addressed the conditions found during the January 1993
outage. For the past 55 months, the plant has been operating virtually 100% of
the time, producing in excess of design guaranteed production quantities of
food-grade CO2.
In addition to these items, operation and maintenance issues were noted with the
condensate return pump and the CO2 oil separator.
Condensate Return Pump
The two condensate return pumps used to pump high-temperature condensate from
the condensate return tank in the CO2 plant have a history of repair and rework.
Each has been repaired approximately ten times since startup in 1991. These
pumps operate with 272(Degree)F condensate at the pump suction with a discharge
pressure of 270 psig and a flow of 150 gpm. Changes in the load can cause the
pressure and temperature of the condensate to lower the net positive suction
head (NPSH) margin, which is the difference between the NPSH available and the
NPSH required. A low NPSH margin can result in cavitation and pump damage.
Various modifications have been made over the years, but these modifications
have not changed pump reliability.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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The NPSH margin can be increased by cooling the condensate or new pumps could be
installed that are designed for these conditions. If the appropriate pump is
available, this alternative will likely be the most cost-effective solution
since it will not require a complete redesign of the system. Plant personnel
estimate that the new pumps would cost approximately $50,000 each.
CO2 Oil Separator
The CO2 high-stage compressor oil separator is an ASME Section VIII pressure
vessel that developed a leak at a coupling for an oil heater. The leak resulted
from a crack just above the coupling, probably caused by vibration and a
concentration of stresses at the weld. These couplings have not been used for
years since the machines are installed indoors and do not require the heaters.
The CO2 high-stage compressor oil separator was repaired by cutting out a
rectangular section that included the coupling and replacing it with a full
penetration weld patch. This repair was accomplished in accordance with the
National Board Inspection Code NB-23, approved by an Authorized Inspector, and
hydrostatically tested.
Because of this leak, all other couplings on the high-stage compressor and the
two low-stage compressor oil separators were liquid-penetrant tested. One other
crack was found on a low-stage separator heater coupling. This crack was not
through-wall and therefore did not leak. This crack is being constantly
monitored, and a similar repair to that performed on the high-stage oil
separator is planned. Westinghouse believes this repair should solve the
problem. Since the additional load of the oil heaters is no longer present,
additional cracking is unlikely.
SUMMARY
The CO2 plant has been in operation since 1991 producing and marketing a
food-grade product. For the past 55 months, the plant has been operating
virtually 100% of the time, producing in excess of the design guaranteed
production quantities of food-grade CO2. This record is a result of a concerted
effort by the plant personnel to identify and eliminate the source of corrosion
that occurred during the startup operation and to establish new predictable
process operating parameters. Based on the consistency of current operations,
the CO2 plant should continue operating at its design parameters and within
projected operating and maintenance costs.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Section 4
PLANT PERFORMANCE REVIEW
The historical capacity, generation, heat rate, and availability of the
Bellingham and Sayreville cogeneration facilities were reviewed in order to
obtain a benchmark for the performance assumed in the pro forma financial
models. The following station documents were reviewed:
* Performance and Reliability Test Procedures
* Performance Test Correction Curves
* Operation and Maintenance Agreements, including the Bellingham
and Sayreville heat rate revisions dated June 23, 1993
* Monthly Generation Reports
* Outage Reports (BEL 97-031, SVL-172)
* Equivalent Availability Charts
The tested capacities were higher than guaranteed and the tested heat rates were
lower than guaranteed for the plants, and both plants are achieving annual
availability rates above the industry average.
CAPACITY, GENERATION, AND HEAT RATE
1991 Plant Acceptance Tests
Plant acceptance tests were conducted in August 1991 at Sayreville and in
September 1991 at Bellingham to affirm the guarantees provided by Westinghouse
in their engineering, procurement, and construction (EPC) contracts. The
guarantees were based on new and clean operation at design conditions, which
include baseload operation at ISO conditions (59(degree)F and 14.7 psia) with
51,500 lb/hr of 57-psig export steam at Bellingham and 230,000 lb/hr of 600-psig
export steam at Sayreville. The capacity guarantees are net of power plant
consumption, and at Bellingham gross of the CO2 plant load. The test results
were corrected, using Westinghouse correction curves, to conform the actual test
conditions to design conditions.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
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The results of the acceptance tests, as shown in Table 4-1, demonstrate that
tested capacities were higher than guaranteed and the tested heat rates were
lower than the guaranteed levels:
Table 4-1 -- EPC Acceptance Tests
Guarantee Test Results
--------------------- ---------------------
Bellingham
Capacity 303.6 MW 312.3 MW
Heat Rate (HHV) 8245 Btu/kWh 8039 Btu/kWh
Sayreville
Total Power 272.34 MW 279.2 MW
Heat Rate (HHV) 9191 Btu/kWh 8748 Btu/kWh
Operating Guarantees
The June 1989 Operating and Maintenance contracts establish performance
guarantees for metered (net) generation and heat rate, based on degradation
factors of 3% for capacity and 1% for heat rate. These factors are typical for
natural gas-fired combined-cycle plants. The Operation and Maintenance contracts
were revised in June 1993 to establish, among other things, guarantees for heat
rate at lower levels while maintaining the generation guarantees at the same
levels.
The bases for the original and revised guarantees are listed in Table 4-2.
Table 4-2 -- O&M Contract Guarantees
Bellingham Sayreville
------------------ -----------------
Capacity 294.5 MW 264.17 MW
Original Heat Rate (HHV) 8323 Btu/kWh 9278 Btu/kWh
Revised Heat Rate (HHV) 8222 Btu/kWh 9057 Btu/kWh
The generation guarantee involves the total annual metered generation assuming
the nominal capacity listed in Table 4-2. The revised heat rate guarantee is the
cumulative average of all periodic heat rate tests performed since the last
combustion turbine overhaul and involves test data corrected from actual to
design conditions. At Sayreville, but not Bellingham, the heat rate is further
corrected for deviations between design and actual export steam.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
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Operating Performance
Actual plant operating data for the first five complete calendar years were
obtained. For consistency, the data were not corrected from actual conditions to
design conditions, since the necessary information was not recorded throughout
time at both plants. The partial 1997 calendar year has not been included
because it does not account for changes in performance that occur throughout a
full-year ambient temperature cycle. However, the operating data for the first
nine months of the 1997 calendar year are consistent with the first nine months
of the other calendar years.
Table 4-3 -- Actual Operating Data
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Bellingham
Total Power Produced (GWh) 2436 2484 2483 2595 2518
Net Plant Heat Rate, HHV (Btu/kWh) 8240 8289 8297 8336 8251
Sayreville
Total Power Produced (GWh) 2035 2005 1830 2104 2019
Net Plant Heat Rate, HHV (Btu/kWh) 9148 9078 8884 9066 9073
The Total Power Produced is the annual net power available for sale, which in
the case of Bellingham includes the power transmitted to the CO2 plant. The Net
Plant Heat Rate is based on the annual heat input from the fuel, divided by the
annual net power available for sale. This method of calculating heat rate does
not correct for ambient conditions, export steam, or plant loading.
The actual heat rate at Sayreville indicated in Table 4-3 cannot be compared to
the guaranteed levels because Sayreville normally operates at a net output of
252 MW due to the pricing structure of the PPA. Similarly, the guarantees are
based on the maximum export steam rate of 230,000 lb/hr, whereas the actual
export steam demand is significantly less at 125,000 lb/hr. At reduced load, the
cycle efficiency is lower, which results in a higher average heat rate.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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As a condition of the revised 1993 Operations and Maintenance Agreement,
instrumentation and other improvements were to be implemented that would allow
correcting the heat rate for ambient conditions and export steam. At Bellingham,
the corrected heat rate has been monitored daily since mid-1993. At Sayreville,
the Power Purchaser must authorize exceeding 252 MW and the corrected heat rate
has been monitored once a month since June 1996. The corrected heat rates and
capacity are listed in Table 4-4.
Table 4-4 -- Corrected Operating Data
1994 1995 1996
---- ---- ----
Bellingham
Capacity (MW) 303.3 303.1 302.9
Net Plant Heat Rate, HHV (Btu/kWh) 8216 8210 8221
Sayreville
Capacity (MW) -- -- 278*
Net Plant Heat Rate, HHV (Btu/kWh) -- -- 8951*
- -----------
*Sayreville data based on July 1996 through June 1997 data
AVAILABILITY
Industry Averages
* The following availability definitions were used for this evaluation:
Equivalent Availability Factor (EAF). The number of equivalent
hours that a unit is available to run at full load as a percentage
of total hours in a given period.
* Corrected Equivalent Availability Factor (CEAF). The number of
equivalent hours that a unit is available to run at full load as a
percentage of the total hours in a given period less curtailment
hours.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
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* Forced Outage Hours (FOH). The number of equivalent outage hours
caused by an unplanned component failure that requires the unit to
be removed from service or derated during services.
When there are two combustion turbines at plants such as Bellingham and
Sayreville, an event that causes two outage hours on one combustion turbine
contributes one equivalent outage hour for the complete plant.
Events affecting availability include forced outages, planned maintenance
outages, curtailments by power purchasers or fuel suppliers, and Force Majeure
events such as snow build-up on the inlet air filters. Curtailments and events
of Force Majeure are beyond the control of the plant personnel, and the planned
maintenance schedule is dictated by the operations and maintenance requirements
of the equipment. Therefore, the forced outage rate is the primary factor that
plant personnel can control to improve availability.
In the United States, industry averages are usually obtained from data submitted
by utilities to the North American Electric Reliability Council (NERC). A sort
of the NERC database was made to extract the most current data being reported
for combined-cycle units operated by U.S. electric utilities. In 1996, data were
reported for 54 units with an average unit age of approximately 12 years.
Average values of EAF = 86% and FOH = 123 were obtained. These data reflect the
increasing reliability achievable with improved technology and newer equipment.
In 1992, for example, data for 25 units with an average unit age of 16 years
indicated an EAF equal to 76% and an FOH equal to 255.
Station Performance
The equivalent availability factor and percentage of curtailments are monitored
monthly. The reported data and the corrected equivalent availability for
Bellingham and Sayreville are listed in Table 4-5.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
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Table 4-5 -- Availability
Equivalent Availability (%) Curtail CEAF
-------------------------------------------------------------------------------------------------------
Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec. Ave. Ave. (%)
-----------------------------------------------------------------------------------------------------------------------
Bellingham
1992 99.5 99.5 100.0 99.4 93.5 75.5 88.5 100.0 100.0 92.1 97.1 66.5 92.6 -- 93.3
1993 87.4 97.8 90.2 99.1 100.0 99.4 96.0 100.0 94.5 87.5 92.5 79.6 93.7 1.2 94.8
1994 88.3 94.1 95.9 59.6 100.0 97.7 98.8 100.0 95.8 89.3 90.2 85.0 91.2 2.3 93.4
1995 99.6 98.7 99.7 96.4 82.2 97.9 96.4 94.1 93.2 93.6 94.7 99.9 95.5 1.4 96.9
1996 99.8 98.2 99.5 96.9 45.4 80.7 99.8 100.0 94.4 93.5 91.5 99.2 91.6 1.3 92.7
1997 96.4 97.4 100.0 100.0 85.3 100.0 100.0 97.7 94.4 91.4 -- -- 96.2 1.2 97.4
Sayreville
1992 99.3 97.3 97.3 98.6 74.5 94.0 94.2 96.3 95.5 77.9 98.8 99.3 93.6 2.3 95.7
1993 99.9 97.9 89.2 100.0 80.4 98.8 99.1 75.5 87.3 99.0 68.2 97.7 91.1 2.3 93.2
1994 72.0 99.1 97.4 98.0 73.6 99.9 99.8 91.1 89.7 6.5 72.6 96.2 83.0 3.8 86.3
1995 99.6 89.8 99.2 98.8 76.1 97.7 98.9 99.2 100.0 74.5 95.9 98.1 94.0 2.9 96.8
1996 98.5 91.5 99.5 76.2 84.9 100.0 98.6 98.3 98.5 50.1 98.1 98.1 91.0 3.8 94.7
1997 93.9 97.5 100.0 100.0 87.2 97.7 100.0 98.7 100.0 44.4 -- -- 91.9 1.0 92.9
Station outage reports were reviewed to identify the equipment that was most
responsible for the forced outages. Equipment failures that resulted in unit
deratings were included by computing an equivalent full outage hour based on the
ratio of the derating to the unit's full output. This information is summarized
in Table 4-6.
Table 4-6 -- Forced Outage Hours
Combustion Steam
Turbine/ Turbine/ Balance of
Generator Generator HRSG Instrumentation Electrical Plant
---------- --------- ------- --------------- ---------- -----------
Bellingham
1992 101 6 23 516 1 23
1993 397 41 0 12 0 89
1994 54 0 87 39 18 35
1995 15 3 7 36 0 0
1996 56 37 34 26 0 6
1997* 19 0 3 12 7 0
Sayreville
1992 56 0 2 28 0 0
1993 57 0 22 21 0 22
1994 2 0 109 6 0 107
1995 28 1 3 6 0 0
1996 9 0 48 0 0 25
1997* 0 0 0 1 72 1
- ---------
*1997 values through November; BEL 97-031, SVL-172.
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The monthly availabilities for both plants are consistently higher than the
industry average availability, which is to be expected since plant forced outage
hours are below those typical of the industry. Also, scheduled outage hours are
minimized by effective outage planning and execution.
Most of the Bellingham forced outage hours were due to combustion turbine and
associated instrumentation problems. To a great extent, these problems have been
corrected. As previously discussed, however, there remains a vibration problem
with Combustion Turbine No. 1 that contributes to most of the combustion turbine
forced outages. Overall, the total number of outage hours since initial startup
is relatively low.
As discussed in Section 3, the Bellingham CO2 plant has also demonstrated its
capability to produce the design quantity and quality of CO2 and to utilize the
necessary amount of steam to fulfill the cogeneration plant's Qualifying
Facility requirements.
The performance of Sayreville has been excellent. Most of the Sayreville forced
outage hours were due to combustion turbine problems; however, the total hours
involved is very low.
As noted, both plants are achieving annual availability rates above the industry
average. Future scheduled outages and maintenance should be similar to present
experience, and continued high unit availabilities can be expected in the future
for both plants.
SUMMARY
The performance and reliability test procedures, performance test correction
curves, operation and maintenance agreements, monthly generation reports, outage
reports, and other documents were reviewed to determine whether the guaranteed
performance parameters are being met and used correctly in projecting the future
performance of the plants. The demonstrated capacity and heat rate of each plant
have shown little annual variance, and each plant has consistently achieved the
contract performance guarantees. The average yearly availabilities for both
plants are consistently higher than the industry average for newer
combined-cycle plants. Finally, the Bellingham CO2 plant has also demonstrated
its capability to produce the design quantity and quality of CO2 and to utilize
the necessary amount of steam to fulfill the cogeneration plant's Qualifying
Facility requirements. The historical performance of the plants should result in
a reasonably accurate forecast of future plant performance.
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Section 5
OPERATION AND MAINTENANCE REVIEW
The Operation and Maintenance (O&M) budget estimates were assessed in light of
the operating history of the two plants and industry experience with other
combined-cycle plants. This assessment determined whether the O&M budget
estimates are adequate, conservative, and consistent with expected performance
characteristics.
The focus of this analysis was on the nonfuel portion of O&M expenses. While
fuel expenses have a more significant impact on the project's net income, they
are based largely on plant performance assumptions such as plant output and net
heat rate. These performance assumptions are addressed in Section 4.
The pro forma O&M expenses reflect continued operation by Westinghouse until the
end of the current contract, followed with operation by ESI Operating Services,
Inc., an affiliate of one of the new owners. ESI Operating Services, Inc. is
fully capable of operating and maintaining these combined-cycle power plant
facilities.
EXISTING O&M AGREEMENTS
The O&M budgets for the Bellingham and Sayreville facilities are based on their
respective O&M agreements, which specify, among other things, the payments to
the operator, the obligations of the owner and the operator, and the performance
guarantees. The net payments to the operator may include liquidated damages or
bonuses tied to the performance guarantees.
The O&M agreements were examined to determine whether the payments to the
operator are sufficient to support expected plant performance and whether the
liquidated damages or bonuses are sufficient to maintain expected project net
income. These determinations were based in part on the power purchase
agreements, which indicate the value of lost or gained electrical output; the
fuel supply agreements, which indicate the value of excess or reduced fuel
consumption; and the steam supply agreements, which indicate the value of lost
steam supply.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Bellingham Facility
The Bellingham facility is being operated by Westinghouse under an O&M agreement
between Northeast Energy Associates (NEA) and Westinghouse, dated June 1989 and
amended June 1993. Westinghouse is paid a monthly sum of $435,417 (January 1990
dollars), which is escalated twice a year according to a composite index of
materials (20%), equipment (30%), and labor (50%). Westinghouse is responsible
for all routine O&M expenses as well as major maintenance, inspections, and
overhauls. The owner must pay for fuel, water, permits, property taxes, and
insurance.
Westinghouse must maintain an average annual electrical output of 90% of net
capacity (adjusted for degradation), measured in kilowatt-hours. They must pay
liquidated damages for shortfalls, but they receive bonuses for excesses, as
measured relative to the 90% guarantee. The 90% guarantee applies to the days of
natural gas operation, but the guarantee level is lower for days of combined
fuel operation: 83% as applied to liquidated damages and 85% as applied to
bonuses. The liquidated damages and bonuses are as follows:
o Liquidated Damages = $15.00/MWh (first 100,000 MWh shortfall)
$33.00/MWh (next 100,000 MWh shortfall)
$50.00/MWh (all additional MWh)
o Bonuses = $ 5.00/MWh (first 25,000 MWh excess)
$10.00/MWh (next 25,000 MWh excess)
$15.00/MWh (all additional MWh)
NEA is a party to five power purchase agreements with three companies: Boston
Edison Company (BECO), Commonwealth Electric Company (CEC), and Montaup Electric
Company. There are no liquidated damages against megawatt-hour shortfalls under
any of these agreements. Electrical output shortfalls, however, would reduce
gross project income by approximately $28/MWh on the basis of the 1997 weighted
average power sales rate. The liquidated damages under the O&M agreements are
triggered after the first 100,000 MWh below the guaranteed level, which is
approximately 4%. Together with the bonuses, the liquidated damages provide an
economic incentive to the operator to maintain or exceed the guarantee. Output
in excess of the guarantee increases the project net income since the cost of
bonuses is less than the incremental power sales income.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Westinghouse must also maintain a guaranteed net plant heat rate and pay
liquidated damages for any incremental fuel costs due to deviations above the
guaranteed value.
Steam sales are made to the CO2 plant under a steam sales agreement with
NECO-Bellingham, Inc. NEA must pay a prorated portion of the CO2 plant's O&M
expenses, property taxes, and basic rent as liquidated damages for any steam
production shortfalls. Even though net profits to NEA from steam sales would be
reduced during steam production shortfalls, NECO-Bellingham, Inc. has an
incentive to maintain production in order to maximize its net profits.
Sayreville Facility
The Sayreville facility is being operated by Westinghouse under an O&M Agreement
between North Jersey Energy Associates (NJEA) and Westinghouse, dated June 1989
and amended June 1993. Westinghouse is paid a monthly sum of $493,750 (January
1990 dollars), which is escalated twice a year according to a composite index of
materials (20%), equipment (30%), and labor (50%). Westinghouse is responsible
for all routine O&M expenses as well as major maintenance, inspections, and
overhauls. The owners must pay for fuel, water, permits, property taxes, and
insurance.
Westinghouse must maintain an average annual electrical output of 90% of net
capacity during peak periods and 85% of net capacity during offpeak periods,
measured in kilowatt-hours. They must pay liquidated damages for shortfalls, but
they receive bonuses for excesses, as measured relative to the 90% peak and 85%
offpeak guarantees. The liquidated damages and bonuses are as follows:
o Liquidated Damages = $15.00/MWh (offpeak shortfall)
$20.00/MWh (onpeak shortfall)
$56.00/MWh (onpeak shortfall for portion
below 90% of 3-year average onpeak output)
o Bonuses = $ 3.00/MWh (offpeak excess above 85% guarantee)
$30.00/MWh (onpeak excess above 90% guarantee)
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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NJEA is party to a power purchase agreement with Jersey Central Power and Light
Company (JCP&L) with a liquidated damages provision that requires the owner to
pay $36.00/MWh (on-peak shortfall for portion below 85% of 3-year average).
The owner is covered under the JCP&L damage provision by the liquidated damages
that would be collected from Westinghouse under the O&M agreement. Electrical
output shortfalls would reduce gross project income by approximately $38/MWh on
the basis of the 1997 weighted average power sales rate. The liquidated damages
mitigate lost income and provide an economic incentive to the operator to
maintain or exceed the guarantee. Output in excess of the guarantee increases
the project net income since the cost of bonuses is less than the incremental
power sales income.
Westinghouse must also maintain a guaranteed net plant heat rate and pay
liquidated damages for any incremental fuel costs due to deviations above the
guaranteed value. Steam sales are made to Hercules under a steam sales
agreement. Under the terms of the O&M agreement, Westinghouse is responsible for
paying the liquidated damages specified in the steam sales agreement for
shortfalls in steam supply. These damages are intended to compensate Hercules
for having to generate steam with their own boilers.
NONFUEL O&M EXPENSES
Since only three years remain on the existing O&M agreement with Westinghouse,
and the cash flows associated with this agreement are predictable based on past
experience, the focus of this analysis is on the years after the Westinghouse
contract expires.
The Westinghouse fee for the 1997/1998 fiscal year is $6,430,000 at Bellingham
and $7,292,000 at Sayreville. Furthermore, the performance bonuses of $2,000,000
at Bellingham and $1,600,000 at Sayreville are reasonable. The pro forma
reflects these values.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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To test the validity of the pro forma O&M budget estimate for years after the
existing O&M agreement, O&M cost estimates were independently developed on the
basis of in-house databases and the following recent industry data sources:
o Federal Energy Regulatory Commission (FERC) Form 1 data for existing
gas turbine and combustion turbine/combined-cycle plants, including O&M
costs, capital modifications, and operating data, submitted annually by
reporting utilities as compiled by the Resource Data Institute.
o O&M cost relationships developed by Oak Ridge National Laboratory
(ORNL), Estimation of Non-Fuel Operation and Maintenance Costs for
Advanced Circulating Fluidized Bed and Advanced Natural Gas-Fired
Combined Cycle Power Plants December 1989. This study includes cost
adjustment factors for differences in sizes and configurations.
o Electric Power Research Institute (EPRI) Report GS-6415, A Comparison
of Steam-Injected Gas Turbine and Combined Cycle Power Plants:
Technology Assessment June 1989.
o Detailed line item budget proposals for long-term O&M contracts
prepared by experienced O&M contractors for other combined-cycle
cogeneration plants, obtained from our in-house data files.
The first two sources were used to validate the estimate totals, adjust costs
for differences in megawatt sizes and number of units, and verify the splits
between fixed and variable components. The first source, the FERC database, was
also used for regression analysis of dollars per kilowatt-year versus annual
operating hours to help validate the fixed and variable cost breakdowns. The
last three sources were used as a means of building up the O&M estimates from
detailed line-item data
The data obtained from FERC include O&M costs that were expensed as well as
those capitalized by reporting utilities. Capitalized amounts are measured by
the year-to-year change in the Form 1 "Cost of Plant" account. According to the
Uniform System of Accounts, routine maintenance is normally expensed while major
repairs that are expected to last several years are capitalized. Since the exact
distinction between expensed and capitalized items varies by individual utility
and public utility commission, the analysis included the sum total of these two
reported costs.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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All data were normalized to 2002 dollars, with costs that occur infrequently,
such as inspections and overhauls, averaged over the long-term maintenance cycle
to an equivalent annual value.
Table 5-1 compares the pro forma estimates with the normalized industry data,
with costs adjusted to 2002 dollars, which is the first full year in which O&M
is by the new owner. The comparison is based on a 93% capacity factor, which is
the 6-year average used in the pro forma. The industry data include estimated
O&M costs of steam injection for NOX control. Although the industry data
subcategories for Total O&M Budget and Total Major Maintenance are different
from those used in the pro forma, the totals are comparable.
Table 5-1 -- Comparison of the Pro Forma Estimates with Normalized Industry Data
Pro Forma Assumptions ($10(3))
---------------------------------------------
Bellingham Sayreville
--------------------- ---------------------
O&M 746 746
Other Direct Costs 644 476
Payroll and Related 2,083 2,013
Operator Fee 750 750
Water Costs 643 1,447
Capital Expenditures 100 100
--------------------- ---------------------
Total O&M Budget 4,966 5,532
Total Major Maintenance 2,514 2,438
Industry Average
---------------------
Labor Cost 1,542
Maintenance Materials 2,174
Raw Water 498
Water Treatment 974
Misc. Consumables 329
---------------------
Total O&M Budget 5,517
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Major Maintenance Inspections 1,531
Major Maintenance Spare Parts 1,050
---------------------
Total Major Maintenance 2,581
The pro forma O&M annual budget, excluding Administrative and Support, of
$4,966,000 for Bellingham is less than the industry average estimate, but within
a reasonable range. The O&M annual budget, excluding Administrative and Support,
of $5,532,000 for Sayreville is consistent with the industry average estimate.
The six-year average Major Maintenance budgets of $2,514,000 for Bellingham and
$2,438,000 for Sayreville are consistent with the industry data estimate of
$2,581,000 and are reasonable. Thus, the assumed O&M budgets are reasonable
forecasts of the actual expenses to be incurred at the plants.
This analysis excludes the pro forma budgets for Property Taxes or Service
Charges, Owner Insurance, Easement Fees, and Other Direct Costs for site
expenses and Administrative and Support expenses. Industry comparisons are
difficult for property taxes and insurance since they are usually reported as
part of corporate overhead not allocated to specific plants. Easement fees and
other site expenses are very site-specific and also not directly comparable with
industry data. Industry comparisons of administrative and support costs are
misleading because of the different methods used to allocate corporate overhead
to individual plants.
The project thereby provides sufficient funds for maintenance practices used in
the industry to minimize degradation of power output and heat rate. The
following schedule is typical of industry practice:
o Routine Maintenance:
- weekly or biweekly online gas turbine compressor water washing;
- offline gas turbine compressor water washing when indicated by plant
performance, which may vary from bimonthly to quarterly depending on
the operating environment; and
- annual gas turbine combustor inspection with minor repairs and
cleaning,
o Major Maintenance:
- hot gas path inspection every three years with full cleaning of the
turbine blade path;
- full gas turbine inspection and overhaul every 5 to 6 years or less
as required; and
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released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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- major steam turbine inspection and overhaul every 5 to 6 years.
The cyclic trend of Major Maintenance expenses in the pro forma reflects the
above schedule.
SUMMARY
The review of the O&M budget estimates for the Bellingham and Sayreville
facilities indicates that the budgets represent reasonable estimates and
assumptions. The budgets provide sufficient funds for routine and major
maintenance practices used in the industry to minimize degradation of power
output and heat rate. The minor corrective actions suggested in this report,
such as routine painting, HRSG tubing inspection and repair, and HRSG foundation
pier inspection and repair, can all be implemented within this budget. Based on
the review of the existing O&M agreements, the specified payments to the
operator should be sufficient to support expected plant performance, and the
liquidated damages for fuel consumption and steam output should be sufficient to
maintain expected net income. The liquidated damages for electrical output
mitigate lost income in the event of reduced plant output and, together with the
bonus provisions, provide an economic incentive to the operator to maintain or
exceed the output guarantee. Once the existing O&M agreements expire, the owner
will bear additional risk for plant performance since the liquidated damage and
bonus incentive will no longer exist. Since the new entity performing the O&M
activities is an affiliate of one of the new owners, the new operator will have
a greater incentive to maintain or improve on the high levels of performance
achieved in the past.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Section 6
PRO FORMA FINANCIAL PROJECTIONS REVIEW
The financial projections presented in Appendix A of this report were prepared
by Northeast Energy, L.P. (Northeast) and are based on the contractual,
operational, and economic assumptions discussed in this section of the report.
The pro forma financial projections prepared for the projects were reviewed. The
review focused on the following issues:
o methodology for preparing the financial projections,
o appropriateness of the general assumptions,
o consistency between the assumptions for plant performance and actual
historical performance,
o consistency between revenue forecasts and existing sales contracts,
o appropriateness of operating expense forecasts, and
o correctness of the pro forma model and calculations therein.
The results of the sensitivity analyses of key parameters were also reviewed.
Certain assumptions incorporated in the pro formas were confirmed in the report
of the Fuel Consultant. Many of the projection assumptions that are discussed in
this section are based on the provisions of individual project contracts,
certain provisions of which are summarized in the Offering Circular. Neither
Northeast's independent accountants, Deloitte & Touche, L.L.P., nor Price
Waterhouse, L.L.P., have either examined or compiled the pro formas or any such
assumptions and, accordingly, do not express any opinion or any other form of
assurance with respect thereto.
The pro formas, while presented with numerical specificity, necessarily are
based on a number of estimates and assumptions that, while considered reasonable
by Northeast, are inherently subject to significant business, economic, and
competitive uncertainties and contingencies, many of which are beyond the
control of Northeast. They are also based on assumptions with respect to future
business decisions that are subject to change.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Accordingly, there can be no assurance that the pro formas will be realized. The
actual results will vary from the pro formas, and such variations may be
significant. The inclusion of the pro formas herein should not be regarded as a
representation by Northeast or any other person that the pro formas will be
achieved. Northeast does not intend to update the pro formas. Prospective
investors in the bonds are cautioned not to place undue reliance on the pro
formas. Capitalized terms used in this section and not otherwise defined have
the meanings assigned in Appendix A of the Offering Circular. The assumptions
described in this section were used in the preparation of a base-case projection
and in the sensitivity case projections except where otherwise noted in the
introduction to the sensitivity case projections.
Under the base-case assumptions, the pro forma financial projections show a
minimum debt service coverage ratio for the Bonds of 2.25 times and an average
debt service coverage ratio of 2.88 times over the life of the Bonds. The debt
service coverage ratios remain relatively stable over a broad range of
sensitivities.
OPERATIONAL ASSUMPTIONS
In general, the pro forma financial models assume that both plants will generate
at the maximum available capacity, will provide export steam for the duration of
existing contracts, will supply power in accordance with the power purchase
agreements, and will sell all surplus generation on the open market.
Capacity
The pro formas assume a base capacity with annual degradation of 0.7% in
nonoverhaul years, returning to base capacity after major maintenance. The net
capacity available for sale for a typical year is determined as shown on Table
6-1.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Table 6-1 -- Determination of Net Capacity Available for Sale
Bellingham Sayreville
------------------------ ------------------------
Base Capacity 315.9 MW 308.0 MW
Degradation 0.7% 0.7%
Power Plant Load 5.5 MW 5.5 MW
Steam Load 0.8 MW 13.2 MW
CO2 Load 4.5 MW NA
Net Capacity 302.9 MW 287.2 MW
The base capacity at each plant is reasonable and conservative. The 1991 Plant
Acceptance Test for Bellingham indicated that the original net capacity,
including the CO2 plant load, was 312.3 MW, equal to a base capacity of 318.6
MW. The pro forma assumption of 315.9 MW allows for 1% nonrecoverable
degradation, which is reasonable. As stated earlier in this report, the
different inlet steam conditions at Sayreville result in reduced performance of
7 MW in the steam turbine. This reduction is reflected in the base capacity
assumptions.
The power plant load is in accordance with Westinghouse energy balances and
plant power consumption observed from control room monitors during plant
walkdowns.
The steam load is appropriate considering the Sayreville heat rate correction
procedure and the minimal export steam at Bellingham.
The CO2 plant load is conservative based on past demand of the plant. The owner
reports indicate the annual consumption of the CO2 plant to be no greater than
37,340 MWh, equivalent to 4.26 MW.
In the pro forma, projected net electrical output for the Bellingham Project is
290 MW in 1998 increasing to approximately 300 MW from 1999 through the
scheduled term of the securities, which reflects the additional sale of power
from unused capacity at the Bellingham Project in varying amounts from 9.6 MW to
15.4 MW between 1999 and 2010, approximately one year before the final maturity
of the Bonds. Upon expiration of the Boston
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
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Edison II PPA in September 2011, approximately three months before the final
maturity of the Bonds, the Bellingham Project is assumed to sell 36.3 MW of
merchant power in the open market.
These assumptions generally reflect the current operating scenario for the
Bellingham Cogeneration Facility, which is currently operating at full capacity,
corrected for export steam. Therefore, the actual plant performance data
discussed in Section 4 of this report can be used directly to assess the
appropriateness of the plant performance assumptions.
In the pro forma, projected net electrical output for the Sayreville Project
under the JCP&L contract is 252 MW. Additional sales of power in the open market
from the Sayreville Project's unused capacity of approximately 35 MW is assumed
to begin January 1, 1999. After the termination of the JCP&L contract in August
2011, approximately four months before the final maturity of the Bonds, the
model assumes that the previously contracted 252 MW will be sold in the open
market.
The above assumptions represent a new operating scenario for the Sayreville
Cogeneration Facility, which is currently operating below its maximum available
capacity. Due to the pricing structure of the single PPA for Sayreville, the
plant generally has been operated at a net output of 252 MW. This is
approximately 20 MW below its rated output when delivering export steam at the
maximum rate of 230,000 lb/hr. The actual average export steam rate of
approximately 125,000 lb/hr has been significantly less than this maximum. At
this lower export rate, the plant's net output of 252 MW is approximately 35 MW
below its rated available capacity. Therefore, the actual plant performance data
discussed in Section 4 of this report, specifically the heat rate and
generation, cannot be used directly to assess the appropriateness of the plant
performance assumptions. Such an assessment must be based on performance trends.
The assumed operating scenario for Sayreville is a credible scenario. The terms
of the PPA with JCP&L give JCP&L the first right to any excess power generated,
which would be sold at unfavorable rates. The pro forma reflects a
revenue-sharing arrangement with JCP&L, which should provide adequate incentive
to JCP&L to allow the sale of excess generation to third parties. The effect of
no merchant power sales is considered in Sensitivity
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released to any third party without the prior written consent of S&L. Copyright
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Case E. In this case, the pro formas yield an average coverage ratio of 2.59
times and a minimum coverage ratio of 1.37 times.
Availability
During a year in which no major inspections or maintenance outages are
scheduled, the Sayreville pro forma assumes a 93.3% availability factor derived
as follows:
o Planned Outage 1.5% 131.4 hours
o Maintenance Outage 1.5% 131.4 hours
o Forced Outage 1.4% 122.2 hours
o Curtailment 2.28% 200.0 hours
The curtailment allowance escalates to 400 hours in 2002 in accordance with the
terms of the PPA. Although additional curtailments enforced by the fuel supplier
do periodically occur, these curtailments are minimal and their exclusion from
the availability calculation should have no bearing on the results. The
allowance for forced outages is in accordance with industry guidelines and
current trends at the plant. The planned outage schedule reflects the equipment
requirements, namely a 3-day annual inspection increasing to 3-4 weeks during
years in which major maintenance activities are scheduled. The routine
maintenance allowance is appropriate considering the availability is in
accordance with current plant trends. In summary, the availability projections
for Sayreville are reasonable.
The corresponding breakdown was not included in the Bellingham pro forma. The
assumed 96% availability during years in which no major maintenance activities
are scheduled generally represents the above breakdown for Sayreville if
curtailment is excluded. There are minor curtailment provisions of the
Bellingham PPAs, and the plant has experienced some curtailments as discussed in
Section 4. The availability projections for Bellingham are reasonable. The
effect of lower station availabilities is evaluated in Sensitivity Case C.
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released to any third party without the prior written consent of S&L. Copyright
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Heat Rate as Fuel Consumption per Kilowatt-Hour
The pro formas assume a baseline heat rate with an annual degradation of 0.7%
for years during which no major maintenance outage is scheduled, returning to
the baseline heat rate after major maintenance has been performed.
At Bellingham, the assumed baseline heat rate is 8229 Btu/kWh, with an average
heat rate of 8304 Btu/kWh over the 6-year major maintenance cycle. As presented
in Section 4, the average actual operating heat rate is 8282.6 Btu/kWh.
Therefore, the degraded heat rates assumed in the pro forma are conservative.
Total fuel consumption is derived by multiplying this heat rate by the output of
the Bellingham Project, including both electricity consumed by the CO2 plant and
electricity sold to the Bellingham Power Purchasers.
At Sayreville, the assumed baseline heat rate is 9057 Btu/kWh in the first year
and 8461 Btu/kWh from 1999 through 2011. This trend reflects continued reduced
load operation in the first year and full-load operation with export steam
starting in 1999.
The operating scenario assumed in the first year is comparable to the actual
operating scenario for which data are presented in Section 4. The assumed heat
rate is in accordance with the actual operating heat rate. At full-load
operation, the fuel consumption rate is unaffected by the relationship between
export steam and electrical generation. Therefore, the heat rate in subsequent
years can be determined using the 1991 Plant Acceptance Test, which was
performed at full-load conditions, and pro-rating according to the relative net
capacities. The heat rates assumed in the pro forma are consistent with this
approach, and they are considered reasonable forecasts of the heat rates in
future years.
The fuel consumption is correctly calculated using the net plant heat rate, the
net capacity available for sale, and the availability factor.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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POWER GENERATION REVENUES
Power Sales Prices
Power from the Bellingham Project and the Sayreville Project is sold to the four
Power Purchasers under six Power Purchase Agreements (PPAs). Power prices in the
financial model are projected on the basis of base prices set forth in the
respective PPAs. The base prices set forth in the respective contracts increase
by either fixed rates, reference to Avoided Cost indices, reference to gas
prices, or reference to fuel oil prices. Certain of the projected power sales
prices are based on assumptions regarding prospective fuel costs. Assumptions
regarding projected fuel prices are reviewed in the Fuel Consultant's Report
included in the Offering Circular. For further detail on the pricing provisions
of these contracts, see "Summary of Principal Project Agreements" as part of the
Offering Circular.
The sales of additional uncontracted merchant power on the open market are at
well-documented market prices for generation and capacity.
In summary, the revenues assumed in the pro forma are reasonable and
appropriate.
Energy Banks
NEA has incurred Energy Bank liabilities under its Boston Edison I and Montaup
Electric Company PPAs. The balance under the Boston Edison I PPA is projected to
decrease to 0 by year 2007, and the balance under the Montaup Electric Company
PPA is projected to increase to approximately $60,000,000 by December 31, 2011.
These Energy Bank liabilities are supported by letters of credit to the
respective utilities. Increases or decreases in the Energy Bank liabilities do
not affect the project cash flows. For a further discussion of the Energy Banks,
see "Summary of Principal Project Agreements."
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Gross Steam Production Income
NEA
The net cash flow impact to NEA from the steam produced by the Bellingham
Project is determined by the production and sale of carbon dioxide. CO2 sales
are projected at nominally 330 tons per day, and steam use is projected at
nominally 51,500 pounds per hour (lb/hr). The actual CO2 sales and steam use are
based on the power plant's availability factor. The price at which CO2 is sold
is projected to escalate with inflation. CO2 cash revenues are applied first to
pay the direct operation costs and fees incurred in the operation of the CO2
plant, and any residual up to the $1,200,000 rent payable under the lease
between NEA and NECO-Bellingham, Inc., is paid to NEA.
NJEA
For the pro formas, output to Hercules is projected to be approximately 125,000
lb/hr, consistent with current operating experience at the Sayreville Project.
The Hercules steam purchase price is escalated at the rate of inflation from the
$2.5 per thousand pounds paid in 1996. This results in a projected price of $2.6
per thousand pounds in 1998, escalated at half the rate of inflation.
Project Operating Costs
Delivered Fuel Cost
Delivered fuel commodity and transportation costs are discussed in the Fuel
Consultant's Report.
Nonfuel Operations and Maintenance Expenses
The nonfuel operations and maintenance expenses are evaluated in detail in
Section 5 of this report. To summarize the conclusion of Section 5, the O&M
budgets for the Bellingham and Sayreville facilities represent reasonable
estimates and assumptions. The budgets provide sufficient funds for routine and
major maintenance practices used in the industry to minimize degradation of
power output and heat rate.
In summary, the operations and maintenance expenses assumed in the pro forma are
reasonable and appropriate.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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General and Administrative Expenses
Costs for insurance, property taxes, easement fees, administrative expenses, and
General Partner management fees are projected on the basis of historical costs.
The General Partner management fee is set forth in the Indenture. Costs for
insurance, property taxes, and easement fees are escalated in a manner
appropriate for these items. All administrative expenses and the General Partner
management fee are projected to grow at the same rate as inflation.
Financing Costs
Bond Payments
The Bond financing is modeled as a $220 million issue, with semi-annual
principal payments beginning June 30, 2002, an assumed issue date of February
15, 1998, and a final maturity of December 30, 2011.
Project Securities Payments
The pro forma identifies approximately $490 million of Project Securities
outstanding as of December 31, 1997. These securities are subject to semi-annual
principal and interest payments through December 30, 2010.
Other Facilities
The pro formas include expected interest and fee expenses for letters of credit
that are issued to support the Projects' Energy Bank and Debt Service Reserve
obligations, and for the Working Capital Facility. Because the Projects are
assumed to be consistently cash-flow positive on a monthly basis, and as the
Working Capital Facility has never been drawn upon, the pro formas do not
anticipate any draws under the Working Capital Facility, and Northeast currently
intends to discontinue this facility.
Interest Income
The pro formas assume that the Projects will earn interest income on all free
cash balances at a rate equal to 2% more than the projected rate of inflation.
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released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Reserve Accounts
Debt Service Reserve
The pro formas assume that ESI Tractebel Funding will obtain a Substitute Letter
of Credit in an amount sufficient to cover six months of principal and interest
on the Project Securities as permitted under the Project Indenture. Similarly,
the pro formas assume that the Issuer will obtain a Letter of Credit in an
amount sufficient to cover six months of principal and interest on the Bonds as
permitted under the Indenture.
Major Overhaul Reserve
A major overhaul reserve is provided during the term of the O&M Agreements in an
amount equal to the next year's projected major maintenance costs. These
expenses are included as cash expenses on a current basis during the period
following the expiration of the O&M Agreements based on a major overhaul expense
projection provided by Northeast. As discussed in Section 5, the O&M budgets for
the Bellingham and Sayreville facilities represent reasonable estimates and
assumptions.
Gas Transmission Reserve
ESI Tractebel Funding has agreed pursuant to the Project Indenture to set aside
funds in the Gas Transmission Reserve Fund, in the event that the Transco
Agreements are not extended through the final maturity of the Project
Securities. Because of regulations governing pipeline transportation, Northeast
believes that it is likely that they will be able to extend these contracts, and
therefore they believe that reserving will not be required, and the pro forma
does not include any reserve.
BASE-CASE RESULTS
On the basis of the analyses of the Projects and the assumptions discussed in
this section, distributions to the Issuer deriving from the projected revenues
from the sale of electrical and thermal energy are adequate to pay annual
operating and maintenance expenses, including provisions for major maintenance;
fuel expenses and other operating expenses; and principal and interest on the
Bonds and to provide a minimum annual debt service
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released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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coverage ratio for the Bonds of 2.25 times and an average annual debt service
coverage ratio of 2.88 times over the life of the Bonds.
SENSITIVITY ANALYSES
To demonstrate the effect on the Base Case of using different assumptions,
certain sensitivity cases were reviewed. It should be noted that other changed
assumptions could have been considered and that the sensitivity cases presented
here reflect only a small number of possible variations on the Base Case. The
sensitivity cases are presented in Appendix B of this report. The sensitivity
cases are described below.
Sensitivity Case A: Increased Spot Gas Prices
For Sensitivity Case A, projected spot market natural gas costs are increased 6%
over the levels assumed in the Base Case. Contracted power sales prices are tied
to either fixed rates or projections of gas-based and avoided-cost based
escalators, as called for in the PPAs.
Sensitivity Case B: Increased Inflation Rate
For Sensitivity Case B, the rate of inflation is assumed to be 4.0% per year
versus the assumed rate of 2.7% to 2.8% per year under the Base Case.
Sensitivity Case C: Lower Station Availability
For Sensitivity Case C, the availability factor for both Projects is assumed to
be 90.0% throughout the projection period versus the assumed average
availability factor of 96% for Bellingham and 93.3% for Sayreville under the
Base Case. Decreasing the station availability reduces both the revenues and the
fuel expense, and it has an overall effect of reducing the projects' cash flow.
The 90% availability factor is below the availability demonstrated at either of
the plants as well as below the industry average for similar plants. The 90%
availability is a reasonable estimate of the lower bound for the plants.
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released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Sensitivity Case D: Lower Fuel Efficiency
For Sensitivity Case D, the heat rate at each plant is assumed to be 110% of
that assumed in each year of the Base Case. Increasing the net plant heat rate
increases the fuel consumption, and thereby reduces cash flow. The 10% increase
places the heat rates used in the pro formas well above the actual heat rates
experienced at either of the plants. Furthermore, the power plant technology is
very mature and the operation and maintenance practices are well established. It
is unlikely that the net plant heat rate will deteriorate beyond the 10%
considered. The 10% heat rate increase is a reasonable estimate of the upper
bound for the plants.
Sensitivity Case E: No Merchant Power Sales
For Sensitivity Case E, it is assumed that there are no sales of uncontracted
merchant power at either Bellingham or Sayreville throughout the duration of the
pro formas. Under this scenario, all contracted costs are paid and a minimum
contract-based coverage of 1.37 is maintained.
SUMMARY
The annual debt service coverage ratios for the base case and sensitivity cases
presented by Northeast are shown in Table 6-2. These coverage ratios represent
cash distributions to Northeast divided by scheduled annual debt service on the
Bonds.
Table 6-2 -- Annual Bond Debt Service Coverage Ratios
Minimum Average
------------------------- -----------------------
Base Case 2.25 x 2.88 x
Sensitivity Case A 2.21 x 2.87 x
Sensitivity Case B 2.17 x 2.80 x
Sensitivity Case C 2.05 x 2.65 x
Sensitivity Case D 1.88 x 2.33 x
Sensitivity Case E 1.37 x 2.59 x
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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The debt service coverage raios under the base case and sensitivity cases
remain relatively stable over a broad range of sensitivities around the key
parameters discussed in this report.
Based on a review of the structure of the pro formas and a detailed review of a
sample of the more significant calculations, the financial model appears
accurate and in accordance with industry practice, and the pro forma financial
projections are reasonable forecasts of the future financial performance of the
projects.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Section 7
PERMITTING AND COMPLIANCE REVIEW
The objective of the environmental permitting and compliance review was to
confirm that all required permits have been obtained, that the plants have been
operating in compliance with those permits, and that adequate facilities and
procedures are in place to ensure continued compliance. If events of
noncompliance have occurred, the corrective actions were reviewed to confirm
that future noncompliance should be prevented. In addition, potential future
environmental regulations were considered to determine the potential impact on
the facilities.
The review included physical walkdowns of the facilities, interviews with key
plant personnel, and reviews of documents and records maintained by the owners
and the operators of the facilities. Engineering and design documents, permits
and permit applications, and records and reports required by those permits and
related regulations were reviewed.
The results of the review are discussed in the following sections.
BELLINGHAM COGENERATION FACILITY
Energy and Utility Approvals and Requirements
Under Massachusetts law, an approval from the Massachusetts Energy Facility
Siting Council for construction of a proposed bulk electric generating unit at a
proposed site is required before a construction permit is issued by any other
state agencies. This approval is also required for the transmission line. An
applicant must show that the energy supplied by the proposed facility is needed
and that the proposed facility can provide the necessary energy supply with the
minimum impact on the environment and at the lowest possible cost.
A Petition for Approval to Construct a Bulk Generating Facility was filed in
June 1987. A Final Decision was issued by the Siting Council on December 9,
1987, approving the petition subject to two conditions:
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o The owners monitor noise levels near the plant for two years and
maintain records of any noise complaints received, and
o The owners provide selective tree plantings along nearby residential
streets to reduce the visibility of the chimney.
Based on our inspection of the facility and of certain documents, the facility
is in compliance with these requirements. Compliance with the noise guidelines
is discussed in further detail later in this section.
A Qualifying Facility (QF) Certification was received from the Federal Energy
Regulatory Commission. The QF certification indicates that the project will have
sufficient steam sales to qualify as a cogeneration facility under the Public
Utilities Regulatory Policies Act of 1978. The certification was initially
received before the plans to construct the CO2 plant were finalized and was
recertified based on steam sales to the plant. On the basis of the review of the
technical parameters of the facility and plant performance, the facility should
continue to meet the QF criteria. No action is required to maintain the QF
certification.
A Self-Certification of Capability to Use Coal or Alternate Fuel was filed with
the Economic Regulatory Administration of the Department of Energy on July 27,
1987. The Economic Regulatory Administration published a notice of the
self-certification in the Federal Register on August 11, 1987. This constitutes
the facility's compliance with the Power Plant and Industrial Fuel Use Act of
1978. No further action to maintain compliance is required.
Environmental Impact Report
A Certificate of the Massachusetts Secretary of Environmental Affairs on the
Final Environmental Impact Report (FEIR) was issued on March 18, 1988,
concluding the state environmental review process under the Massachusetts
Environmental Policy Act that was begun in August 1986. The Secretary noted that
the FEIR was thorough in its presentation of the various environmental issues
and that several improvements to the project had been made during the course of
the review. No conditions for compliance were imposed. Therefore, the project is
in compliance with the certificate and is expected to remain in compliance.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Soil and Groundwater Contamination
The Site Assessment Relative to Oil and Hazardous Material, dated May 9, 1988,
which was prepared by the BSC Group - Boston, Inc. (BSC) for the Bellingham
site, was reviewed. The site assessment was conducted by BSC in December 1987
and January 1988. The site assessment consisted of historical research into past
land uses of the site and adjacent properties, investigation of state and
federal records, interviews with local authorities, field reconnaissance of the
site, and sampling and analysis of groundwater and soil samples.
BSC concluded that there was no evidence that oil or hazardous material was on
the site or had been released on the site. They also concluded that the
potential for offsite migration of contaminants from an adjacent parcel was
negligible. Subsequent sampling and analysis of groundwater in April 1989 by BSC
further supported these conclusions. The scope and methodology of the site
assessment was adequate in connection with the conclusions reached, and the
conclusions were reasonably drawn.
Soil and groundwater contamination that occurred after the construction and
operation of the plant is discussed in the Oil and Chemical Spill Response
section.
Air Pollution Control Permits
Several air quality control permits are required by state and federal law, all
under the authority of the Massachusetts Department of Environmental Protection
(MDEP), formerly the Massachusetts Department of Environmental Quality
Engineering. All of the permits and approvals currently required have been
obtained, including the following:
o Prevention of Significant Deterioration (PSD) Permit, issued by the
MDEP on February 1, 1989
o Conditional Approval to construct and operate the facility, issued by
the MDEP on February 1, 1989
o Final Approval for operation, issued by the MDEP on June 11, 1989
o An NOX Emission Control Plan (ECP), approved by the MDEP, initially on
September 15, 1994, with an updated ECP plan approved on November 3,
1994.
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released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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The four permits and approvals provide numerous conditions with which the
facility must comply, including the following key conditions:
o Operating Limitations restrict the plant to a maximum operating rate of
2560 mmBtu/hr* when burning natural gas and 2472 mmBtu/hr when burning
fuel oil.
o Emission limits for SO2, NOX, particulate, CO, and VOC, for both oil-
and gas-fired operations, in lb/mmBtu per turbine, lb/hr for the plant,
and ton/yr for the plant. Opacity of the chimney emissions and noise
impacts are also limited. The following emission limits apply:
Table 7-1 -- Emission Limits for Bellingham
Emission Limits Emission Limits
for Natural Gas Firing for Distillate Oil Firing
---------------- -------------------------------------- -------------------------------------
Per Turbine Plant Total Per Turbine Plant Total
Pollutant (lb/mmBtu) (lb/hr) (lb/mmBtu) (lb/hr)
---------------- ------------------ ----------------- ----------------- -----------------
SO2 0.0016 4.0 0.2136 528.0
NOX 0.0859 (1) 220.0 0.1497 (2) 370.0
PM 0.0047 12.0 0.0647 160.0
CO 0.0516 132.0 0.3277 810.0
VOC 0.0043 11.0 0.0151 37.4
Opacity 10% 10% 10% 10%
------------------------------------
1 Equivalent to 25 ppmvd @ 15% O2
2 Equivalent to 42 ppmvd @ 15% O2
o Fuel oil restrictions limit the use of distillate fuel oil to 1440
turbine hours per year and limit fuel oil sulfur content to 0.2% or
less.
o Operation of the steam injection NOX control system with a
steam-to-fuel ratio of at least 1 to 1 during all modes of operation
except the startup and shutdown periods.
- ----------------------
* mmBtu=10(6) Btu
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o Testing and Reporting Requirements include NOX minimization tests to
optimize fuel-to-water ratios, initial performance tests for compliance
with emission limits, and a noise survey. Noise compliance studies are
discussed in further detail later in this section.
o Monitoring and Recording Requirements for the installation and
operation of Continuous Emission Monitors and Recorders (CEM),
Continuous Operating Parameters Monitors and Recorders, and an
operating log.
o Reporting and Record Keeping Requirements, which specify monthly
operation and emissions reports during the first year and quarterly
reports thereafter.
Initially, the plant experienced periods of excess emissions that were reported
to the MDEP. The owner and the operator of the plant have since instituted
changes to eliminate excess emissions. The changes included the installation of
a steam flow gauge for better control of steam injection and adjustment of the
NOX emission target for plant operators from 25 ppm NOX (the permit limit) to
approximately 22 ppm NOX. The most recent quarterly emission reports through the
third quarter of 1997, which covers the period since implementation of the
changes were reviewed. Based on the review, the plant has successfully reduced
periods of excess emissions to those periods acceptable to the MDEP according to
the terms of the permits.
Based on the technical review of the plant and quarterly emissions reports
submitted to the MDEP, the facility is currently operating in compliance with
its air pollution control permits. Based on current operation and maintenance
practices, the plant should continue to operate in compliance.
Other Air Pollution Control Requirements
The Bellingham site is in the Boston-Lawrence-Worcester (Eastern Massachusetts)
Ozone Nonattainment Area, which is classified as a serious nonattainment area
and is part of the Northeast States Ozone Transport Region. Title I of the Clean
Air Act Amendments of 1990 (CAAA) requires states to impose NOX and VOC
Reasonably Available Control Technology (RACT) requirements on existing plants
in ozone nonattainment areas. Existing facilities were required to comply with
the RACT rules by May 31, 1995. The MDEP RACT rules for combustion turbines
require NOX limits of 42 ppmvd when burning natural gas and 65 ppmvd when
burning oil.
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The cogeneration plant already meets these limits, and the ECP was submitted in
compliance with the MDEP requirements for NOX RACT. No additional controls were
required. The plant is exempt from VOC RACT because VOC emissions, other than
those from incomplete combustion, which are exempt, are below the threshold. On
November 14, 1994, the owner submitted a letter to the MDEP documenting the
plant's exemption from VOC RACT.
Under Title V of the CAAA, both the cogeneration plant and the CO2 plant are
required to obtain an Operating Permit that consolidates all existing air
pollution requirements. A Title V Permit Application for the facility was
submitted on May 1, 1995. On October 18, 1995, the MDEP notified the owner that
the application was administratively complete. In early 1997, the MDEP issued a
preliminary draft of the Operating Permit, but has not yet issued a draft for
public comment or a final Operating Permit.
The Operating Permit is intended to consolidate existing air pollution
requirements, not to create new requirements. The preliminary draft reviewed
does not impose additional air pollution control requirements.
Noise Guidelines Compliance
Pursuant to the siting approval, the air pollution control permits, and the
local zoning permits, the facility must not violate industrial noise level
limits in the Bellingham Zoning Codes and in the MDEP's Air Quality Control
Regulations. A noise compliance evaluation was jointly conducted by HMM
Associates, Inc. and Sigma Research Corporation during a period when both the
cogeneration facility and the CO2 plant were operating at essentially full load.
The conclusions of the study were that the noise levels generated by the plant
are well within MDEP and local requirements. The scope and methodology of the
study were appropriate and the conclusions reached were reasonably drawn.
No additional data on plant noise levels have been collected or are required.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Airspace Obstruction Approval
On December 3, 1987, the Federal Aviation Administration determined that
construction of the plant, including the chimney, fuel oil storage tank, and
associated transmission lines, do not constitute an obstruction or a hazard to
air navigation. Marking or lighting of the facility was not required.
Wastewater Discharges
Under state and federal laws, the facility must have permits for discharges of
pollutants to surface waters. The plant discharges two types of wastewater:
sanitary wastes and storm water runoff. Industrial wastewater, including
blowdown from the steam cycle, is generated on site but is not discharged to the
environment because the facility uses a zero-discharge water recycling system.
There is no cooling water discharge, because the facility uses an air-cooled
condenser system.
The cogeneration plant and the CO2 plant each have a septic system for the
disposal of sanitary wastes. A Disposal Works Construction Permit for both of
these septic systems was issued by the Bellingham Board of Health on May 9,
1990. At the request of the Board of Health, the holding tanks for the septic
systems are pumped out once per year. Based on our site inspection, the septic
systems have been constructed and are being operated in compliance with all
conditions.
A determination that a National Pollutant Discharge Elimination System (NPDES)
permit was not required for storm water discharges was made by the MDEP in 1988.
Regulations have changed since that time and now require NPDES permits for storm
water discharges from all industrial facilities. The cogeneration plant has
complied with current regulations by filing a Notice of Intent (NOI) for Storm
Water Discharges Associated with Industrial Activity Under the NPDES General
Permit on September 30, 1992 and, for a renewal, on September 4, 1997. The
general permit requires the facility to develop a storm water pollution
prevention plan (SWPPP). The general permit does not require that the SWPPP be
submitted to or approved by the United States Environmental Protection Agency
(USEPA). This plan was completed in November 1993 and revised in August 1997.
The SWPPP now covers both of the facilities and appears to meet the requirements
of the permit.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Water Withdrawal Permits
The MDEP issued a Water Withdrawal Permit on November 30, 1990, and a modified
permit on March 7, 1991, authorizing the facility to draw groundwater from five
wells in the Charles River Basin, for a 20-year permit term. The authorization
limits the daily average withdrawal to 0.66 million gallons per day (mgd) and
the total annual withdrawal to 240.9 million gallons per year (mgy). The permit
requires metering of the withdrawal amounts and annual reports of the withdrawal
amounts. The permit was issued based on the water conservation program developed
by the facility, in particular, the air-cooled condenser and the zero discharge
water recycling system.
Based on the annual reports filed by Westinghouse for 1991 and by the owner for
1992 through 1996, the facility has been operating in compliance with this
permit, and we expect that the facility will continue to operate in compliance
with this permit.
A permit for water use during construction of the facilities was issued by the
Bellingham Water and Sewer Department on March 8, 1990. The requirements of this
permit are no longer applicable.
Solid and Hazardous Waste Disposal
The facility generates some solid waste, such as small quantities of waste oil,
solvents, and cleaning agents, and approximately one ton per day of solid
residue, evaporator sludge, from the zero-discharge water recycling system.
There are small quantities of non-hazardous-type wastes such as office trash,
fluorescent lighting, scrapped parts, and similar wastes.
The facility is registered with the MDEP as a small quantity generator of waste
oil, and with the USEPA as a very small quantity generator for hazardous wastes.
The owner filed a Notification of Hazardous Waste Activity under RCRA Section
3010. The USEPA issued an Acknowledgment of Notification of Hazardous Waste
Activity on July 15, 1992, and issued an "EPA Identification Number" for the
facility. The Identification Number must be
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released to any third party without the prior written consent of S&L. Copyright
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used on all shipping manifests for transporting hazardous wastes, and on all
annual reports for generators of hazardous wastes required under Subtitle C of
RCRA. All documents reviewed complied with these requirements.
The plant also generates wastes contaminated with polychlorinated biphenyl
compounds (PCBs). These wastes come from a gas-liquid stripper installed by the
Algonquin Gas Transmission Company in 1995 on the incoming natural gas supply
pipeline. The liquids collected in the traps of the stripper can contain small
amounts of PCBs. A Notification of PCB Activity was filed with the USEPA on
February 13, 1996, and acknowledged by the USEPA on February 28, 1996. A USEPA
Identification Number was also issued.
Chemical and Petroleum Storage
Most of the chemicals used at the facility, including chemicals used in the
HRSGs, are used and stored in the water treatment building where adequate
storage facilities are provided. Any spills or leaks in the water treatment
building are contained within the wastewater treatment system. Fuel oil is
stored in a 2,500,000-gallon tank with a concrete secondary containment dike
designed to contain 150% of the contents of the tank.
Tank Permits from the Massachusetts Department of Public Safety were issued on
February 1, 1991, for construction or installation of the evaporator feed tank,
the neutralization tank, and the fuel oil storage tank. The only conditions of
the permits are that the tanks be constructed in accordance with the approved
plans and operated in accordance with the department's rules and regulations.
The state inspected the fuel oil tank on August 22, 1991, and the wastewater
tanks on October 18, 1991. The tanks are in compliance with all requirements.
A Spill Prevention Control and Countermeasure (SPCC) Plan is required by the
Clean Water Act and implementing regulations issued by the USEPA because the
facility stores a large quantity of oil, greater than 660 gallons, on site. A
Facility Response Plan (FRP) is required by the Oil Pollution Act of 1990
because the facility has more than 1,000,000 gallons of storage capacity. The
SPCC plan was prepared by Westinghouse in June 1992, updated on October 7, 1996,
and March 31, 1997, and is kept on site. The FRP was prepared by Westinghouse on
February 14, 1995, and approved by the USEPA on August 21, 1995. The FRP
identifies a emergency response contractor, Zeeco, Inc. of Westborough,
Massachusetts, for responding to an oil discharge.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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The plant is registered with the Massachusetts Department of Public Safety,
Division of Fire Protection. A license for the storage of flammable materials
was granted on September 10, 1990.
Oil and Chemical Spill Response
The cogeneration plant has had only one oil or chemical spill. On February 11,
1992, an oil leak occurred due to a failed flange gasket in the fuel oil
pumphouse. Approximately 23,000 gallons of No. 1 fuel oil were released. The
fuel oil flowed downhill and collected in a low area on the site property. Upon
discovery, immediate action was taken by the plant operating personnel to stop
the leak and contain the release. Eventually, emergency response actions were
taken by Westinghouse Remediation Services, Zecco, Inc., and ENSR Consulting and
Engineering (ENSR). The approximate extent of soil contamination consisted of an
area 200 feet by 120 feet. The oil was contained on site, and no oil was ever
observed in the drainage swale leading to Box Pond or in the pond itself.
All of the oil was removed from the ground surface, and eventually all
oil-contaminated soil, approximately 2500 tons, was removed. A groundwater
pump-and-treat operation was established to remove any remaining groundwater
contamination and prevent impacts to Box Pond and its associated wetlands. The
pump-and-treat operation uses two activated carbon units to remove petroleum
hydrocarbons from the pumped groundwater.
Petroleum hydrocarbons were initially detected in groundwater on site, but
petroleum hydrocarbon concentrations are now generally low.
Within the pumphouse, where the leak occurred, several changes have been made.
The pumphouse has been surrounded by a low concrete sill to prevent oil from
escaping, and the floor drains in the pumphouse have been routed to a sump with
an oil separator. Any oil collected in the oil separator is returned to the fuel
oil storage tank. All of the gaskets similar to the one that failed have been
replaced.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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On September 23, 1993, ENSR submitted a Waiver Application and a Phase 1 Report
on the remedial actions to the MDEP. The report concluded that the remedial
actions taken at the site had successfully addressed the MDEP's concerns. On
February 16, 1994, the MDEP approved the Waiver Application on the condition
that the groundwater treatment system continue to be operated until petroleum
hydrocarbon concentrations are consistently below standards. ENSR has submitted
periodic updates on the progress of the remedial groundwater treatment system
through April 24, 1997.
The oil spill and subsequent remediation activities have been the responsibility
of Westinghouse, the EPC contractor and operator. Westinghouse is continuing to
evaluate options to obtain site closure for the groundwater remediation,
consistent with the Massachusetts Contingency Plan. Recommendations from their
remediation consultant, ENSR, are expected soon. To date, Westinghouse has
diligently pursued closure of this issue, and they should be able to do so to
the satisfaction of the MDEP.
Wetlands and Floodplain Permits
Floodplain construction permits were not required because construction of the
facility did not impact any flood hazard zones delineated by the Federal
Emergency Management Agency.
The Bellingham Conservation Commission (BCC) issued an amended Order of
Conditions under the Massachusetts Wetlands Protection Act for the construction
of the transmission line on September 16, 1988, and for the construction of the
water pipeline on September 12, 1988.
The Orders were required to be recorded at the Registry of Deeds before starting
work. They were recorded, and a Certificate of Compliance was issued by the
Conservation Commission. A condition of the Order of Conditions requires
on-going maintenance of certain on-site facilities, such as drainage structures
and vegetative cover. Based on the inspection of the site, the facility is in
compliance with these conditions.
The excavation of oil-contaminated soil, as discussed in the preceding Oil and
Chemical Spill Response section, impacted approximately 7200 ft2 of wetlands.
The BCC issued a Notice of Emergency Certification on February 13, 1992, for the
initial remedial activities. On August 5, 1994, an application for wetland
restoration activities for the affected wetlands was submitted to the BCC. The
BCC issued an Order of Conditions for the activities, which were completed in
September 1995. An annual wetlands restoration monitoring report was submitted
to the BCC in April 1996.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Zoning Approvals
The facility was built on a site that was principally within the Industrial
Zoning District and partially within B-1 and Residential Zoning Districts. The
Bellingham Planning Board approved the subdivision of the site, issued three
special permits under the Bellingham Zoning Bylaw, and approved the site plan
for the project on May 11, 1989. The special permits include the following key
conditions:
o The owner was required to retain a consultant to review material
storage and safety measures on the site;
o The owner was required to provide groundwater quality monitoring wells
and surface water quality monitoring in the storm water detention pond
and Box Pond;
o Residue from the water treatment process is to be disposed of in a
properly licensed out-of-town landfill;
o Certain fire fighting features were to be incorporated into the plant's
design, construction, and operation, such as access for fire fighting
equipment, provision of onsite fire fighting equipment, training for
local fire fighters, and alarms at the Bellingham Fire House; and
o Periodic inspections are to be performed of oil and chemical storage
tanks.
On June 24, 1997, the Bellingham Planning Board agreed to reduce the groundwater
monitoring program to once every two years and to limit the sampling to
parameters indicative of petroleum and other industrial chemicals used at the
plant.
Based on the inspection of the facilities and review of certain documents, the
plant is in compliance with all of these requirements.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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The Bellingham Zoning Board of Appeals issued a Special Permit to allow the use
of land for the transmission line, provided the approval for the transmission
line was obtained from the BCC. The BCC approved the transmission line, as
discussed in the preceding Wetlands and Floodplain Permits section.
Building Permits
The Town Inspector for the Village of Bellingham has issued building permits.
All of the structures were inspected, and Occupancy Permits were issued on
February 25, 1992.
Right-of-Way Permits
The Norfolk County Commissioners approved construction of a railroad spur across
Depot Street on May 13, 1990. The approval required that the construction be
completed in accordance with plans filed with the commission. Based on the
inspection of the crossing, the facility is in compliance with this approval.
The Massachusetts Office of Transportation and Construction approved
construction of a building on former railroad right-of-way at the Bellingham
site on September 3, 1991. No specific conditions were required.
Future Environmental Regulations
Because the plant has already received the required permits and approvals, has
been constructed, and has operated for several years, it is unlikely that future
environmental requirements will significantly affect the project. Many new
environmental regulations have provisions to "grandfather" existing facilities.
However, some environmental programs have the potential to affect existing
facilities in the future. These include the following programs:
o The Continuous Assurance Monitoring (CAM) rule
o Reporting requirements under Section 313 of the Emergency Planning and
Community Right-To-Know Act (EPCRA)
o New National Ambient Air Quality Standards (NAAQS) for ozone and PM2.5
o Additional NOX restrictions to control ground-level ozone, pursuant to
the recommendations of the Ozone Transport Assessment Group (OTAG), the
Ozone Transport Commission (OTC), and the MDEP NOX Allowance Program
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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o Any greenhouse effect/global warming requirements resulting from
ongoing international political debates.
In our opinion, the facility is generally well designed and has existing systems
in place to meet any expected requirements from these programs. Some
administrative or management changes may be required, for example, to meet the
EPCRA reporting requirements.
The OTAG and OTC recommendations may ultimately require NOX emission limits as
low as 0.15 lb/mmBtu for existing plants. The facility is already required to
meet an emission limit of 0.0859 lb/mmBtu while burning natural gas and 0.1497
lb/mmBtu when burning oil. The MDEP NOX Allowance Program has allocated 458 tons
of NOX emissions per ozone season to the facility. This allowance exceeds the
already-permitted emissions by over 50 tons when burning natural gas. The
allowance will permit firing oil for 722 hours during the ozone season and
firing gas for 100% of the remaining hours in the ozone season. Therefore, it is
unlikely that the facility will be substantially affected by additional NOX
restrictions. A worst-case scenario would be the required installation of a
selective catalytic reduction (SCR) system to further reduce NOX emissions. The
estimated cost for installation of an SCR system is in the range of $1,200,000
to $1,500,000.
CO2 Plant - Air Permit
The MDEP issued an air permit to construct and operate the CO2 plant on March 8,
1989. A revised permit was issued on December 11, 1989. The permit establishes
emission limits for MEA and VOCs from the absorber. As required by the permit,
various performance tests and emissions tests were completed in 1992, and a
report of the results was submitted to MDEP.
On May 20, 1993, Fluor Daniel and Eastmount Engineering, Inc., issued a
certificate confirming that during the June 1992 performance tests, the plant
emissions were in compliance with the permit and all applicable rules and
regulations of the MDEP. The supporting documentation was reviewed and found to
support this certification.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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CO2 Plant - Chemical Spill Response
Three accidental chemical spills have occurred at the CO2 plant. On January 18,
1992, between 10 and 20 gallons of backwash water from a new activated carbon
bed were spilled to the plant sewer system. On April 2, 1992, a soda ash spill
of up to 50 gallons occurred. Finally, on August 4, 1992, approximately 150
gallons of MEA solution were sprayed on the ground, of which approximately 25
gallons drained to the plant sewer system.
Initial response to all three spills, taken by the operator, included quickly
stopping the source of the leaks and containing spilled materials. All three
spills were reported to state and local authorities, and prompt cleanup action
was initiated. No spilled material was released from the plant site, and
appropriate follow-up actions were taken to prevent reoccurrence. All three
spills were contained within the plant sewer system. If they had not been
contained within the sewer system, the spills would have been retained in the
plant retention pond.
SAYREVILLE COGENERATION FACILITY
Energy and Utility Approvals and Requirements
A Qualifying Facility (QF) Certification was received from the Federal Energy
Regulatory Commission. The QF certification indicates that the project will have
sufficient steam sales to qualify as a cogeneration facility under the Public
Utilities Regulatory Policies Act of 1978. On the basis of the review of the
technical parameters of the facility and plant performance, the facility should
continue to meet the QF criteria. No action is required to maintain the QF
certification.
A Self-Certification of Capability to Use Coal or Alternate Fuel was filed with
the Economic Regulatory Administration of the Department of Energy on July 27,
1987. The Economic Regulatory Administration published a notice of the
self-certification in the Federal Register on August 11, 1987. This action
constitutes the facility's compliance with the Power Plant and Industrial Fuel
Use Act of 1978. No further action to maintain compliance is needed.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Soil and Groundwater Contamination
The Environmental Site Assessment, dated May 4, 1989, which was prepared by EFP
Associates, Inc. (EFP) for the Sayreville site, was reviewed. EFP conducted the
site assessment in March and April 1989. The site assessment included historical
research relating to prior land use, a site reconnaissance, and a field
investigation of soils and groundwater conditions. Samples of soil and
groundwater were analyzed for numerous chemical parameters.
No chemical compounds were detected in the soil or groundwater samples above
NJDEP Cleanup Action Levels. Therefore, EFP concluded that no soil or
groundwater remediation was warranted for the Sayreville site. The scope and
methodology of the environmental site assessment was adequate in connection with
the conclusions reached, and the conclusions were reasonably drawn.
Soil and groundwater contamination that occurred after the construction and
operation of the plant is discussed in the Oil and Chemical Spill Response
section.
Air Pollution Control Permits
Several air quality control permits are required by state and federal law, all
issued by the New Jersey Department of Environmental Protection and Energy
(NJDEPE). All of the permits currently required have been obtained, including--
o Prevention of Significant Deterioration (PSD) Permit, issued by the
NJDEPE on May 22, 1989
o A Permit to Construct, Install or Alter Control Apparatus or Equipment,
and a Temporary Certificate to Operate the facility, also issued by the
NJDEPE on May 22, 1989
o A five-year Certificate to Operate Control Apparatus or Equipment,
originally issued by the NJDEPE on February 8, 1990. The current
certificate expires on July 21, 1998.
These permits provide numerous conditions with which the facility must comply
including the following key conditions:
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released to any third party without the prior written consent of S&L. Copyright
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o Operating Limitations restrict the total annual natural gas fired in
the turbines to a maximum of 2.474 x 1013 Btu.
o Emission limits for total suspended particulates, PM10, SO2, NOX, CO,
and total nonmethane hydrocarbons (TNMH), in lb/hr, lb/mmBtu, and
ton/yr for the plant. Opacity of the chimney emissions and odors are
also limited. The following emission limits apply:
Table 7-2 -- Emission Limits for Sayreville
Emission Limits
for Natural Gas Firing
---------------------------------------------
Per Turbine Per Turbine
Pollutant (lb/mmBtu) (lb/hr)
----------------- --------------------- ---------------------
TSP 0.0153 21.4
PM-10 0.0153 21.4
SO2 0.00164 2.3
H2SO3 0.0005 0.7
NOX 0.0921 (1) 129.0
CO 0.0589 (2) 82.5
TNMH 0.0055 (3) 7.7
Opacity 10% 10%
-----------------------------------------
1 Equivalent to 25.0 ppmvd @ 15% O2
2 Equivalent to 25.0 ppmvd @ 15% O2
3 Equivalent to 4.0 ppmvd @ 15% O2
o Testing and Reporting Requirements require initial emissions
performance tests for compliance with emission limits and to determine
the minimum steam to fuel ratio required to comply with NOX limits.
These emission tests must be repeated in five years before the
expiration of the operating certificate.
o Monitoring and Recording Requirements for the installation and
operation of Continuous Emission Monitors and Recorders (CEM) for NOX,
nonmethane hydrocarbons, CO, and O2, and a continuous monitoring system
for gas and steam flow.
o Reporting and Record Keeping Requirements, which specify quarterly
operation and emission reports.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
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o Ambient Monitoring of toluene, ethyl acrylate, and acrylonitrile at one
location is required. Quarterly reports must be submitted. Until 1994,
ambient monitoring of NOX also was required, but the NJDEPE has dropped
this requirement.
In 1993, the NJDEPE proposed a $6,000 penalty for the plant because of two hours
of excess NOX emissions during the third quarter of 1993. The owner protested
the penalty and submitted information showing that the excess emissions were
caused by equipment shutdown. The NJDEPE and the owner have agreed to settle the
enforcement action through the payment of a penalty of $3,000 without admitting
any noncompliance.
The plant has continued to experience occasional exceedances of the NOX emission
limit. These exceedances occur due to various steam turbine trips that require
the steam injection system to switch from extraction steam to steam from the
main header. For six such incidences, between May 1995 and February 1997, the
owner has been able to successfully assert an "affirmative defense" and has not
been subject to violation notices or penalties.
An affirmative defense, under New Jersey air pollution control laws (NJSA
26:2C-19.2b) is applicable when a violation is the result of startup, shutdown,
or an equipment malfunction. The violation must not be the result of an operator
error, lack of maintenance, or part of a recurrent pattern. If an affirmative
defense is applicable, the NJDEP will not issue a Notice of Violation or assess
penalties for an exceedance of an emission rate, limit, or standard.
Based on the review of the initial performance tests, written reports to the
NJDEPE, and ambient NOX monitoring reports, the plant has been operating in
compliance with the air pollution control permits with the minor exceptions
noted above. The facility should continue to operate in compliance with these
permits.
Under Title V of the CAAA, the plant is required to obtain an Operating Permit
that consolidates all existing air pollution requirements. The permit
application must include a certification that the plant is in compliance with
all existing requirements. The owner submitted the permit application on August
15, 1995. The Operating Permit is intended to consolidate existing air pollution
requirements, not to create new requirements. Because the plant is relatively
new and has low emissions, however, additional air pollution control
requirements do not seem likely.
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Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Noise Levels
Noise levels from the facility are limited by a local zoning ordinance. Based on
the review of the documents, there are no requirements for monitoring noise
levels. Based on a qualitative inspection of the facility, the project appears
to be in compliance with the noise level limitations, and the facility should
remain in compliance in the future.
Airspace Obstruction Approval
On May 8, 1988, the Federal Aviation Administration determined that construction
of the plant, including the chimney and associated transmission lines, do not
constitute an obstruction or a hazard to air navigation. Marking or lighting of
the facility was not required.
Wastewater Discharges
Under state and federal laws, the facility must have permits for discharges of
wastewater to surface water and groundwater. The plant discharges industrial
wastewater, sanitary wastes, and storm water runoff. Industrial and sanitary
wastewater are discharged to the local municipal treatment plant. Storm water
runoff is directed to an infiltration/percolation lagoon where the water is
discharged primarily to the groundwater, with occasional surface discharges.
There are no cooling water discharges, because the facility uses an air-cooled
condenser system. The water and wastewater treatment systems do not generate any
solid residues.
The Middlesex County Utilities Authority (MCUA) approved the facility's
application for sewer service through the Borough of Sayreville system on June
22, 1989, and issued a Non-Domestic Wastewater Discharge Permit for the facility
on April 1, 1992. A modified permit was issued October 1, 1992. The NJDEPE
approved the construction of the sewer main extension to the facility and issued
a Treatment Works Approval (TWA) on March 10, 1993, for the construction of an
oil-water separator and the wastewater holding tank, all of which have been
completed. Monthly monitoring and semi-annual reporting is now required. The
semi-annual Self-Monitoring Reports (SMRs) through June 1997 were reviewed.
These reports show that plant wastewaters are in compliance with permit
conditions. The MCUA has conducted regular inspections of the facility. The most
recent inspection, on January 29, 1997, found some "minor deficiencies" but
otherwise rated the facility as "acceptable."
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A New Jersey Pollutant Discharge Elimination System (NJPDES) permit was issued
by the NJDEPE for discharges of runoff to surface waters and groundwater. The
permit was issued on November 1, 1989, a revised permit was issued on June 15,
1993, and a minor modification was issued on August 27, 1993. The current
expiration date is July 31, 1998. The revised permit, as now in effect,
establishes discharge limits for lead and petroleum hydrocarbons and requires
monitoring of flow, pH, ammonia nitrogen, lead, petroleum hydrocarbons, and
total dissolved solids in the lagoon. Reports must be submitted quarterly. The
discharge monitoring reports (DMRs) through October 1997 were reviewed. These
reports show compliance with permit conditions.
The original NJPDES permit required groundwater monitoring to monitor for
pollution from the runoff. After collecting data during the initial two years of
plant operation, the owner received a revised permit that discontinued the
groundwater monitoring requirement because no evidence of pollution had been
detected. The revised permit required that all existing groundwater monitoring
wells previously required by the permit be sealed and discontinued requirements
for groundwater monitoring.
Three incidences of noncompliance occurred after November 1995 that involved
discharges resulting from boiler tube leaks. These noncompliances were
identified by the facility owner and the operator and were reported to the
NJDEPE. Since then, the HRSG drain valves have been modified so that they no
longer discharge to site runoff, but instead go to the plant's chemical drains.
On April 25, 1997, a Compliance Evaluation Inspection was conducted by the
NJDEPE Enforcement office. The facility received a rating of "acceptable" and no
deficiencies were noted. Earlier NJDEPE inspection reports also indicate no
deficiencies. Based on the review of the permits, records, and reports and on
the findings of the NJDEPE, the facility is now operating in compliance with its
wastewater discharge permits and should continue to do so.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Water Withdrawal Permits
The facility obtains process and potable water from the Sayreville Water
Department. The Sayreville Water Department obtained a permit from the NJDEPE to
construct the water main and provide water to the facility on January 9, 1990.
Water is also supplied by Hercules from its private water supply system in an
amount equal to 115% of the steam use rate. The NJDEPE issued a Physical
Connection Permit for connecting the private system to the potable water system
on February 23, 1993. A renewed Physical Connection Permit was issued in
mid-1997. The permit requires testing and inspections of the backflow preventor
device.
Solid and Hazardous Waste Disposal
The only hazardous waste generated by the facility is waste oil and oily/dirty
rags. No solid residues are generated on the site. Waste oil is properly stored
and removed by a disposal contractor, Advanced Environmental Technology
Corporation, which is registered with the USEPA. The facility has been assigned
a USEPA identification number, and the wastes are manifested upon removal. The
manifested wastes are ultimately disposed of at hazardous waste facilities
regulated by the state. The facility also generates nonhazardous wastes, such as
office wastes. The facility has a recycling system in place for newspaper,
glass, aluminum, cardboard, and office paper.
Chemical and Petroleum Storage
The Sayreville Bureau of Fire Safety issued Fire Safety Permits for the storage
or use of natural gas on March 10, 1992, and annual reauthorization thereafter.
The facility does not have any bulk oil storage on the site. Most of the
hazardous chemicals are used in the water treatment building, where adequate
storage facilities are provided. The most recent inspection certificate from the
Bureau indicates compliance with the New Jersey Uniform Fire Code and expires
September 1, 1998.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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Oil and Chemical Spill Response
The facility does not handle any large volumes of oil on the site. The majority
of the hazardous chemical use occurs in the water treatment building where the
chemicals are properly stored as previously discussed. Therefore, no oil or
chemical spills have occurred that have required reporting.
Wetlands and Stream Encroachment Permits
On June 22, 1989, the NJDEPE issued a Freshwater Wetlands Letter of
Interpretation confirming the jurisdictional boundary of regulated wetlands on
the Sayreville site, identified them as "intermediate value resource" wetlands,
and required a buffer area 50 feet wide between the wetlands and regulated
activities. They also issued an authorization, Freshwater Wetlands General
Permit #2, for construction of the steam line and the transmission line across
wetland areas. Typical conditions apply. The U.S. Army Corps of Engineers issued
an authorization, Nationwide Permit No. 7, for the wetlands work on September
27, 1988.
A Stream Encroachment Permit was issued by the NJDEPE on November 30, 1989. The
permit authorized construction of the steam lines and a storm water outfall on
Duck Creek. A completion report was filed on June 17, 1991, stating that all
work under the permit has been completed.
Zoning Approvals and Building Permits
The Sayreville site is zoned Heavy Industrial. On May 12, 1989, the Sayreville
Planning Board approved the subdivision, the site plan, and several variances or
waivers from the Zoning Ordinance and from the Borough Design Standards and
Details. They also directed that building permits be issued. The facility is in
compliance with the conditions that were specified. On June 27, 1989, the
Middlesex County Planning Board also approved the subdivision and site plan. No
specific conditions were mentioned.
Future Environmental Regulations
Because the plant has already received the required permits and approvals, has
been constructed, and has operated for several years, it is unlikely that future
environmental requirements will significantly affect the project. Many new
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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environmental regulations have provisions to "grandfather" existing facilities.
However, some environmental programs have the potential to affect existing
facilities in the future. These include the following programs:
o The Continuous Assurance Monitoring (CAM) rule
o Reporting requirements under Section 313 of the Emergency Planning and
Community Right-To-Know Act (EPCRA)
o New National Ambient Air Quality Standards (NAAQS) for ozone and PM2.5
o Additional NOX restrictions to control ground-level ozone, pursuant to
the recommendations of the Ozone Transport Assessment Group (OTAG), the
Ozone Transport Commission (OTC), and any regulations adopted by the
NJDEP pursuant to the recommendations
o Any greenhouse effect/global warming requirements resulting from
ongoing international political debates.
In our opinion, the facility is generally well designed and has existing systems
in place to meet any expected requirements from these programs. Some
administrative or management changes may be required, for example, to meet the
EPCRA reporting requirements.
The OTAG and OTC recommendations may ultimately require NOX emission limits as
low as 0.15 lb/mmBtu for existing plants. The facility is already required to
meet an emission limit of 0.921 lb/mmBtu. Therefore, it is unlikely that the
facility will be substantially affected by additional NOX restrictions. A
worst-case scenario would be the required installation of a selective catalytic
reduction (SCR) system to further reduce NOX emissions. The estimated cost for
installation of an SCR system is in the range of $1,200,000 to $1,500,000.
SUMMARY
Based on the environmental permitting and compliance review of the Bellingham
and Sayreville cogeneration facilities, the following conclusions were reached:
o All of the permits and approvals currently required for construction
and operation of the plants have been obtained.
o The plants have been operating in compliance with all of their permit
conditions, except for minor exceedances of NOX emission limits at
Sayreville, which have been adequately addressed.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
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o Based on the physical walkdowns of the facilities, interviews with key
plant personnel, and reviews of documents and records, the plants
should be able to operate in compliance in the future based on the
procedures and equipment now in place.
o The plants have been operating in compliance with qualifying facility
requirements as defined under the Public Utilities Regulatory Policies
Act.
o The four environmental releases, a fuel oil spill and three chemical
spills at Bellingham, were promptly and effectively resolved and
actions were taken to prevent future occurrences. Additional
remediation of the oil spill at Bellingham is required. This
remediation continues to be the responsibility of Westinghouse. To
date, Westinghouse has diligently pursued closure of this issue, and
the remediation effort has apparently been satisfactory to the relevant
environmental authorities. There should be no additional impacts to the
operation of the facilities because of these spills.
o The plants are required to obtain Title V Operating Permits, and the
owner is actively pursuing issuance of the permits. There is no reason
to believe the plants will be adversely affected by the permits.
Due to the existing systems already in place, the facilities are generally well
designed to meet any expected requirements from future environmental
regulations.
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or
released to any third party without the prior written consent of S&L. Copyright
Sargent & Lundy 1998; all rights reserved.
B-101
Appendix A
Financial Projections for Base Case
B-102
Northeast Energy, LP
The financial projections presented in this Appendix were prepared by, and are
the responsibility of, Northeast Energy, LP on a cash basis and are based on the
contractual, operational, and economic assumptions summarized below. Certain
aspects of the Projections have been reviewed by the Independent Engineer and
the Fuel Consultant. See the Independent Engineer's Report in Appendix B and the
Fuel Consultant's Reports in Appendix C to the Prospectus. Price Waterhouse LLP
has neither examined nor compiled the Projects or any such assumptions and,
accordingly, Price Waterhouse LLP does not express any opinion or any other form
of assurance with respect thereto. The Price Waterhouse LLP report included in
the Prospectus relates solely to the Partnerships' historical financial
information. It does not extend to the Projections and should not be read to do
so. Many of the projection assumptions that appear below are based on the
provisions of individual project contracts, the Project Indenture and the
Indenture, certain provisions of which are summarized in the Prospectus. See
"Summary of Principal Project Agreements" in the Prospectus and "Summary of the
Project Indenture" in Appendix D to the Prospectus. The projections, wile
presented with numerical specificity, necessarily are based upon a number of
estimates and assumptions that, while considered reasonable by Northeast Energy,
LP, are inherently subject to significant business, economic, and competitive
uncertainties and contingencies, many of which are beyond the control of
Northeast Energy, LP, and upon assumptions with respect to future business
decisions that are subject to change. Accordingly, there can be no assurance
that the Projections will be realized. The actual results will vary from the
Projections, and such variations may be material. The inclusion of the
Projections herein should not be regarded as a representation by Northeast
Energy, LP or any other person that the Projections will be achieved. Northeast
Energy, LP does not intend to update the Projections. Prospective investors in
the Bonds are cautioned not to place undue reliance on the Projections.
Capitalized terms used in this Appendix and not otherwise defined have the
meaning assigned in Appendix A to the Prospectus. The assumptions described
below were used in the preparation of a base-case projection and in the
sensitivity case projections except where otherwise noted.
Summary of Underlying Assumptions
Power Generation Revenue
Power Sales Prices: Contracted power prices in the financial model are projected
on the basis of the prices set forth in the respective Power
Purchase Agreements. For further detail on the pricing
provisions of these contracts, see "Summary of Principal
Project Agreements" in the Prospectus.
The Projects also contain the assumption of the sale of
certain amounts of uncontracted energy produced by the
Projects on the open market. The assumed merchant sale price
for such energy is presented in the Projections and
represents Northeast Energy, LP's expectation of market
rates available for sales from the Projects. These merchant
sales price assumptions are consistent with studies
completed for this region of the United States.
B-103
Northeast Energy, LP
Summary of Underlying Assumptions
Power Output: Projected net electrical output for the Bellingham Project
is 290 MW in 1998, increasing to approximately 300 MW from
1999.
Projected net electrical output for the Sayreville Project
is 252 MW in 1998, increasing to approximately 287 MW
from 1999.
From 1999, the projections assume that all uncontracted net
electricity produced by the Projects is sold in the
merchant power market.
Equivalent
Availability
Factor: During a year in which no major inspections or maintenance
outages are scheduled, the Sayreville and Bellingham pro
formas assume an average annual equivalent availability
factor of 93.3% and 96%, respectively.
Energy Banks: Energy Bank liabilities are supported by letters of credit
to the respective utilities. Increases or decreases in the
Energy Bank liabilities do not affect project cash flows
and, therefor, are not reflected in the projected cash
flows. For a further discussion of the Energy Banks, see
"Summary of Principal Project Agreements" in
the Prospectus.
Cost of Power Generation
Fuel Consumption
per kwh (Heat
Rate): The projections assume a baseline heat rate with an annual
degradation of 0.7% in each year. The assumed heat rate
returns to the baseline heat rate after major maintenance
has been performed. Major maintenance is performed every six
years.
At Bellingham, using the assumed baseline heat rate and the
0.7% annual degradation factor included in the projections,
there is an average heat rate of 8,304 Btu/kWh over the
6-year major maintenance cycle.
At Sayreville, the assumed baseline heat rate is 9,057
Btu/kWh in 1998 and 8,461 Btu/kWh from 1999 through 2011.
This reflects continued reduced load operation in the first
year and full-load operation starting in 1999.
Total fuel consumption is equal to a plant's net electrical
output in kWh multiplied by the heat rate.
Delivered Fuel
Costs: Non-contract fuel commodity and transportation prices are
based on current market prices and represent annual
estimates for market rates prepared by Northeast Energy, LP.
Contract fuel commodity, transportation and storage costs
are based on prices set forth in the applicable contracts.
Average fuel costs for the Projects are a function of the
mix of fuel sources used by the Projects. See The Fuel
Consultant's Report in Appendix C to the Prospectus.
B-104
Northeast Energy, LP
Summary of Underlying Assumptions
Gross Steam Production Income
NEA: Steam sales are projected at nominally 51,000 pounds
per hour (lb/hr) based on historic amounts sold. The price
at which steam is sold is based on the Steam Sales Agreement
between NEA and NECO.
NJEA: Output to Hercules is projected to be approximately
125,000 lb/hr consistent with current operating experience
at the Sayreville Project. The Hercules steam purchase price
is based on pricing contained in the Steam Sales Agreement
between NJEA and Hercules and is projected to escalate at
half the rate of inflation.
Project Operating Costs
General Operations
and Maintenance: The base prices for the operations and maintenance services
provided by Westinghouse Services are projected on the basis
of the current O&M Agreements through their initial term
expiring in 2001. From 2001, when the New Operator is
expected to assume operation and maintenance of the
Projects, operation and maintenance costs are projected to
increase with inflation from base costs derived from
historical costs at similar facilities. The projection of
bonuses during the remaining term of the O&M Agreements are
capped per the terms of such agreements.
Bonus Payments: For NEA and NJEA, output bonuses paid to Westinghouse
Services are determined based on the number of bonus
megawatt hours produced (calculated as the projected output
of the Projects multiplied by availability over the
guaranteed level), multiplied by payment amounts in the
respective agreements. Such bonuses are included in
operations and maintenance costs in the Projections.
General and
Administrative
Expenses: Costs for water, insurance, property taxes, easement
fees, and General Partner management costs are projected on
the basis of historical costs. Water costs are projected to
increase at half the rate of inflation; property taxes and
insurance costs increase with inflation; easement fees
increase by $12,000 per annum from the 1997 estimate. The
General Partner management fee is set forth in the
Indenture. In general administrative costs and the General
Partner management fee are projected to grow from Northeast
Energy, LP's estimates of 1998 levels at the same rate as
inflation.
B-105
Northeast Energy, LP
Summary of Underlying Assumptions
Gas Hedge & Peak
Service Loss
(Savings}: Northeast Energy, LP expects to realize cash inflows of
approximately $4,158 million in 1998, based on recent prices
for natural gas, resulting from the monetization of certain
gas hedging arrangements. Beginning in 1999, Northeast
Energy, LP expects NEA to exercise its ability to operate
with Number 2 fuel oil for a certain number of hours each
year. Northeast Energy, LP expects this operation on Number
2 fuel oil to result in annual savings of between
approximately $575,000 and $1,325,000 between 1999 and 2011.
Financing Costs
Bond Payments: The Bond financing is modeled as a $220 million issue,
with semi-annual principal payments beginning June 30,
2002, an assumed issue date of February 15, 1998, and a
final maturity of December 30, 2001.
Project Securities
Payments: The projections assume approximately $490 million of Project
Securities outstanding as of December 31, 1997. These
securities are subject to semi-annual principal and interest
payments through December 30, 2010.
Other Facilities: The projections include expected interest and fee expenses
for letters of credit that are issued to support the
Projects' Energy Bank and Debt Service Reserve obligations
and for the Working Capital Facility. Because the Projects
are cash-flow positive on a monthly basis, and as the
Working Capital Facility has never been drawn upon, the
projections do not anticipate any draws under the Working
Capital Facility, and Northeast Energy, LP intends to
discontinue this facility.
Interest Income: The projections assume that the Projects will earn interest
income on all free cash balances at a rate equal to 2% more
than the projected rate of inflation.
B-106
Northeast Energy, LP
Summary of Underlying Assumptions
Balance Sheet Entries
Debt Service
Reserves: ESI Tractebel Funding has obtained a letter of credit in an
amount sufficient to cover six months of principal and
interest on the Project Securities as permitted under the
Project Indenture. Similarly, the projections assume that
the Issuer will obtain a letter of credit in an amount
sufficient to cover six months of principal and interest on
the Bonds as permitted under the Indenture.
Major Overhaul
Reserve: A major overhaul reserve is provided in accordance with the
Project Indenture and the O&M Agreements in an amount equal
to the next year's projected major maintenance costs. Based
on historical maintenance of similar plants, Northeast
Energy, LP estimates that annual reserve contributions with
respect to NEA will be in amounts that average $2.3 million
through 2009, the last year deposits to the reserve are
required. For NJEA, Northeast Energy, LP expects such
contributions will average $2.7 million through 2009. Such
amounts deposited to the reserve are included in operations
and maintenance in the projections.
Gas Transmission:
Reserve: The projections assume that the Transco Agreements are
extended beyond the final maturity of the Project
Securities, and therefore, deposits will not need to be
made to the Gas Transmission Reserve pursuant to the
Project Indenture.
Working Capital
Accounts: Working capital balances are projected on the basis of
historical levels.
Sensitivity Analysis
In order to examine the effect of changes in certain assumptions on projected
cash flows and coverage ratios, Northeast Energy, LP has run five sensitivity
cases. These sensitivities involve variation of the base case assumptions in the
following parameters:
o Spot gas prices
o Inflation
o Station availability
o Fuel efficiency (heat rate)
o No merchant power sales
These sensitivities are discussed in further detail in Section 6 of the
Independent Engineer's Report, and the financial projections corresponding to
each sensitivity case are presented in Appendix B to the Independent Engineer's
Report.
B-107
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Base Case Projections
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
-------- -------- -------- -------- -------- -------- --------
NEA Operating Results
Revenues
Boston Edison I $73,649 $73,649 $74,415 $73,266 $68,288 $73,649 $71,351
Boston Edison II 48,928 52,665 57,202 60,526 60,597 70,290 73,220
Commonwealth I 13,635 13,607 13,805 10,954 9,905 11,523 11,144
Commonwealth II 12,153 13,081 14,207 15,033 15,051 17,458 18,186
Montaup 13,550 13,550 13,691 6,453 6,476 7,385 7,588
Merchant Sales 0 2,709 3,187 2,881 2,400 4,504 4,108
Steam 1,256 1,153 1,099 1,051 729 1,137 997
Interest Income 404 404 481 552 479 518 541
-------- -------- -------- -------- -------- -------- --------
Total Revenues $163,576 $170,819 $178,088 $170,717 $163,925 $186,465 $187,135
Expenses
Operations and maintenance $8,677 $8,998 $12,825 $10,180 $3,122 $7,987 $4,264
Water costs and easement fee 304 317 331 495 883 904 925
Insurance 887 912 937 964 991 1,017 1,045
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 3,601 3,712 3,824 3,936 4,049 4,154 4,259
Management fees 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Peak Service Loss/(Savings) (4,158) (991) (1,011) (575) (753) (941) (1,133)
Other 1,039 1,062 1,076 1,036 2,190 2,413 2,309
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $13,476 $17,223 $21,286 $19,433 $13,974 $19,121 $15,350
Total fuel cost 91,654 96,006 99,494 101,159 99,318 106,904 107,483
-------- -------- -------- -------- -------- -------- --------
Total expenses $105,130 $113,229 $120,780 $120,592 $113,291 $126,025 $122,833
Operating Cash Flow $58,445 $57,590 $57,308 $50,125 $50,634 $60,441 $64,302
NJEA Operating Results
Revenues
JCP&L $142,607 $145,606 $148,580 $148,879 $147,531 $144,865 $157,667
Merchant Sales 0 8,150 7,405 8,308 8,080 7,714 10,483
Steam 2,635 2,672 2,709 2,747 2,785 2,823 2,861
Interest Income 284 284 306 389 476 396 378
-------- -------- -------- -------- -------- -------- --------
Total Revenues $145,526 $156,711 $159,000 $160,322 $158,872 $155,797 $171,389
Expenses
Operations and maintenance $9,130 $9,336 $10,447 $11,539 $7,377 $3,412 $6,780
Water costs and easement fee 800 821 842 1,094 1,687 1,719 1,751
Insurance 748 769 790 812 835 858 881
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 866 867 868 870 871 872 874
Management fees 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 420 431 437 463 512 527 548
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $15,090 $15,438 $16,688 $18,174 $14,774 $10,973 $14,516
Total fuel cost 62,837 68,689 71,620 72,740 73,181 72,865 80,026
-------- -------- -------- -------- -------- -------- --------
Total expenses $77,927 $84,127 $88,308 $90,914 $87,955 $83,838 $94,542
Operating Cash Flow $67,598 $72,584 $70,692 $69,408 $70,916 $71,959 $76,847
Combined Operating Results
Total Revenues $309,101 $327,530 $337,088 $331,039 $322,796 $342,262 $358,524
Non-fuel operating expenses 28,566 32,660 37,974 37,607 28,748 30,093 29,866
Total fuel cost 154,491 164,696 171,114 173,899 172,499 179,769 187,509
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $126,044 $130,174 $128,000 $119,533 $121,550 $132,400 $141,149
Change in Working Capital 10,097 3,005 1,401 (1,190) (1,200) 3,276 2,663
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $115,947 $127,169 $126,599 $120,723 $122,750 $129,124 $138,486
Subordinated Management Fee $1,649 $1,695 $1,742 $1,791 $1,841 $1,891 $1,942
Project Securities
Principal 21,563 23,511 26,333 20,160 22,688 23,818 28,564
Interest 45,327 43,468 41,426 39,300 37,396 35,264 32,933
Project Security Debt Service Coverage
Project Security debt service coverage* 1.76x 1.92x 1.89x 2.06x 2.07x 2.22x 2.28x
Minimum Project Security debt service coverage 1.76x
Average Project Security debt service coverage 2.16x
Distributions to NE LP $49,058 $60,191 $58,840 $61,263 $62,666 $70,043 $76,988
The Bonds
Principal 0 0 0 0 8,800 8,800 8,800
Interest 15,381 17,578 17,578 17,578 17,402 16,699 15,996
Debt Service Coverages
Bond debt service coverage 3.19x 3.42x 3.35x 3.49x 2.39x 2.75x 3.10x
Minimum Bond debt service coverage 2.25x
Average Bond debt service coverage 2.88x
Consolidated coverage 1.41x 1.50x 1.48x 1.57x 1.42x 1.53x 1.60x
Minimum consolidated debt service coverage 1.41x
Average consolidated coverage 1.57x
*The numerator of the Project Security Debt Service Coverage Ratio is calculated
before payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projections should be read in conjunction with the attached
Summary of Underlying Assumptions.
B-108
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Base Case Projections
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
-------- -------- -------- -------- -------- -------- --------
NEA Operating Results
Revenues
Boston Edison I $73,266 $73,649 $73,266 $68,288 $73,649 $71,351 $73,266
Boston Edison II 80,795 87,351 93,350 93,543 108,502 112,971 88,537
Commonwealth I 11,908 12,267 12,421 11,288 13,078 12,684 13,423
Commonwealth II 20,068 21,696 23,186 23,234 26,949 28,059 30,972
Montaup 8,238 8,495 8,655 8,249 9,204 9,256 9,663
Merchant Sales 3,863 5,122 4,647 3,831 7,157 6,475 18,416
Steam 1,170 1,232 1,234 855 1,334 1,170 1,374
Interest Income 439 480 578 514 519 514 404
-------- -------- -------- -------- -------- -------- --------
Total Revenues $199,746 $210,293 $217,337 $209,802 $240,393 $242,479 $236,056
Expenses
Operations and maintenance $3,833 $6,174 $8,149 $3,646 $8,516 $3,601 $5,085
Water costs and easement fee 946 967 988 1,009 1,030 1,052 1,074
Insurance 1,073 1,102 1,132 1,162 1,194 1,226 1,260
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 4,362 4,464 4,564 4,661 4,756 4,846 4,943
Management fees 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) (1,155) (1,185) (1,215) (622) (886) (1,099) (1,325)
Other 2,352 2,327 2,322 2,145 2,381 2,248 2,347
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $15,192 $17,733 $19,928 $16,098 $21,198 $16,195 $17,826
Total fuel cost 112,220 115,566 118,085 115,546 124,633 125,012 130,697
-------- -------- -------- -------- -------- -------- --------
Total expenses $127,411 $133,299 $138,013 $131,644 $145,830 $141,207 $148,523
Operating Cash Flow $72,335 $76,994 $79,325 $78,158 $94,562 $101,273 $87,533
NJEA Operating Results
Revenues
JCP&L $159,702 $162,480 $166,309 $164,315 $160,776 $175,260 $113,850
Merchant Sales 10,490 10,739 12,634 12,583 12,351 17,278 62,814
Steam 2,900 2,939 2,979 3,019 3,060 3,101 1,965
Interest Income 406 323 382 493 400 284 284
-------- -------- -------- -------- -------- -------- --------
Total Revenues $173,498 $176,481 $182,303 $180,410 $176,586 $195,922 $178,913
Expenses
Operations and maintenance $4,759 $3,385 $7,447 $8,284 $3,658 $3,514 $6,869
Water costs and easement fee 1,783 1,815 1,848 1,880 1,914 1,947 1,982
Insurance 905 929 954 980 1,006 1,034 1,062
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 875 876 878 879 881 882 884
Management fees 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 564 575 585 598 617 588 605
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $12,667 $11,464 $15,700 $16,718 $12,282 $12,287 $15,844
Total fuel cost 82,196 84,596 87,376 87,445 86,461 94,569 97,716
-------- -------- -------- -------- -------- -------- --------
Total expenses $94,863 $96,060 $103,076 $104,163 $98,744 $106,855 $113,560
Operating Cash Flow $76,635 $80,421 $79,227 $76,247 $77,842 $89,067 $65,353
Combined Operating Results
Total Revenues $373,244 $386,774 $399,641 $390,212 $416,979 $438,402 $414,969
Non-fuel operating expenses 27,859 29,197 35,629 32,816 33,480 28,481 33,670
Total fuel cost 194,415 200,162 205,460 202,990 211,094 210,581 228,413
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $150,970 $157,414 $158,552 $154,405 $172,405 $190,340 $152,886
Change in Working Capital 2,416 2,233 2,088 (1,673) 4,568 3,603 (4,666)
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $148,554 $155,182 $156,464 $156,078 $167,837 $186,737 $157,552
Subordinated Management Fee $1,994 $2,048 $2,103 $2,160 $2,219 $2,278 $2,342
Project Securities
Principal 45,349 52,641 54,021 51,801 54,616 65,223 0
Interest 29,880 25,484 20,545 15,504 10,374 4,779 0
Project Security Debt Service Coverage
Project Security debt service coverage* 2.00x 2.01x 2.13x 2.35x 2.62x 2.70x
Distribution to NE LP $73,325 $77,058 $81,897 $88,773 $102,847 $116,734 $157,552
The Bonds
Principal 8,800 13,200 22,000 22,000 26,400 35,200 66,000
Interest 15,293 14,502 13,271 11,514 9,668 7,383 3,955
Debt Service Coverages
Bond debt service coverage 3.04x 2.78x 2.32x 2.65x 2.85x 2.74x 2.25x
Consolidated coverage 1.50x 1.47x 1.42x 1.55x 1.66x 1.66x 2.25x
*The numerator of the Project Security Debt Service Coverage Ratio is calculated
before payment of a subordianted management fee.
Amounts may not add due to rounding.
These financial projects should be read in conjunction with
the attached Summary of Underlying Assumptions.
B-109
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Base Case Projections
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.80% 2.80% 2.80% 2.80% 2.80% 2.70% 2.70%
#6 fuel oil, 2.2% S ($/MMBtu) $2.74 $2.77 $2.81 $2.83 $2.86 $2.89 $2.92
#2 fuel oil ($/MMBtu) 4.42 4.51 4.61 4.67 4.73 4.79 4.85
Nominal Spot Gas Price Escalation 4.37% 4.35% 4.33% 3.80% 3.79% 3.68% 3.67%
Spot gas ($/MMBtu) 2.10 2.19 2.28 2.37 2.46 2.55 2.65
NEA Operational Factors
Net GWh generated 2,443 2,534 2,583 2,526 2,338 2,570 2,472
Net capacity (MW) 290 301 304 301 299 305 303
Equivalent availability factor 96.15% 96.15% 97.15% 95.65% 89.15% 96.15% 93.15%
Heat rate (Btu/kWh) 8,283 8,339 8,270 8,325 8,380 8,229 8,283
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Commonwealth I 6.54 6.53 6.55 5.28 5.12 5.53 5.52
Commonwealth II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Montaup 6.50 6.50 6.50 3.11 3.35 3.54 3.76
Merchant Sales 0.00 2.88 2.72 2.94 3.20 3.48 3.80
---- ---- ---- ---- ---- ---- ----
Average all-in rate 6.66 6.71 6.86 6.72 6.99 7.22 7.54
Electricity Sales (GWh)
Boston Edison I 1,133 1,133 1,145 1,127 1,051 1,133 1,098
Boston Edison II 705 705 712 701 654 705 683
Commonwealth I 208 208 211 207 193 208 202
Commonwealth II 175 175 177 174 162 175 170
Montaup 208 208 211 207 193 208 202
Merchant Sales 0 94 117 98 75 129 108
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.37 $4.46 $4.47 $4.59 $4.74 $4.98 $4.98
Annual Volume (BBtu/yr) 20,416 20,552 21,455 21,675 21,348 19,945 21,463
NJEA Operational Factors
Net GWh generated 2,071 2,361 2,344 2,307 2,216 2,101 2,320
Net capacity (MW) 252 287 285 288 286 284 289
Equivalent availability factor 93.82% 93.82% 93.82% 91.54% 88.54% 84.54% 91.54%
Heat rate (Btu/kWh) 9,057 8,461 8,574 8,503 8,560 8,617 8,461
Electricity Sales Rates (cents/kWh)
JCP&L 6.90 7.05 7.19 7.38 7.56 7.78 7.82
Merchant Sales 0.00 2.81 2.71 2.90 3.09 3.29 3.50
---- ---- ---- ---- ---- ---- ----
Average all-in rate 6.90 6.51 6.65 6.81 7.02 7.26 7.25
Electricity Sales (GWh)
JCP&L 2,071 2,071 2,071 2,021 1,955 1,866 2,021
Merchant Sales 0 290 273 287 262 235 299
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 1,013
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $3.35 $3.44 $3.56 $3.70 $3.85 $4.02 $4.07
Annual Volume (BBtu/yr) 18,760 19,977 20,100 19,634 18,995 18,147 19,641
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-110
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Base Case Projections
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.70% 2.70% 2.70% 2.70% 2.70% 2.70% 2.80%
#6 fuel oil, 2.2% S ($/MMBtu) $2.95 $2.98 $3.01 $3.04 $3.07 $3.10 $3.09
#2 fuel oil ($/MMBtu) 4.92 4.94 4.96 4.99 5.01 5.03 5.01
Nominal Spot Gas Price Escalation 3.66% 3.18% 3.18% 3.17% 2.70% 3.17% 3.74%
Spot gas ($/MMBtu) 2.74 2.83 2.92 3.01 3.09 3.19 3.31
NEA Operational Factors
Net GWh generated 2,521 2,556 2,526 2,338 2,570 2,472 2,521
Net capacity (MW) 301 304 301 299 305 303 301
Equivalent availability factor 95.65% 96.15% 95.65% 89.15% 96.15% 93.15% 95.65%
Heart rate (Btu/kWh) 8,339 8,270 8,325 8,380 8,229 8,283 8,339
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Commonwealth I 5.74 5.88 5.99 5.84 6.27 6.28 6.47
Commonwealth II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Montaup 3.97 4.07 4.17 4.27 4.42 4.58 4.66
Merchant Sales 4.13 4.42 4.75 5.11 5.54 5.99 6.19
----- ----- ----- ----- ----- ----- -----
Average all-in rate 7.89 8.19 8.57 8.95 9.32 9.78 9.33
Electricity Sales (GWh)
Boston Edison I 1,127 1,133 1,127 1,051 1,133 1,098 1,127
Boston Edison II 701 705 701 654 705 683 498
Commonwealth I 207 208 207 193 208 202 207
Commonwealth II 174 175 174 162 175 170 174
Montaup 207 208 207 193 208 202 207
Merchant Sales 93 116 98 75 129 108 298
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average $5.16 $5.26 $5.39 $5.53 $5.79 $5.81 $6.01
all-in cost ($/MMBtu)
Annual Volume (BBtu/yr) 20,813 21,347 21,460 21,348 19,945 21,463 20,813
NJEA Operational Factors
Net GWh generated 2,291 2,275 2,307 2,216 2,101 2,320 2,311
Net capacity (MW) 287 285 288 286 284 289 290
Equivalent availability factor 91.04% 91.04% 91.54% 86.54% 84.54% 91.54% 91.04%
Heat rate (Btu/kWh) 8,518 8,574 8,503 8,560 8,617 8,461 8,518
Electricity Sales Rates (cents/kWh)
JCP&L 7.96 8.10 8.25 8.42 8.63 8.69 8.88
Merchant Sales 3.73 4.06 4.41 4.81 5.26 5.78 5.95
----- ------ ----- ------ ------ ----- ------
Average all-in rate 7.43 7.62 7.75 7.98 8.24 8.30 7.57
Electricity Sales (GWh)
JCP&L 2,010 2,010 2,021 1,955 1,866 2,021 1,279
Merchant Sales 281 265 287 262 235 299 1,055
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 633
Delivered Natural Gas - Average $4.21 $4.33 $4.45 $4.60 $4.76 $4.81 $4.96
all-in cost ($/MMBtu)
Annual Volume (BBtu/yr) 19,526 19,517 19,634 18,995 18,147 19,641 19,701
These financial projections should be read in conjunction with the attached
Summary of Underlying Assumptions.
B-111
Conversion to GAAP Accounting
The following table converts the operating cash flow values in the base case
projections to operating income values consistent with GAAP.
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
---- ---- ---- ---- ---- ---- ----
NEA
Operating cash flow $58,445 $57,590 $57,308 $50,125 $50,634 $60,441 $64,302
Deduct:
Interest income 404 404 481 552 479 518 541
Depreciation 15,215 15,220 15,225 15,230 15,199 15,194 15,199
Amortization of power
purchase contracts 22,339 23,302 24,471 25,328 25,346 27,844 28,599
Accrual of major maintenance
expenditure 957 1,569 2,067 2,489 2,446 2,492 2,602
Add:
Major maintenance funding 0 0 3,208 2,927 194 4,982 1,180
Above-market fuel/O&M
contract amortization 17,091 17,091 17,091 17,091 14,593 14,593 14,593
Change in fixed assets 100 100 100 100 100 100 100
Letter of credit fees 259 259 251 253 252 246 217
Change in Energy Bank balances* 719 5,047 7,047 5,133 6,693 12,755 25,108
GAAP operating income $37,699 $39,592 $42,762 $32,029 $28,995 $47,069 $58,559
NJEA
Operating cash flow $67,598 $72,584 $70,692 $69,408 $70,916 $71,959 $76,847
Deduct:
Interest income 284 284 306 389 476 396 378
Depreciation 6,130 6,135 6,140 6,145 6,136 6,133 6,138
Amortization of power purchase
contracts 27,964 27,964 27,964 27,964 27,964 27,964 27,964
Accrual of major maintenance
expenditure 1,717 1,811 2,357 2,740 2,830 2,515 2,266
Add:
Major maintenance funding 0 0 899 3,457 4,518 478 3,770
Above-market fuel/O&M
contract amortization 8,442 8,442 8,442 8,442 6,253 6,253 6,253
Change in fixed assets 100 100 100 100 100 100 100
Letter of credit fees 42 42 37 37 37 38 47
GAAP operating income $40,088 $44,975 $43,403 $44,207 $44,419 $41,821 $50,271
Combined Partnerships with NE LP
GAAP operating income $77,787 $84,566 $86,165 $76,236 $73,414 $88,890 $108,830
Deduct:
Interest expense on Project
Securities 45,327 43,468 41,426 39,300 37,396 35,264 32,933
Interest expense on Bonds 15,381 17,578 17,578 17,578 17,402 16,699 15,996
Net interest expense on swaps 86 19 0 0 0 0 0
Amortization of financing fees 450 450 450 450 450 450 450
Letter of credit fees 300 302 288 290 289 285 263
Add:
Interest income 688 688 787 940 955 913 919
GAAP net income 16,931 23,438 27,209 19,558 16,832 37,106 60,106
2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
NEA
Operating cash flow $72,335 $76,994 $79,325 $78,158 $94,562 $101,273 $87,533
Deduct:
Interest income 439 480 578 514 519 514 404
Depreciation 14,823 14,828 14,833 14,011 14,016 14,015 14,020
Amortization of power
purchase contracts 30,552 32,241 33,787 33,837 37,692 38,844 34,048
Accrual of major maintenance
expenditure 2,447 2,559 2,538 2,610 2,574 2,596 2,657
Add:
Major maintenance funding 668 2,927 4,817 227 5,007 0 1,386
Above-market fuel/O&M
contract amortization 14,593 14,593 14,593 14,593 14,593 14,593 14,593
Change in fixed assets 100 100 100 100 100 100 100
Letter of credit fees 165 106 97 95 99 38 38
Change in Energy Bank balances' 33,230 34,243 (1,949) (3,728) (3,867) (4,084) (4,368)
GAAP operating income $72,830 $78,854 $45,247 $38,473 $55,693 $55,952 $48,153
NJEA
Operating cash flow $78,635 $80,421 $79,227 $76,247 $77,842 $89,067 $65,353
Deduct:
Interest income 406 323 382 493 400 284 284
Depreciation 5,987 5,992 5,997 5,670 5,675 5,677 5,682
Amortization of power purchase
contracts 27,964 27,964 27,964 27,964 27,964 27,964 27,964
Accrual of major maintenance
expenditure 2,284 2,326 2,581 2,657 2,957 2,739 2,824
Add:
Major maintenance funding 1,671 215 4,195 4,947 233 0 3,259
Above-market fuel/O&M
contract amortization 6,253 6,253 6,253 6,253 6,253 6,253 6,253
Change in fixed assets 100 100 100 100 100 100 100
Letter of credit fees 49 46 42 40 44 0 0
GAAP operating income $50,066 $50,431 $52,893 $50,803 $47,476 $58,756 $38,210
Combined Partnerships with NE LP
GAAP operating income $122,896 $129,285 $98,140 $89,276 $103,169 $114,707 $86,362
Deduct:
Interest expense on Project
Securities 29,880 25,484 20,545 15,504 10,374 4,779 0,000
Interest expense on Bonds 15,293 14,502 13,271 11,514 9,668 7,383 3,955
Net interest expense on swaps 0 0 0 0 0 0 0
Amortization of financing fees 450 450 450 450 450 450 450
Letter of credit fees 214 152 139 135 143 38 38
Add:
Interest income 845 803 960 1,007 919 797 688
GAAP net income 77,905 89,500 64,694 62,680 83,452 102,854 82,608
*Changes in Energy Bank balances include non-cash interest expense on the Energy
Banks.
Amounts may not add due to rounding.
B-112
Appendix B
Financial Projections for Sensitivity Cases
B-113
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case A: Spot Gas Prices Increased 6%
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
-------- -------- -------- -------- -------- -------- --------
NEA Operating Results
Revenues
Boston Edison I $73,649 $73,649 $74,415 $73,266 $68,288 $73,649 $71,351
Boston Edison II 48,928 52,665 57,202 60,526 60,597 70,290 73,220
Commonwealth I 13,635 13,607 13,805 10,954 9,905 11,523 11,144
Commonwealth II 12,153 13,081 14,207 15,033 15,051 17,458 18,186
Montaup 13,550 13,550 13,691 6,453 6,476 7,385 7,588
Merchant Sales 0 2,709 3,187 2,881 2,400 4,504 4,108
Steam 1,256 1,153 1,099 1,051 729 1,137 997
Interest Income 404 404 481 552 479 518 541
-------- -------- -------- -------- -------- -------- --------
Total Revenues $163,576 $170,819 $178,088 $170,717 $163,925 $186,465 $187,135
Expenses
Operations and maintenance $8,677 $8,998 $12,825 $10,180 $3,122 $7,987 $4,264
Water costs and easement fee 304 317 331 495 883 904 925
Insurance 887 912 937 964 991 1,017 1,045
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 3,601 3,712 3,824 3,936 4,049 4,154 4,259
Management fees 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Peak Service Loss/(Savings) (4,158) (991) (1,011) (575) (753) (941) (1,133)
Other 1,039 1,062 1,076 1,036 2,190 2,413 2,309
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $13,476 $17,223 $21,286 $19,433 $13,974 $19,121 $15,350
Total fuel cost 92,124 97,619 101,193 102,903 101,012 108,791 109,382
-------- -------- -------- -------- -------- -------- --------
Total expenses $105,600 $114,841 $122,479 $122,336 $114,986 $127,912 $124,732
Operating Cash Flow $57,975 $55,977 $55,609 $48,381 $48,939 $58,553 $62,403
NJEA Operating Results
Revenues
JCP&L $146,753 $149,932 $153,085 $153,458 $152,121 $149,410 $162,773
Merchant Sales 0 8,150 7,405 8,308 8,080 7,714 10,483
Steam 2,635 2,672 2,709 2,747 2,785 2,823 2,861
Interest Income 264 284 306 389 476 396 378
-------- -------- -------- -------- -------- -------- --------
Total Revenues $149,671 $161,037 $163,504 $164,901 $163,461 $160,343 $176,495
Expenses
Operations and maintenance $9,130 $9,336 $10,447 $11,539 $7,377 $3,412 $6,780
Water costs and easement fee 800 821 842 1,094 1,687 1,719 1,751
Insurance 748 769 790 812 835 858 881
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 866 867 868 870 871 872 874
Management fees 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 420 431 437 463 512 527 548
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $15,090 $15,438 $16,688 $18,174 $14,774 $10,973 $14,516
Total fuel cost 64,224 71,798 74,881 76,053 76,506 76,159 83,725
-------- -------- -------- -------- -------- -------- --------
Total expenses $79,314 $87,236 $91,569 $94,227 $91,281 $87,132 $98,241
Operating Cash Flow $70,358 $73,801 $71,935 $70,675 $72,180 $73,211 $78,254
Combined Operating Results
Total Revenues $313,247 $331,856 $341,592 $335,618 $327,386 $346,808 $363,630
Non-fuel operating expenses 28,566 32,660 37,974 37,607 28,748 30,093 29,866
Total fuel cost 156,348 169,417 176,074 178,955 177,519 184,951 193,108
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $128,333 $129,779 $127,544 $119,056 $121,119 $131,764 $140,657
Change in Working Capital 10,781 2,921 1,424 (1,181) (1,197) 3,261 2,749
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $117,551 $126,858 $126,121 $120,237 $122,316 $128,503 $137,908
Subordinated Management Fee $1,649 $1,695 $1,742 $1,791 $1,841 $1,891 $1,942
Project Securities
Principal 21,563 23,511 26,333 20,160 22,688 23,818 28,564
Interest 45,327 43,468 41,426 39,300 37,396 35,264 32,933
Project Security Debt Service Coverage
Project Security debt service coverage* 1.78x 1.92x 1.89x 2.05x 2.07x 2.21x 2.27x
Minimum Project Security debt service coverage 1.78x
Average Project Security debt service coverage 2.15x
Distributions to NE LP $50,662 $59,880 $58,361 $60,777 $62,232 $69,422 $76,410
The Bonds
Principal 0 0 0 0 8,800 8,800 8,800
Interest 15,381 17,578 17,578 17,578 17,402 16,699 15,996
Debt Service Coverages
Bond debt service coverage 3.29x 3.41x 3.32x 3.46x 2.38x 2.72x 3.08x
Minimum Bond debt service coverage 2.21x
Average Bond debt service coverage 2.87x
Consolidated coverage 1.43x 1.50x 1.48x 1.56x 1.42x 1.52x 1.60x
Minimum consolidated debt service coverage 1.42x
Average consolidated coverage 1.57x
* The numerator of the Project Security Debt Service Coverage Ratio is
calculated before payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-114
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case A: Spot Gas Prices Increased 6%
(data in $000's unless noted)
NEA Operating Results 2005 2006 2007 2008 2009 2010 2011
-------- -------- -------- -------- -------- -------- --------
Revenues
Boston Edison I $73,266 $73,649 $ 73,266 $ 68,288 $73,649 $71,351 $73,266
Boston Edison II 80,795 87,351 93,350 93,543 108,502 112,971 88,537
Commonwealth I 11,906 12,267 12,421 11,288 13,078 12,684 13,423
Commonwealth II 20,068 21,696 23,186 23,234 26,949 28,059 30,972
Montaup 8,238 8,495 8,655 8,249 9,204 9,256 9,663
Merchant Sales 3,863 5,122 4,647 3,831 7,157 6,475 18,416
Steam 1,170 1,232 1,234 855 1,334 1,170 1,374
Interest Income 439 480 578 514 519 514 404
-------- -------- -------- -------- -------- -------- --------
Total Revenues $199,746 $210,293 $217,337 $209,802 $240,393 $242,479 $236,056
Expenses
Operations and maintenance $3,833 $6,174 $8,149 $3,646 $8,516 $3,601 $5,085
Water costs and easement fee 946 967 988 1,009 1,030 1,052 1,074
Insurance 1,073 1,102 1,132 1,162 1,194 1,226 1,260
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 4,362 4,464 4,564 4,661 4,756 4,846 4,943
Management fees 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) (1,155) (1,185) (1,215) (622) (886) (1,099) (1,325)
Other 2,352 2,327 2,322 2,145 2,381 2,248 2,347
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $15,192 $17,733 $19,928 $16,098 $21,198 $16,195 $17,826
Total fuel cost 114,237 117,665 120,239 117,627 126,934 127,310 133,132
-------- -------- -------- -------- -------- -------- --------
Total expenses $129,429 $135,398 $140,167 $133,725 $148,131 $143,505 $150,958
Operating Cash Flow $70,317 $74,895 $77,171 $76,077 $92,262 $98,975 $85,098
NJEA Operating Results
Revenues
JCP&L $164,949 $167,894 $171,934 $169,911 $166,276 $181,422 $117,893
Merchant Sales 10,490 10,739 12,634 12,583 12,351 17,278 62,814
Steam 2,900 2,939 2,979 3,019 3,060 3,101 1,965
Interest Income 406 323 382 493 400 284 284
-------- -------- -------- -------- -------- -------- --------
Total Revenues $178,745 $18,894 $187,928 $186,006 $182,086 $202,084 $182,956
Expenses
Operations and maintenance $4,759 $3,385 $7,447 $8,284 $3,658 $3,514 $6,869
Water costs and easement fee 1,783 1,815 1,848 1,880 1,914 1,947 1,982
Insurance 905 929 954 980 1,006 1,034 1,062
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 875 876 878 879 881 882 884
Management fees 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 564 575 585 598 617 588 605
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expenses $12,667 $11,464 $15,700 $16,718 $12,282 $12,287 $15,844
Total fuel cost 86,008 88,537 91,466 91,526 90,473 99,042 102,352
-------- -------- -------- -------- -------- -------- --------
Total expenses $96,675 $100,001 $107,166 $108,245 $102,755 $111,328 $118,196
Operating Cash Flow $80,069 $81,893 $80,762 $77,761 $79,331 $90,756 $64,760
Combined Operating Results
Total Revenues $378,491 $392,187 $405,266 $395,808 $422,479 $444,563 $419,012
Non-fuel operating expenses 27,859 29,197 35,629 32,816 33,480 28,481 33,670
Total fuel cost 200,246 206,201 211,705 209,153 217,406 226,352 235,483
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $150,387 $156,789 $157,932 $153,839 $171,593 $189,731 $149,858
Change in Working Capital 2,432 2,255 2,119 (1,675) 4,544 3,706 (5,067)
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $147,955 $154,534 $155,814 $155,513 $167,049 $186,025 $154,926
Subordinated Management Fee $1,994 $2,048 $2,103 $2,160 $2,219 $2,278 $2,342
Project Securities
Principal 45,349 52,641 54,021 51,801 54,616 65,223 0
Interest 29,880 25,484 20,545 15,504 10,374 4,779 0
Project Security Debt Service Coverage
Project Security debt service coverage* 1.99x 2.00x 2.12x 2.34x 2.60x 2.69x
Distributions to NE LP $72,726 $76,410 $81,247 $88,208 $102,059 $116,022 $154,926
The Bonds
Principal 8,800 13,200 22,000 22,000 26,400 35,200 66,000
Interest 15,293 14,502 13,271 11,514 9,668 7,383 3,955
Debt Service Coverages
Bond debt service coverage 3.02x 2.76x 2.30x 2.63x 2.83x 2.72x 2.21x
Consolidated coverage 1.49x 1.46x 1.42x 1.54x 1.65x 1.65x 2.21x
*The numerator of the Project Security Debt Service Coverage Ratio is calculated
before payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-115
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case A: Spot Gas Prices Increased 6%
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.80% 2.80% 2.80% 2.80% 2.80% 2.70% 2.70%
#6 fuel oil, 2.2% S ($/MMBtu) $2.74 $2.77 $2.81 $2.83 $2.86 $2.89 $2.92
#2 fuel oil ($/MMBtu) 4.42 4.51 4.61 4.67 4.73 4.79 4.85
Nominal Spot Gas Price Escalation 10.64% 4.35% 4.33% 3.80% 3.79% 3.68% 3.67%
Spot gas ($/MMBtu) 2.22 2.32 2.42 2.51 2.61 2.71 2.81
NEA Operational Factors
Net GWh generated 2,443 2,534 2,583 2,526 2,338 2,570 2,472
Net capacity (MW) 290 301 304 301 299 305 303
Equivalent availability factor 96.15% 96.15% 97.15% 95.65% 89.15% 96.15% 93.15%
Heat rate (Btu/kWh) 8,283 8,339 8,270 8,325 8,380 8,229 8,283
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Commonwealth I 6.54 6.53 6.55 5.28 5.12 5.53 5.52
Commonwealth II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Montaup 6.50 6.50 6.50 3.11 3.35 3.54 3.76
Merchant Sales 0.00 2.88 2.72 2.94 3.20 3.48 3.80
------ ------ ------ ------ ------ ------ ------
Average all-in rate 6.66 6.71 6.86 6.72 6.99 7.22 7.54
Electricity Sales (GWh)
Boston Edison I 1,133 1,133 1,145 1,127 1,051 1,133 1,098
Boston Edison II 705 705 712 701 654 705 683
Commonwealth I 208 208 211 207 193 208 202
Commonwealth II 175 175 177 174 162 175 170
Montaup 208 208 211 207 193 208 202
Merchant Sales 0 94 117 98 75 129 108
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.37 $4.48 $4.55 $4.67 $4.82 $5.06 $5.07
Annual Volume (BBtu/yr) 20,416 20,552 21,455 21,675 21,348 19,945 21,463
NJEA Operational Factors
Net GWh generated 2,071 2,361 2,344 2,307 2,216 2,101 2,320
Net capacity (MW) 252 287 285 288 286 284 289
Equivalent availability factor 93.82% 93.82% 93.82% 91.54% 88.54% 84.54% 91.54%
Heat rate (Btu/kWh) 9,057 8,461 8,574 8,503 8,560 8,617 8,461
Electricity Sales Rates (cents/kWh)
JCP&L 7.10 7.25 7.41 7.61 7.80 8.02 8.07
Merchant Sales 0.00 2.81 2.71 2.90 3.09 3.29 3.50
------ ------ ------ ------ ------ ------ ------
Average all-in rate 7.10 6.70 6.85 7.01 7.23 7.48 7.47
Electricity Sales (GWh)
JCP&L 2,071 2,071 2,071 2,021 1,955 1,866 2,021
Merchant Sales 0 290 273 287 262 235 299
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 1,013
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $3.42 $3.59 $3.73 $3.87 $4.03 $4.20 $4.26
Annual Volume (BBtu/yr) 18,760 19,977 20,100 19,634 18,995 18,147 19,641
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-116
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case A: Spot Gas Prices Increased 6%
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.70% 2.70% 2.70% 2.70% 2.70% 2.70% 2.80%
#6 fuel oil, 2.2% S ($/MMBtu) $2.95 $2.98 $3.01 $3.04 $3.07 $3.10 $3.09
#2 fuel oil ($/MMBtu) 4.92 4.94 4.96 4.99 5.01 5.03 5.01
Nominal Spot Gas Price Escalation 3.66% 3.18% 3.18% 3.17% 2.70% 3.17% 3.74%
Spot gas ($/MMBtu) 2.91 3.00 3.10 3.19 3.28 3.38 3.51
NEA Operational Factors
Net GWh generated 2,521 2,556 2,526 2,338 2,570 2,472 2,521
Net capacity (MW) 301 304 301 299 305 303 301
Equivalent availability factor 95.65% 96.15% 95.65% 89.15% 96.15% 93.15% 95.65%
Heat rate (Btu/kWh) 8,339 8,270 8,325 8,380 8,229 8,283 8,339
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Commonwealth I 5.74 5.88 5.99 5.84 6.27 6.28 6.47
Commonwealth II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Montaup 3.97 4.07 4.17 4.27 4.42 4.58 4.66
Merchant Sales 4.13 4.42 4.75 5.11 5.54 5.99 6.19
------ ------ ------ ------ ------ ------ ------
Average all-in rate 7.89 8.19 8.57 8.95 9.32 9.78 9.33
Electricity Sales (GWh)
Boston Edison I 1,127 1,133 1,127 1,051 1,133 1,098 1,127
Boston Edison II 701 705 701 654 705 683 498
Commonwealth I 207 208 207 193 208 202 207
Commonwealth II 174 175 174 162 175 170 174
Montaup 207 208 207 193 208 202 207
Merchant Sales 93 116 98 75 129 108 298
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $5.26 $5.35 $5.48 $5.63 $5.90 $5.91 $6.12
Annual Volume (BBtu/yr) 20,813 21,347 21,460 21,348 19,945 21,463 20,813
NJEA Operational Factors
Net GWh generated 2,291 2,275 2,307 2,216 2,101 2,320 2,311
Net capacity (MW) 287 285 288 286 284 289 290
Equivalent availability factor 91.04% 91.04% 91.54% 88.54% 84.54% 91.54% 91.04%
Heat rate (Btu/kWh) 8,518 8,574 8,503 8,560 8,617 8,461 8,518
Electricity Sales Rates (cents/kWh)
JCP&L 8.22 8.37 8.53 8.71 8.93 8.99 9.19
Merchant Sales 3.73 4.06 4.41 4.81 5.26 5.78 5.95
------ ------ ------ ------ ------ ------ ------
Average all-in rate 7.66 7.85 8.00 8.24 8.50 8.57 7.74
Electricity Sales (GWh)
JCP&L 2,010 2,010 2,021 1,955 1,866 2,021 1,279
Merchant Sales 281 265 287 262 235 299 1,055
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 633
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.40 $4.54 $4.66 $4.82 $4.99 $5.04 $5.20
Annual Volume (BBtu/yr) 19,526 19,517 19,634 18,995 18,147 19,641 19,701
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-117
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Class B: 4% Inflation
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
---- ---- ---- ---- ---- ---- ----
NEA Operating Results
Revenues
Boston Edison I $73,649 $73,649 $74,415 $73,266 $68,288 $73,649 $71,351
Boston Edison II 48,928 52,665 57,202 60,526 60,597 70,290 73,220
Commonwealth I 13,635 13,607 13,805 10,954 9,905 11,523 11,144
Commonwealth II 12,153 13,081 14,207 15,033 15,051 17,458 18,186
Montaup 13,550 13,550 13,691 6,453 6,476 7,385 7,588
Merchant Sales 0 2,709 3,187 2,881 2,400 4,504 4,108
Steam 1,213 1,065 962 921 598 1,024 886
Interest Income 505 505 605 699 605 674 707
-------- -------- -------- -------- -------- -------- --------
Total Revenues $163,634 $170,831 $178,076 $170,734 $163,919 $186,509 $187,190
Expenses
Operations and maintenance $8,753 $9,154 $13,220 $10,603 $3,206 $8,528 $4,533
Water costs and easement fee 304 318 333 502 902 928 953
Insurance 897 933 971 1,009 1,050 1,092 1,135
G&A and Professional fees 650 676 703 731 760 791 822
Property tax 3,643 3,844 4,052 4,270 4,495 4,729 4,971
Management fees 2,050 2,132 2,217 2,306 2,398 2,494 2,594
Fuel management fee 450 468 487 506 526 547 569
Gas Hedge & Peak Service Loss/(Savings) (4,158) (991) (1,011) (575) (753) (941) (1,133)
Other 1,048 1,080 1,105 1,075 2,234 2,467 2,374
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $13,638 $17,615 $22,076 $20,426 $14,819 $20,635 $16,819
Total fuel cost 91,654 96,006 99,494 101,159 99,318 106,904 107,483
-------- -------- -------- -------- -------- -------- --------
Total expenses $105,292 $113,621 $121,571 $121,586 $144,137 $127,539 $124,302
Operating Cash Flow $58,342 $57,210 $56,504 $49,148 $49,783 $58,969 $62,887
NJEA Operating Results
Revenues
JCP&L $142,607 $146,606 $148,580 $148,879 $147,531 $144,865 $157,667
Merchant Sales 0 8,150 7,405 8,308 8,080 7,714 10,483
Steam 2,650 2,703 2,757 2,813 2,869 2,926 2,985
Interest Income 355 355 383 493 611 516 495
-------- -------- -------- -------- -------- -------- --------
Total Revenues $145,612 $156,814 $159,126 $160,493 $159,090 $156,021 $171,630
Expenses
Operations and maintenance $9,215 $9,514 $10,766 $12,031 $7,776 $3,560 $7,307
Water costs and easement fee 804 828 853 1,114 1,731 1,772 1,815
Insurance 757 787 818 851 885 920 957
G&A and Professional fees 650 676 703 731 760 791 822
Property tax 867 868 870 872 874 876 878
Management fees 2,050 2,132 2,217 2,306 2,398 2,494 2,594
Fuel management fee 450 468 487 506 526 547 569
Gas Hedge & Peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 424 440 451 485 544 566 596
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $15,217 $15,713 $17,165 $18,896 $15,495 $11,527 $15,538
Total fuel cost 62,837 68,689 71,620 72,740 73,181 72,865 80,026
-------- -------- -------- -------- -------- -------- --------
Total expenses $78,054 $84,402 $88,785 $91,636 $88,676 $64,392 $95,565
Operating Cash Flow $67,558 $72,412 $70,341 $68,856 $70,414 $71,629 $76,065
Combined Operating Results
Total Revenues $309,246 $327,646 $337,202 $331,227 $323,009 $342,530 $358,820
Non-fuel operating expenses 28,855 33,327 39,242 39,323 30,313 32,163 32,358
Total fuel cost 154,491 164,696 171,114 173,899 172,499 179,769 187,509
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $125,900 $129,622 $126,846 $118,005 $120,197 $130,598 $138,953
Change in Working Capital 10,084 2,989 1,383 (1,193) (1,191) 3,272 2,656
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $115,817 $126,634 $125,463 $119,198 $121,388 $127,326 $136,297
Subordinated Management Fee $1,668 1,735 1,804 1,876 1,951 2,029 2,110
Project Securities
Principal 21,563 23,511 26,333 20,160 22,688 23,818 28,564
Interest 45,327 43,468 41,426 39,300 37,396 35,264 32,933
Project Security Debt Service Coverage
Project Security debt service coverage* 1.76x 1.92x 1.88x 2.04x 2.05x 2.19x 2.25x
Minimum Project Security debt service coverage 1.76x
Average Project Security debt service coverage 2.12x
Distribution to NE LP $48,927 $59,655 $57,703 $59,738 $61,304 $68,245 $74,800
The Bonds
Principal 0 0 0 0 8,800 8,800 8,800
Interest 15,381 17,578 17,578 17,578 17,402 16,699 15,996
Debt Service Coverages
Bond debt service coverage 3.18x 3.39x 3.28x 3.40x 2.34x 2.68x 3.02x
Minimum Bond debt service coverage 2.17x
Average Bond debt service coverage 2.80x
Consolidated coverage 1.41x 1.50x 1.47x 1.55x 1.41x 1.51x 1.58x
Minimum consolidated debt service coverage 1.39x
Average consolidated coverage 1.54x
*The numerator of the Project Security Debt Service Coverage Ratio is calculated
before payment of a subordianted management fee.
Amounts may not add due to rounding.
These financial projects should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-118
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case B: 4% Inflation
(data in $000's unless noted)
NEA Operating Results 2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
Revenues
Boston Edison I $73,266 $73,649 $73,266 $68,288 $73,649 $71,351 $73,266
Boston Edison II 80,795 87,351 93,350 93,543 108,502 112,971 88,537
Commonwealth I 11,906 12,267 12,421 11,288 13,078 12,684 13,423
Commonwealth II 20,068 21,696 23,186 23,234 26,949 28,059 30,972
Montaup 8,238 8,495 8,655 8,249 9,204 9,256 9,663
Merchant Sales 3,863 5,122 4,647 3,831 7,157 6,475 18,416
Steam 1,077 1,152 1,165 756 1,296 1,121 1,363
Interest Income 567 627 770 678 689 681 505
-------- -------- -------- -------- -------- -------- --------
Total Revenues $199,780 $210,360 $217,460 $209,867 $240,525 $242,598 $236,145
Expenses
Operations and maintenance $4,104 $6,763 $9,130 $4,029 $9,782 $4,066 $5,868
Water costs and easement fee 979 1,005 1,031 1,058 1,085 1,112 1,140
Insurance 1,181 1,228 1,277 1,328 1,381 1,437 1,494
G&A and Professional fees 855 890 925 962 1,001 1,041 1,082
Property tax 5,222 5,480 5,745 6,017 6,296 6,580 6,868
Management fees 2,697 2,805 2,918 3,034 3,156 3,282 3,413
Fuel management fee 592 616 640 666 693 720 749
Gas Hedge & Peak Service Loss/(Savings) (1,155) (1,185) (1,215) (622) (886) (1,099) (1,325)
Other 2,429 2,416 2,424 2,260 2,511 2,393 2,507
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $16,904 $20,048 $22,877 $18,734 $25,017 $19,531 $21,797
Total fuel cost 112,220 115,566 118,085 115,546 124,633 125,012 130,697
--------------- -------- -------- -------- -------- -------- -------- --------
Total expenses $129,124 $135,615 $140,961 $134,279 $149,650 $144,543 $152,494
Operating Cash Flow $70,656 $74,745 $76,499 $75,588 $90,875 $98,056 $83,651
NJEA Operating Results
Revenues
JCP&L $159,702 $162,480 $166,309 $164,315 $160,776 $175,260 $113,850
Merchant Sales 10,490 10,739 12,634 12,583 12,351 17,278 62,814
Steam 3,044 3,105 3,167 3,231 3,295 3,361 2,143
Interest Income 536 418 506 671 535 363 355
-------- -------- -------- -------- -------- -------- --------
Total Revenues $173,772 $176,743 $182,617 $180,799 $176,957 $196,262 $179,161
Expense
Operations and maintenance $5,142 $3,650 $8,333 $9,402 $4,094 $3,969 $7,988
Water costs and easement fee 1,858 1,901 1,946 1,991 2,036 2,082 2,129
Insurance 996 1,035 1,077 1,120 1,165 1,211 1,260
G&A and Professional fees 855 890 925 962 1,001 1,041 1,082
Property tax 880 882 885 887 890 892 895
Management fees 2,697 2,805 2,918 3,034 3,156 3,282 3,413
Fuel management fee 592 616 640 666 693 720 749
Gas Hedge & peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 620 640 660 683 712 695 723
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $13,640 $12,421 $17,383 $18,745 $13,745 $13,893 $18,240
Total fuel cost 82,196 84,596 87,376 87,445 86,461 94,569 97,716
-------- -------- -------- -------- -------- -------- --------
Total expenses $95,836 $97,016 $104,759 $106,189 $100,206 $108,461 $115,955
Operating Cash Flow $77,936 $79,727 $77,858 $74,610 $76,751 $87,801 $63,206
Combined Operating Results
Total Revenue $373,552 $387,103 $400,076 $390,666 $417,482 $438,861 $415,307
Non-fuel operating expenses 30,545 32,469 40,260 37,478 38,762 33,424 40,036
Total fuel cost 194,415 200,162 205,460 202,990 211,094 219,581 228,413
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $148,592 $154,472 $154,356 $150,198 $167,626 $185,856 $146,857
Change in Working Capital 2,411 2,226 2,081 (1,689) 4,568 3,590 (4,691)
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $146,181 $152,245 $152,276 $151,886 $163,058 $182,267 $151,548
Subordinated Management Fee 2,195 2,283 2,374 2,469 2,568 2,670 2,777
Project Securities
Principal 45,349 52,641 54,021 51,801 54,616 65,223 0
Interest 28,880 25,484 20,545 15,504 10,374 4,779 0
Project Security Debt Service Coverage
Project Security debt service coverage* 1.97x 1.98x 2.07x 2.29x 2.55x 2.64x
Distributions to NE LP $70,953 $74,121 $77,709 $84,581 $98,068 $112,264 $151,548
The Bonds
Principal 8,800 13,200 22,000 22,000 26,400 35,200 66,000
Interest 15,293 14,502 13,271 11,514 9,668 7,383 3,955
Debt Service Coverages
Bond debt service coverage 2.94x 2.68x 2.20x 2.52x 2.72x 2.64x 2.17x
Consolidated coverage 1.47x 1.44x 1.39x 1.51x 1.61x 1.62x 2.17x
*The numerator of the Project Security Debt Service Coverage Ratio is calculated
before payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projects should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-119
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case B: 4% Inflation
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00%
#6 fuel oil, 2.2% S ($/MMBtu) $2.74 $2.77 $2.81 $2.83 $2.86 $2.89 $2.92
#2 fuel oil ($/MMBtu) 4.42 4.51 4.61 4.67 4.73 4.79 4.85
Nominal Spot Gas Price Escalation 4.37% 4.35% 4.33% 3.80% 3.79% 3.68% 3.67%
Spot gas ($/MMBtu) 2.10 2.19 2.28 2.37 2.46 2.55 2.65
NEA Operational Factors
Net GWh generated 2,443 2,534 2,583 2,526 2,338 2,570 2,472
Net capacity (MW) 290 301 304 301 299 305 303
Equivalent availability factor 96.15% 96.15% 97.15% 95.65% 89.15% 96.15% 93.15%
Heat rate (Btu/kWh) 8,283 8,339 8,270 8,325 8,380 8,229 8,283
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Commonwealth I 6.54 6.53 6.55 5.28 5.12 5.53 5.52
Commonwealth II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Montaup 6.50 6.50 6.50 3.11 3.35 3.54 3.76
Merchant Sales 0.00 2.88 2.72 2.94 3.20 3.48 3.80
------ ------ ------ ------ ------ ------ ------
Average all-in rate 6.66 6.71 6.86 6.72 6.99 7.22 7.54
Electricity Sales (GWh)
Boston Edison I 1,133 1,133 1,145 1,127 1,051 1,133 1,098
Boston Edison II 705 705 712 701 654 705 683
Commonwealth I 208 208 211 207 193 208 202
Commonwealth II 175 175 177 174 162 175 170
Montaup 208 208 211 207 193 208 202
Merchant Sales 0 94 117 98 75 129 108
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.37 $4.46 $4.47 $4.59 $4.74 $4.98 $4.98
Annual Volume (BBtu/yr) 20,416 20,552 21,455 21,675 21,348 19,945 21,463
NJEA Operational Factors
Net GWh generated 2,071 2,361 2,344 2,307 2,216 2,101 2,320
Net capacity (MW) 252 287 285 288 286 284 289
Equivalent availability factor 93.82% 93.82% 93.82% 91.54% 88.54% 84.54% 91.54%
Heat rate (Btu/kWh) 9,057 8,461 8,574 8,503 8,560 8,617 8,461
Electricity Sales Rates (cents/kWh)
JCP&L 6.90 7.05 7.19 7.38 7.56 7.78 7.82
Merchant Sales 0.00 2.81 2.71 2.90 3.09 3.29 3.50
------ ------ ------ ------ ------ ------ ------
Average all-in rate 6.90 6.51 6.65 6.81 7.02 7.26 7.25
Electricity Sales (GWh)
JCP&L 2,071 2,071 2,071 2,021 1,955 1,866 2,021
Merchant Sales 0 290 273 287 262 235 299
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 1,013
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $3.35 $3.44 $3.56 $3.70 $3.85 $4.02 $4.07
Annual Volume (BBtu/yr) 18,760 19,977 20,100 19,634 18,995 18,147 19,641
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-120
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case B: 4% Inflation
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00%
#6 fuel oil, 2.2% S ($/MMBtu) $2.95 $2.98 $3.01 $3.04 $3.07 $3.10 $3.09
#2 fuel oil ($/MMBtu) 4.92 4.94 4.96 4.99 5.01 5.03 5.01
Nominal Spot Gas Price Escalation 3.66% 3.18% 3.18% 3.17% 2.70% 3.17% 3.74%
Spot gas ($/MMBtu) 2.74 2.83 2.92 3.01 3.09 3.19 3.31
NEA Operational Factors
Net GWh generated 2,521 2,556 2,526 2,338 2,570 2,472 2,521
Net capacity (MW) 301 304 301 299 305 303 301
Equivalent availability factor 95.65% 96.15% 95.65% 89.15% 96.15% 93.15% 95.65%
Heat rate (Btu/kWh) 8,339 8,270 8,325 8,380 8,229 8,283 8,339
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Commonwealth I 5.74 5.88 5.99 5.84 6.27 6.28 6.47
Commonwealth II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Montaup 3.97 4.07 4.17 4.27 4.42 4.58 4.66
Merchant Sales 4.13 4.42 4.75 5.11 5.54 5.99 6.19
------ ------ ------ ------ ------ ------ ------
Average all-in rate 7.89 8.19 8.57 8.95 9.32 9.78 9.33
Electricity Sales (GWh)
Boston Edison I 1,127 1,133 1,127 1,051 1,133 1,098 1,127
Boston Edison II 701 705 701 654 705 683 498
Commonwealth I 207 208 207 193 208 202 207
Commonwealth II 174 175 174 162 175 170 174
Montaup 207 208 207 193 208 202 207
Merchant Sales 93 116 98 75 129 108 298
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $5.16 $5.26 $5.39 $5.53 $5.79 $5.81 $6.01
Annual Volume (BBtu/yr) 20,813 21,347 21,460 21,348 19,945 21,463 20,813
NJEA Operational Factors
Net GWh generated 2,291 2,275 2,307 2,216 2,101 2,320 2,311
Net capacity (MW) 287 285 288 286 284 289 290
Equivalent availability factor 91.04% 91.04% 91.54% 88.54% 84.54% 91.54% 91.04%
Heat rate (Btu/kWh) 8,518 8,574 8,503 8,560 8,617 8,461 8,518
Electricity Sales Rates (cents/kWh)
JCP&L 7.96 8.10 8.25 8.42 8.63 8.69 8.88
Merchant Sales 3.73 4.06 4.41 4.81 5.26 5.78 5.95
------ ------ ------ ------ ------ ------ ------
Average all-in rate 7.43 7.62 7.75 7.98 8.24 8.30 7.57
Electricity Sales (GWh)
JCP&L 2,010 2,010 2,021 1,955 1,866 2,021 1,279
Merchant Sales 281 265 287 262 235 299 1,055
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 633
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.21 $4.33 $4.45 $4.60 $4.76 $4.81 $4.96
Annual Volume (BBtu/yr) 19,526 19,517 19,634 18,995 18,147 19,641 19,701
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-121
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case C: 90% Availability
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
----- ----- ----- ----- ----- ----- -----
NEA Operating Results
Revenues
Boston Edison I $68,939 $68,939 $68,939 $68,939 $68,939 $68,939 $68,939
Boston Edison II 45,798 49,296 52,992 56,951 61,175 65,794 70,743
Commonwealth I 12,273 12,245 12,216 9,852 10,069 10,286 10,509
Commonwealth II 11,375 12,244 13,162 14,145 15,194 16,342 17,571
Montaup 12,683 12,683 12,683 6,066 6,520 6,892 7,306
Merchant Sales 0 2,536 2,953 2,711 2,423 4,216 3,970
Steam 941 839 733 754 775 796 817
Interest Income 404 404 481 552 479 518 541
-------- -------- -------- -------- -------- -------- --------
Total Revenues $152,414 $159,186 $164,158 $159,968 $165,574 $173,782 $180,396
Expenses
Operations and maintenance $6,631 $6,830 $10,229 $8,864 $3,122 $7,987 $4,264
Water costs and easement fee 304 317 331 495 883 904 925
Insurance 887 912 937 964 991 1,017 1,045
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 3,601 3,712 3,824 3,936 4,049 4,154 4,259
Management fees 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Peak Service Loss/(Savings) (4,158) (991) (1,011) (575) (753) (941) (1,133)
Other 1,039 1,062 1,077 1,036 2,215 2,234 2,231
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $11,430 $15,055 $18,691 $18,116 $13,998 $18,942 $15,272
Total fuel cost 88,029 91,938 94,417 96,880 99,350 101,942 104,561
-------- -------- -------- -------- -------- -------- --------
Total expenses $99,459 $106,993 $113,108 $114,996 $113,348 $120,883 $119,834
Operating Cash Flow $52,955 $52,193 $51,050 $44,972 $52,226 $52,899 $60,562
NJEA Operating Results
Revenues
JCP&L $137,789 $140,662 $143,512 $146,677 $149,487 $152,348 $155,306
Merchant Sales 0 7,818 7,103 8,168 8,213 8,212 10,307
Steam 2,635 2,672 2,709 2,747 2,785 2,823 2,861
Interest Income 284 284 306 389 476 396 378
-------- -------- -------- -------- -------- -------- --------
Total Revenues $140,708 $151,436 $153,630 $157,981 $160,961 $163,778 $168,851
Expenses
Operations and maintenance $8,987 $9,193 $10,305 $11,495 $7,377 $3,412 $6,780
Water costs and easement fee 800 821 842 1,094 1,687 1,719 1,751
Insurance 748 769 790 812 835 858 881
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 866 867 868 870 871 872 874
Management fees 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 420 431 437 463 512 527 548
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $14,948 $15,295 $16,545 $18,130 $14,774 $10,973 $14,516
Total fuel cost 60,913 66,552 69,376 71,799 74,107 76,453 78,976
-------- -------- -------- -------- -------- -------- --------
Total expenses $75,860 $81,847 $85,922 $89,929 $88,882 $87,426 $93,492
Operating Cash Flow $64,847 $69,589 $67,708 $68,052 $72,080 $76,352 $75,360
Combined Operating Results
Total Revenues $293,122 $310,622 $317,788 $317,949 $326,535 $337,560 $349,248
Non-fuel operating expenses 26,378 30,350 35,236 36,246 28,773 29,915 29,789
Total fuel cost 148,942 158,490 163,794 168,679 173,457 178,395 183,537
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $117,802 $121,782 $118,758 $113,024 $124,305 $129,251 $135,922
Change in Working Capital 7,453 2,865 1,019 (176) 1,597 1,828 1,928
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $110,349 $118,917 $117,739 $113,200 $122,709 $127,423 $133,994
Subordinated Management Fee $1,649 1,695 1,742 1,791 1,841 1,891 1,942
Project Securities
Principal 21,563 23,511 26,333 20,160 22,688 23,818 28,564
Interest 45,327 43,468 41,426 39,300 37,396 35,264 32,933
Project Security Debt Service Coverage
Project Security debt service coverage* 1.67x 1.80x 1.76x 1.93x 2.07x 2.19x 2.21x
Minimum Project Security debt service coverage 1.67x
Average Project Security debt service coverage 2.07x
Distributions to NE LP $43,459 $51,939 $49,980 $53,740 $62,625 $68,341 $72,497
The Bonds
Principal 0 0 0 0 8,800 8,800 8,800
Interest 15,381 17,578 17,578 17,578 17,402 16,699 15,996
Debt Service Coverages
Bond debt service coverage 2.83x 2.95x 2.84x 3.06x 2.39x 2.68x 2.92x
Minimum Bond debt service coverage 2.05x
Average Bond debt service coverage 2.65x
Consolidated coverage 1.34x 1.41x 1.38x 1.47x 1.42x 1.51x 1.55x
Minimum consolidated debt service coverage 1.34x
Average consolidated coverage 1.51x
*The numerator of the Project Security Debt Service Coverage Ratio is calculated
before payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projects should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-122
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case C: 90% Availability
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
NEA Operating Results
Revenues
Boston Edison I $68,939 $68,939 $68,939 $68,939 $68,939 $68,939 $68,939
Boston Edison II 76,023 81,764 87,835 94,435 101,562 109,151 83,307
Commonwealth I 10,739 10,975 11,218 11,467 11,723 11,987 12,147
Commonwealth II 18,882 20,308 21,816 23,455 25,225 27,110 29,143
Montaup 7,722 7,918 8,106 8,285 8,615 8,943 9,092
Merchant Sales 3,635 4,794 4,373 3,868 6,699 6,256 17,328
Steam 839 862 885 909 934 959 986
Interest Income 439 480 578 514 519 514 404
-------- -------- -------- -------- -------- -------- --------
Total Revenues $187,218 $196,040 $203,750 $211,872 $224,217 $233,858 $221,346
Expenses
Operations and maintenance $3,833 $6,174 $8,149 $3,646 $8,516 $3,601 $5,085
Water costs and easement fee 946 967 988 1,009 1,030 1,052 1,074
Insurance 1,073 1,102 1,132 1,162 1,194 1,226 1,260
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 4,362 4,464 4,564 4,661 4,756 4,846 4,943
Management fees 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) (1,155) (1,185) (1,215) (622) (886) (1,099) (1,325)
Other 2,204 2,170 2,152 2,170 2,194 2,154 2,178
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $15,043 $17,575 $19,758 $16,123 $21,011 $16,101 $17,655
Total fuel cost 107,271 110,040 112,780 115,609 118,515 121,431 124,628
-------- -------- -------- -------- -------- -------- --------
Total expenses $122,314 $127,616 $132,537 $131,731 $139,526 $137,531 $142,283
Operating Cash Flow $64,904 $68,425 $71,212 $80,140 $84,691 $96,326 $79,063
NJEA Operating Results
Revenues
JCP&L $158,211 $160,958 $163,790 $166,545 $169,275 $172,579 $113,842
Merchant Sales 10,370 10,617 12,422 12,791 13,148 16,987 62,097
Steam 2,900 2,939 2,979 3,019 3,060 3,101 1,965
Interest Income 406 323 382 493 400 284 284
-------- -------- -------- -------- -------- -------- --------
Total Revenues $171,888 $174,836 $179,573 $182,847 $185,882 $192,951 $178,188
Expenses
Operations and maintenance $4,759 $3,385 $7,447 $8,284 $3,658 $3,514 $6,869
Water costs and easement fee 1,783 1,815 1,848 1,880 1,914 1,947 1,982
Insurance 905 929 954 980 1,006 1,034 1,062
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 875 876 878 879 881 882 884
Management fees 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 564 575 585 598 617 588 605
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $12,667 $11,464 $15,700 $16,718 $12,282 $12,287 $15,844
Total fuel cost 81,461 83,836 86,214 88,581 90,829 93,300 96,822
-------- -------- -------- -------- -------- -------- --------
Total expenses $94,128 $95,300 $101,914 $105,300 $103,111 $105,586 $112,666
Operating Cash Flow $77,760 $79,536 $77,658 $77,548 $82,771 $87,364 $65,522
Combined Operating Results
Total Revenues $359,106 $370,877 $383,322 $394,719 $410,099 $426,808 $399,534
Non-fuel operating expenses 27,710 29,040 35,458 32,841 33,294 28,387 33,499
Total fuel cost 188,731 193,876 198,994 204,190 209,343 214,730 221,450
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $142,664 $147,961 $148,871 $157,688 $167,462 $183,691 $144,585
Change in Working Capital 1,596 1,935 2,018 1,830 2,604 2,863 (5,282)
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $141,068 $145,026 $146,853 $155,858 $164,858 $180,828 $149,867
Subordinated Management Fee 1,994 2,048 2,103 2,160 2,219 2,278 2,342
Project Securities
Principal 45,349 52,641 54,021 51,801 54,616 65,223 0
Interest 29,880 25,484 20,545 15,504 10,374 4,779 0
Project Security Debt Service Coverage
Project Security debt service coverage* 1.90x 1.90x 2.00x 2.35x 2.57x 2.62x
Distribution to NE LP $65,840 $67,902 $72,286 $88,553 $99,867 $110,825 $149,867
The Bonds
Principal 8,800 13,200 22,000 22,000 26,400 35,200 66,000
Interest 15,293 14,502 13,371 11,514 9,668 7,383 3,955
Debt Service Coverages
Bond debt service coverage 2.73x 2.45x 2.05x 2.64x 2.77x 2.60x 2.14x
Consolidated coverage 1.42x 1.38x 1.34x 1.55x 1.63x 1.61x 2.14x
*The numerator of the Project Security Debt Service Coverage Ratio is calculated
before payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projects should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-123
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case C: 90% Availability
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.80% 2.80% 2.80% 2.80% 2.80% 2.70% 2.70%
#6 fuel oil, 2.2% S ($/MMBtu) $2.74 $2.77 $2.81 $2.83 $2.86 $2.89 $2.92
#2 fuel oil ($/MMBtu) 4.42 4.51 4.61 4.67 4.73 4.79 4.85
Nominal Spot Gas Price Escalation 4.37% 4.35% 4.33% 3.80% 3.79% 3.68% 3.67%
Spot gas ($/MMBtu) 2.10 2.19 2.28 2.37 2.46 2.55 2.65
NEA Operational Factors
Net GWh generated 2,286 2,372 2,393 2,376 2,360 2,405 2,389
Net capacity (MW) 290 301 304 301 299 305 303
Equivalent availability factor 90.00% 90.00% 90.00% 90.00% 90.00% 90.00% 90.00%
Heat rate (Btu/kWh) 8,283 8,339 8,270 8,325 8,380 8,229 8,283
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Commonwealth I 6.29 6.28 6.26 5.05 5.16 5.27 5.39
Commonwealth II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Montaup 6.50 6.50 6.50 3.11 3.34 3.53 3.74
Merchant Sales 0.00 2.88 2.72 2.94 3.20 3.48 3.80
------ ------ ------ ------ ------ ------ ------
Average all-in rate 6.64 6.69 6.84 6.70 6.99 7.20 7.53
Electricity Sales (GWh)
Boston Edison I 1,061 1,061 1,061 1,061 1,061 1,061 1,061
Boston Edison II 660 660 660 660 660 660 660
Commonwealth I 195 195 195 195 195 195 195
Commonwealth II 164 164 164 164 164 164 164
Montaup 195 195 195 195 195 195 195
Merchant Sales 0 88 109 92 76 121 104
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.37 $4.56 $4.57 $4.69 $4.81 $4.94 $5.06
Annual Volume (BBtu/yr) 20,416 19,284 20,131 20,135 20,132 20,128 20,138
NJEA Operational Factors
Net GWh generated 1,987 2,265 2,249 2,269 2,253 2,237 2,281
Net capacity (MW) 252 287 285 288 286 284 289
Equivalent availability factor 90.00% 90.00% 90.00% 90.00% 90.00% 90.00% 90.00%
Heat rate (Btu/kWh) 9,057 8,461 8,574 8,503 8,560 8,617 8,461
Electricity Sales Rates (cents/kWh)
JCP&L 6.95 7.10 7.24 7.40 7.54 7.68 7.83
Merchant Sales 0.00 2.81 2.71 2.90 3.09 3.29 3.50
------ ------ ------ ------ ------ ------ ------
Average all-in rate 6.95 6.56 6.70 6.83 7.00 7.18 7.26
Electricity Sales (GWh)
JCP&L 1,987 1,987 1,987 1,987 1,987 1,987 1,987
Merchant Sales 0 278 262 282 266 250 294
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 1,013
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $3.38 $3.47 $3.59 $3.72 $3.84 $3.96 $4.09
Annual Volume (BBtu/yr) 18,012 19,180 19,299 19,311 19,302 19,292 19,318
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-124
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case C: 90% Availability
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.70% 2.70% 2.70% 2.70% 2.70% 2.70% 2.80%
#6 fuel oil, 2.2% S ($/MMBtu) $2.95 $2.98 $3.01 $3.04 $3.07 $3.10 $3.09
#2 fuel oil ($/MMBtu) 4.92 4.94 4.96 4.99 5.01 5.03 5.01
Nominal Spot Gas Price Escalation 3.66% 3.18% 3.18% 3.17% 2.70% 3.17% 3.74%
Spot gas ($/MMBtu) 2.74 2.83 2.92 3.01 3.09 3.19 3.31
NEA Operational Factors
Net GWh generated 2,372 2,393 2,376 2,360 2,405 2,389 2,372
Net capacity (MW) 301 304 301 299 305 303 301
Equivalent availability factor 90.00% 90.00% 90.00% 90.00% 90.00% 90.00% 90.00%
Heat rate (Btu/kWh) 8,339 8,270 8,325 8,380 8,229 8,283 8,339
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Commonwealth I 5.50 5.62 5.75 5.88 6.01 6.14 6.23
Commonwealth II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Montaup 3.96 4.06 4.15 4.25 4.42 4.58 4.66
Merchant Sales 4.13 4.42 4.75 5.11 5.54 5.99 6.19
------ ------ ------ ------ ------ ------ ------
Average all-in rate 7.87 8.17 8.55 8.95 9.30 9.77 9.31
Electricity Sales (GWh)
Boston Edison I 1,061 1,061 1,061 1,061 1,061 1,061 1,061
Boston Edison II 660 660 660 660 660 660 469
Commonwealth I 195 195 195 195 195 195 195
Commonwealth II 164 164 164 164 164 164 164
Montaup 195 195 195 195 195 195 195
Merchant Sales 88 109 92 76 121 104 280
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $5.19 $5.33 $5.46 $5.60 $5.74 $5.89 $6.03
Annual Volume (BBtu/yr) 20,134 20,131 20,135 20,132 20,128 20,138 20,134
NJEA Operational Factors
Net GWh generated 2,265 2,249 2,269 2,253 2,237 2,281 2,285
Net capacity (MW) 287 285 288 286 284 289 290
Equivalent availability factor 90.00% 90.00% 90.00% 90.00% 90.00% 90.00% 90.00%
Heat rate (Btu/kWh) 8,518 8,574 8,503 8,560 8,617 8,461 8,518
Electricity Sales Rates (cents/kWh)
JCP&L 7.98 8.12 8.26 8.40 8.54 8.70 8.89
Merchant Sales 3.73 4.06 4.41 4.81 5.26 5.78 5.95
------ ------ ------ ------ ------ ------ ------
Average all-in rate 7.44 7.63 7.77 7.96 8.16 8.31 7.58
Electricity Sales (GWh)
JCP&L 1,987 1,987 1,987 1,987 1,987 1,987 1,278
Merchant Sales 278 262 282 266 250 294 1,043
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 633
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.22 $4.34 $4.46 $4.59 $4.71 $4.83 $4.97
Annual Volume (BBtu/yr) 19,308 19,299 19,311 19,302 19,292 19,318 19,481
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-125
ESI Tractebel Acquisition Corp. -- Projected Operating Results
for NEA and NJEA
Sensitivity Case D: Heat Rates Increased 10%
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
---- ---- ---- ---- ---- ---- ----
NEA Operating Results
Revenues
Boston Edison I $73,649 $73,649 $74,415 $73,266 $68,288 $73,649 $71,351
Boston Edison II 48,928 52,665 57,202 60,526 60,597 70,290 73,220
Commonwealth I 13,635 13,607 13,805 10,954 9,905 11,523 11,144
Commonwealth II 12,153 13,081 14,207 15,033 15,051 17,458 18,186
Montaup 13,550 13,550 13,691 6,453 6,476 7,385 7,588
Merchant Sales 0 2,709 3,187 2,881 2,400 4,504 4,108
Steam 1,256 1,153 1,099 1,051 729 1,137 997
Interest Income 404 404 481 552 479 518 541
-------- -------- -------- -------- -------- -------- --------
Total Revenues $163,576 $170,819 $178,088 $170,717 $163,925 $186,465 $187,135
Expenses
Operations and maintenance $8,677 $8,998 $12,825 $10,180 $3,122 $7,987 $4,264
Water costs and easement fee 304 317 331 495 883 904 925
Insurance 887 912 937 964 991 1,017 1,045
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 3,601 3,712 3,824 3,936 4,049 4,154 4,259
Management fees 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Peak Service
Loss/(Savings) (4,158) (991) (1,011) (575) (753) (941) (1,133)
Other 1,039 1,062 1,076 1,036 2,190 2,413 2,309
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $13,476 $17,223 $21,286 $19,433 $13,974 $19,121 $15,350
Total fuel cost 97,264 102,243 106,015 107,798 105,766 114,007 114,608
-------- -------- -------- -------- -------- -------- --------
Total expenses $110,740 $119,466 $127,301 $127,231 $119,740 $133,127 $129,957
Operating Cash Flow $52,835 $51,353 $50,787 $43,486 $44,185 $53,338 $57,177
NJEA Operating Results
Revenues
JCP&L $142,607 $145,606 $148,580 $148,879 $147,531 $144,865 $157,667
Merchant Sales 0 8,150 7,405 8,308 8,080 7,714 10,483
Steam 2,635 2,672 2,709 2,747 2,785 2,823 2,861
Interest Income 284 284 306 389 476 396 378
-------- -------- -------- -------- -------- -------- --------
Total Revenues $145,526 $156,711 $159,000 $160,322 $158,872 $155,797 $171,389
Expenses
Operations and maintenance $9,130 $9,336 $10,447 $11,539 $7,377 $3,412 $6,780
Water costs and easement fee 800 821 842 1,094 1,687 1,719 1,751
Insurance 748 769 790 812 835 858 881
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 866 867 868 870 871 872 874
Management fees 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Peak Service
Loss/(Savings) 0 0 0 0 0 0 0
Other 420 431 437 463 512 527 548
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $15,090 $15,438 $16,688 $18,174 $14,774 $10,973 $14,516
Total fuel cost 68,470 74,899 78,089 79,275 79,727 79,344 87,191
-------- -------- -------- -------- -------- -------- --------
Total expenses $83,560 $90,336 $94,777 $97,449 $94,501 $90,317 $101,707
Operating Cash Flow $61,966 $66,375 $64,223 $62,874 $64,371 $65,480 $69,682
Combined Operating Results
Total Revenues $309,101 $327,530 $337,088 $331,039 $322,796 $342,262 $358,524
Non-fuel operating expenses 28,566 32,660 37,974 37,607 28,748 30,093 29,866
Total fuel cost 165,734 177,142 184,104 187,073 185,493 193,350 201,798
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $114,801 $117,728 $115,011 $106,359 $108,556 $118,819 $126,860
Change in Working Capital 9,635 2,956 1,378 (1,198) (1,193) 3,252 2,634
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $105,166 $114,772 $113,632 $107,557 $109,748 $115,567 $124,225
Subordinated Management Fee $1,649 1,695 1,742 1,791 1,841 1,891 1,942
Project Securities
Principal 21,563 23,511 26,333 20,160 22,688 23,818 28,564
Interest 45,327 43,468 41,426 39,300 37,396 35,264 32,933
Project Security Debt Service
Coverage
Project Security debt service
coverage* 1.60x 1.74x 1.70x 1.84x 1.86x 1.99x 2.05x
Minimum Project Security debt
service coverage 1.60x
Average Project Security debt
service coverage 1.94x
Distributions to NE LP $38,276 $47,794 $45,873 $48,097 $49,665 $56,486 $62,728
The Bonds
Principal 0 0 0 0 8,800 8,800 5,500
Interest 15,381 17,578 17,578 17,578 17,402 16,699 15,996
Debt Service Coverages
Bond debt service coverage 2.49x 2.72x 2.61x 2.74x 1.90x 2.22x 2.53x
Minimum Bond debt service
coverage 1.88x
Average Bond debt service
coverage 2.33x
Consolidated coverage 1.28x 1.36x 1.33x 1.40x 1.27x 1.37x 1.44x
Minimum consolidated debt
service coverage 1.27x
Average consolidated debt
coverage 1.41x
*The numerator of the Project Security Debt Service Ratio is calculated before
payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-126
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case D: Heat Rates Increased 10%
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
NEA Operating Results
Revenues
Boston Edison I $73,226 $73,649 $73,266 $68,288 $73,649 $71,351 $73,286
Boston Edison II 80,795 87,351 93,350 93,543 108,502 112,971 88,537
Commonwealth I 11,906 12,267 12,421 11,288 13,078 12,684 13,423
Commonwealth II 20,068 21,696 23,186 23,234 26,949 28,059 30,972
Montaup 8,238 8,495 8,655 8,249 9,204 9,256 9,663
Merchant Sales 3,863 5,122 4,647 3,831 7,157 6,475 18,416
Steam 1,170 1,232 1,234 855 1,334 1,170 1,374
Interest income 439 480 578 514 519 514 404
-------- -------- -------- -------- -------- -------- --------
Total Revenues $199,746 $210,293 $217,337 $209,802 $240,393 $242,479 $236,056
Expenses
Operations and maintenance $3,833 $6,174 $8,149 $3,646 $8,516 $3,601 $5,085
Water costs and easement fee 946 967 988 1,009 1,030 1,052 1,074
Insurance 1,073 1,102 1,132 1,162 1,194 1,226 1,260
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 4,362 4,464 4,564 4,661 4,756 4,846 4,943
Management fees 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) (1,155) (1,185) (1,215) (622) (886) (1,099) (1,325)
Other 2,352 2,327 2,322 2,145 2,381 2,248 2,347
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $15,192 $17,733 $19,928 $16,098 $21,198 $16,195 $17,826
Total fuel cost 119,736 123,329 126,024 123,220 133,031 133,406 139,564
-------- -------- -------- -------- -------- -------- --------
Total expenses $134,928 $141,062 $145,952 $139,317 $154,228 $149,601 $157,390
Operating Cash Flow $64,818 $69,231 $71,385 $70,485 $86,164 $92,879 $78,666
NJEA Operating Results
Revenues
JCP&L $159,702 $162,480 $166,309 $164,315 $160,776 $175,260 $113,850
Merchant Sales 10,490 10,739 12,634 12,583 12,351 17,278 62,814
Steam 2,900 2,939 2,979 3,019 3,060 3,101 1,965
Interest income 406 323 382 493 400 284 284
-------- -------- -------- -------- -------- -------- --------
Total Revenues $173,498 $176,481 $182,303 $180,410 $176,586 $195,922 $178,913
Expenses
Operations and maintenance $4,759 $3,385 $7,447 $8,284 $3,658 $3,514 $6,869
Water costs and easement fee 1,783 1,815 1,848 1,880 1,914 1,947 1,982
Insurance 905 929 954 980 1,006 1,034 1,062
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 875 876 878 879 881 882 884
Management fees 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 564 575 585 598 617 588 605
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $12,667 $11,464 $15,700 $16,718 $12,282 $12,287 $15,844
Total fuel cost 89,543 92,138 95,166 95,214 94,098 102,989 106,433
-------- -------- -------- -------- -------- -------- --------
Total expenses $102,210 $103,603 $110,866 $111,932 $106,380 $115,275 $122,277
Operating Cash Flow $71,288 $72,878 $71,437 $68,478 $70,206 $80,647 $56,636
Combined Operating Results
Total Revenues $373,244 $386,774 $399,641 $390,212 $416,979 $438,402 $414,969
Non-fuel operating expenses 27,859 29,197 35,629 32,816 33,480 28,481 33,670
Total fuel cost 209,279 215,467 221,189 218,433 227,129 236,395 245,997
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $136,106 $142,109 $142,823 $138,962 $156,370 $173,526 $135,302
Change in Working Capital 2,392 2,214 2,071 (1,661) 4,543 3,571 (4,698)
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $133,714 $139,895 $140,752 $140,623 $151,827 $169,955 $140,000
Subordinated Management Fee 1,994 2,048 2,103 2,160 2,219 2,278 2,342
Project Securities
Principal 45,349 52,641 54,021 51,801 54,616 65,223 0
Interest 29,880 25,484 20,545 15,504 10,374 4,779 0
Project Security Debt Service Coverage
Project Security debt service coverage* 1.80x 1.82x 1.92x 2.12x 2.37x 2.46x
Distributions to NE LP $58,486 $61,771 $66,185 $73,318 $86,837 $99,952 $140,000
The Bonds
Principal 8,800 13,200 22,000 22,000 26,400 35,200 66,000
Interest 15,293 14,502 13,271 11,514 9,668 7,383 3,955
Debt Service Coverages
Bond debt service coverage 2.43x 2.23x 1.88x 2.19x 2.41x 2.35x 2.00x
Consolidated coverage 1.35x 1.32x 1.28x 1.39x 1.50x 1.51x 2.00x
*The numerator of the Project Security Debt Service Coverage Ratio is calculated
before payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projects should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-127
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case D: Heat Rates Increased 10%
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.80% 2.80% 2.80% 2.80% 2.80% 2.70% 2.70%
#6 fuel oil, 2.2% S ($/MMBtu) $2.74 $2.77 $2.81 $2.83 $2.86 $2.89 $2.92
#2 fuel oil ($/MMBtu) 4.42 4.51 4.61 4.67 4.73 4.79 4.85
Nominal Spot Gas Price Escalation 4.37% 4.35% 4.33% 3.80% 3.79% 3.68% 3.67%
Spot gas ($/MMBtu) 2.10 2.19 2.28 2.37 2.46 2.55 2.65
NEA Operational Factors
Net GWh generated 2,443 2,534 2,583 2,526 2,338 2,570 2,472
Net capacity (MW) 290 301 304 301 299 305 303
Equivalent availability factor 96.15% 96.15% 97.15% 95.65% 89.15% 96.15% 93.15%
Heat rate (Btu/kWh) 9,112 9,172 9,097 9,157 9,218 9,051 9,112
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Commonwealth I 6.54 6.53 6.55 5.28 5.12 5.53 5.52
Commonwealth II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Montaup 6.50 6.50 6.50 3.11 3.35 3.54 3.76
Merchant Sales 0.00 2.88 2.72 2.94 3.20 3.48 3.80
---- ----- ---- ----- ----- ---- ----
Average all-in rate 6.66 6.71 6.86 6.72 6.99 7.22 7.54
Electricity Sales (GWh)
Boston Edison I 1,133 1,133 1,145 1,127 1,051 1,133 1,098
Boston Edison II 705 705 712 701 654 705 683
Commonwealth I 208 208 211 207 193 208 202
Commonwealth II 175 175 177 174 162 175 170
Montaup 208 208 211 207 193 208 202
Merchant Sales 0 94 117 98 75 129 108
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.21 $4.30 $4.33 $4.45 $4.59 $4.82 $4.83
Annual Volume (BBtu/yr) 22,457 22,607 23,600 23,843 23,483 21,940 23,609
NJEA Operational Factors
Net GWh generated 2,071 2,361 2,344 2,307 2,216 2,101 2,320
Net capacity (MW) 252 287 285 288 286 284 289
Equivalent availability factor 93.82% 93.82% 93.82% 91.54% 88.54% 84.54% 91.54%
Heat rate (Btu/kWh) 9,963 9,307 9,432 9,354 9,416 9,479 9,307
Electricity Sales Rates (cents/kWh)
JCP&L 6.90 7.05 7.19 7.38 7.56 7.78 7.82
Merchant Sales 0.00 2.81 2.71 2.90 3.09 3.29 3.50
---- ----- ---- ----- ----- ---- -----
Average all-in rate 6.90 6.51 6.65 6.81 7.02 7.26 7.25
Electricity Sales (GWh)
JCP&L 2,071 2,071 2,071 2,021 1,955 1,866 2,021
Merchant Sales 0 290 273 287 262 235 299
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 1,013
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $3.32 $3.41 $3.53 $3.67 $3.82 $3.97 $4.04
Annual Volume (BBtu/yr) 20,636 21,975 22,110 21,597 20,895 19,962 21,605
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-128
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case D: Heat Rates Increased 10%
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.70% 2.70% 2.70% 2.70% 2.70% 2.70% 2.80%
#6 fuel oil, 2.2% S ($/MMBtu) $2.95 $2.98 $3.01 $3.04 $3.07 $3.10 $3.09
#2 fuel oil ($/MMBtu) 4.92 4.94 4.96 4.99 5.01 5.03 5.01
Nominal Spot Gas Price Escalation 3.66% 3.18% 3.18% 3.17% 2.70% 3.17% 3.74%
Spot gas ($/MMBtu) 2.74 2.83 2.92 3.01 3.09 3.19 3.31
NEA Operational Factors
Net GWh generated 2,521 2,556 2,526 2,338 2,570 2,472 2,521
Net capacity (MW) 301 304 301 299 305 303 301
Equivalent availability factor 95.65% 96.15% 95.65% 89.15% 96.15% 93.15% 95.65%
Heat rate (Btu/kWh) 9,172 9,097 9,157 9,218 9,051 9,112 9,172
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Commonwealth I 5.74 5.88 5.99 5.84 6.27 6.28 6.47
Commonwealth II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Montaup 3.97 4.07 4.17 4.27 4.42 4.58 4.66
Merchant Sales 4.13 4.42 4.75 5.11 5.54 5.99 6.19
---- ---- ---- ---- ---- ---- ----
Average all-in rate 7.89 8.19 8.57 8.95 9.32 9.78 9.33
Electricity Sales (GWh)
Boston Edison I 1,127 1,133 1,127 1,051 1,133 1,098 1,127
Boston Edison II 701 705 701 654 705 683 498
Commonwealth I 207 208 207 193 208 202 207
Commonwealth II 174 175 174 162 175 170 174
Montaup 207 208 207 193 208 202 207
Merchant Sales 93 116 98 75 129 108 298
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $5.01 $5.10 $5.22 $5.37 $5.62 $5.63 $5.83
Annual Volume (BBtu/yr) 22,894 23,482 23,606 23,483 21,940 23,609 22,894
NJEA Operational Factors
Net GWh generated 2,291 2,275 2,307 2,216 2,101 2,320 2,311
Net capacity (MW) 287 285 288 286 284 289 290
Equivalent availability factor 91.04% 91.04% 91.54% 88.54% 84.54% 91.54% 91.04%
Heat rate (Btu/kWh) 9,369 9,432 9,354 9,416 9,479 9,307 9,369
Electricity Sales Rates (cents/kWh)
JCP&L 7.96 8.10 8.25 8.42 8.63 8.69 8.88
Merchant Sales 3.73 4.06 4.41 4.81 5.26 5.78 5.95
---- ---- ---- ---- ---- ---- ----
Average all-in rate 7.43 7.62 7.75 7.98 8.24 8.30 7.57
Electricity Sales (GWh)
JCP&L 2,010 2,010 2,021 1,955 1,866 2,021 1,279
Merchant Sales 281 265 287 262 235 299 1,055
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 633
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.17 $4.29 $4.41 $4.56 $4.71 $4.77 $4.91
Annual Volume (BBtu/yr) 21,479 21,469 21,597 20,895 19,962 21,605 21,671
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-129
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case E: No Merchant Sales
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
-------- -------- -------- -------- -------- -------- --------
NEA Operating Results
Revenues
Boston Edison I $73,649 $73,649 $74,415 $73,266 $68,288 $73,649 $71,351
Boston Edison II 48,928 52,665 57,202 60,526 60,597 70,290 73,220
Commonwealth I 13,635 13,607 13,805 10,954 9,905 11,523 11,144
Commonwealth II 12,153 13,081 14,207 15,033 15,051 17,458 18,186
Montaup 13,550 13,550 13,691 6,453 6,476 7,385 7,588
Merchant Sales 0 0 0 0 0 0 0
Steam 1,256 1,153 1,099 1,051 729 1,137 997
Interest Incomes 404 404 481 552 479 518 541
-------- -------- -------- -------- -------- -------- --------
Total Revenues $163,576 $168,110 $174,901 $167,836 $161,524 $181,961 $183,026
Expenses
Operations and maintenance $8,677 $8,859 $12,635 $10,089 $3,122 $7,987 $4,264
Water costs and easement fee 304 317 331 495 883 904 925
Insurance 887 912 937 964 991 1,017 1,045
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 3,601 3,712 3,824 3,936 4,049 4,154 4,259
Management fee 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Peak Service Loss/(Savings) (4,158) (991) (1,011) (575) (753) (941) (1,133)
Other 1,039 1,062 1,076 1,036 2,190 2,413 2,309
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $13,476 $17,084 $21,096 $19,341 $13,974 $19,121 $15,350
Total fuel cost 91,654 93,846 96,726 98,750 97,386 103,558 104,558
-------- -------- -------- -------- -------- -------- --------
Total expenses $105,130 $110,930 $117,822 $118,091 $111,359 $122,679 $119,907
Operating Cash Flow $58,445 $57,180 $57,079 $49,745 $50,165 $59,282 $63,119
NJEA Operating Results
Revenues
JCP&L $142,607 $145,606 $148,580 $148,879 $147,531 $144,865 $157,667
Merchant Sales 0 0 0 0 0 0 0
Steam 2,635 2,672 2,709 2,747 2,785 2,823 2,861
Interest income 284 284 306 389 476 396 378
-------- -------- -------- -------- -------- -------- --------
Total Revenues $145,526 $148,562 $151,595 $152,014 $150,792 $148,083 $160,906
Expenses
Operations and maintenance $9,130 $9,336 $10,447 $11,539 $7,377 $3,412 $6,780
Water costs and easement fee 800 821 842 1,094 1,687 1,719 1,751
Insurance 748 769 790 812 835 858 881
G&A and Professional fees 650 668 687 706 726 746 766
Property tax 866 867 868 870 871 872 874
Management fees 2,026 2,083 2,141 2,201 2,263 2,324 2,387
Fuel management fee 450 463 476 489 503 516 530
Gas Hedge & Park Service Loss/(Savings) 0 0 0 0 0 0 0
Other 420 431 437 463 512 527 548
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expenses $15,090 $15,438 $16,688 $18,174 $14,774 $10,973 $14,516
Total fuel cost 62,837 64,906 68,114 68,649 69,522 69,681 75,183
-------- -------- -------- -------- -------- -------- --------
Total expenses $77,927 $80,344 $84,802 $86,823 $84,296 $80,654 $89,699
Operating Cash Flow $67,598 $68,218 $66,793 $65,191 $66,496 $67,429 $71,207
Combined Operating Results
Total Revenues $309,101 $316,672 $326,496 $319,850 $312,316 $330,044 $343,932
Non-fuel operating expenses 28,566 32,522 37,784 37,515 28,748 30,093 29,866
Total fuel cost 154,491 158,752 164,839 167,399 166,908 173,240 179,741
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $126,044 $125,398 $123,872 $114,936 $116,661 $126,711 $134,326
Change in Working Capital 10,097 1,260 1,465 (1,293) (1,110) 2,995 2,279
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $115,947 $124,138 $122,408 $116,230 $117,771 $123,716 $132,047
Subordinated Management Fee $1,649 $1,695 $1,742 $1,791 $1,841 $1,891 $1,942
Project Securities
Principal 21,563 23,511 26,333 20,160 22,688 23,818 28,564
Interest 45,327 43,468 41,426 39,300 37,396 35,264 32,933
Project Security Debt Service Coverage
Project Security debt service coverage* 1.76x 1.88x 1.83x 1.98x 1.99x 2.13x 2.18x
Minimum Project Security debt service coverage 1.76x
Average Project Security debt service coverage 2.05x
Distributions to NE LP $49,058 $57,160 $54,648 $56,770 $57,687 $64,634 $70,550
The Bonds
Principal 0 0 0 0 8,800 8,800 8,800
Interest 15,381 17,578 17,578 17,578 17,402 16,699 15,996
Debt Service Coverages
Bond debt service coverage 3.19x 3.25x 3.11x 3.23x 2.20x 2.53x 2.85x
Minimum Bond debt service coverage 1.37x
Average Bond debt service coverage 2.59x
Consolidated coverage 1.41x 1.47x 1.43x 1.51x 1.36x 1.46x 1.53x
Minimum consolidated debt service coverage 1.34x
Average consolidated coverage 1.45x
*The numerator of the Project Security Debt Service Coverage Ratio is
calculated before payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-130
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Base Case E. No Merchant Sales
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
-------- -------- -------- -------- -------- -------- --------
NEA Operating Results
Revenues
Boston Edison I $73,266 $73,649 $73,266 $68,288 $73,649 $71,351 $73,266
Boston Edison II 80,795 87,351 93,350 93,543 108,502 112,971 88,537
Commonwealth I 11,906 12,267 12,421 11,288 13,078 12,684 13,423
Commonwealth II 20,068 21,696 23,186 23,234 26,949 28,059 30,972
Montaup 8,238 8,495 8,655 8,249 9,204 9,256 9,663
Merchant Sales 0 0 0 0 0 0 0
Steam 1,170 1,232 1,234 855 1,334 1,170 1,374
Interest Income 439 480 578 514 519 514 404
-------- -------- -------- -------- -------- -------- --------
Total Revenues $195,884 $205,171 $212,690 $205,971 $233,236 $236,005 $217,640
Expenses
Operations and maintenance $3,833 $6,174 $8,149 $3,646 $8,516 $3,601 $5,085
Water costs and easement fee 946 967 988 1,009 1,030 1,052 1,074
Insurance 1,073 1,102 1,132 1,162 1,194 1,226 1,260
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 4,362 4,464 4,564 4,661 4,756 4,846 4,943
Management fees 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) (1,155) (1,185) (1,215) (622) (886) (1,099) (1,325)
Other 2,352 2,327 2,322 2,145 2,381 2,248 2,347
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $15,192 $17,733 $19,928 $16,098 $21,198 $16,195 $17,826
Total fuel cost 109,607 112,259 115,195 113,241 120,665 121,557 127,608
-------- -------- -------- -------- -------- -------- --------
Total expenses $124,799 $129,992 $135,124 $129,339 $141,863 $137,752 $145,434
Operating Cash Flow $71,085 $75,179 $77,567 $76,632 $91,373 $98,253 $72,206
NJEA Operating Results
Revenues
JCP&L $159,702 $162,480 $166,309 $164,315 $160,776 $175,260 $113,850
Merchant Sales 0 0 0 0 0 0 0
Steam 2,900 2,939 2,979 3,019 3,060 3,101 1,965
Interest Income 406 323 382 493 400 284 284
-------- -------- -------- -------- -------- -------- --------
Total Revenues $163,008 $165,741 $169,669 $167,826 $164,235 $178,645 $116,099
Expenses
Operations and maintenance $4,759 $3,385 $7,447 $8,284 $3,658 $3,514 $6,869
Water costs and easement fee 1,783 1,815 1,848 1,880 1,914 1,947 1,982
Insurance 905 929 954 980 1,006 1,034 1,062
G&A and Professional fees 786 808 829 852 875 898 924
Property tax 875 876 878 879 881 882 884
Management fee 2,451 2,517 2,585 2,655 2,727 2,800 2,879
Fuel management fee 544 559 574 590 606 622 639
Gas Hedge & Peak Service Loss/(Savings) 0 0 0 0 0 0 0
Other 564 575 585 598 617 588 605
-------- -------- -------- -------- -------- -------- --------
Non-fuel operating expense $12,667 $11,464 $15,700 $16,718 $12,282 $12,287 $15,844
Total fuel cost 77,719 80,506 82,499 83,102 82,708 88,877 91,678
-------- -------- -------- -------- -------- -------- --------
Total expenses $90,386 $91,971 $98,199 $99,820 $94,991 $101,164 $107,522
Operating Cash Flow $72,621 $73,771 $71,470 $68,006 $69,245 $77,481 $8,577
Combined Operating Results
Total Revenues $358,891 $370,913 $382,360 $373,797 $397,471 $414,649 $333,739
Non-fuel operating expenses 27,859 29,197 35,629 32,816 33,480 28,481 33,670
Total fuel cost 187,326 192,766 197,694 196,343 203,373 210,435 219,286
-------- -------- -------- -------- -------- -------- --------
Operating Cash Flow $143,706 $148,949 $149,037 $144,638 $160,618 $175,733 $80,784
Change in Working Capital 2,432 1,968 1,843 (1,560) 4,044 2,883 (15,217)
-------- -------- -------- -------- -------- -------- --------
Cash Available for Debt Service $141,274 $146,981 $147,194 $146,198 $156,574 $172,851 $96,001
Subordinated Management Fee 1,994 2,048 2,103 2,160 2,219 2,278 2,342
Project Securities
Principal 45,349 52,641 54,021 51,801 54,616 65,223 0
Interest 29,880 25,484 20,545 15,504 10,374 4,779 0
Project Security Debt Service Coverage
Project Security debt service coverage* 1.90x 1.91x 2.00x 2.20x 2.44x 2.50x
Distribution to NE LP $66,046 $68,857 $72,627 $78,893 $91,584 $102,848 $96,001
The Bonds
Principal 8,800 13,200 22,000 22,000 26,400 35,200 66,000
Interest 15,293 14,502 13,271 11,514 9,668 7,383 3,955
Debt Service Coverages
Bond debt service coverage 2.74x 2.49x 2.06x 2.35x 2.54x 2.42x 1.37x
Consolidated coverage 1.42x 1.39x 1.34x 1.45x 1.55x 1.54x 1.37x
*The numerator of the Project Security Debt Service Coverage Ratio is calculated
before payment of a subordinated management fee.
Amounts may not add due to rounding.
These financial projects should be read in conjunction with the attached
Summary of Underlying Assumptions.
B-131
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case E: No Merchant Sales
(data in $000's unless noted)
1998 1999 2000 2001 2002 2003 2004
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.80% 2.80% 2.80% 2.80% 2.80% 2.70% 2.70%
#6 fuel oil, 2.2% S ($/MMBtu) $2.74 $2.77 $2.81 $2.83 $2.86 $2.89 $2.92
#2 fuel oil ($/MMBtu) 4.42 4.51 4.61 4.67 4.73 4.79 4.85
Nominal Spot Gas Price Escalation 4.37% 4.35% 4.33% 3.80% 3.79% 3.68% 3.67%
Spot gas ($/MMBtu) 2.10 2.19 2.28 2.37 2.46 2.55 2.65
NEA Operational Factors
Net GWh generated 2,443 2,443 2,468 2,430 2,265 2,443 2,366
Net capacity (MW) 290 290 290 290 290 290 290
Equivalent availability factor 96.15% 96.15% 97.15% 95.65% 89.15% 96.15% 93.15%
Heat rate (Btu/kWh) 8,283 8,399 8,270 8,325 8,380 8,229 8,283
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Commonwealth I 6.54 6.63 6.55 5.28 5.12 5.53 5.52
Commonwealth II 6.94 7.47 8.03 8.63 9.27 9.97 10.72
Montaup 6.50 6.50 6.50 3.11 3.35 3.54 3.76
Merchant Sales 0.00 0.00 0.00 0.00 0.00 0.00 0.00
------ ------ ------ ------ ------ ------ ------
Average all-in rate 6.66 6.85 7.05 6.87 7.11 7.41 7.70
Electricity Sales (GWh)
Boston Edison I 1,133 1,133 1,145 1,127 1,051 1,133 1,098
Boston Edison II 705 705 712 701 654 705 683
Commonwealth I 208 208 211 207 193 208 202
Commonwealth II 175 175 177 174 162 175 170
Montaup 208 208 211 207 193 208 202
Merchant Sales 0 0 0 0 0 0 0
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.37 $4.46 $4.54 $4.67 $4.81 $5.04 $5.07
Annual Volume (BBtu/yr) 20,416 20,552 20,689 20,724 20,551 19,332 20,416
NJEA Operational Factors
Net GWh generated 2,071 2,071 2,071 2,021 1,955 1,866 2,021
Net capacity (MW) 252 252 252 252 252 252 252
Equivalent availability factor 93.82% 93.82% 93.82% 91.54% 88.54% 84.54% 91.54%
Heat rate (Btu/kWh) 9,057 9,057 9,178 9,102 9,163 9,224 9,057
Electricity Sales Rates (cents/kWh)
JCP&L 6.90 7.05 7.19 7.38 7.56 7.78 7.82
Merchant Sales 0.00 0.00 0.00 0.00 0.00 0.00 0.00
------ ------ ------ ------ ------ ------ ------
Average all-in rate 6.90 7.05 7.19 7.38 7.56 7.78 7.82
Electricity Sales (GWh)
JCP&L 2,071 2,071 2,071 2,021 1,955 1,866 2,021
Merchant Sales 0 0 0 0 0 0 0
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 1,013
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $3.35 $3.46 $3.58 $3.73 $3.88 $4.04 $4.11
Annual Volume (BBtu/yr) 18,760 18,760 19,011 18,405 17,933 17,256 18,313
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-132
ESI Tractebel Acquisition Corp. -- Projected Operating Results for NEA and NJEA
Sensitivity Case E: No Merchant Sales
(data in $000's unless noted)
2005 2006 2007 2008 2009 2010 2011
---- ---- ---- ---- ---- ---- ----
Commodity Prices
Inflation 2.70% 2.70% 2.70% 2.70% 2.70% 2.70% 2.80%
#6 fuel oil, 2.2% S ($/MMBtu) $2.95 $2.98 $3.01 $3.04 $3.07 $3.10 $3.09
#2 fuel oil ($/MMBtu) 4.92 4.94 4.96 4.99 5.01 5.03 5.01
Nominal Spot Gas Price Escalation 3.66% 3.18% 3.18% 3.17% 2.70% 3.17% 3.74%
Spot gas ($/MMBtu) 2.74 2.83 2.92 3.01 3.09 3.19 3.31
NEA Operational Factors
Net GWh generated 2,430 2,443 2,430 2,265 2,443 2,366 2,430
Net capacity (MW) 290 290 290 290 290 290 290
Equivalent availability factor 95.65% 96.15% 95.65% 89.15% 96.15% 93.15% 95.65%
Heat rate (Btu/kWh) 8,339 8,270 8,325 8,380 8,229 8,283 8,339
Electricity Sales Rates (cents/kWh)
Boston Edison I 6.50 6.50 6.50 6.50 6.50 6.50 6.50
Boston Edison II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Commonwealth I 5.74 5.88 5.99 5.84 6.27 6.28 6.47
Commonwealth II 11.52 12.39 13.31 14.31 15.39 16.54 17.78
Montaup 3.97 4.07 4.17 4.27 4.42 4.58 4.66
Merchant Sales 0.00 0.00 0.00 0.00 0.00 0.00 0.00
---- ---- ---- ---- ---- ---- ----
Average all-in rate 8.03 8.37 8.72 9.07 9.51 9.94 8.92
Electricity Sales (GWh)
Boston Edison I 1,127 1,133 1,127 1,051 1,133 1,098 1,127
Boston Edison II 701 705 701 654 705 683 498
Commonwealth I 207 208 207 193 208 202 207
Commonwealth II 174 175 174 162 175 170 174
Montaup 207 208 207 193 208 202 207
Merchant Sales 0 0 0 0 0 0 0
Steam volume (MMlbs) 568 568 568 568 568 568 568
CO2 output (ton/day) 330 330 330 330 330 330 330
Delivered Natural Gas - Average all-in
cost ($MMBtu) $5.25 $5.32 $5.47 $5.61 $5.86 $5.91 $6.10
Annual Volume (BBtu/yr) 19,933 20,585 20,518 20,551 19,332 20,416 19,933
NJEA Operational Factors
Net GWh generated 2,010 2,010 2,021 1,955 1,866 2,021 2,010
Net capacity (MW) 252 252 252 252 252 252 252
Equivalent availability factor 91.04% 91.04% 91.54% 88.54% 84.54% 91.54% 91.04%
Heat rate (Btu/kWh) 9,117 9,178 9,102 9,163 9,224 9,057 9,117
Electricity Sales Rates (cents/kWh)
JCP&L 7.96 8.10 8.25 8.42 8.63 8.69 8.88
Merchant Sales 0.00 0.00 0.00 0.00 0.00 0.00 0.00
---- ---- ---- ---- ---- ---- ----
Average all-in rate 7.96 8.10 8.25 8.42 8.63 8.69 8.88
Electricity Sales (GWh)
JCP&L 2,010 2,010 2,021 1,955 1,866 2,021 1,279
Merchant Sales 0 0 0 0 0 0 0
Steam volume (MMlbs) 1,013 1,013 1,013 1,013 1,013 1,013 633
Delivered Natural Gas - Average all-in
cost ($/MMBtu) $4.24 $4.36 $4.48 $4.63 $4.79 $4.85 $5.00
Annual Volume (BBtu/yr) 18,337 18,459 18,405 17,933 17,256 18,313 18,337
These financial projections should be read in conjunction with the
attached Summary of Underlying Assumptions.
B-133
APPENDIX C
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NORTHEAST ENERGY ASSOCIATES AND
NORTH JERSEY ENERGY ASSOCIATES COGENERATION PROJECTS
FUEL CONSULTANT'S REPORT
FINAL REPORT
By:
Benjamin Schlesinger and Associates, Inc.
The Bethesda Gateway
7201 Wisconsin Avenue, Suite 740
Bethesda, MD 20814
February 12, 1998
- --------------------------------------------------------------------------------
Legal Notice: This report is meant to be read as a whole. In preparing this
report, BSA relied on information and statements obtained from various sources,
including ESI Energy, Tractebel Power and other private and governmental
entities. BSA makes no assurances as to the accuracy of any such information and
statements or any conclusions based thereon. Neither BSA nor any BSA employee:
(a) makes any warranty, expressed or implied, with respect to the use of any
information, statements, conclusions, or methods disclosed in this report; or
(b) assumes any liability with respect to the use of any information,
statements, conclusions, or methods disclosed in this report.
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TABLE OF CONTENTS
I. INTRODUCTION......................................................... 1
II. SUMMARY AND CONCLUSIONS.............................................. 4
III. NEA'S AND NJEA'S FUEL SUPPLY AND DELIVERY ARRANGEMENTS............... 7
A. Firm Gas Supply Arrangements...................................... 7
1. ProGas:.................................................... 7
2. PSE&G:..................................................... 10
B. Gas Storage Arrangements.......................................... 11
C. Firm Gas Transportation Arrangements.............................. 12
1. CNG........................................................ 12
2. Transco.................................................... 12
3. TETCO...................................................... 13
4. Algonquin (NEA only)....................................... 13
5. PSE&G (NJEA only).......................................... 14
D. Peak Shaving Arrangements......................................... 14
1. NEA........................................................ 14
2. NJEA....................................................... 14
IV. ANALYSIS OF PRO FORMA GAS COSTS TO NEA/NJEA.......................... 16
V. ASSESSMENT OF NEA/NJEA'S NON-CONTRACT GAS PROCUREMENT................ 18
VI. ANALYSIS OF POTENTIAL FUEL ISSUES.................................... 20
A. ProGas's lay-off gas responsibilities............................. 20
B. Continuation of interstate pipeline services beyond contract
expiration........................................................ 20
C. Economic Risk of PSE&G Contract Termination in 2011............... 22
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LIST OF EXHIBITS
Exhibit 1 - NEA: Schematic of Firm Daily Contract Capacities................. 2
Exhibit 2 - NJEA: Schematic of Firm Daily Contract Capacities................ 3
Exhibit 3 - Summary of NEA's and NJEA's Gas Supply and
Transportation Portfolio......................................... 4
Exhibit 4 - NEA and NJEA Gas Supply Sources by Price Category: 10/95-9/97.... 5
Exhibit 5 - TETCO Receipt/Delivery Points & MDQs............................. 13
Exhibit 6 - Comparison of Henry Hub Gas Price Forecasts...................... 18
LIST OF APPENDICES
Appendix A: Power Contract and Gas Price Comparisons
Appendix B: Catalogue of Principal NEA/NJEA Fuel Contracts
Appendix C: Analysis of Transco's and CNG's Part 284 and 7(c) Rates
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NORTHEAST ENERGY ASSOCIATES AND
NORTH JERSEY ENERGY ASSOCIATES COGENERATION PROJECTS
("NEA" and "NJEA") FUEL CONSULTANT'S REPORT
I. INTRODUCTION
NEA and NJEA constructed and, since 1991, have operated two 300 MW,
gas-fired, combined cycle cogeneration facilities located respectively in
Bellingham, MA and Sayreville, NJ. NECO, a carbon dioxide manufacturer, serves
as the steam host for the NEA facility while Hercules, Inc., a chemical
manufacturer, is the steam host for NJEA. NEA has contracted to sell 290 MW of
its electric generating capacity to Boston Edison Company, Commonwealth Electric
Company, and Montaup Electric Company while NJEA sells approximately 252 MW of
its generating capacity to Jersey Central Power and Light Company.
In light of their anticipated and continuing high load factor of
operations (approximately 94%), NEA and NJEA have adopted a fuel strategy that
involves long-term, firm gas supply and transportation arrangements. Each has
entered into long-term gas purchase contracts with ProGas, Ltd. ("ProGas"), a
major Canadian gas supplier. In addition, NJEA has entered into a long-term gas
purchase and delivery agreement with Public Service Electric and Gas Company
("PSE&G") of New Jersey. Both projects also have long-term gas storage contracts
with CNG Transmission Corporation ("CNG"). In addition, both projects have
executed long-term, firm transportation (FT) service agreements with CNG,
Transcontinental Gas Pipe Line Corporation ("Transco," a subsidiary of
Williams), and Texas Eastern Transmission Company ("TETCO," a subsidiary of Duke
Energy Company). NEA also has a long-term FT contract with Algonquin Gas
Transmission Company ("Algonquin," also a subsidiary of Duke Energy Company).
As illustrated in Exhibits 1 and 2, respectively for NEA and NJEA, this
set of long-term agreements enables the projects to secure approximately 80% of
their combined overall natural gas requirements on a firm basis if they operated
100% of the time./1 According to plan, NEA and NJEA satisfy the remaining 20% of
their gas requirements through spot purchases delivered both to storage and
directly to the plants, primarily in the non-winter months of April through
October.
Subsidiaries of ESI Energy, Inc. and Tractebel Power, Inc. (the
"Owners"), as owners of Northeast Energy, LP ("NE LP"), are involved in a
capital market financing in connection with the acquisition of interest in the
partnerships that own the NEA and NJEA projects, with closing expected to take
place in February 1998. The bonds, which will mature by December 30, 2011, are
expected to have an average life of approximately 11 years.
In conjunction with the proposed financing, Benjamin Schlesinger and
Associates, Inc. (BSA) was retained to prepare the following fuel due diligence
report. BSA is a natural gas consulting firm based in Bethesda, MD, specializing
in all strategic aspects of the natural gas
- -----------------
1 Actual, as opposed to contract, firm gas supplies to the projects equaled
approximately 85% over the past two years.
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FINAL REPORT
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industry. Since 1984, BSA has prepared fuel supply audits, fuel plans and
similar analyses for 94 cogenerators and independent power projects in the U.S.,
Canada, Mexico, and Colombia. BSA's clients have included all major banks and
project developers, as well as investors, governments, fuel suppliers, and
others. In particular, BSA's previous independent opinion reports concerning NEA
and NJEA include fuel due diligence reports in 1990 and 1994 in conjunction with
construction financing and subsequent refinancing, respectively.
The purpose of this report is to provide a timely due diligence analysis
and evaluation of the fuel supply, transportation and delivery arrangements to
serve NEA and NJEA.
Exhibit 1 - NEA: Schematic of Firm Daily Contract Capacities
[GRAPHIC OMITTED]
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FINAL REPORT
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Exhibit 2 - NJEA: Schematic of Firm Daily Contract Capacities
[GRAPHIC OMITTED]
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II. SUMMARY AND CONCLUSIONS
Overall Fuel Supply Plan: NEA and NJEA have arranged a portfolio of gas
supply, transportation and storage arrangements, summarized below in Exhibit
3, that has succeeded in matching the economic terms of their power sales
agreements, and has fully met their physical operating fuel requirements.
This same set of arrangements has been in place with minor modification
since the projects' initial operation in September 1991. Under this set of
long-term gas supply, transportation and storage arrangements, NEA and NJEA
have secured delivery of their contract gas supplies to the plants on a
highly reliable basis, and neither has ever had to shut down due to lack of
fuel availability since start-up.
Exhibit 3 - Summary of NEA's and NJEA's Principal Gas Supply and
Transportation Portfolio
Gas Supplier Plant Volume Supply Source
------------ ----- ------ -------------
ProGas NEA 48,817 Dth/day Alberta
NJEA 22,019 Dth/day Alberta
PSE&G NJEA 25,000 Dth/day PSE&G system supply
CNG Storage NEA 14,000 Dth/day Various (On withdrawal days)+
NJEA 10,508 Dth/day Various (On withdrawal days)+
Spot Volumes NEA 14,000 Dth/day Various (On non-withdrawal days)
NJEA 10,508 Dth/day Various (On non-withdrawal days)
Firm Transporter Plant Volume From To
---------------- ----- ------ ---- --
CNG NEA 48,817 Dth/day Niagara, NY (ProGas) Leidy, PA
NJEA 22,019 Dth/day Niagara, NY (ProGas) Leidy, PA
Transco NEA 48,800 Mcf/day Leidy, PA Centreville, NJ
NJEA 22,019 Mcf/day Leidy, PA Centreville, NJ
TETCO NEA 14,000 Dth/day CNG Storage Centreville, NJ*
NJEA 10,508 Dth/day CNG Storage Sayreville, NJ*
Algonquin NEA 62,000 Dth/day Centreville, NJ Plant
PSE&G NJEA 32,527 Dth/day Sayreville, NJ Plant
+ Storage injection spot volumes are not indicated in this table.
* This route is representative; the contract permits certain amount of gas
flows in the opposite direction as well.
Linkage of Fuel Costs and Power Revenues: NJEA's power revenues are based on
the delivered cost of gas to New Jersey electric utilities as reported on
Federal Energy Regulatory Commission (FERC) Form 423. NJEA's gas supply
prices are tied to its power revenues (a) directly in its ProGas contract,
which escalates with Form 423 prices in New Jersey, and (b) indirectly
through the commodity cost of PSE&G sales service, which correlates highly
(91.8%) with Form 423 prices in New Jersey. NEA's power revenues are based
on a mix of fixed and avoided cost pricing. NEA's ProGas supplies are priced
to match power revenues, while the remainder of its gas purchases (NJEA's
ProGas supplies
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FINAL REPORT
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delivered to NEA and spot gas) also match power revenues. We conclude that,
taken together, NEA and NJEA's delivered fuel costs and power revenues are
naturally hedged; i.e., the degree to which NJEA's and NEA's gas purchases
are tied to their energy payments equals approximately 95% and 91%,
respectively (see Exhibit 4 below and Appendix A):
Exhibit 4 - NEA and NJEA Gas Supply Sources by Price Category: 10/95-9/97
[GRAPHIC OMITTED]
Projected Cost of Gas: In our opinion, the assumptions contained in NE LP's
pro forma financial model for the NEA and NJEA projects, as they relate to
the current and projected price of natural gas, are reasonable. As a
sensitivity analysis, BSA requested the Owners to modify the projections of
gas prices contained in NE LP's pro forma model. The resulting financial
projections indicated that expected cash flows for NE LP are robust enough
to withstand alternative foreseeable fuel price scenarios.
Gas Supply and Transportation Arrangements: NEA's and NJEA's contracted gas
supply, storage and transportation services are adequate to satisfy 80% of
the plants' daily fuel requirements at full operations. NEA and NJEA's
amended firm gas supply contracts with ProGas extend to 2013 and NJEA's
supply contract with PSE&G extends to 2011. The projects' transportation
agreements with CNG, Transco, Tetco and Algonquin extend to 2011, 2006, 2012
and 2016, respectively. We considered and resolved in this report three
issues associated with NEA's and NJEA's gas supply and transportation
arrangements:
o While NEA and NJEA will continue to rely on non-contract gas
supplies for approximately 20% of their combined daily fuel
requirements during most of the next 15 years,/2 we conclude that
NEA and NJEA are well positioned to continue to obtain competitive
and reliable spot supplies because of (a) the significant liquidity
of spot gas markets as an ongoing feature of the Northeast natural
gas industry, and (b) their individual and combined purchasing
power. Most prudent fuel managers in the U.S.
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2 Virtually all the projects' spot gas is consumed at NEA, as shown in Exhibit
4.
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rely with comfort on spot gas market purchases for a portion of
their gas procurement practices and systems.
o While NEA and NJEA's gas transportation contracts with Transco and
CNG expire on October 31, 2006 and November 1, 2011, respectively,
as federally regulated interstate pipelines, neither can simply
abandon transportation services. Instead, both pipelines are
required to offer NEA and NJEA the right to extend their
transportation contracts on a year-to-year basis upon expiration. In
order to abandon service to NEA and NJEA, Transco or CNG would have
to receive approval from the FERC, and BSA is unaware of any
instance where the FERC has approved a contested abandonment
application. As a worst case, in order to retain firm transportation
(FT) services provided by Transco and CNG beyond their terminations
in 2006 and 2011, respectively, NEA and NJEA might have to pay the
maximum prevailing Part 284 rates after the contracts expire,
instead of their currently lower rates. We project that Transco's
Part 284 rates during the five years from 2006 to 2011 will be 5%
higher than the Transco rates used in NE LP's pro forma model.
Therefore, even if Transco requires both projects to convert to Part
284 service in 2006, their gas transportation rates would not
increase significantly over their projected Section 7(c) rates.
Likewise, we estimate that CNG's Part 284 rate may exceed by
approximately 20% the projects' negotiated Section 7(c) rates during
November and December of 2011, the two months following contract
termination, which could result in an additional expenditure of
approximately $329,000 in 2011. Sensitivity analysis of NE LP's pro
forma financial model indicated these additional expenditures would
not have a material impact on cash flow available to NE LP or on
debt coverages.
o While NJEA's 20-year gas supply and transportation contract with
PSE&G expires on August 12, 2011, we believe that PSE&G will
continue to maintain the capability to provide competitive rates to
customers of NJEA's size, flexibility, and physical access to
alternative suppliers. NJEA pays PSE&G a price equal to PSE&G's
weighted average cost of gas (WACOG) plus an added negotiated rate.
PSE&G's WACOG correlates significantly (96.4% for the past two
years) with spot gas market prices in the New York-New Jersey
region./3 Moreover, we reasonably expect that PSE&G will continue to
provide customers like NJEA with competitively priced gas
transportation services, as they have in the past, because of NJEA's
scale, flexibility and location. Consequently, as documented later
in this report, we foresee no material adverse economic impact upon
NJEA's financial projections associated with the termination of the
PSE&G contract as scheduled in 2011.
In light of the foregoing, we conclude that NEA and NJEA have executed
exceptionally strong fuel supply and transportation strategies, and will be able
to continue meeting all of their gas requirements reliably, and in a way that
will protect bondholders at least over the next 15 years.
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3 PSE&G's WACOG has averaged approximately 3.5% less than spot gas market prices
in the region since 1995.
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III. NEA'S AND NJEA'S FUEL SUPPLY AND DELIVERY ARRANGEMENTS
In this section, we briefly describe NEA's and NJEA's gas purchase and
delivery portfolio, which consists of four basic components: firm supply, firm
transportation, firm storage, and spot gas. We also describe the peak shaving
arrangements for each plant.
A. Firm Gas Supply Arrangements
NEA and NJEA have arranged to buy up to a combined maximum daily
quantity ("MDQ") of 70,836 MMBtu/day of firm gas supply from ProGas. In
addition, NJEA has arranged to buy up to 25,000 MMBtu/day of firm gas supply
from PSE&G (see Part 2 of this section).
1. ProGas:
ProGas is a major Canadian aggregator and marketer of natural gas.
ProGas holds more than 4 trillion cubic feet (Tcf) of proved and probable gas
reserves, approximately twice the amount needed to meet all of its long-term
requirements, including its contract commitment to NEA and NJEA./4
On May 12, 1988, NEA and NJEA each contracted to purchase from ProGas an
MDQ of 30,358 MMBtu/day and on October 28, 1988, both plants increased their
respective MDQs, as permitted under the original contract, by 5,060 MMBtu/day to
35,418 MMBtu/day. On July 2, 1991, NEA and NJEA notified ProGas of their
intention to divert 13,399 MMBtu/day from NJEA to NEA, thereby raising NEA's MDQ
to 48,817 MMBtu/day and decreasing NJEA's MDQ to 22,019 Dth/day. ProGas prices
the gas diverted from NJEA to NEA as per the NJEA contract (see pricing
description in NJEA Price below). Both ProGas contracts, as amended, extend to
November 2013.
ProGas delivers the daily nominations up to the MDQ for NEA and NJEA to
the interconnection of TransCanada Pipelines Ltd. ("TCPL") and CNG at Niagara
Falls, on the international border between the province of Ontario, Canada, and
the State of New York.
In any contract year (November 1 - October 31), NEA and NJEA must take
from ProGas at least 75% of the sum of their respective MDQs of gas in the
contract year. Should NEA and NJEA fail to take this threshold quantity of gas
in any contract year n, then, in the following contract year n+1, they are
obligated to take (i) the threshold quantity for contract year n+1, plus (ii)
the shortfall from contract year n. Take-or-pay requirements under the contracts
are both 75%, which level is well below anticipated operating requirements of
NEA and NJEA. See the section in this report, entitled ANALYSIS OF POTENTIAL
FUEL ISSUES.
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4 Source: John R. Lacey International, Ltd., Gas Reserves and Resources and the
Supply to Meet Requirements of Gas Sales Contracts, prepared for ProGas Limited
and Various Gas Buyers, June 1996.
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NEA Price: ProGas charges a monthly demand charge and a commodity charge
for gas purchased under the NEA contract. The monthly demand charge is
determined as follows:
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Monthly Demand Chargei = Average MDi x Monthly Demand Ratei
where:
i = billing month
The Monthly Demand Ratei is the sum of the following charges in the billing
month:
(a) the monthly demand charge per Mcf on TCPL's system for transporting the gas
to Niagara Falls,
(b) the monthly demand charge per Mcf that NOVA charges ProGas for gathering and
delivering the gas to the Alberta/Saskatchewan border, and
(c) ProGas' monthly demand charge per Mcf approved by the Alberta Petroleum
Marketing Commission.
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The Commodity Charge per MMBtu is calculated as follows:
- --------------------------------------------------------------------------------
Commodity Chargei = Base Pricen - (MHDRi x 12)/365
where:
i = billing month
n = contract year
"MHDR" is the Monthly Heating Demand Rate and is simply the Monthly Demand Rate
per MMBtu payable in the billing month.2
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The initial commodity charge for 1/1/90 was US$ 1.9365 per MMBtu. The
Base Price is determined on January 1 of every year as follows:
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Base Pricen = Base Pricen-1 x [{(Fixed Rate Sales/Total NEA Sales) x Fixed Price
Escalator} + {(Avoided Cost Sales/Total NEA Sales) x (Avoided Cost Sales
Raten/Avoided Cost Sales Raten-1)}]
where:
n = year of calculation
Fixed Rate Sales is the sum of total megawatt power sales that NEA has
contracted for at fixed rates and cannot be less than 100 MW.
Avoided Cost Sales is the sum of total megawatt power sales that NEA has
contracted for on the basis of the avoided cost of the power purchasers and
cannot exceed 150 MW.
Total Sales is the sum of fixed rate sales and avoided cost sales.
Fixed Price Escalator = 1.1478 (1/1/91)
= 1.1364 (1/1/92)
= 1.0750 (1/1/93 onwards)
Avoided Cost Sales Rate is the weighted average unit sales rate (cents/kWh) of
power sold by NEA under avoided cost sales contracts. This rate can never be
less than 6.5 cents/kWh.
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NJEA Price: ProGas charges a monthly demand charge and a commodity
charge for gas purchased under the NJEA contract. The monthly demand charge is
determined as follows:
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Monthly Demand Chargei = Average MDQi x Monthly Demand Ratei
where:
i = billing month
The Monthly Demand Ratei is the sum of the following charges in the billing
month:
(i) the monthly demand charge per Mcf on TCPL's system for transporting
the gas to Niagara Falls,
(ii) the monthly demand charge per Mcf that NOVA charges ProGas for
gathering and delivering the gas to the Alberta/Saskatchewan border,
and
(iii) ProGas' monthly demand charge per Mcf approved by the Alberta Petroleum
Marketing Commission.
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The Commodity Charge per MMBtu is calculated as follows:
- --------------------------------------------------------------------------------
Commodity Chargei = Base Pricen - (MHDRi x 12)/365
where:
i = billing month
n = contract year
"MHDR" is the Monthly Heating Demand Rate and is the Monthly Demand Rate per
MMBtu in the billing month.
- --------------------------------------------------------------------------------
The initial commodity charge for 1/1/90 was US$ 1.9365 per MMBtu. The
Base Price is determined on January 1 of every year as follows:
- --------------------------------------------------------------------------------
Base Pricen = Base Pricen-1 x [NGCn-1/NGCn-2]
where:
n = year of calculation
NGC = cost of natural gas purchased by New Jersey electric
utilities, as reported on FERC Form 423
- --------------------------------------------------------------------------------
Under 1993 amendments to the ProGas contracts, if NEA or NJEA do not
require gas because of a scheduled or unscheduled outage at the plants, ProGas
must use all reasonable efforts to remarket the gas ("layoff" sale). If ProGas
makes layoff sales, NEA or NJEA will be relieved of their purchase obligations
by the amount of the layoff sales and will receive a commensurate credit of the
monthly demand charges, see ANALYSIS OF POTENTIAL FUEL ISSUES.
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2. PSE&G:
PSE&G is a major natural gas utility ($14.7 billion in assets as of
12/31/96) whose franchised service area covers much of northern and central New
Jersey. PSE&G provides firm gas supply service to NJEA for up to 25,000
MMBtu/day until August 12, 2011 (i.e., 20 years after commencement of commercial
operations).
Price: NJEA pays PSE&G a monthly charge comprised of a customer charge,
a commodity charge, a charge for services, and a charge for loss and shrinkage.
The customer charge was $86.00 per month in 1990 and is adjusted annually on
January 1 of every year by the U.S. GNP deflator. The commodity charge is equal
to the weighted average commodity cost of gas received by PSE&G (i.e., the
commodity portion of PSE&G's overall weighted average cost of gas or "WACOG").
The commodity portion of PSE&G's WACOG essentially includes the wellhead price
of gas, all commodity transportation charges (including ACA and GRI surcharges),
and pipeline retainages./5 By definition, it excludes pipeline demand charges.
The per Dth charge for service is calculated as follows:
- --------------------------------------------------------------------------------
Service Charge = $0.30 per Dth in 1990.
After 1990 the Service Charge is adjusted by the weighted average
change in PSE&G's base rates under all rate schedules, as approved by the New
Jersey Board of Public Utilities ("NJBPU"). The adjusted charge will be
effective on the first day of the month immediately following the NJBPU's
approval of the base rate change.
- --------------------------------------------------------------------------------
The charge for loss and shrinkage is 1.5%./6
If over any one-year period extending from November 1 through October
31, the average price payable to PSE&G for sales service is higher than (i) the
average delivered price to NJEA of gas not sold by PSE&G,/7 and (ii) is 15%
greater than the comparable average cost of gas to New Jersey electric
utilities, then NJEA may request renegotiation of pricing by notifying PSE&G
before the following April 30.
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5 "Retainage" or "compression gas" is gas volume that a pipeline retains for
purposes of fueling its compressors; also known as "fuel gas."
6 The retainage charge is usually quoted as a percentage of gas volume at the
inlet. The associated costs are essentially the cost for purchasing the required
volumes to account for retainage and any transportation charges (commodity and
demand) incurred upstream of the relevant pipeline to move the required volumes.
7 Note, however, that PSE&G still makes the final delivery to NJEA under a
transportation service agreement (see Firm Gas Transportation Arrangements
section).
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Similarly, if the average price of PSE&G sales service is less than 85%
of the comparable average cost of gas to New Jersey electric utilities over a
one-year period extending from November 1 through October 31, then PSE&G may
request a renegotiation of the pricing formula by notifying NJEA before the
following April 30.
Thus far, neither of the foregoing situations has occurred since the
projects began commercial operations in 1991.
Extended Gas Service: On days when the weather service retained by PSE&G
forecasts the mean daily temperature to be below 22(degree)F, PSE&G has an
option to interrupt the sales service. However, if the temperature is forecast
to be above 14(degree)F, PSE&G will allow NJEA to buy Extended Gas Service to
replace its sales service volumes. NJEA must notify PSE&G by May 1 of any year
in which it intends to elect Extended Gas Service commencing on November 1 of
the same calendar year. Once NJEA elects to receive Extended Gas Sales and
Transportation Services in any given year, NJEA then receives all of its gas
needs through such Extended Services whenever the temperature is between
14(degree)F and 22(degree)F degrees.
The price for Extended Gas Service equals the Service Charge per Dth,
described above, plus an Extended Gas Service Charge calculated as follows:
- --------------------------------------------------------------------------------
Extended Gas Service Charge = Propane Cost per Dth + $0.80 (1988)
Propane Cost per Dth is the price of 11 gallons of propane delivered to PSE&G's
production facilities. After 1988, the $0.80 charge is escalated on January 1 of
every calendar year using the following formula:
(L*0.40) + (F*0.60)
where:
L = percentage change in the previous year in the
index for average hourly earnings in the
manufacturing sector in New Jersey
F = percentage change from the previous January
through March in the average price of #2 fuel oil at
Northern New Jersey terminals as published in the
Platt's Oilgram Daily Price Report
- --------------------------------------------------------------------------------
BSA understands that NJEA has made use of Extended Gas Sales service
each year since 1995, based on our analysis of its past fuel invoices. We are,
therefore, comfortable that this service will continue to be reliably available
for future use by NJEA as needed.
B. Gas Storage Arrangements
As part of their fuel plan, NEA and NJEA have arranged for gas storage
services that enable them to purchase relatively inexpensive spot market gas in
the summer, and save it for use in the winter, when spot gas is typically more
costly. Their gas storage is firm in the same sense that their gas
transportation is firm, i.e., up to the contracted maximum amounts, service
cannot be interrupted for reasons other than force majeure.
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CNG is a major U.S. interstate natural gas pipeline company ($6.0
billion in assets as of 12/31/96) based in Pittsburgh, PA. CNG provides gas
transportation services throughout the northern Appalachian region and, in
particular, is also a major provider of gas storage services.
NEA has acquired storage capacity on the CNG system under CNG's GSS-II
storage service schedule for a maximum storage quantity ("MSQ") of 1,400,000 Dth
per year. NEA may withdraw the lesser of its storage inventory or the maximum
daily withdrawal quantity ("MDWQ") of 14,000 Dth/day. The receipt and delivery
points are, respectively, Leidy, PA and Chambersburg, PA or other points
mutually agreed upon by CNG and NEA. The primary term of the contract extends
until March 31, 2012 and may be extended by NEA from year to year thereafter.
NJEA has acquired similar storage service from CNG with an MSQ of
1,050,800 Dth per year and an MDWQ of 10,508 Dth/day. As above, the receipt and
delivery points are Leidy, PA and Chambersburg, PA or other points mutually
agreed upon by CNG and NJEA. The primary term of the contract extends until
March 31, 2012 and may be extended by NJEA from year to year thereafter.
C. Firm Gas Transportation Arrangements
NEA and NJEA have arranged with CNG, Transco, TETCO, Algonquin, and
PSE&G for FT service to deliver the ProGas supply from Niagara to the NEA and
NJEA plants and also gas from CNG's storage facilities to the NEA and NJEA
plants.
1. CNG
CNG transports on a firm (FT) basis up to 48,817 Dth/day (NEA) and
22,019 Dth/day (NJEA) of the gas that ProGas delivers to it at Niagara Falls, NY
to its interconnect either with Transco or TETCO at Leidy, PA, or with TETCO at
either Oakford or Chambersburg, PA. CNG bills NEA and NJEA under its rate
schedules X71 and X70, respectively. The terms of the CNG transportation
contracts extend until November 1, 2011.
2. Transco
Transcontinental Gas Pipe Line Corporation ("Transco") is a subsidiary
of Williams of Tulsa, OK. Williams ($12.4 billion in assets as of 12/31/96)
operates one of the nation's largest interstate gas pipeline networks. Under its
tariff X320, Transco delivers up to 49,971 Dth/day of NEA's gas from CNG at
Leidy, PA to Algonquin at Centreville, NJ. Similarly, under schedule X319,
Transco delivers up to 22,547 Dth/day of NJEA's gas from CNG at Leidy to PSE&G
at Sayreville. The terms of the contracts nominally extend until October 31,
2006, although FERC policies would make it virtually impossible for Transco to
terminate firm transportation service to NEA or NJEA over the latter's
objections.
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See ANALYSIS OF POTENTIAL FUEL ISSUES for a discussion of the
implications of the termination date of the Transco contracts.
3. TETCO
Texas Eastern Transmission Company ("TETCO") is a subsidiary of Duke
Energy Company ($13.5 billion in assets as of 12/31/96), which is one of the
nation's largest integrated energy companies. TETCO operates a major interstate
gas pipeline system throughout the Appalachian and eastern portions of the U.S.
TETCO provides firm transportation services for NEA and NJEA under its
FTS-5 Rate Schedule. The term of each of the contracts extends until March 31,
2012. The receipt points, delivery points and MDQs at these points are as
depicted in Exhibit 5 below:
- --------------------------------------------------------------------------------
Exhibit 5 - TETCO Receipt/Delivery Points & MDQs
Receipt/Delivery Pts. NEA Vol. NJEA Vol.
(Dth/day) (Dth/day)
Hunterdon Cty., interconnect
with Algonquin 14,000 10,508
11 points on PSE&G's
system 14,000 10,508
Chambersburg, PA,
interconnect with CNG 14,000 10,508
Delivery Points only
Leidy, PA,
interconnect with CNG 7,778 5,838
Oakford, PA,
interconnect with CNG 14,000 10,508
- --------------------------------------------------------------------------------
Source: BSA 1997.
4. Algonquin (NEA only)
Algonquin Gas Pipeline Company ("Algonquin"), also a subsidiary of Duke
Energy Company, provides gas transportation services from northern New Jersey to
customers in New England. Under Rate Schedule AFT-1, Algonquin transports up to
62,000 Dth/day of NEA's gas from its interconnects with Transco at Centreville,
NJ (up to 48,000 Dth/day) and with TETCO at
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Lambertville, NJ (up to 14,000 Dth/day) to the plant. The primary term of the
Service Agreement covering this transportation extends to November 30, 2016, and
NEA may extend the Agreement for an additional eight-year term.
5. PSE&G (NJEA only)
PSE&G provides NJEA gas transportation of up to a maximum volume of
32,500 MMBtu/day until August 12, 2011. In addition, NJEA may elect to receive
an additional amount of transportation capacity in the winter not to exceed
7,200 MMBtu/day.
The price for transportation service per Dth is the Service Charge, as
described earlier in this Section III, under subsection A, Firm Gas Supply
Arrangements (2. PSE&G). Similar to the sales service, the transportation
service is subject to interruption when the forecast mean daily temperature
falls below 22(degree)F (except in the month of March). Likewise, NJEA can elect
to receive Extended Gas Service to replace its transportation volumes if the
forecast mean daily temperature is greater than 14(degree)F and will pay the
same price as it would for Extended Gas Service to replace interrupted sales
service volumes.
D. Peak Shaving Arrangements
1. NEA
NEA has been designed and permitted to burn #2 fuel oil. To the extent
the plant's daily fuel requirements exceed daily gas availability, fuel oil
capability provides a backup to NEA's gas supplies. Although NEA has
fuel-switching capability, and had originally expected to contract with Bay
State Gas to exchange peak gas supplies for oil, it has no gas peak shaving or
sales arrangement in place at this time.
2. NJEA
When the forecast mean daily temperature falls below 14(degree)F, PSE&G
may interrupt NJEA's sales and transportation service, including any additional
winter transportation service./8 PSE&G will compensate NJEA only for curtailment
(or PSE&G's retention) of NJEA's transportation service volumes, including any
additional winter transportation capacity that PSE&G provides.
The foregoing events have taken place for NJEA in the past. PSE&G has
retained NJEA's gas because the temperature fell below 14(degree)F degrees on an
average of 1.8 days per year since plant operations commenced in 1991. Note that
the 1.8 days refers to the average number of days on which PSE&G withheld gas
service to NJEA, although the interruptions were not always for a full day,
e.g., some interruptions only lasted for a few hours. NJEA does have the
- -----------------
8 PSE&G cannot interrupt transportation service in March.
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option of buying spot gas and transporting to the plant directly on Transco, and
has done so on a few occasions. ESI Northeast Fuel Management, Inc., the new
fuel manager for NEA and NJEA, plans to rely on spot gas purchases as necessary
to keep NJEA fully operational even when the temperature falls below 14(degree)F
degrees. The Owners ran a sensitivity analysis in NE LP's pro forma financial
model incorporating the assumption that the project would have to purchase spot
gas at 150% of the cost of New Jersey spot gas prices to replace the PSE&G sales
and transportation services interrupted below 14(degree)F degrees. The results
confirmed that projected cash flows for NJEA are robust enough to withstand the
foregoing sensitivity change with comfort.
PSE&G calculates the monthly commodity charge paid on all volumes it
retains as follows:
- --------------------------------------------------------------------------------
Commodity Charge = Dth retained by PSE&G on Extended Gas Service days x
max[PSE&G WACOG commodity, min(propane cost per Dth, fuel oil cost per Dth)] +
Dth retained by PSE&G on non-Extended Gas Service days x Fuel oil cost per Dth
where:
PSE&G WACOG commodity is calculated as described in the Firm Gas
Supply Arrangements section
Propane cost per Dth determined as described in the Firm Gas Supply
Arrangements section
Fuel oil cost per Dth is the average price of 7.21 gallons of #2
fuel oil at Northern New Jersey terminals as reported in Platt's
Oilgram Daily Price Report + a delivery charge of $0.0721 per Dth
adjusted annually by the GNP deflator of the preceding year.
- --------------------------------------------------------------------------------
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PSE&G also pays NJEA a Peak Gas Service Credit every month of the year
and this is calculated as follows:
- --------------------------------------------------------------------------------
Peak Gas Service Crediti = 32,000 Dth/day x Unit Credit x Days in month i
where:
32,000 Dth/day is the maximum daily tran sportation quantity that NJEA
can have interstate pipelines deliver to PSE&G and that PSE&G will
deliver to the plant.
Unit credit = min(0.375*Firm Supply Demand Charge per Dth + 0.125*
Storage-Related Demand Charge per Dth, $0.157 per Dth in 1988)
The Firm Supply Demand Charge per Dth is the actual per Dth demand
charges paid by NEA for transportation of its firm gas supplies to
PSE&G.
The Storage-Related Demand Charge per Dth is the actual per Dth demand
charges (excluding storage capacity charges) paid by NJEA for storage
and transportation of storage gas to PSE&G.
The $0.157 per Dth charge is escalated on January 1 of every year by
the average change in the following pipeline rates:(i) TETCO's DCQ
and FT-1, (ii) Transco's CD and FT, (iii) CNG's CD and TF, as further
specified in the contract.
The Unit Credit can only vary within a band of values. The floor to
this band is 37% of the Service Charge and the ceiling is 68% of the
Service Charge.
- --------------------------------------------------------------------------------
IV. ANALYSIS OF PRO FORMA GAS COSTS TO NEA/NJEA
NEA and NJEA's fuel costs are linked to its power revenues as follows:
o NJEA's power revenues are based on the delivered cost of gas to New
Jersey electric utilities as reported on Federal Energy Regulatory
Commission (FERC) Form 423. NJEA's gas supply prices are tied to its
power revenues (a) directly in its ProGas contract, which escalates
with Form 423 prices in New Jersey, and (b) indirectly through the
commodity cost of PSE&G sales service, which correlates highly
(91.8%) with Form 423 prices in New Jersey.
o NEA's power revenues are based on a mix of fixed and avoided cost
pricing. NEA's ProGas supplies are priced to match power revenues,
while the remainder of its gas purchases (NJEA's ProGas supplies
delivered to NEA and spot gas) also match power revenues.
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We conclude that, taken together, NEA and NJEA's delivered fuel costs
and power revenues are naturally hedged; i.e., the degree to which NJEA's and
NEA's gas purchases are tied to their energy payments equals approximately 95%
and 91%, respectively (see Appendix A). Nonetheless, BSA reviewed the
assumptions contained in NE LP's pro forma financial model for the NEA and NJEA
projects ("the pro forma") as they relate to the current and projected price of
natural gas. We conclude that those assumptions are reasonable, as follows (see
Exhibit 6):
o Through 2000, the pro forma's gas price projection, which is taken
at Henry Hub (Erath, Louisiana):
- Tracks very closely the gas price forecast issued in 1997 by the
U.S. Department of Energy's Energy Information Administration
(DOE)
- Also tracks the 1997 gas price forecast of the Gas Research
Institute (GRI), which is nearly identical to DOE's projection
- Falls below the current gas price forecasts of the American Gas
Association (AGA), Cambridge Energy Research Associates (CERA),
and Petroleum Industry Research
Associates (PIRA)
- Falls significantly below the average 1997 closing price of the
gas futures contract for delivery at Henry Hub, as traded on the
New York Mercantile Exchange (NYMEX).
o Beyond 2000, the pro forma's gas price projection rises by 1% over
the GNP deflator, and thus escalates more rapidly than the DOE and
GRI projections (which increases at the GNP deflator), and more
slowly than that of AGA (which increases at approximately 2% over
the GNP deflator).
The pro forma's gas projection beyond 2000 falls well within the range
of existing gas price forecasts. The pro forma's gas price projection before
2000 appears to be lower than most (except DOE and GRI) and is lower than the
average 1997 NYMEX gas price. As a sensitivity analysis, therefore, BSA
requested the Owners to modify the projections of gas prices contained in the
pro forma to reflect current NYMEX closing prices for delivery through 2000. The
resulting financial projections enabled us to conclude with comfort that
expected cash flows for NEA and NJEA are robust enough to withstand alternative
foreseeable fuel price scenarios.
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FINAL REPORT
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Exhibit 6 - Comparison of Henry Hub Gas Price Forecasts
[GRAPHIC OMITTED]
We conclude, therefore, that NE LP's pro forma embodies fully reasonable
assumptions as to future fuel prices.
V. ASSESSMENT OF NEA/NJEA'S NON-CONTRACT GAS PROCUREMENT
NEA's and NJEA's spot gas utilization can be classified into three
categories:
o Storage Gas: During the summer months, NEA and NJEA fill up their
storage with spot volumes.
o Flow-through Gas (Summer): After taking ProGas and PSE&G (NJEA
only) contract volumes, NEA and NJEA make up the remaining portion
of required volumes at the plants with spot purchases.
o Replacement Gas (Winter): Under the CNG GSS II contracts, NEA and
NJEA may each withdraw gas from storage, up to the contract
allowable maximum daily rates, during a tariff-defined winter period
(November 1- March 31). Assuming that NEA's and NJEA's inventory
balances are at 100% of capacity when they begin withdrawals on
November 1, and that they have no opportunity to inject gas into
storage during the
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winter period,/9 they may withdraw gas at the contract maximum daily
withdrawal rate for a total of 100 days. Thus, for the remaining 51
days/10 of CNG's winter period, NEA and NJEA replace the storage gas
flowing to the plants with matching spot purchases flowing to the
plants.
Spot gas supplies are available 12 months per year in the regions where
NEA and NJEA procure their non-contract gas. This availability extends both to
the Appalachian region, where the projects procure spot gas for injection into
CNG's storage facilities, and to the New York/New Jersey region, where the
projects procure spot gas directly for consumption in the plants. We use the
term "spot gas" broadly to encompass all of the projects' non-contract supplies,
including supplies arranged on a seasonal basis.
The Owners, on behalf of NEA and NJEA, entrusted ESI Northeast Fuel
Management, Inc. (the "Fuel Manager") with the responsibility of managing the
procurement of all gas supplies, and transportation and storage services which
the projects will require in its operations. The Fuel Manager has put into place
a Fuel Supply team consisting of experienced personnel in the natural gas
industry. We anticipate that this Fuel Supply team will be able to access the
kinds of markets referred to above, and will maintain the skills, information
technologies, and equipment necessary to operate the projects' long-term
contracts and short-term spot gas purchasing activities.
Prior to the end of every month, Fuel Supply personnel will receive from
the plant managers anticipated daily natural gas requirements for the following
month for the NEA and NJEA projects. Based on these requirements, Fuel Supply
personnel will then negotiate with and enter into short-term gas supply
arrangements with marketers during the end-of-the-month bid-week (when many
shippers arrange transportation service on pipelines for the following month).
Their strategy is one of "best available supply," with an emphasis on
reliability of deliveries.
Based on BSA's discussions with the Fuel Manager, we are comfortable
that the Fuel Supply team will install a suitable system to track daily and
monthly purchases and flows of gas to both plants, as has existed in the past on
behalf of NEA and NJEA. The system must produce daily and monthly management
reports which managers will use for operational purposes, such as imbalance
management./11 These reports will also form the basis for accounting functions
including invoicing and to keep track of variances from budgetary targets.
- -----------------
9 NEA and NJEA may have opportunities to cycle gas into storage during the
winter period in order to partially restock their inventory balances.
10 52 days when leap years occur.
11 If, at any point in time, a shipper takes out more or less gas than it has
put into a pipeline's or LDC's system, it creates an imbalance with respect to
its own account. The pipeline or LDC may charge the shipper a certain fee for
unreconciled daily or monthly imbalances.
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VI. ANALYSIS OF POTENTIAL FUEL ISSUES
In this section, we assess potential fuel-related issues related to the
financial performance of NEA and NJEA. We resolved each issue in a way that
enabled us to conclude that none poses any material risk to bondholders in the
area of fuel price, supply and delivery.
A. ProGas's lay-off gas responsibilities.
By amendment entered into in 1996, ProGas agreed to use all reasonable
efforts to remarket, or "layoff" to third parties, any gas that NEA or NJEA may
not require due to scheduled or unscheduled outages at the plants. If ProGas
makes layoff sales, NEA and NJEA will be relieved of their purchase obligations
by the amount of the layoff sales and will receive a commensurate credit of
their monthly demand charges. If ProGas does not make layoff gas sales, the Fuel
Manager will continue to have the following choices, as in the past:
o The Fuel Manager may inject the unneeded ProGas supplies into
storage. If NEA and NJEA do not require the gas at the plants on any
given day, the marginal economics may lead them to take delivery of
the gas at Niagara and inject it into CNG storage rather than buying
spot gas for storage injection. Previous fuel managers at NEA and
NJEA report having injected ProGas supplies into storage in the
past.
o The Fuel Manager may sell unneeded supplies into local markets. The
previous fuel managers report having economically sold some of the
ProGas supplies to third parties during an outage at NEA that took
place during the winter of 1992-1993. The ability to deliver gas to
Niagara or further downstream in the Northeast U.S. market area on a
firm basis allows ProGas or the Fuel Manager to guarantee
comfortably gas deliveries to a layoff customer for the duration of
any foreseeable plant outage.
We conclude that the recently agreed upon provision allowing ProGas to
"layoff" unneeded gas adds a further protection to bondholders to the options
already available to the Fuel Manager during infrequent instances when the
projects do not require ProGas supplies.
B. Continuation of interstate pipeline services beyond contract
expiration.
The terms of NEA's and NJEA's FT contracts with Transco extend through
October 31, 2006, and year to year thereafter unless either party elects to
terminate the contracts with six months notice. In addition, the projects'
contracts with CNG for transportation services expire on November 1, 2011. We
discuss below the risk associated with these contract terminations, which
predate bond maturity.
Transco and CNG are each interstate pipelines regulated by the Federal
Energy Regulatory Commission (FERC), and will remain so through 2011 and beyond.
As such, they provide services subject to FERC regulatory oversight and
procedures. Both pipelines provide
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services to NEA and NJEA under Section 7(c) of the Natural Gas Act of 1938
(NGA), under which the FERC allows shippers such as NEA and NJEA to pay a rate
for transportation based on cost of the specific facilities that the pipelines
built to provide service to them. Transco and CNG also provide FT service to
shippers pursuant to Part 284 of the Natural Gas Policy Act of 1978 (NGPA)
utilizing overall system capacity, i.e., facilities not specifically dedicated
to Section 7(c) service. Part 284 shippers pay a "rolled-in" rate by which the
pipeline recovers the overall embedded costs of its system, excluding the costs
of the specific facilities devoted to Section 7(c) service.
If Transco or CNG were to abandon service to NEA and NJEA when their
contracts expire, then NEA and NJEA could be left paying higher rates for
alternative transportation services. We conclude in this section that neither
pipeline has the ability under the FERC's rules and procedures to cancel service
to NEA or NJEA. As a worst case, the projects could, when the contracts expire,
be required to pay a higher Part 284 transportation rate, matching the economic
value of the highest alternative offer from other shippers, subject to the
maximum rate./12
Our analysis is as follows:/13
o First, under Section 7(b) of the NGA, pipelines subject to the
jurisdiction of the FERC cannot terminate service simply because the
contract has expired. The contract is not controlling in this
regard. Unless the FT certificate was obtained with pregranted
abandonment - which is not the case under any of the contracts
between CNG and Transco and NEA/NJEA/14 - the pipeline cannot
terminate service without additional authorization after a hearing.
The pipeline has the burden to demonstrate that abandonment meets
the "public convenience and necessity" test before it will get
authorization to terminate service. In a contested abandonment case,
meeting this test is a great burden and it is virtually impossible
to meet this test.
o Second, the year-to-year extension feature included in all of the
Transco and CNG contracts with NEA and NJEA is a source of
protection for the projects. FERC has consistently applied a 1950's
doctrine regarding a Sunray case that applies the notice of
dependence and reliance on pipeline capacity for not allowing
abandonment.
o Finally, the FERC's recent pipeline services restructuring Order
636, which changed abandonment procedures, reaffirmed protection for
shippers protesting service abandonments. Pipelines such as Transco
and CNG must furnish a Notice of
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12 Alternatively, the Part 284 rate may in the future fall below the Section
7(c) rate applicable to NEA and NJEA.
13 BSA discussed the issue of pipeline service abandonment with counsel to
several pipelines and LDCs, and with FERC staff.
14 A Section 7(c) contract, which we are dealing with here, offers greater
protection than a Part 284 contract does. Part 284 transportation contracts have
a pregranted abandonment procedure, which is not a part of a Section 7(c)
contract, thus the latter offers greater protection to shippers against
abandonment than the former.
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Abandonment and existing shippers (such as NEA and NJEA) have the
first right of refusal. The pipelines may only terminate service if
the preexisting shipper fails to match a higher offer from another
shipper. Consequently, the worst case is that, in order to retain FT
services on Transco and CNG, NEA and NJEA would have to match a
higher value offer (both in terms of rate and duration of contract)
from another shipper, subject to maximum rates.
In the unlikely event that the projects are forced to convert to
Transco's Part 284 Rates in 2007, the projected Part 284 rates will be only 5%
higher than the currently projected Transco rates used in NE LP's pro forma
model and would not materially impact gas costs. BSA also notes that the
projects anticipate negotiating a demand charge reduction on Transco of
approximately $1.00 per Dth per month beginning in 1999. Such a reduction, if
successfully implemented, would enable the projects to reduce significantly
their cost of transportation on Transco from 1999 forward.
Similarly, if the projects are unable to negotiate contract extensions
with CNG, we project that in November and December of 2011, the two months
following contract expiration that precede bond maturity, CNG's Part 284 demand
charge may be as much as 20% higher than the rates the projects pay under Rate
Schedules X-70 and X-71, or an estimated $329,000 in 2011. Sensitivity analysis
of NE LP's pro forma model using this higher cost for Part 284 service in 2011,
together with Part 284 service costs for Transco during 2007-2011 showed
virtually no impact on NE LP's revenues or debt service coverages.
We conclude that the maximum risk to NEA and NJEA associated with early
termination of its Transco and CNG gas transportation contracts is that, in
order to continue these services, the projects could have to match the terms of
an offer from an alternative bidder/shipper, but that the rate they pay will not
exceed the maximum Part 284 rate then in effect./15 We further conclude that
there is essentially no risk of actual physical loss of the firm transportation
and storage services that the projects currently have under contract with CNG
and Transco.
C. Economic Risk of PSE&G Contract Termination in 2011
PSE&G provides both firm gas supply service and transportation service
to NJEA under an agreement that expires on August 12, 2011. Termination of this
agreement predates bond maturity by approximately four and one half months. We
discuss below the risks associated with early termination of this contract.
PSE&G is an intrastate public utility in New Jersey and as such will
continue to be subject to regulation by the New Jersey Board of Utilities. NJEA
has the right to request and PSE&G has the obligation to provide NJEA both gas
sales and transportation services under its State
- -----------------
15 In exchange for paying the higher Part 284 rate (if it proves to be higher),
NEA and NJEA would have the same service rights as all other Part 284 shippers,
including such features required by the FERC's Order 636 of Part 284 services as
flexible receipt and delivery points and capacity release options.
- --------------------------------------------------------------------------------
Benjamin Schlesinger and Associates, Inc. Page 22
C-25
FINAL REPORT
- --------------------------------------------------------------------------------
approved tariffs upon expiration of its current contract on August 12, 2011./16
NJEA will, however, have the obligation to pay for these services at the then
prevailing sales and transportation tariff rates. Alternatively, NJEA will have
the opportunity to negotiate with PSE&G for a more favorable rate, as it has in
the past.
NJEA will have the following options to continue to receive gas supply
and transportation services from PSE&G upon expiration of its current contract:
o Renegotiate the existing contract for gas sales and transportation
with PSE&G under mutually agreeable terms. Renegotiation of
contracts upon expiration is done routinely by large gas users such
as NJEA; moreover, NJEA has the flexibility to receive gas directly
off the Transco pipeline by virtue of its physical location and
working equipment on site. Hence this would be the most likely
option.
o Receive gas supply under an alternative arrangement with PSE&G
using its Cogeneration Tariff to replace the contract sales service
agreement with PSE&G upon its expiration. This gas supply
arrangement would be for 25,000 Dth/day.
o Receive gas transportation service under PSE&G's interruptible
transportation tariff for 32,527 Dth/day for transporting both the
Canadian ProGas gas supply and spot gas from storage from
Sayreville, NJ to the NJEA plant. We believe that the quality of
this transportation service would be generally comparable to NJEA's
existing transportation service with PSE&G.
In light of NJEA's physical capability to receive gas directly from
Transco, we view the latter two options above to be extremely unlikely.
We conclude that there is no risk of physical loss of gas supply or
transportation services from PSE&G upon expiration of existing contract in 2011,
since PSE&G will retain the obligation to serve customers situated within its
franchised service area.
We further conclude that there is essentially no risk that NJEA will
have to pay PSE&G's standard transportation tariff rates because NJEA is
physically located adjacent to the Transco pipeline. In our opinion, PSE&G will
continue to maintain the capability to provide competitive rates to customers of
NJEA's size, flexibility, and physical access to alternative suppliers.
- -----------------
16 Telephone conversation with Mr. Vic Bozzo, Bureau of Competitive Services,
Energy Division, NJ Board of Utilities, on December 23, 1997.
- --------------------------------------------------------------------------------
Benjamin Schlesinger and Associates, Inc. Page 23
C-26
Appendix A: Power Contract and Gas Price Comparisons
NJEA Gas Commodity Price Correlation with Power Revenues
Jun-95 through May-97
Actual % of Total % Correlation w/ Volume Weighted
Purchased Volume Purchased Volume NJ Form 423 Correlation
---------------- ---------------- ----------- -----------
ProGas 15,310,018 48.4% 100.0% 48.4%
PSE&G Sales 15,098,819 47.8% 91.8% 43.8%
PSE&G Extended 1,037,639 3.3% 67.1% 2.2%
Spot 162,061 0.5% 86.5% 0.4%
Total 31,608,537 94.9%
NEA Gas Commodity Price Correlation with Power Revenues
Jun-95 through May-97
Actual % of Total % Correlation w/ Volume Weighted
Purchased Volume Purchased Volume Power Rev. Correlation
----------------- ---------------- ---------- -----------
ProGas (NEA Price) 24,622,439 55.5% 100.0% 55.5%
ProGas (NJEA Price) 9,316,153 21.0% 71.0% 14.9%
Spot 10,397,968 23.5% 86.0% 20.2%
Total 44,336,560 90.6%
1
C-27
Appendix A (cont.)
PSE&G vs. NY/NJ Citygate Spot Index
Mid-point of Inside
PSE&G Sales FERC's NY/NJ Citygates PSE&G less Spot
($/Dth) ($/Dth) ($/Dth)
------- --------------- -------
Jun-95 $1.95 $1.87 $0.08
Jul-95 $1.64 $1.67 ($0.02)
Aug-95 $1.63 $1.53 $0.10
Sep-95 $1.68 $1.74 ($0.06)
Oct-95 $1.86 $1.82 $0.04
Nov-95 $2.09 $2.03 $0.06
Dec-95 $2.45 $2.57 ($0.11)
Jan-96 $3.21 $3.28 ($0.06)
Feb-96 $2.50 $2.51 ($0.01)
Mar-96 $2.84 $3.72 ($0.88)
Apr-96 $2.60 $2.89 ($0.28)
May-96 $2.43 $2.35 $0.08
Jun-96 $2.41 $2.55 ($0.13)
Jul-96 $2.79 $2.82 ($0.03)
Aug-96 $2.53 $2.51 $0.02
Sep-96 $2.01 $1.95 $0.07
Oct-96 $2.03 $2.00 $0.03
Nov-96 $2.65 $2.84 ($0.19)
Dec-96 $4.09 $4.04 $0.05
Jan-97 $4.20 $4.61 ($0.41)
Feb-97 $3.09 $3.37 ($0.28)
Mar-97 $1.87 $1.96 ($0.09)
Apr-97 $2.06 $2.07 ($0.01)
May-97 $2.12 $2.30 ($0.18)
Jun-97 $2.51 $2.62 ($0.11)
Jul-97 $2.37 $2.37 $0.00
Aug-97 $2.62 $2.38 $0.25
Sep-97 $2.61 $2.78 ($0.16)
Average $2.45 $2.54 ($0.09)
PSE&G Correlation w/ NY/NJ Citygate Spot Prices: 96.4%
Data Source: Inside FERC's Gas Market Report.
2
C-28
Appendix B: Catalogue of Principal NEA/NJEA Fuel Contracts
(received 11/13/97 by BSA)
TITLE PARTIES TERMINATION EXTENSION TERMS
A. Gas Purchase
- ------------------------------------------------------------------------------------------------------------------------------------
1 Gas Purchase and Sale Agreement NJEA and PSE&G August 12, 2011 None
(NJEA and PSE&G)
- ------------------------------------------------------------------------------------------------------------------------------------
2 Gas Purchase Contract for Bellingham NEA and ProGas November 1, 2013 Two 5-year terms
- ------------------------------------------------------------------------------------------------------------------------------------
3 Gas Purchase Contract for Sayreville NJEA and ProGas November 1, 2013 Two 5-year terms
- ------------------------------------------------------------------------------------------------------------------------------------
4 Amending Agreements for Gas Purchase NEA/NJEA and ProGas September 3, 2006 Two 5-year terms
Contract
- ------------------------------------------------------------------------------------------------------------------------------------
B. Storage
- ------------------------------------------------------------------------------------------------------------------------------------
1 Gas Storage Service Agreement NEA and CNG March 31, 2012 Year-to-Year
(Schedule GSS-II)
- ------------------------------------------------------------------------------------------------------------------------------------
2 Gas Storage Service Agreement NJEA and CNG March 31, 2012 Year-to-Year
(Schedule GSS-II)
- ------------------------------------------------------------------------------------------------------------------------------------
C. Transportation
- ------------------------------------------------------------------------------------------------------------------------------------
1 Firm Transportation Service Agreement NEA, CNG, ProGas USA November 1, 2011 Shall not terminate until
and ProGas 7(b) authority received
- ------------------------------------------------------------------------------------------------------------------------------------
2 Firm Transportation Service Agreement NJEA, CNG, ProGas USA November 1, 2011 Shall not terminate until
and ProGas 7(b) authority received
- ------------------------------------------------------------------------------------------------------------------------------------
3 Service Agreement for Schedule FTS-5 NEA and Texas Eastern March 31, 2012 Year-to-Year
- ------------------------------------------------------------------------------------------------------------------------------------
4 Service Agreement for Schedule FTS-5 NJEA and Texas Eastern March 31, 2012 Year-to-Year
- ------------------------------------------------------------------------------------------------------------------------------------
5 Firm Gas Transportation Agreement NEA and Transco October 31, 2006 Year-to-Year
(Rate Schedule X-320) (15 years from agreement)
- ------------------------------------------------------------------------------------------------------------------------------------
6 Firm Gas Transportation Agreement NJEA and Transco October 31, 2006 Year-to-Year
(Schedule X-319) (15 years from start)
- ------------------------------------------------------------------------------------------------------------------------------------
7 Firm Gas Transportation Agreement NEA and Algonquin October 1, 2018 Single 8-year term
(Schedule X-35)
- ------------------------------------------------------------------------------------------------------------------------------------
8 Firm Gas Transportation Agreement NEA and Algonquin November 30, 2016 Option period for renewal
(Schedule AFT-1 converted from X-35) is single 8-year term
- ------------------------------------------------------------------------------------------------------------------------------------
9 Gas Purchase and Sale Agreement NJEA and PSE&G August 12, 2011 None
(NJEA and PSE&G)
- ------------------------------------------------------------------------------------------------------------------------------------
Page B-1
C-29
Appendix C: Analysis of Transco's and CNG's Part 284 and 7(c) Rates
Comparison of Transco's Part 284 and Section 7(c) Demand Charges
($/MMBtu/Month)
------------------------------------------------------
Inflation: 2.8%
Escalation Factor: 1.4%
------------------------------------------------------
- --------------------------------------------------------------------------------
Section 7(c) Section 7(c) Part 284
Contract Rate Proforma Rate Rolled-in Rates
Year (declining) (increasing) (increasing)
- --------------------------------------------------------------------------------
1997 4.47 4.47 3.58
1998 4.41 4.53 3.63
1999 4.34 3.50 3.68
2000 4.28 3.55 3.73
2001 4.22 3.60 3.78
2002 4.16 3.65 3.83
2003 4.11 3.70 3.89
2004 4.05 3.75 3.94
2005 3.99 3.80 4.00
2006 3.94 3.86 4.05
2007 3.88 3.91 4.11
2008 3.83 3.97 4.17
2009 3.77 4.02 4.22
2010 3.72 4.08 4.28
2011 3.67 4.14 4.34
% difference from Proforma Rate in 2011: 0.0% 5.0%
% difference from Proforma Rate - Avg. 2007-2011: 0.0% 5.0%
- --------------------------------------------------------------------------------
Note: Excludes GRI and retainage charges.
C-30
Appendix C (cont.)
Comparison of CNG's Part 284 and Section 7(c) Demand Charges
($/MMBtu/Month)
--------------------------------------------------
Inflation: 2.8%
Escalation Factor: 1.4%
--------------------------------------------------
- --------------------------------------------------------------------------------
Section 7(c) Section 7(c) Part 284
Contract Rate Proforma Rate Rolled-in Rates
Year (constant) (declining) (increasing)
- --------------------------------------------------------------------------------
1997 4.94 4.50 4.87
1998 4.94 4.44 4.94
1999 4.94 4.37 5.01
2000 4.94 4.31 5.08
2001 4.94 4.25 5.15
2002 4.94 4.19 5.22
2003 4.94 4.13 5.30
2004 4.94 4.08 5.37
2005 4.94 4.02 5.45
2006 4.94 3.96 5.52
2007 4.94 3.91 5.60
2008 4.94 3.85 5.68
2009 4.94 3.80 5.76
2010 4.94 3.75 5.84
2011 4.94 3.69 5.92
% difference from Contract Rate in 2011: -25.2% 20.0%
- --------------------------------------------------------------------------------
Note: Excludes GRI and retainage charges.
C-31
APPENDIX D
SUMMARY OF PROJECT INDENTURE
The following is a summary of selected provisions of the Project Indenture
and is not to be considered to be a full statement of the terms of the Project
Indenture. Accordingly, the following summaries are qualified by reference to
the Project Indenture and are subject to the terms of the full text of the
Project Indenture. Copies of the Project Indenture are available for review. See
"Available Information." Capitalized terms used in this Appendix D and not
otherwise defined in this Prospectus have the meaning assigned to such terms in
the Project Indenture.
The Funds
Establishment of Funds
Under the Project Indenture, the following Funds and Subfunds have been
established with the Project Trustee in the name of the Partnerships:
(i) Capital Expenditure Fund, including
(a) Loss Proceeds Subfund, and
(b) Additional Bonds Subfund;
(ii) Revenue Fund;
(iii) Working Capital Fund;
(iv) Operating Fund, including
(a) General Subfund, and
(b) Subordinated Management Fee Subfund;
(v) Major Overhaul Reserve Fund;
(vi) Interest Fund, including
(a) Note Subfund, and
(b) Other Obligations Subfund;
(vii) L/C Fee Fund;
(viii) Principal Fund, including
(a) Note Subfund, and
(b) Other Obligations Subfund;
(ix) Debt Service Reserve Fund;
(x) Gas Transmission Reserve Fund;
(xi) Gas Supply Reserve Fund;
(xii) Partnership Suspense Fund;
(xiii) Partnership Distribution Fund, including
(a) Tax Payment Subfund, and
(b) General Subfund; and
(xiv) Good Faith Contest Fund.
D-1
Capital Expenditure Fund
Loss Proceeds Subfund
All Loss Proceeds received in respect of an Event of Loss are required to be
deposited in the Loss Proceeds Subfund of the Capital Expenditure Fund, except
as provided in the last paragraph of this subsection. Such proceeds are then
required to be applied (i) to the payment of the costs of Restoring the Project
in respect of which such Loss Proceeds were received (the "Affected Project") in
accordance with the terms and conditions of the Project Indenture; and (ii) in
the event that the applicable Partnership elects not to Restore the Affected
Project or in the event that the Restoration Conditions with respect to the
Affected Project are not satisfied, to the redemption or repurchase of the
Project Securities.
With respect to any Event of Loss, prior to the initial release of Loss
Proceeds from the Loss Proceeds Subfund to pay Restoration costs in respect of
such Event of Loss, it is a condition to such initial release that the Project
Trustee shall have received (a) an officer's certificate of the applicable
Partnership (i) stating its irrevocable election to Restore the Affected Project
pursuant to the Project Indenture, (ii) setting forth a reasonable good faith
estimate of the cost of Restoring the Affected Project and (iii) stating that in
the opinion of such Partnership the Restoration Conditions with respect to the
Affected Project are then, and during the period of any such Restoration are
expected to continue to be, satisfied; and (b) in the case of any Event of Loss
for which the amount of Loss Proceeds shall exceed $30 million, an Independent
Engineer's certificate to the effect that the Independent Engineer concurs with
(i) the applicable Partnership's estimate of the costs of Restoring the Affected
Project and (ii) such Partnership's determination that the Restoration
Conditions are then, and during the period of any such Restoration are expected
to continue to be, satisfied with respect to the Affected Project.
In the case of each release of Loss Proceeds from the Loss Proceeds Subfund
to pay the costs of Restoration, it is a condition to such release that the
Project Trustee shall have received a requisition from the applicable
Partnership dated not more than five business days prior to the date such
payment is requested to be made, stating (i) the amount to be paid; (ii) that
the payment will be used to pay the costs associated with the Restoration of the
Affected Project, such costs are then due and payable and such payment is a
proper charge against the Loss Proceeds Subfund; (iii) that bills, invoices or
other evidence of payment are in the possession of the applicable Partnership or
NE LP; (iv) that the item for which payment is requested has not been the basis
for a prior requisition from any Fund which has been paid or with respect to
which a request for payment is pending; (v) that (a) no written notice of any
Lien, right to Lien or attachment upon, or claim affecting the right to receive
payment of, any of the monies payable under such requisition has been received
(other than in respect of a Permitted Lien) or (b) if any such notice has been
received, then any such Lien, attachment or claim has been released or
discharged or will be released or discharged (to the extent of the payment to be
made) upon payment of such requisition; and (vi) that such requisition contains
no items representing payment on account of any retained percentages, if any, to
be retained at the date of such requisition.
Upon Substantial Completion of the Restoration of the Affected Project, the
applicable Partnership is required to furnish an officer's certificate to the
Project Trustee stating (a) that Substantial Completion has been achieved, and
D-2
that the Restoration was performed in accordance with Prudent Utility Practices,
and (b) the amount (the "Retained Amount"), if any, required, in the applicable
Partnership's reasonable opinion, to be retained in the Capital Expenditure Fund
for the payment of all remaining costs of completing the Restoration of the
Affected Project. Upon receipt of such certification (and if the aggregate
amount of Loss Proceeds relating to such Restoration exceeds $30 million,
receipt of an Independent Engineer's certificate concurring with the statements
in such officer's certificate referenced in clause (a) above), the balance of
all Loss Proceeds in excess of the Retained Amount (and following completion of
the Restoration and payment of all costs, any excess Retained Amount) is
required to be transferred to the Revenue Fund.
If in connection with the Restoration of an Affected Project (or in
connection with the construction of any Required Improvements) either
Partnership is entitled to receive any liquidated damages from a contractor and
such damages are attributable to the inadequate performance of the applicable
Project (but not construction delays), then such condition is deemed to
constitute an independent Event of Loss and such liquidated damages are required
to be treated as Loss Proceeds to be applied as described herein; provided that
if the aggregate amount of such liquidated damages exceeds $10 million, then, in
addition to the other conditions to release of Loss Proceeds described herein,
it is a condition to the release of such Loss Proceeds to pay Restoration costs
that the Project Trustee shall have received an Independent Engineer's
certificate to the effect that the applicable Partnership's plan for Restoration
is in accordance with Prudent Utility Practices and that the contractor engaged
to perform such Restoration is competent to do so in accordance with Prudent
Utility Practices.
In the event that the total Loss Proceeds to be received in respect of any
event does not exceed $5 million, then such Loss Proceeds are to be released to
the applicable Partnership upon receipt of an officer's certificate stating (i)
the applicable Partnership's irrevocable election to Restore the Affected
Project and to apply such Loss Proceeds to the payment of the costs of such
Restoration (with any excess to be deposited in the Revenue Fund) and (ii) that
no event of default under the Project Indenture has occurred and is continuing.
Additional Bonds Subfund
All proceeds of the sale of any Additional Project Securities are required
to be deposited in the Additional Bonds Subfund for application (i) toward the
payment of the costs of construction of Required Improvements, (ii) to furnish
additional cash security (to support additional Energy Bank obligations that may
be incurred if either Partnership were to enter into additional Power Purchase
Agreements, or amend existing Power Purchase Agreements, in accordance with the
Project Indenture), (iii) to the extent the Project Trustee is directed to do so
by ESI Tractebel Funding or required to do so by the applicable series
supplemental indenture, to the payment of fees, expenses or other costs incurred
in connection with the issuance of such Additional Project Securities and (iv)
to the extent the Project Trustee is directed to do so by ESI Tractebel Funding
or required to do so by the applicable series supplemental indenture, to fund
the Debt Service Reserve Fund, to the extent that the balance of such Fund upon
issuance of such Additional Project Securities is less than the Debt Service
Reserve Requirement upon such issuance.
The conditions to the release of funds from the Additional Bonds Subfund for
the payment of construction costs relating to any Required Improvement, and the
provisions relating the disposition of any excess funds upon Substantial
Completion of such construction, are substantially the same as those applicable
to the Loss Proceeds Subfund, summarized above.
D-3
Revenue Fund
All Project Revenues are required to be deposited into the Revenue Fund held
by the Project Trustee.
Prior to the first business day of each calendar month (a "Monthly Transfer
Date"), the Partnerships are required to deliver to the Project Trustee a
certificate (the "Applicable Monthly Transfer Certificate") providing certain
information to the Project Trustee, and on each Monthly Transfer Date, the
Project Trustee is required to transfer funds from the Revenue Fund, to the
extent then available in the Revenue Fund (after giving effect to all transfers
to be made to the Revenue Fund on such date), in the following amounts and order
of priority:
to the Working Capital Fund, the excess, if any, of (a) the sum of the
aggregate principal amount of all loans then outstanding under the Working
Capital Facility (or such lesser amount of such loans as the Partnerships
may elect to repay during the month commencing on such Monthly Transfer
Date), plus all interest, fees and other amounts estimated by the
Partnerships to be or become due and payable under or pursuant to the
Working Capital Facility during the month commencing on such Monthly
Transfer Date over (b) the aggregate amount of all funds then on deposit in
the Working Capital Fund;
to the General Subfund of the Operating Fund, the excess, if any, of (a) the
aggregate amount of all Operating Expenses (excluding Subordinated
Management Fees) estimated by the Partnerships to be or to become due and
payable during the month commencing on such Monthly Transfer Date over (b)
the aggregate amount of all funds then on deposit in the Operating Fund and
the Operating Accounts, other than amounts in the Operating Accounts against
which outstanding checks have been drawn and mailed or delivered;
commencing on the first Monthly Transfer Date in calendar year 2001, to the
Major Overhaul Reserve Fund, the sum of (a) the amount, if any, specified in
the Project Indenture to be deposited in such Fund on such date plus (b) the
amount of any deficiency in such Fund that may have resulted from the
failure to fully fund any previous scheduled deposit to such Fund or any
withdrawals from such Fund to satisfy deficiencies in other Funds as
described herein;
to the respective Subfunds of the Interest Fund, the amounts hereinafter set
forth (or a ratable portion of each such amount to each such Subfund, in the
event of a shortfall): (a) to the Note Subfund of the Interest Fund, the
excess, if any, of (1) the aggregate amount of interest payable on the
Project Notes (for application to the payment of interest on the Project
Securities) on the immediately succeeding interest payment date therefor (or
if such Monthly Transfer Date is an interest payment date, then on such
date) over (2) any funds then on deposit in the Note Subfund of the Interest
Fund; and (b) to the Other Obligations Subfund of the Interest Fund, the
excess, if any, of (1) the sum of (A) all interest payments estimated by the
Partnerships to be or to become due and payable during the month commencing
on such Monthly Transfer Date in respect of certain permitted Debt of the
Partnerships (consisting of Permitted Purchase Money Indebtedness and
Permitted Unsecured Indebtedness), plus (B) unless the existing Swaps are
terminated, all payments estimated by the Partnerships to be or to become
payable by the Partnerships to the Swap Banks during the month commencing on
such Monthly Transfer Date pursuant to the Swaps, over (2) the aggregate
amount of all funds then on deposit in the Other Obligations Subfund of the
Interest Fund;
to the L/C Fund, the excess, if any, of (a) the amount estimated by the
Partnerships to be or become due and payable to the Project Letter of Credit
Banks pursuant to the Project Letter of Credit Facility during the month
D-4
commencing on such Monthly Transfer Date (other than the principal amount of
and interest on any reimbursement obligation and any interest payable
thereunder) over (b) the aggregate amount of all funds then on deposit in
the L/C Fee Fund;
to the respective Subfunds of the Principal Fund, the amounts hereinafter
set forth (or a ratable portion of each such amount to each such Subfund, in
the event of a shortfall): (a) to the Note Subfund of the Principal Fund,
the excess, if any, of (1) the aggregate principal amount of the Project
Notes due and payable on the principal payment date for such Project Notes
first following such Monthly Transfer Date (or, if such Monthly Transfer
Date is an interest payment date, then on such date) over (2) the aggregate
amount of all funds then on deposit in the Note Subfund of the Principal
Fund and (b) to the Other Obligations Subfund of the Principal Fund, the
excess, if any, of (1) the sum of (A) the Aggregate Amortization Reserve
Amount, plus (B) without duplication of (A) above, the principal amount
estimated by the Partnerships to be or become due and payable during the
month commencing on such Monthly Transfer Date in respect of any Permitted
Purchase Money Indebtedness as a consequence of the sale or other
disposition, consistent with the provisions of the Project Indenture and the
Project Security Documents, of any property or asset to which such Permitted
Purchase Money Indebtedness relates, plus (C) without duplication of (A) or
(B) above, the principal amount estimated by the Partnerships to be or
become due and payable during the six-month period commencing on such
Monthly Transfer Date in respect of Permitted Purchase Money Indebtedness
and/or Permitted Unsecured Indebtedness, but only to the extent that the sum
of such principal payments exceeds the amount of funds on deposit in the
Other Obligations Subfund after giving effect to (A) and (B) above and
provided that no transfer described in this clause (C) is permitted unless
the amounts then on deposit in the Debt Service Reserve Fund, the Gas
Transmission Reserve Fund and the Gas Supply Reserve Fund equal or exceed
the amounts then required to be on deposit in each such Fund as set forth in
the Project Indenture, over (2) the aggregate amount of all funds then on
deposit in the Other Obligations Subfund of the Principal Fund;
to the Subordinated Management Fee Subfund of the Operating Fund, the
excess, if any, of (x) the amount set forth in the Applicable Monthly
Transfer Certificate as the amount of Operating Expenses constituting
Subordinated Management Fees that are due and payable or estimated to become
due and payable during the Monthly Transfer Period commencing on such
Monthly Transfer Date, over (y) the aggregate amount of all funds then on
deposit in the Subordinated Management Fee Subfund of the Operating Fund;
to the Tax Payment Subfund of the Partnership Distribution Fund, the excess,
if any, of (a) the aggregate amount of Tax Requirements estimated by the
Partnerships to be or become due and payable on Quarterly Tax Payment Dates
during the six month period following such Monthly Transfer Date (such
estimated amount hereinafter the "Estimated Semi-Annual Tax Requirements")
over (b) the aggregate amount of all funds then on deposit in the Tax
Payment Subfund of the Partnership Distribution Fund;
to the Debt Service Reserve Fund, the excess, if any, of (a) the then
current Debt Service Reserve Requirement over (b) the aggregate amount of
all funds then on deposit in the Debt Service Reserve Fund;
on each Gas Transmission Reserve Contribution Date, to the Gas Transmission
Reserve Fund, the excess, if any, of (a) the then current Gas Transmission
Reserve Requirement over (b) the aggregate amount of all funds then on
D-5
deposit in the Gas Transmission Reserve Fund, provided that the aggregate
amount of transfers described in this clause (ix) shall not exceed the sum
of (1) $10.6 million plus (2) the aggregate amount of all withdrawals from
the Gas Transmission Reserve Fund made to satisfy deficiencies in other
Funds, as described herein; and
to the Partnership Suspense Fund, the remaining balance, if any, on deposit
in the Revenue Fund on such date.
Certain provisions of the Project Indenture permit ESI Tractebel Funding and
the Partnerships to contest various claims and other items that otherwise would
not be permitted provided that such contest is a Good Faith Contest, which
requires, among other things, the establishment of accounting reserves to the
extent required by GAAP ("GAAP Reserves") and certain cash reserves in an amount
equal to any such GAAP Reserves less the amount of any asset which GAAP allows
to be established in connection therewith representing a source of payment for
the contested item ("Good Faith Contest Reserves"). On the first Monthly
Transfer Date following the establishment of GAAP Reserves relating to a Good
Faith Contest and on each Monthly Transfer Date thereafter for so long as any
such GAAP Reserves are maintained, the Project Trustee is required to transfer
to the Good Faith Contest Fund from funds available in the Revenue Fund in the
same manner and priority as if the potential obligation giving rise to such Good
Faith Contest was being paid without contest and was then due and payable, the
excess, if any, of (a) the aggregate amount of all Good Faith Contest Reserves
relating to such GAAP Reserves over (b) the aggregate amount of all funds then
on deposit in the Good Faith Contest Fund.
Working Capital Fund
Amounts on deposit in the Working Capital Fund are to be applied for the
payment of principal, interest, fees and other amounts payable pursuant to the
Working Capital Facility.
If at any time the amount of funds in the Working Capital Fund is
insufficient to pay (i) the principal of any loans then due under the Working
Capital Facility which the Partnerships may not elect to repay at a later date
or (ii) any interest, fees or other amounts then due thereunder (a "Working
Capital Payment Deficiency"), then the Project Trustee is required, upon receipt
of an officer's certificate of the Partnerships, or, if the Partnerships fail to
deliver such certificate, a certificate from the Working Capital Banks, to
transfer to the Working Capital Fund an amount equal to such Working Capital
Payment Deficiency from the following Funds in the following order of priority:
the General Subfund of the Partnership Distribution Fund; the Partnership
Suspense Fund; the Gas Supply Reserve Fund; the Gas Transmission Reserve Fund;
the Debt Service Reserve Fund; the Tax Payment Subfund of the Partnership
Distribution Fund; the Subordinated Management Fee Subfund of the Operating
Fund; each Subfund of the Principal Fund (ratably in proportion to the amounts
on deposit in such Subfunds); the L/C Fee Fund; each Subfund of the Interest
Fund (ratably in proportion to the amounts on deposit in such Subfunds); the
Major Overhaul Reserve Fund; and the General Subfund of the Operating Fund.
In the event that at any time the Partnerships deliver an officer's
certificate to the Project Trustee to the effect that a surplus of funds exists
in the Working Capital Fund, the Project Trustee is required to transfer from
the Working Capital Fund to any other Fund specified in such officer's
certificate an amount equal to such surplus (or any portion thereof specified in
such officer's certificate).
Operating Fund
General Subfund
Amounts on deposit in the General Subfund of the Operating Fund are to be
applied (i) to fund any Operating Account (to be used for the payment of
Operating Expenses, excluding Subordinated Management Fees) and (ii) for the
payment when due of Operating Expenses (excluding Subordinated Management Fees).
D-6
If at any time the amount of funds in the General Subfund of the Operating
Fund and Operating Accounts is insufficient to pay Operating Expenses (excluding
Subordinated Management Fees) then due (an "Operating Expense Deficiency"), then
the Project Trustee is required, upon receipt of an officer's certificate of
either Partnership or ESI Tractebel Funding, to transfer to the General Subfund
of the Operating Fund an amount equal to such Operating Expense Deficiency from
the following Funds in the following order of priority: the General Subfund of
the Partnership Distribution Fund; the Partnership Suspense Fund; the Gas Supply
Reserve Fund; the Gas Transmission Reserve Fund; the Debt Service Reserve Fund;
the Tax Payment Subfund of the Partnership Distribution Fund; the Subordinated
Management Fee Subfund of the Operating Fund; each Subfund of the Principal Fund
(ratably in proportion to the amounts on deposit in such Subfunds); the L/C Fee
Fund; each subfund of the Interest Fund (ratably in proportion to the amounts on
deposit in such Subfunds); the Major Overhaul Reserve Fund; and the Revenue
Fund; provided that no such amounts may be transferred (other than from the
General Subfund of the Partnership Distribution Fund and the Partnership
Suspense Fund) unless a Partnership or ESI Tractebel Funding also certifies that
the Operating Expense Deficiency has been determined after borrowing and
applying all amounts under the Working Capital Facility available for the
purpose.
Subordinated Management Fee Subfund
Amounts on deposit in the Subordinated Management Fee Subfund of the
Operating Fund are to be applied solely for the payment of Operating Expenses
constituting Subordinated Management Fees then due. The Project Trustee will
from time to time disburse monies in the Subordinated Management Fee Subfund of
the Operating Fund as directed in writing by an authorized representative of
either Partnership.
If at any time the amount of funds in the Subordinated Management Fee
Subfund of the Operating Fund is insufficient to pay the Operating Expenses then
due constituting Subordinated Management Fees (a "Subordinated Management Fee
Deficiency"), the Project Trustee is required, upon receipt of an officer's
certificate of the applicable Partnership, to transfer to the Subordinated
Management Fee Subfund of the Operating Fund an amount equal to the amount of
such Subordinated Management Fee Deficiency from the following funds in the
following order of priority: the General Subfund of the Partnership Distribution
Fund and the Partnership Suspense Fund.
Major Overhaul Reserve Fund
Amounts on deposit in the Major Overhaul Reserve Fund are to be applied to
pay Major Overhaul Expenses, subject to certain conditions set forth in the
Project Indenture relating to requisitions to be submitted to the Project
Trustee by the applicable Partnership. In the event that the balance on deposit
in the Major Overhaul Reserve Fund is insufficient to pay any Major Overhaul
Expense, such expense will constitute an Operating Expense and be payable from
funds on deposit in the General Subfund of the Operating Fund.
The amounts scheduled to be deposited in the Major Overhaul Reserve Fund
have been determined on the assumption that, upon expiration of the O&M
Agreements (which provide for Major Overhaul Expenses to be paid by the
Operator), the Operator (or its successor) will cease to pay any Major Overhaul
Expenses. In the event that either O&M Agreement is amended or replaced (by the
New O&M Agreements or otherwise) in order to provide for the payment by an
D-7
Operator for either Project of all or any portion of any Major Overhaul
Expenses, then the Independent Engineer will revise the amounts scheduled to be
deposited in the Major Overhaul Reserve Fund in accordance with the Project
Indenture and certify such revised amounts to the Project Trustee. If the
Independent Engineer determines that, as a result of such revision, there are
any excess amounts then on deposit in the Major Overhaul Reserve Fund, such
excess will be transferred to the Revenue Fund.
Interest Fund
Note Subfund
Amounts on deposit in the Note Subfund of the Interest Fund are to be
applied for the payment when due (whether at stated maturity or on call for
redemption or by acceleration or otherwise) of interest on the Project Notes
(for application to the payment of interest on the Project Securities). At the
time any payment of interest on the Project Notes is due, the Project Trustee is
required to withdraw the amount of such payment from the Note Subfund of the
Interest Fund for application toward interest then due and payable in respect of
the Project Notes (for application to the payment of interest on the Project
Securities on behalf of ESI Tractebel Funding).
If at any time the amount of funds in the Note Subfund of the Interest Fund
is insufficient to pay any interest on the Project Notes then due (a "Note
Interest Deficiency"), then the Project Trustee is required to (i) notify the
Partnerships of such Note Interest Deficiency, and (ii) subject to the proviso
below, transfer to the Note Subfund of the Interest Fund an amount equal to such
Note Interest Deficiency from the following Funds in the following order of
priority: the Other Obligations Subfund of the Interest Fund; the General
Subfund of the Partnership Distribution Fund; the Partnership Suspense Fund; the
Gas Supply Reserve Fund; the Debt Service Reserve Fund; the Tax Payment Subfund
of the Partnership Distribution Fund; the Subordinated Management Fee Subfund of
the Operating Fund; each Subfund of the Principal Fund (ratably in proportion to
the amounts on deposit in such Subfunds); and the L/C Fee Fund; provided that
the Partnerships may (but except as described below, are not obligated to)
borrow funds available under the Working Capital Facility and pay such funds to
the Project Trustee for application toward interest then due in respect of the
Project Notes and the amount of the transfers referred to above will be reduced
by the amount of such payment to the Project Trustee. The transfers to the Note
Subfund described above are required to be made (a) on the date interest on the
Project Notes first becomes due, if such transfer is from the Other Obligations
Subfund of the Interest Fund, the General Subfund of the Partnership
Distribution Fund, or the Partnership Suspense Fund, (b) on the first business
day thereafter, if such transfer is from the Gas Supply Reserve Fund, the Gas
Transmission Reserve Fund, or the Debt Service Reserve Fund, and (c) on the
third business day thereafter, if such transfer is from any other Fund. On the
second business day following the occurrence of any Note Interest Deficiency, or
as promptly thereafter as is reasonably possible (and in any event within two
business days of receipt of notice from the Project Trustee of any Note Interest
Deficiency), the Partnerships are required to borrow all amounts available to be
borrowed for the purpose under the Working Capital Facility, to the extent of
the Note Interest Deficiency at the time of such borrowing, and the funds so
borrowed are to be paid to the Project Trustee for application toward interest
then due in respect of the Project Notes.
In the event that at any time a surplus of funds exists in the Note Subfund
of the Interest Fund, the Project Trustee is required to (i) notify the
Partnerships of the existence and amount of such surplus and (ii) upon receipt
of written direction from an authorized representative of the Partnerships,
transfer from the Note Subfund of the Interest Fund to the Revenue Fund or any
other Fund specified by the Partnerships that is senior to the Interest Fund in
the order of priority set forth in the Indenture an amount equal to such surplus
(or any portion thereof specified in such written direction).
D-8
Other Obligations Subfund
Amounts on deposit in the Other Obligations Subfund of the Interest Fund are
to be applied to the payment when due of interest in respect of Permitted
Purchase Money Indebtedness, interest in respect of Permitted Unsecured
Indebtedness and payments to Swap Banks pursuant to the Swaps, if any
(collectively, "Other Interest Obligations").
If at any time the amount of funds in the Other Obligations Subfund of the
Interest Fund is insufficient to pay any Other Interest Obligations then due (an
"Other Interest Obligations Deficiency"), then the Project Trustee is required,
upon receipt of an officer's certificate of the applicable Partnership, to
transfer to the Other Obligations Subfund of the Interest Fund an amount equal
to such Other Interest Obligations Deficiency from the following Funds in the
following order of priority: the Note Subfund of the Interest Fund; the General
Subfund of the Partnership Distribution Fund; the Partnership Suspense Fund; the
Gas Supply Reserve Fund; the Gas Transmission Reserve Fund; the Debt Service
Reserve Fund; the Tax Payment Subfund of the Partnership Distribution Fund; the
Subordinated Management Fee Subfund of the Operating Fund; each Subfund of the
Principal Fund (ratably in proportion to the amounts on deposit in such
Subfunds); and the L/C Fee Fund; provided that no such amounts may be
transferred (other than from the General Subfund of the Partnership Distribution
Fund and the Partnership Suspense Fund) unless the applicable Partnership also
certifies that the Other Interest Obligations Deficiency has been determined
after borrowing and applying all amounts under the Working Capital Facility
available for the purpose.
In the event that at any time the Partnerships deliver an officer's
certificate to the Project Trustee to the effect that a surplus of funds exists
in the Other Obligations Subfund of the Interest Fund, the Project Trustee is
required to transfer from the Other Obligations Subfund of the Interest Fund to
the Revenue Fund or any other Fund specified by the Partnerships that is senior
to the Interest Fund in the order of priority set forth in the Project Indenture
an amount equal to such surplus (or any portion thereof specified in such
officer's certificate).
L/C Fee Fund
Amounts on deposit in the L/C Fee Fund are to be applied to the payment when
due of amounts payable to the Project Letter of Credit Banks pursuant to the
Project Letter of Credit Facility (other than the principal sum of any
reimbursement obligations or derivative loans payable thereunder) ("L/C
Payables").
If at any time the amount of funds in the L/C Fee Fund is insufficient to
pay any L/C Payables then due (an "L/C Payable Deficiency"), then the Project
Trustee is required, upon receipt of an officer's certificate of the
Partnerships, to transfer to the L/C Fee Fund an amount equal to such L/C
Payable Deficiency from the following Funds in the following order of priority:
the General Subfund of the Partnership Distribution Fund; the Partnership
Suspense Fund; the Gas Supply Reserve Fund; the Gas Transmission Reserve Fund;
the Debt Service Reserve Fund; the Tax Payment Subfund of the Partnership
Distribution Fund; the Subordinated Management Fee Subfund of the Operating
Fund; and each Subfund of the Principal Fund (ratably in proportion to the
amounts on deposit in such Subfunds); provided that no such amounts may be
transferred (other than from the General Subfund of the Partnership Distribution
Fund and the Partnership Suspense Fund) unless the Partnerships also certify
that the L/C Payable Deficiency has been determined after borrowing and applying
all amounts under the Working Capital Facility available for the purpose.
D-9
In the event that at any time the Partnerships deliver an officer's
certificate to the Project Trustee to the effect that a surplus of funds exists
in the L/C Fee Fund, the Project Trustee is required to transfer from the L/C
Fee Fund to the Revenue Fund or any other Fund specified by the Partnerships
that is senior to the L/C Fee Fund in the order of priority set forth in the
Project Indenture an amount equal to such surplus (or any portion thereof
specified in such officer's certificate).
Principal Fund
Note Subfund
Amounts on deposit in the Note Subfund of the Principal Fund are to be
applied for the payment when due (whether at stated maturity or on call for
redemption or by acceleration or otherwise) of principal of the Project Notes
(for application to the payment of principal of the Project Securities). At the
time any payment of principal of the Project Notes is due, the Project Trustee
is required to withdraw the amount of such payment from the Note Subfund of the
Principal Fund for application toward the principal then due and payable in
respect of the Project Notes (for application to the payment of principal of the
Project Securities on behalf of the ESI Tractebel Funding).
If at any time the amount of funds in the Note Subfund of the Principal Fund
is insufficient to pay any principal of the Project Notes then due (a "Note
Principal Deficiency"), then the Project Trustee is required to (i) notify the
Partnerships of such Note Principal Deficiency, and (ii) subject to the proviso
below, transfer to the Note Subfund of the Principal Fund an amount equal to
such Note Principal Deficiency from the following Funds in the following order
of priority: the Other Obligations Subfund of the Principal Fund; the General
Subfund of the Partnership Distribution Fund; the Partnership Suspense Fund; the
Gas Supply Reserve Fund; the Gas Transmission Reserve Fund; the Debt Service
Reserve Fund; the Tax Payment Subfund of the Partnership Distribution Fund; and
the Subordinated Management Fee Subfund of the Operating Fund; provided that the
Partnerships may (but except as described below are not obligated to) borrow
funds available under the Working Capital Facility and pay such funds to the
Project Trustee for application toward principal then due in respect of the
Project Notes and the amount of the transfers referred to above shall be reduced
by the amount of such payment to the Project Trustee. The transfers to the Note
Subfund described above are required to be made (a) on the date principal on the
Project Notes first becomes due, if such transfer is from the Other Obligations
Subfund of the Principal Fund, the General Subfund of the Partnership
Distribution Fund or the Partnership Suspense Fund, (b) on the first business
day thereafter, if such transfer is from the Gas Supply Reserve Fund, the Gas
Transmission Reserve Fund or the Debt Service Reserve Fund and (c) on the third
business day thereafter, if such transfer is from the Tax Payment Subfund of the
Partnership Distribution Fund. On the second business day following the
occurrence of any Note Principal Deficiency, or as promptly thereafter as is
reasonably possible (and in any event within two business days of receipt from
the Project Trustee of notice of any Note Principal Deficiency) the Partnerships
are required to borrow all amounts available to be borrowed under the Working
Capital Facility for the purpose, to the extent of such Note Principal
Deficiency at the time of such borrowing, and the funds so borrowed are to be
paid to the Project Trustee for application toward principal then due in respect
of the Project Notes.
In the event that at any time a surplus of funds exists in the Note Subfund
of the Principal Fund, the Project Trustee is required to (i) notify the
Partnerships of the existence and amount of such surplus and (ii) upon receipt
of written direction from an authorized representative of the Partnerships,
D-10
transfer from the Note Subfund of the Principal Fund to the Revenue Fund or any
other Fund specified by the Partnerships that is senior to the Interest Fund in
the order of priority set forth in the Project Indenture an amount equal to such
surplus (or any portion thereof specified in such written direction).
Other Obligations Subfund
Amounts on deposit in the Other Obligations Subfund of the Principal Fund
are to be applied (i) to the payment when due of principal in respect of
Permitted Purchase Money Indebtedness or Permitted Unsecured Indebtedness
("Other Principal Obligations") or (ii) to the prepayment of Other Principal
Obligations, but only if, at the time of such proposed prepayment, the Project
Trustee has received an officer's certificate of the Partnerships to the effect
that after giving effect to such prepayment the aggregate amount of funds
remaining on deposit in the Other Obligations Subfund of the Principal Fund will
not be less than the sum of (x) the Aggregate Amortization Reserve Amount plus
(y) the amount of any funds previously deposited to such Subfund pursuant to the
provisions of the Project Indenture described in clauses (b)(2)(B) and (b)(2)(C)
of clause (vi) above under "The Funds -- Revenue Fund" and not yet applied to
pay or prepay the Other Principal Obligations in respect of which such deposits
were made or otherwise withdrawn from such Subfund pursuant to the Project
Indenture.
If at any time the amount of funds in the Other Obligations Subfund of the
Principal Fund is insufficient to pay any Other Principal Obligations then due
(an "Other Principal Obligation Deficiency"), then the Project Trustee is
required, upon receipt of an officer's certificate of the applicable
Partnership, to transfer to the Other Obligations Subfund of the Principal Fund
an amount equal to such Other Principal Obligation Deficiency from the following
Funds in the following order of priority: the Note Subfund of the Principal
Fund; the General Subfund of the Partnership Distribution Fund; the Partnership
Suspense Fund; the Gas Supply Reserve Fund; the Gas Transmission Reserve Fund;
the Debt Service Reserve Fund; the Tax Payment Subfund of the Partnership
Distribution Fund; and the Subordinated Management Fee Subfund of the Operating
Fund; provided that no such amounts may be transferred (other than from the
General Subfund of the Partnership Distribution Fund and the Partnership
Suspense Fund) unless the applicable Partnership also certifies that the Other
Principal Obligation Deficiency has been determined after borrowing and applying
all amounts under the Working Capital Facility available for the purpose.
In the event that at any time the Partnerships deliver an officer's
certificate to the Project Trustee to the effect that a surplus of funds exists
in the Other Obligations Subfund of the Principal Fund, the Project Trustee is
required to transfer from the Other Obligations Subfund of the Principal Fund to
the Revenue Fund or any other Fund specified by the Partnerships that is senior
to the Other Obligations Subfund of the Principal Fund in the order of priority
set forth in the Project Indenture an amount equal to such surplus (or any
portion thereof specified in such officer's certificate).
Debt Service Reserve Fund
Amounts on deposit in the Debt Service Reserve Fund are to be applied to
cover deficiencies in certain other Funds as described herein. At any time,
either Partnership may, in lieu of funding the Debt Service Reserve Fund with
cash, deliver to the Project Trustee one or more Substitute Letters of Credit in
an aggregate maximum amount available to be drawn thereunder, without
duplication, equal to all or any portion of the then current Debt Service
Reserve Requirement, provided that any Substitute Letter of Credit will be in a
minimum amount of $1 million. The Debt Service Reserve Fund is deemed to be
funded to the extent amounts are available to be drawn by the Project Trustee
under any Substitute Letter of Credit.
D-11
If on any Monthly Transfer Date the balance on deposit in the Debt Service
Reserve Fund exceeds the then current Debt Service Reserve Requirement, any such
excess funds are required to be transferred to the Revenue Fund, unless such
excess is attributable to any Substitute Letter of Credit, in which case the
Project Trustee shall not draw on such Substitute Letter of Credit but shall
take such action as ESI Tractebel Funding shall reasonably direct in order to
reduce the stated amount of such Substitute Letter of Credit by the amount of
the excess.
Gas Transmission Reserve Fund
Commencing on the first Monthly Transfer Date occurring at least one month
after October 31, 2006 (subject to extension to a later date in the event of an
extension of the term of each Transco Agreement that satisfies certain
conditions set forth in the Project Indenture), and on each Monthly Transfer
Date thereafter, a portion (or the remaining balance) of amounts on deposit in
the Gas Transmission Reserve Fund are to be transferred to the Revenue Fund
pursuant to a formula set forth in the Project Indenture. The amount to be
transferred on each such Monthly Transfer Date will be the lesser of (a) the
remaining balance on deposit in the Gas Transmission Reserve Fund and (b) an
amount equal to the product of (i) the excess, if any, of (A) the all-inclusive
weighted-average per unit cost for gas transportation (including the allocable
portion of any demand charges) between the receipt and delivery points on the
Leidy line specified in the Transco Agreements (and/or any applicable substitute
receipt and delivery points) paid by the Partnerships in the preceding month,
over (B) the all-inclusive per unit cost for gas transportation on the Leidy
line under the Transco Agreements as of the commencement date of transfers from
the Gas Transmission Reserve Fund, multiplied by (ii) the excess, if any, of (A)
70,836 MMBtus per day multiplied by 30 days over (B) the contracted volume of
gas, if any, entitled to be transported between such receipt and delivery points
during such month pursuant to any agreement which resulted in an extension or
replacement of a Transco Agreement and that satisfies certain conditions set
forth in the Project Indenture.
The Project Indenture also provides for (a) the transfer to the Revenue Fund
of the entire balance on deposit in the Gas Transmission Reserve Fund in certain
events involving the extension or replacement of the Transco Agreements in
accordance with conditions set forth in the Project Indenture and (b)
recomputation of the Gas Transmission Reserve Requirement, and transfer to the
Revenue Fund of any resulting surplus funds in the Gas Transmission Reserve
Fund, in certain other events involving the extension or replacement of the
Transco Agreements in accordance with conditions set forth in the Project
Indenture.
Gas Supply Reserve Fund
At the time of issuance of the Original Project Securities, the agreements
extending the term of the ProGas Agreements from 2006 to 2013 remained subject
to certain contingencies. In order to mitigate the risk that such extensions
might ultimately be ineffective, the Project Indenture provides for the
establishment of a Gas Supply Reserve Fund. However, such extensions have since
become final and non-appealable and, accordingly, there is no requirement to
fund the Gas Supply Reserve Fund.
Partnership Suspense Fund and General Subfund of Partnership Distribution Fund
On any day on which the Partnerships are entitled to transfer funds from the
Partnership Suspense Fund pursuant to the Project Indenture, the Project Trustee
D-12
is required, upon receipt of a Restricted Payment Certificate from the
Partnerships as contemplated by the Project Indenture, to transfer from the
Partnership Suspense Fund to the General Subfund of the Partnership Distribution
Fund the amount specified in such Restricted Payment Certificate. The conditions
to such transfers and limitations on the amounts that may be so transferred are
described below under "Certain Covenants -- Restricted Payments."
The Project Indenture also requires the Project Trustee, upon receipt of
instructions from the Partnerships, to (i) transfer any funds on deposit in the
Partnership Suspense Fund to any other Fund specified by the Partnerships that
is senior to the Partnership Suspense Fund in the order of priority set forth in
the Project Indenture or (ii) disburse any funds on deposit in the Partnership
Suspense Fund for the payment of any obligation of either or both Partnerships;
provided that, in the case of any such disbursement described in clause (ii),
the Partnerships will be required to certify that such payment does not
constitute a Restricted Payment and will not violate any provision of the
Project Indenture or any other Project Credit Document.
The Partnerships may from time to time withdraw any funds on deposit in the
General Subfund of the Partnership Distribution Fund, without restriction, and
such funds may be disbursed for any purpose, including for Restricted Payments.
Tax Payment Subfund of Partnership Distribution Fund
Amounts on deposit in the Tax Payment Subfund of the Partnership
Distribution Fund are to be released to the Partnerships by the Project Trustee
upon receipt of a duly completed Tax Withdrawal Certificate from the
Partnerships specifying the amount to be released (calculated by reference to
Tax Requirements payable within 30 days thereafter). Amounts so released may be
distributed by the Partnerships to the Partners without restriction.
If at the time of delivery of a Tax Withdrawal Certificate the amount of
funds in the Tax Payment Subfund is less than the amount specified in the Tax
Withdrawal Certificate to be released (a "Tax Requirements Deficiency"), then
the Project Trustee is required to transfer to the Tax Payment Subfund an amount
equal to such Tax Requirements Deficiency from the following Funds in the
following order of priority: the General Subfund of the Partnership Distribution
Fund; the Partnership Suspense Fund; the Gas Supply Reserve Fund; the Gas
Transmission Reserve Fund; and the Debt Service Reserve Fund; provided that no
such amounts may be transferred (other than from the General Subfund of the
Partnership Distribution Fund and the Partnership Suspense Fund) unless the
Partnerships certify that the Tax Requirements Deficiency has been determined
after borrowing and applying all amounts under the Working Capital Facility
available for the purpose.
In the event that at any time the balance on deposit in the Tax Payment
Subfund exceeds the Estimated Semi-Annual Tax Requirements set forth in the most
recent Applicable Monthly Transfer Certificate, the Partnerships are required to
direct the Project Trustee to transfer the amount of such surplus from the Tax
Payment Subfund to the Revenue Fund or any other fund that is senior to the Tax
Payment Subfund in the order of priority set forth in the Project Indenture.
Good Faith Contest Fund
Amounts on deposit in the Good Faith Contest Fund are to be applied to the
payment of obligations relating to contested matters giving rise to deposits to
the Good Faith Contest Fund ("Good Faith Contest Obligations"). In the event
D-13
that the balance on deposit in the Good Faith Contest Fund is insufficient to
pay any Good Faith Contest Obligation, such excess Good Faith Contest Obligation
shall constitute an Operating Expense and shall be paid upon final resolution or
settlement of the contested item giving rise to such Good Faith Contest
Obligation from funds on deposit in the General Subfund of the Operating Fund.
In the event that at any time the Partnerships deliver an officer's
certificate to the Project Trustee to the effect that a surplus exists in the
Good Faith Contest Fund, the Project Trustee is required to transfer the amount
of such surplus from the Good Faith Contest Fund to the Revenue Fund.
Investment of Funds
The Project Trustee is required to invest the moneys on deposit in the Funds
as directed by the Partnerships in Permitted Investments with maturities of one
year or less from, or which permit redemption at the option of the holder within
one year of, the date of investment or reinvestment (or with a longer maturity
if the holder of such Permitted Investment may redeem without restriction or
penalty amounts required by the terms of the Project Indenture to be applied to
a particular purpose, at the time so required), provided that, when an Event of
Default has occurred and is continuing, Permitted Investments must have a
maturity of 30 days or less. The Partnerships are required to select investments
that, in their reasonable opinion, will mature or be subject to redemption at
the option of the holder thereof in the amounts and at the times needed for the
purposes of the funds invested. The Project Trustee is not liable for any loss
incurred on the liquidation of investments. Profits from Permitted Investments
are required to be deposited into the Revenue Fund. Losses on Permitted
Investments are to be charged to the applicable Fund.
Identity and Qualifications of Independent Experts
The Project Indenture provides for the appointment of Independent Experts,
consisting of an Independent Engineer (currently Sargent & Lundy), an
Independent Gas Consultant (currently Schlesinger and Associates) and an
Independent Insurance Consultant.
The Partnerships may at any time remove any Independent Expert, subject to
certain restrictions set forth in the Project Indenture. If an Independent
Expert fails to be independent (within the meaning specified in the Project
Indenture), or becomes incapable of acting or fails to perform its functions
contemplated under the Project Indenture, or becomes subject to certain events
of bankruptcy or insolvency, then the Project Trustee may (and, if requested to
do so by holders of a majority of the aggregate principal amount of the
outstanding Project Securities, is required to) remove such Independent Expert.
Upon the resignation or removal of any Independent Expert, the Partnerships are
required to appoint a successor, which must be a nationally recognized
engineering firm, gas consulting firm or insurance consulting firm, as
applicable, selected by the Partnerships and not objected to by the Project
Trustee within 10 days after notice (an "Eligible Successor"). If the
Partnerships fail to appoint a successor within 30 days of notice of such
resignation or removal, the Project Trustee is then required to appoint a
successor from among the Eligible Successors. The Partnerships will compensate
the Independent Experts for their services in accordance with such arrangements
as may be agreed by the Partnerships with such Independent Experts.
D-14
Certain Covenants
Insurance
The Partnerships are required at all times to maintain, with responsible
insurance carriers, and periodically to provide evidence of, the following
insurance coverages: worker's compensation insurance (as required by law);
general liability insurance; automobile liability insurance; excess liability
insurance covering claims in excess of the Partnerships' primary worker's
compensation, general liability and automobile liability coverage with a minimum
limit per occurrence (when combined with such primary insurance coverages) of
$19 million, subject to inflation; physical damage insurance in a minimum
aggregate amount equal to replacement value (subject to a sublimit for earth
movement and flood); boiler and machinery insurance in a minimum amount equal to
replacement value plus expediting expenses of $1 million; and business
interruption insurance insuring gross earnings for a period of 12 months (with a
maximum deductible of 60 days). Notwithstanding the foregoing, (i) the
Partnerships may satisfy the requirements for workers' compensation insurance,
general liability insurance, automobile liability insurance and excess liability
insurance described above by being added as a named insured to insurance
coverages maintained by the Operator, and (ii) if at any time any of the
required insurance shall no longer be available on commercially reasonable
terms, the Partnerships are required to procure substitute insurance coverage
that is the most equivalent to the required coverage and available on
commercially reasonable terms (and such substitute insurance coverage shall be
deemed to satisfy the applicable insurance requirement) or, if no such
substitute coverage is available on commercially reasonable terms, then such
insurance coverage shall not be required. The Partnerships are permitted to have
deductibles under the required insurance coverages, subject to limitations
specified in the Project Indenture.
Limitations on Debt
ESI Tractebel Funding is not permitted to create or incur or suffer to exist
any Debt, except for: (i) the Original Project Securities; (ii) the Project
Securities; and (iii) any Additional Project Securities issued (a) to provide a
source of funds for the construction of Required Improvements, (b) to furnish
cash collateral to secure Energy Bank Obligations (or to secure obligations with
respect to Project Letters of Credit issued to support Energy Bank Obligations)
arising as a result of Power Purchase Agreements (or amendments thereto) entered
into after the date of the Project Indenture to sell electrical energy or
capacity at levels in excess of those contracted for under the existing Power
Purchase Agreements ("Additional Cash Collateral Proceeds") or (c) to the extent
directed to do so by ESI Tractebel Funding or required pursuant to the
applicable series supplemental indenture, (i) to pay any fees or costs
associated with the issuance of the Additional Project Securities or (ii) to
fund the Debt Service Reserve Fund to the extent that the balance in such Fund
upon issuance of such Additional Project Securities is less than the Debt
Service Reserve Requirement upon such issuance; provided that (A) any such
Required Improvements must be subject to the Lien granted to the Collateral
Agent pursuant to the Project Security Documents; (b) such Additional Project
Securities must be issued under the Project Indenture and subject to the
Collateral Agency Agreement; (C) the proceeds from the sale of such Additional
Project Securities must be loaned to the Partnerships and Project Notes must be
issued under the Project Credit Agreement to evidence such loans, which Project
Notes must be pledged to the Collateral Agent, (D) until applied, such proceeds
must be pledged to the Collateral Agent and deposited with the Project Trustee
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in accordance with the Project Indenture, (E) no more than an aggregate
principal amount of $100 million of such Additional Project Securities may be
issued and outstanding at any time, with a sublimit of no more than $25 million
of such outstanding Additional Project Securities that were issued for the
purpose of providing Additional Cash Collateral Proceeds, (F) the Partnerships
must certify to the Project Trustee that any such Required Improvements are
necessary to comply with a change in Environmental Laws or other Government
Rules (or interpretation thereof) or to maintain the QF status of the applicable
Project, (G) the Partnerships must certify to the Project Trustee that the
proceeds from the issuance of any such Additional Project Securities for the
construction of Required Improvements (together with any other funds available
for the purpose) are sufficient for the purposes for which such Additional
Project Securities were issued and (H) the Partnerships must certify to the
Project Trustee that after giving effect to the issue of the Additional Project
Securities and application of the proceeds therefrom, the minimum annual
Projected Debt Service Coverage Ratio for any calendar year commencing with the
year in which such Additional Project Securities are issued through the year in
which the final maturity date of the Project Securities occurs will not be less
than 1.0:1 and the average annual Projected Debt Service Coverage Ratio for all
such calendar years will not be less than 1.1:1.
Neither Partnership is permitted to create or incur or suffer to exist any
Debt, except for: (i) Debt arising under the Project Credit Agreement in an
aggregate principal amount equal to the aggregate outstanding principal amount
of the Project Securities and any Additional Project Securities; (ii) Debt in
respect of Project Letters of Credit in an aggregate amount at no time greater
than the lesser of (a) the combined maximum amount of the Energy Bank
Obligations for both Partnerships required by the terms of any Power Purchase
Agreement to be supported by Project Letters of Credit at any time prior to the
final maturity date of the Project Securities plus certain other obligations as
provided in the Project Indenture and (b) $82 million; (iii) Debt under the
Working Capital Facility in an aggregate principal amount at any time not
greater than $20 million; (iv) obligations of the Partnerships under the Swaps;
(v) Debt arising under any of the Project Documents; (vi) Subordinated Debt not
to exceed an aggregate principal amount of $50 million, the proceeds of which
are applied to the payment of Capital Expenditures for the Projects; (vii)
purchase money or lease obligations incurred to finance items of equipment not
comprising an integral part of either Project (and Debt incurred to refinance
any such obligations) provided that (a) if such obligations are secured, they
are secured only by Liens upon the equipment being financed and (b) such
obligations do not in the aggregate have annual scheduled interest, principal,
lease and purchase price installment payments in excess of $5 million (any such
permitted Debt is referred to as "Permitted Purchase Money Indebtedness");
(viii) trade accounts payable (other than for borrowed money) arising, and
accrued expenses incurred, in the ordinary course of business so long as such
trade accounts payable are payable or are paid within 90 days of the date the
respective goods are delivered or the respective services are rendered; (ix)
unsecured Debt in an aggregate outstanding principal amount at no time greater
than $10 million ("Permitted Unsecured Indebtedness"); (x) certain permitted
Project Guarantees (described below under "Limitations on Guarantees"); (xi)
Debt in respect of fuel price hedging arrangements related to the acquisition of
fuel reasonably necessary for the operation of the Projects; and (xii) Debt
incurred by either Partnership to the other Partnership.
Limitations on Liens
ESI Tractebel Funding is not permitted to create or suffer to exist or
permit any Lien upon or with respect to any of its properties, except for: (i)
Liens created or otherwise expressly permitted or required to exist by the
Project Indenture or any Project Security Document; (ii) Liens for taxes which
are either not yet due, are due but payable without penalty or are the subject
of a Good Faith Contest; (iii) legal or equitable encumbrances deemed to exist
by reason of the existence of any litigation or other legal proceedings if the
same is the subject of a Good Faith Contest; and (iv) Liens substantially
similar to any of the foregoing, provided such Lien could not reasonably be
expected to result in a Material Adverse Effect.
Neither Partnership is permitted to create or suffer to exist or permit any
Lien upon or with respect to any of its properties, except for: (i) Liens
created or otherwise expressly permitted or required to exist by the Project
Indenture of any other Project Transaction Document with respect to such
Partnership or its Property (including Liens on the Cash Collateral Proceeds to
secure the Project Letters of Credit); (ii) Liens securing Permitted Purchase
Money Indebtedness as described in clause (vii) of the second paragraph under
"Limitations on Debt" above; (iii) Liens securing fuel hedging arrangements
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related to the acquisition of fuel reasonably necessary for the operation of the
Projects, subordinated in accordance with certain requirements of the Project
Indenture; (iv) Liens for taxes which are either not yet due, are due but
payable without penalty or are the subject of a Good Faith Contest; (v) any
exceptions to title which are contained in the title insurance policies
delivered to the Project Trustee in connection with the issuance of the Project
Securities; (vi) such minor defects, easements, rights of way, restrictions,
irregularities, encumbrances and clouds on title and statutory Liens that do not
individually or in the aggregate materially impair the use of the property
affected thereby for its intended purpose; (vii) deposits or pledges to secure:
statutory or other public obligations or appeals; releases of attachments, stays
of execution or injunctions; performance of bids, tenders, contracts (other than
for the repayment of borrowed money) or leases; or for purposes of like general
nature in the ordinary course of business; (viii) Liens in connection with
workmen's compensation, unemployment insurance or other social security or
pension obligations; (ix) legal or equitable encumbrances deemed to exist by
reason of the existence of any litigation or other legal proceeding if the same
is the subject of Good Faith Contest; (x) mechanic's, workmen's, materialmen's,
construction or other like Liens arising in the ordinary course of business or
incident to the construction or improvement of any property in respect of
obligations which are not yet due or which are the subject of a Good Faith
Contest; (xi) Liens existing on property prior to the time such property is
acquired by the Partnerships and not created in contemplation of such
acquisition; and (xii) Liens substantially similar to any of the foregoing
Liens, provided such Lien could not reasonably be expected to result in a
Material Adverse Effect.
Limitations on Guarantees
ESI Tractebel Funding is not permitted to be or become liable, directly or
indirectly, in connection with any Guaranty.
Neither Partnership is permitted to be or become liable, directly or
indirectly, in connection with any Guaranty, except for: (i) Guarantees
expressly required or contemplated by the Project Transaction Documents,
including the Project Guaranty; (ii) indemnities with respect to certain unfiled
Liens permitted as described above; (iii) indemnities to Government Authorities
relating to any expenses incurred that are incidental to obtaining easements for
the benefit of either Project; (iv) Guarantees which arise by endorsement of
negotiable instruments for deposit or collection in the ordinary course of
business; (v) Guarantees by one Partnership of Permitted Indebtedness incurred
by the other Partnership; and (vi) any other Guarantees reasonably required for
the Operation of the Projects and incurred in the ordinary course of business
and in accordance with Prudent Utility Practices.
Prohibition on Fundamental Changes and Disposition of Assets
ESI Tractebel Funding is not permitted to Transfer or lease (as lessor) any
of its Property except as contemplated by certain of the Project Security
Documents and except as payment of its obligations permitted under the Project
Indenture. Neither Partnership is permitted to Transfer or lease (as lessor) any
Property material to the operation of the Projects except (i) as contemplated by
the Project Transaction Documents, (ii) pursuant to the NECO Lease or any
replacement or successor agreement, (iii) in the ordinary course of business and
(iv) to the extent such Property is worn out or no longer useful or useable.
Neither ESI Tractebel Funding nor either Partnership is permitted to enter
into any transaction of merger or consolidation, change its form of organization
D-17
or its business, or liquidate or dissolve, nor is it permitted to acquire all or
substantially all of the assets of any other Person; provided that either
Partnership may assign all its rights and obligations (as a whole) in respect of
the Project Transaction Documents (other than any Non-Material Project Documents
that are not assignable), its Project, all applicable Government Approvals
(other than those that are not assignable provided that the failure to do so
could not reasonably be expected to result in a Material Adverse Effect) and all
of its other Property to a corporation or other limited liability company (a
"Permitted Successor"), subject to the conditions that (a) all Voting Stock of
the Permitted Successor shall have been pledged to the Collateral Agent, (b) the
Project Trustee shall have received an officer's certificate of such Partnership
containing certain certifications specified in the Project Indenture, including
to the effect that such assignment and assumption would not result in a Default
or an Event of Default and could not reasonably be expected to result in a
Material Adverse Effect and (c) the Project Trustee shall have received an
opinion of counsel as to certain matters specified in the Project Indenture,
including opinions to the effect that (i) based upon laws in effect at the time,
after giving effect to such assignment, the aggregate amount of taxes to which
the Permitted Successor may be subject will not materially exceed the aggregate
amount of taxes to which such Partnership would have been subject if such
assignment had not been made, (ii) based upon laws in effect at the time, after
giving effect to such assignment, the amount of Tax Requirements attributable to
the Permitted Successor will not exceed the amount of Tax Requirements that
would have been attributable to such Partnership if such assignment had not been
made, (iii) all necessary consents to such assignment have been obtained and
(iv) the Permitted Successor has lawfully and validly assumed all such assigned
obligations, which obligations constitute legal, valid and binding obligations
of the Permitted Successor.
Limitations on Amendments to Project Contracts
ESI Tractebel Funding is not permitted to terminate, amend or modify any
Project Transaction Document to which it is a party or enter into any new
contract unless (i) such action is reasonably and necessarily related to the
issuance of the Project Securities or any Additional Project Securities pursuant
to the Project Indenture or the performance of its obligations under the Project
Transaction Documents and (ii) such action could not reasonably be expected to
result in a Material Adverse Effect.
Neither of the Partnerships is permitted to terminate, amend or modify any
Project Document to which it is a party or enter into any Additional Project
Document unless either: (i) such action could not reasonably be expected to (x)
result in a Material Adverse Effect or (y) except in the case of Additional
Project Documents pertaining to fuel hedging arrangements in respect of the
acquisition of fuel reasonably necessary for the operation of the Projects,
materially increase the Partnerships' contingent liabilities (including in
respect of any Energy Bank Obligations); or (ii) as a result of such action
(including, in the case of any such action with respect to a Power Purchase
Agreement, after giving effect to the issuance of any Additional Project
Securities which ESI Tractebel Funding anticipates issuing for the purpose of
furnishing Additional Cash Collateral Proceeds), the minimum annual and average
annual Projected Debt Service Coverage Ratios for any and all years commencing
with the year of effectiveness of such termination, amendment, modification or
Additional Project Document, as the case may be, through the year of the final
maturity of the Project Securities are not less than the lesser of (x) the
minimum annual and average annual Projected Debt Service Coverage Ratios for
such periods without giving effect to such termination, amendment, modification
or Additional Project Document and (y) a minimum annual Projected Debt Service
Coverage Ratio and an average annual Projected Debt Service Coverage Ratio for
such periods of 1.4:1 and 1.6:1, respectively, in each case as certified by the
Partnerships and the Independent Engineer.
Promptly upon the execution of any Additional Project Document (other than a
Non-Material Project Document), the applicable Partnership is required to take
actions necessary to grant to the Collateral Agent an assignment of such
D-18
Partnership's rights under such Additional Project Document and a Lien on all
property interests acquired by such Partnership in connection therewith
(perfected to the extent such Lien can be perfected by filing a mortgage or
fixture filing under local law or a financing statement under the UCC); provided
that no such assignment or Lien shall be required with respect to equipment
financed with Permitted Purchase Money Indebtedness if prohibited by the terms
thereof.
Restricted Payments
The Partnerships and ESI Tractebel Funding are not permitted to make any
Restricted Payment (other than (i) Management Costs, as described under "Certain
Relationships and Related Transactions -- Management Fee", which will be payable
from the Operating Fund as Operating Expenses, and (ii) distributions to
Partners from the Tax Payment Subfund as described above under "The Funds -- Tax
Payment Subfund of Partnership Distribution Fund") except from, and to the
extent of, moneys then on deposit in the General Subfund of the Partnership
Distribution Fund. The Partnerships may instruct the Project Trustee to transfer
funds from the Partnership Suspense Fund to the General Subfund of the
Partnership Distribution Fund on any day that the following conditions are
satisfied as certified by the Partnerships to the Project Trustee: (i) the
amounts on deposit in each of the General Subfund of the Operating Fund, the
Major Overhaul Reserve Fund, the Interest Fund, the L/C Fee Fund, the Principal
Fund, the Subordinated Management Fee Subfund of the Operating Fund, the Tax
Payment Subfund of the Partnership Distribution Fund, the Debt Service Reserve
Fund, the Gas Transmission Reserve Fund, the Gas Supply Reserve Fund and the
Good Faith Contest Fund shall be equal to or in excess of the minimum amount
then required to be on deposit in such Fund in accordance with the Project
Indenture; (ii) no Default or Event of Default has occurred and is continuing;
(iii) no Debt is outstanding under the Working Capital Facility; (iv) either the
Debt Service Coverage Ratio or the Substitute Debt Service Coverage Ratio for
the Rolling Prior Year shall equal or exceed 1.25:1; and (v) the Partnerships
have no knowledge of any event or circumstance that could reasonably be expected
to result in the Debt Service Coverage Ratio for the period of two consecutive
fiscal quarters commencing on the expiration date of the Rolling Prior Year,
treated as a single period, being less than 1.25:1.
Upon receipt of an officer's certificate from the Partnerships as to the
satisfaction of the foregoing conditions, the Project Trustee is required to
transfer from the Partnership Suspense Fund to the General Subfund of the
Partnership Distribution Fund the amount set forth in such officer's
certificate. The amount set forth in any such officer's certificate may not
exceed the applicable "Distributable Percentage," set forth below, of the
balance then on deposit in the Partnership Suspense Fund; provided that if the
Debt Service Coverage Ratio for the Rolling Prior Year is less than a "Hurdle
Ratio" (defined as any of the ratios set forth below in the definition of
"Distributable Percentage") and the Substitute Debt Service Coverage Ratio for
the Rolling Prior Year is greater than such Hurdle Ratio, then the amount set
forth in such officer's certificate may be increased to the "Distributable
Percentage" of the balance then on deposit in the Partnership Suspense Fund
determined as if the Debt Service Coverage Ratio were equal to such Hurdle
Ratio, but not to exceed the amount that, after giving effect to the transfer of
such amount from the Partnership Suspense Fund, would reduce the Substitute Debt
Service Coverage Ratio for the Rolling Prior Year to such Hurdle Ratio. The
applicable "Distributable Percentage" is determined as follows:
if the Debt Service Coverage Ratio for the Rolling Prior Year is greater
than or equal to 1.40:1, the "Distributable Percentage" is 100%;
D-19
if the Debt Service Coverage Ratio for the Rolling Prior Year is less than
1.40:1 but greater than or equal to 1.35:1, the "Distributable Percentage"
is 75%;
if the Debt Service Coverage Ratio for the Rolling Prior Year is less than
1.35:1 but greater than or equal to 1.30:1, the "Distributable Percentage"
is 50%; and
if the Debt Service Coverage Ratio for the Rolling Prior Year is less than
1.30:1 but greater than or equal to 1.25:1, the "Distributable Percentage"
is 25%.
Limitations on Activities of ESI Tractebel Funding and the Partnerships
ESI Tractebel Funding is not permitted to engage in any business other than
the issuance of the Project Securities and any Additional Project Securities and
the performance of the Project Transaction Documents to which it is a party.
Neither of the Partnerships is permitted to engage in any business other than
the operation of its Project as contemplated by the Project Transaction
Documents and the performance of the Project Transaction Documents to which it
is a party.
Additional Covenants
In addition to the covenants described above, the Project Indenture also
contains covenants of ESI Tractebel Funding and the Partnerships regarding:
delivery to the Project Trustee of financial statements, compliance certificates
and certain other information; maintenance of existence, properties and certain
rights; compliance with laws; payment of taxes and other claims; maintenance of
books and records; inspection rights of the Project Trustee and the Independent
Engineer; opinions of counsel regarding the maintenance of recordations and
filings; providing further assurance; replacement of O&M Agreements; employee
plans; transactions with Affiliates; delivery of certain information required to
be delivered pursuant to Rule 144A(d)(4) under the Securities Act in order to
permit compliance by a holder with Rule 144A in connection with the resale of
Original Project Securities; maintenance of Project Letters of Credit; Events of
Loss; Investment; and certain required contributions to the Revenue Fund.
Events of Default
The following events constitute "Events of Default" under the Project
Indenture:
(a) failure by ESI Tractebel Funding to pay any principal, interest or
premium, if any, on any Project Bond when the same becomes due and payable,
whether by scheduled maturity or required prepayment or by acceleration or
otherwise, and such failure continues uncured for 15 or more days;
(b) any representation or warranty made by either of the Partnerships,
ESI Tractebel Funding, NE LP or any pledgor under the ESI Tractebel Funding
Stock Pledge Agreement, in any Project Security Document or in any
representation, warranty or statement in any certificate, financial
statement or other document furnished to the Project Trustee or any other
Person by or on behalf of either of the Partnerships or ESI Tractebel
Funding under the Project Indenture or the Project Security Documents shall
prove to have been false or misleading in any material respect as of the
time made, confirmed or furnished and the inaccuracy has resulted in a
Material Adverse Effect and such Material Adverse Effect continues uncured
for 30 or more days after the earlier of (x) written notice thereof to ESI
Tractebel Funding by the Project Trustee or to ESI Tractebel Funding and the
D-20
Project Trustee by the holders of at least 25% in aggregate principal amount
of the outstanding Project Securities and (y) the date that ESI Tractebel
Funding or either Partnership furnishes the Project Trustee with the notice
thereof as required by the Project Indenture, provided that if a
Partnership, ESI Tractebel Funding, NE LP or any such pledgor commences and
diligently pursues efforts to cure such Material Adverse Effect within such
30 day period, and such Material Adverse Effect may not be cured by the
payment of money, such Person may continue to effect such cure (and such
inaccuracy shall not be deemed an "Event of Default" under the Project
Indenture) for an additional 90 days;
(c) failure by either Partnership or ESI Tractebel Funding to perform or
observe certain covenants contained in the Project Indenture (relating to
insurance, limitations on Debt, limitations on Guarantees, prohibition of
fundamental changes, prohibition of disposition of assets, limitation of
activities by the Partnerships or ESI Tractebel Funding, Restricted Payments
and Project Letters of Credit), and such failure shall continue uncured for
30 or more days after the earlier of (x) written notice thereof to ESI
Tractebel Funding by the Project Trustee or to ESI Tractebel Funding and the
Project Trustee by the holders of at least 25% in aggregate principal amount
of the outstanding Project Securities and (y) the date that ESI Tractebel
Funding or either Partnership furnishes the Project Trustee with the notice
thereof as required by the Project Indenture;
(d) failure by either Partnership, ESI Tractebel Funding, NE LP or any
pledgor under the ESI Tractebel Funding Stock Pledge Agreement to perform or
observe any of its covenants contained in the Project Indenture and not
described in the preceding paragraph or any of its covenants under the
Project Security Documents and such failure shall continue uncured for 30 or
more days after the earlier of (x) written notice thereof to ESI Tractebel
Funding by the Project Trustee or to ESI Tractebel Funding and the Project
Trustee by the holders of at least 25% in aggregate principal amount of the
outstanding Project Securities and (y) the date that ESI Tractebel Funding
or either Partnership furnishes the Project Trustee with the notice thereof
as required by the Project Indenture; provided that if either Partnership,
ESI Tractebel Funding, NE LP or any pledgor under the ESI Tractebel Funding
Stock Pledge Agreement commences and diligently pursues efforts to cure such
default within such 30 day period, and such default is not curable the
payment of money, such Person may continue to effect such cure of the
default (and such default shall not be deemed an "Event of Default" under
the Project Indenture) for an additional 90 days so long as such Person is
diligently pursuing the cure;
(e) the occurrence and continuance beyond any stated "grace" period of
(i) any "event of default" under the Working Capital Facility or the Swaps
which has not been waived or (ii) any acceleration or right of acceleration
of the maturity of any Debt under the Working Capital Facility or the Swaps
other than such event or circumstance which (x) also causes the Project
Securities to be redeemed in full prior to their final maturity date and is
not otherwise an Event of Default under the Project Indenture or (y) is in
the nature of a "clean-up" obligation under the Working Capital Facility;
(f) certain events involving the bankruptcy, insolvency or receivership
of either Partnership or ESI Tractebel Funding;
(g) the entry of a final and nonappealable judgment or judgments for the
payment of money in excess of $20 million against either of the Partnerships
or ESI Tractebel Funding, which remain unpaid and unstayed for a period of
90 or more consecutive days;
D-21
(h) failure by either Partnership or ESI Tractebel Funding to make any
payment when due (subject to any applicable grace period) in respect of any
Debt with an outstanding balance exceeding $10 million (other than any
amount due in respect of the Project Securities);
(i) any Material Project Agreement at any time (prior to its scheduled
expiration) ceases to be valid and binding and in full force and effect or
any party thereto substantially ceases performance thereunder; provided,
however, that no such event shall be an Event of Default unless and until
180 days shall have elapsed from the occurrence of such (or 360 days shall
have elapsed from the occurrence thereof if the Partnerships have promptly
commenced and are diligently using their best efforts to cure such event and
on the 180th day after such occurrence the balance on deposit in the Debt
Service Reserve Fund is equal to or greater than the then current Debt
Service Reserve Requirement as of the 180th day) and during such period the
Partnerships shall not have either (1) caused the non-performing party to
resume performance, or (2) entered into a replacement agreement which
satisfies the following conditions, to be certified by the Partnerships and
the Independent Engineer: (A) after giving effect to such replacement
agreement, the Projects shall be projected to maintain either (x) a minimum
annual and an average annual Project Debt Service Coverage Ratio, in each
case commencing from the year in which such replacement agreement is
executed (the "Replacement Year") through the year in which the final
maturity date of the Project Securities occurs, equal to or greater than the
ratios that would have been projected during such period had performance
under the original Material Project Agreement been obtained or (y) a minimum
annual Projected Debt Service Coverage Ratio equal to or greater than 1.05:1
and an average annual Projected Debt Service Coverage Ratio equal to or
greater than 1.25:1 (with respect to both the remaining term of the Project
Securities and the period commencing immediately following the year with the
lowest annual Projected Debt Service Coverage Ratio during such remaining
term and ending with the year of the final maturity of the Project
Securities); and (B) in the case of the replacement of any Power Purchase
Agreement, such replacement agreement is with (or unconditionally guaranteed
or otherwise supported by) one or more entities having long-term unsecured
debt rated at the time of execution of the replacement agreement equal to
the lesser of (x) the current long-term unsecured debt rating of the
purchaser under the Power Purchase Agreement being replaced or (y) Baa by
Moody's or BBB by S&P or BBB by Fitch (or an equivalent rating by another
nationally recognized credit rating agency of similar standing if two or
more such corporations are not then in the business of rating long-term
unsecured debt of commercial entities);
(j) any grant of Lien contained in any Project Security Document ceases
to be effective to grant a Lien to the Collateral Agent on any material
portion of the Project Collateral described therein, or ceases to be
perfected or to have the priority required by the applicable Project
Security Documents, and such cessation continues uncured for 10 days after
ESI Tractebel Funding or the Partnerships have knowledge thereof;
(k) either Project loses its certification or status as a Qualifying
Facility; provided, however, that any such loss shall not be an Event of
Default unless and until 180 days shall have elapsed since such loss of
certification or status (or 360 days shall have elapsed since such loss if
the applicable Partnership has promptly commenced and is diligently using
its best efforts to cure such loss and on the 180th day after such loss the
balance on deposit in the Debt Service Reserve Fund shall be equal to or
greater than the then current Debt Service Reserve Requirement as of the
180th day) and during such period the applicable Partnership shall not have
either (i) restored such Project's certification or status as a Qualifying
Facility or (ii) (A) obtained all Government Approvals and all amendments to
D-22
the Project Documents necessary to own and operate such Project without such
certification or status in a manner which will not result in a Regulatory
Event and to continue the sale of electricity pursuant to the applicable
Power Purchase Agreements at wholesale at the same rates and volumes or at
such rates and in such volumes which, taken as a whole, result in either (x)
a minimum annual and an average annual Projected Debt Service Coverage
Ratio, in each case commencing from the year in which such Government
Approvals and amendments have been obtained through the year of the final
maturity date of the Project Securities, equal to or greater than the ratios
that would have been projected during such period had such loss of
certification or status as a Qualifying Facility not occurred or (y) a
minimum annual Projected Debt Service Coverage Ratio equal to or greater
than 1.05:1 and an average annual Projected Debt Service Coverage Ratio
equal to or greater than 1.25:1 (with respect to both the remaining term of
the Securities and the period commencing immediately following the year with
the lowest Projected Debt Service Coverage Ratio during such remaining term
and ending with the final maturity date of the Project Securities), in each
case as certified by the applicable Partnership and the Independent Engineer
and (B) as a result of the applicable Partnership's obtaining all requisite
Government Approvals and necessary amendments to the Project Documents
necessary to own and operate such Project in accordance with clause (A)
immediately above, either (x) such loss of certification or status as a
Qualifying Facility for the applicable Project shall not result in a loss of
Certification or status as a Qualifying Facility for the other Project or
(y) in the event such loss of certification or status as a Qualifying
Facility for the applicable Project shall result in a loss of certification
or status as a Qualifying Facility for the other Project, the applicable
Partnership shall have obtained all requisite Government Approvals and all
amendments to the Project Documents necessary to own and operate the other
Project without such certification or status in a manner which will not
result in a Regulatory Event and to continue the sale of electricity
pursuant to the applicable Power Purchase Agreements at wholesale at the
same rates and volumes or at such rates and in such volumes, which taken as
a whole, satisfy the Projected Debt Service Coverage Ratio requirement set
forth in clause (A) immediately above, in each case as certified by the
applicable Partnership and the Independent Engineer;
(l) the applicable Partnership shall cease to have (i) ownership of its
Project or (ii) the Government Approvals necessary to Operate its Project,
unless such loss of Government Approvals could not in the opinion of the
Partnerships and the Independent Engineer reasonably be expected to result
in a Material Adverse Effect; provided that an event described in this
clause (1) shall not constitute a Default or an Event of Default unless such
event would not constitute a Default or an Event of Default under any other
clause defining Events of Default under the Project Indenture;
(m) neither ESI Energy or Tractebel, alone or together, owns or
controls, directly or indirectly (i) at least 25% of the equity interests in
each of the Partnerships, or (ii) at least 51% of the Voting Stock in NE LP;
(n) any Person other than ESI Energy, Tractebel or an Affiliate thereof
holds any general partner interest in a Partnership.
The Project Indenture provides that upon the occurrence of an Event of
Default with respect to ESI Tractebel Funding described in clause (f) above, all
interest and principal on the Project Securities outstanding shall become
automatically due and payable. In the case of Events of Default described in
clause (a) above all interest and principal on the Project Securities shall be
declared due and payable upon the direction of the holders of not less than 25%
in aggregate principal amount of the outstanding Project Securities. In the case
of any other Event of Default, all interest and principal on the Project
Securities shall be declared due and payable upon the direction of the holders
of not less than 50% in aggregate principal amount of the outstanding Project
D-23
Bond Securities. Subject to the provisions of the Project Indenture relating to
the duties of the Project Trustee, in case an Event of Default occurs and is
continuing, the Project Trustee is under no obligation to exercise any of the
rights or powers vested in it under the Project Indenture at the request or
direction of any of the holders of the Project Securities unless it is offered
reasonable security or indemnity against costs, expenses and liabilities. The
exercise or remedies by the Collateral Agent under the Project Security
Documents is subject to the terms and conditions contained in the Collateral
Agency Agreement.
Amendments and Supplements
Without the consent of the holders of any Project Securities, ESI Tractebel
Funding and the Project Trustee may enter into one or more supplemental
indentures for any of the following purposes: (a) to establish the form and
terms of the debt securities of any series permitted by the Project Indenture;
(b) to evidence the succession of another entity to ESI Tractebel Funding or
either Partnership, and the assumption by any such successor of the covenants of
such entity under the Project Securities or the Project Indenture; (c) to
evidence the succession of a new Project Trustee pursuant to the Project
Indenture; (d) to add to the covenants of ESI Tractebel Funding and/or either
Partnership or to surrender any right or power therein conferred upon ESI
Tractebel Funding and/or either Partnership; (e) to convey, transfer and assign
to the Project Trustee properties or assets to secure the Project Securities,
and to correct or amplify the description of any property at any time subject to
the Project Indenture or to assure, convey and confirm unto the Project Trustee
or the Collateral Agent any property subject or required to be subject to the
Project Indenture; (f) to modify, eliminate or add to the provisions of the
Project Indenture to the extent necessary to qualify, requalify or continue the
qualification of the Project Indenture under the Trust Indenture Act or any
similar statute later enacted and to add to the Project Indenture such other
provisions as may be expressly permitted by the Trust Indenture Act (exclusive
of Section 316(a)(2) of the Trust Indenture Act as in effect on the date of the
execution of the Project Indenture); (g) to change or eliminate any provision of
the Project Indenture, provided that if the interests of the holders of any
series would be adversely affected, such change or elimination will not become
effective as to such series; and provided further that, if the interests of the
Working Capital Banks or the Project Letter of Credit Banks would be adversely
affected, such change or elimination will not become effective until the Project
Trustee receives a certificate consenting to such change or elimination from the
working Capital Banks or an agent therefor; (h) to permit or facilitate the
issuance of the Project Securities in uncertified form; (i) to cure any
ambiguity or to correct or supplement any provision of the Project Indenture
that may be defective or inconsistent with any other provision therein; (j) to
make any other provisions with respect to matters or questions arising under the
Project Indenture, provided such action shall not adversely affect the interests
of the holders of any series in any material respect; or (k) to provide for the
issuance of the Project Securities and so make such other changes as are
necessary or appropriate in connection therewith, provided such action shall not
adversely affect the interests of the holders of any series of the Project
Securities in any material respect.
With the consent of the holders of not less than a majority in aggregate
principal amount of the Project Securities of all series then outstanding,
considered as one class, ESI Tractebel Funding and the Partnerships may, and the
Project Trustee shall, enter into an indenture or indentures supplemental to the
Project Indenture for the purpose of adding any provisions to or changing in any
manner or eliminating or waiving any of the provisions of, the Project
Indenture; provided, however, that if there are Project Securities of more than
one series outstanding under the Project Indenture and if a proposed
supplemental indenture will directly affect the rights of the holders of one or
more, but less than all, of such series, then the consent only of the holders of
not less than a majority in aggregate principal amount of the outstanding
Project Securities of all series so directly affected, considered as one class,
shall be required; and provided further that no such supplemental indenture
D-24
shall, without the consent of the holder of each outstanding Project Bond
directly affected thereby, (a) change the stated maturity of any Project Bond
(or, if the principal thereof is payable in installments, the stated maturity of
any such installment), or of any payment of interest thereon, or the dates or
circumstances of payment of premium, if any, on any Project Bond, or change the
principal amount thereof or the interest thereon or any premium payable upon the
redemption thereof, or change the place of payment where, or the coin or
currency in which, any Project Bond or the premium, if any, or the interest
thereon is payable, or impair the right to institute suit for the enforcement of
any such payment of principal or interest on or after the stated maturity
thereof (or, in the case of redemption, on or after the Redemption Date) or such
payment of premium, if any, on or after the date such payment of premium becomes
due and payable, or change the dates or the amounts of payments to be made
through the operation of the sinking fund in respect of such Project Securities,
if any; or (b) permit the creation of any Lien prior to or, except in the case
of Project Securities issued in accordance with the terms of the Project
Indenture, pari passu with the Lien of the Project Security Documents with
respect to all or any substantial portion of the Project Collateral or terminate
the Lien of the Project Security Documents on all or any substantial portion of
the collateral or deprive any holder of the security afforded by the lien of the
Project Security Documents, except to the extent expressly permitted by the
Project Indenture or any of the Project Security Documents; or (c) reduce the
percentage in principal amount of the outstanding Project Securities, the
consent of whose holders is required for any waiver (of compliance with certain
provisions of the Project Indenture or certain defaults thereunder and their
consequences) provided for in the Project Indenture; or (d) modify any of the
Project Indenture provisions relating to the waiver of defaults or the making of
modifications to the Project Indenture.
Any supplemental indenture which adds any provisions to or changes or
eliminates any provisions of the Project Indenture which shall adversely affect
the interests of the Working Capital Banks shall not become effective without
the consent of the Working Capital Banks, as the case may be, or an agent
therefor.
A supplemental indenture that changes or eliminates any covenant or other
provision of the Project Indenture which has been expressly included solely for
the benefit of one or more particular series of Project Securities, or which
modifies the rights of the holders of Project Securities of such series with
respect to such covenant or other provision, shall be deemed not to affect the
rights under the Indenture of the holders of Project Securities of any other
series.
Satisfaction and Discharge of the Indenture; Defeasance
ESI Tractebel Funding may terminate the Project Indenture and the Project
Guaranty by delivering all outstanding Project Securities to the Project Trustee
for cancellation and by paying all other sums payable under the Project
Indenture.
In addition to the foregoing, ESI Tractebel Funding shall be deemed to have
paid and discharged the entire indebtedness on all the Project Securities of any
series on the 91st day after the date of the deposit described in clause (1)
below, and the provisions of the Project Guaranty and the Project Indenture, as
they relate to the Project Securities of such series, shall no longer be in
effect (except (i) the right to receive, solely from the trust funds described
in clause (1) below, payments in respect of such Project Securities as and when
due, (ii) certain ministerial rights and obligations of ESI Tractebel Funding
and the Project Trustee relating to the registration and transfer of such
Project Securities and similar matters, and (iii) the rights, powers, trusts and
immunities of the Project Trustee), provided that the following conditions have
been satisfied:
(1) ESI Tractebel Funding has irrevocably deposited with the Project
Trustee, in trust, money or U.S. Government Obligations (or a combination
thereof) in an amount which will be sufficient to pay the principal of and
D-25
premium, if any, and interest on the Project Securities of such series on
the respective dates on which such payments become due;
(2) specified Defaults (regarding failure to make payments in respect to
the Project Securities and certain events of bankruptcy or insolvency) shall
not occur with respect to Project Securities of such series on the date of
such deposit or during the period ending 91 days thereafter;
(3) ESI Tractebel Funding has delivered to the Project Trustee an
opinion of counsel to the effect that (i) the holders of the Project
Securities will not recognize income, gain or loss for Federal income tax
purposes as a result of the deposit, defeasance and discharge and will be
subject to Federal income tax on the same amounts and in the same manner and
at the same times as would have been the case if such deposit, defeasance
and discharge had not occurred and (ii) the defeasance trust is not an
investment company under the Investment Company Act of 1940; and
(4) if the deposit described in clause (1) above has been made to make
payments in respect to the Project Securities of such series to and
including a redemption date on which all the outstanding Project Securities
of such series are eligible for redemption and on which such Project
Securities are to be redeemed, then ESI Tractebel Funding shall have
irrevocably designated such redemption date and requested that the Project
Trustee give notice of such redemption to the holders not less than 30 nor
more than 60 days prior to such redemption date in accordance with the
applicable provisions of the Project Indenture.
If the conditions described in clauses (1), (2) and (4) above have been
satisfied with respect to the Project Securities of any series (but the
condition described in clause (3) above is not satisfied), then, effective on
the 91st day after the date of the deposit described in clause (1) above:
(a) with respect to the Project Securities of such series, ESI Tractebel
Funding, the Partnerships and NE LP (and the pledgors under the ESI
Tractebel Funding Stock Pledge Agreement) will be released from
substantially all of their covenants and other obligations contained in the
Project Indenture, the Project Guaranty and the other Project Transaction
Documents, and thereafter any failure to comply with any such covenant or
obligation will not constitute a Default or an Event of Default with respect
to the Project Securities of such series;
(b) the occurrence of any event described in clause (b), (c), (d), (e),
(g), (h), (i), (j), (k), (l), (m) or (n) under "Events of Default" above
will no longer constitute a Default or an Event of Default with respect to
the Project Securities of such series;
(c) the Project Securities of such series will thereafter be deemed not
to be outstanding for purposes of determining whether the holders of the
requisite aggregate principle amount of Project Securities have approved any
amendment, modification or waiver with respect to any covenant or obligation
described in clause (a) above or any event described in clause (b) above;
and
(d) the Project Securities of such series will cease to be secured by or
be entitled to any benefit under the Project Security Documents or any other
Lien upon any Project Collateral (other than the trust funds deposited with
the Project Trustee in respect of such Project Securities in order to effect
the defeasance described therein);
D-26
provided that the foregoing will not relieve ESI Tractebel Funding of its
obligations to make payments in respect of the Project Securities of such
series.
If ESI Tractebel Funding or the Partnerships incur any Debt and all or any
portion of the proceeds therefrom are concurrently applied to make a deposit
described in clause (1) above in respect of any series of Project Securities (or
to acquire U.S. Government Obligations that are so deposited), then any Default
or Event of Default that would arise as a result of such an incurrence or as a
result of any Lien granted to secure such Debt will not constitute a Default or
Event of Default with respect to the Project Securities of such series.
The Project Trustee
State Street Bank and Trust Company is the Project Trustee under the Project
Indenture. The Project Trustee's current address is Two International Place,
Boston, MA 02110, Attention: Ms. Jill Olson, Corporate Trust Department.
D-27
================================================================================
NO DEALER, SALESMAN OR ANY OTHER PERSON IS AUTHORIZED IN CONNECTION
WITH ANY OFFERING MADE HEREBY TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED
BY ESI TRACTEBEL ACQUISITION OR NE LP. THIS PROSPECTUS DOES NOT CONSTITUTE AN
OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITY OTHER THAN THE
SECURITIES OFFERED HEREBY, NOR DOES IT CONSTITUTE AN OFFER TO SELL OR A
SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY TO ANY
PERSON IN ANY JURISDICTION IN WHICH IT IS UNLAWFUL TO MAKE SUCH OFFER OR
SOLICITATION TO SUCH PERSON. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY
SALE MADE HEREUNDER SHALL UNDER ANY CIRCUMSTANCES CREATE ANY IMPLICATION THAT
THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY DATE SUBSEQUENT TO THE
DATE HEREOF.
--------------------
TABLE OF CONTENTS
Page
AVAILABLE INFORMATION.................................................iii
DEFINED TERMS.........................................................iii
SAFE HARBOR STATEMENT
UNDER THE PRIVATE
SECURITIES LITIGATION
REFORM ACT OF 1995..................................................iv
SUMMARY.................................................................1
SUMMARY HISTORICAL AND PRO
FORMA COMBINED FINANCIAL
DATA................................................................13
RISK FACTORS...........................................................16
USE OF PROCEEDS........................................................27
CAPITALIZATION.........................................................27
UNAUDITED PRO FORMA
FINANCIAL STATEMENTS................................................29
SELECTED HISTORICAL
COMBINED FINANCIAL DATA.............................................33
MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF
OPERATIONS..........................................................35
BUSINESS...............................................................41
THE PROJECTS...........................................................42
REGULATION.............................................................52
SUMMARY OF PRINCIPAL
PROJECT AGREEMENTS..................................................60
MANAGEMENT.............................................................94
EXECUTIVE COMPENSATION.................................................95
SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT......................................................95
CERTAIN TRANSACTIONS...................................................96
THE EXCHANGE OFFER.....................................................97
DESCRIPTION OF SECURITIES.............................................106
OUTSTANDING PROJECT
INDEBTEDNESS.......................................................134
CERTAIN FEDERAL TAX
CONSIDERATIONS.....................................................140
PLAN OF DISTRIBUTION..................................................142
LEGAL MATTERS.........................................................142
EXPERTS...............................................................143
TRUSTEE...............................................................143
INDEX TO FINANCIAL
STATEMENTS.........................................................F-1
Appendix A: Defined Terms.............................................A-1
Appendix B: Independent Engineer's Report.............................B-1
Appendix C: Fuel Consultant's Report..................................C-1
Appendix D: Summary of Project Indenture..............................D-1
--------------------
Until ___________, 1998, all dealers effecting transactions in the New
Securities, whether or not participating in the Exchange Offer, may be required
to deliver a Prospectus. This is in addition to the obligation of dealers to
deliver a Prospectus when acting as underwriters and with respect to their
unsold allotments or subscriptions.
================================================================================
================================================================================
ESI Tractebel Acquisition Corp.
Northeast Energy, LP
7.99% Series B Secured Bonds Due 2011
----------------------
PROSPECTUS
----------------------
________________, 1998
================================================================================
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF OFFICERS AND DIRECTORS.
Section 145 of the Delaware General Corporation Law and paragraph 9 of
ESI Tractebel Acquisition's Certificate of Incorporation provide for
indemnification of the Registrant's directors and officers in a variety of
circumstances, which may include liabilities under the Securities Act of 1933,
as amended.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) EXHIBITS
A list of exhibits is set forth in the Exhibit Index appearing
elsewhere in this Registration Statement and is incorporated herein by
reference.
(b) FINANCIAL STATEMENT SCHEDULES
None.
ITEM 22. UNDERTAKINGS
(a) Insofar as indemnification for liabilities arising under the
Securities Act of 1933 (the "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 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 Act and
will be governed by the final adjudication of such issue.
(b) The undersigned registrant hereby undertakes to respond to
requests for information that is incorporated by reference into the 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.
(c) The undersigned registrant hereby undertakes to supply by
means of a post-effective amendment all information concerning a transaction,
and the company being acquired involved therein, that was not the subject of and
included in the registration statement when it became effective.
II-1
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended,
the registrant has duly caused this Registration Statement on Form S-4 to be
signed on its behalf by the undersigned, thereunto duly authorized, in the City
of North Palm Beach, State of Florida on May 11, 1998.
ESI TRACTEBEL ACQUISITION CORP.
By: /s/ Glenn E. Smith
-----------------------------
Glenn E. Smith
Vice President
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement on Form S-4 has been signed by the following persons in
the capacities indicated on May 11, 1998.
Signature Title
- --------- -----
/s/ Glenn E. Smith
- ------------------------------
Glenn E. Smith Vice President
(Principal Executive Officer)
/s/ Peter D. Boylan
- ------------------------------
Peter D. Boylan Treasurer
(Principal Financial and
Accounting Officer)
II-2
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended,
the registrant has duly caused this Registration Statement on Form S-4 to be
signed on its behalf by the undersigned, thereunto duly authorized, in the City
of North Palm Beach, State of Florida on May 11, 1998.
NORTHEAST ENERGY, A LIMITED PARTNERSHIP
By: ESI NORTHEAST ENERGY GP, INC.
By: /s/ Glenn E. Smith
---------------------------------
Glenn E. Smith
Vice President
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement on Form S-4 has been signed by the following persons in
the capacities indicated on May 11, 1998.
Signature Title
- --------- -----
/s/ Glenn E. Smith
- -----------------------------
Glenn E. Smith Vice President
(Principal Executive Officer)
/s/ Peter D. Boylan
- ----------------------------- Treasurer
Peter D. Boylan
(Principal Financial and
Accounting Officer)
II-3
Exhibit Index
Exhibit No. Description
----------- -----------
1. Purchase Agreement dated February 12, 1998 by and
between ESI Tractebel Acquisition Corp., Northeast
Energy, LP, ESI Energy, Inc., Tractebel Power,
Inc. and Goldman, Sachs & Co.
3.1 Certificate of Incorporation of ESI Tractebel
Acquisition Corp. as filed with the Secretary of
State of the State of Delaware on January 12,
1998.
3.2 By-laws of ESI Tractebel Acquisition Corp.
3.3* Certificate of Limited Partnership of Northeast
Energy, LP, a Delaware limited partnership, as
filed with the Secretary of State of the State of
Delaware on November 21, 1997
3.4* Agreement of Limited Partnership of Northeast
Energy, LP, a Delaware limited partnership, dated
as of November 21, 1997.
4.1 Indenture, dated as of February 19, 1998, among
ESI Tractebel Acquisition Corp., Northeast Energy,
LP, Northeast Energy, LLC and State Street Bank
and Trust Company as trustee and collateral agent.
4.2 Registration Rights Agreement, dated as of
February 19, 1998, by and among ESI Tractebel
Acquisition Corp., Northeast Energy, LP and
Goldman, Sachs & Co.
4.3 Company & Partner Pledge Agreement dated as of
February 19, 1998 by and among ESI Tractebel
Acquisition Corp., Northeast Energy, LP and
Northeast Energy, LLC in favor of State Street
Bank and Trust Company as trustee and collateral
agent.
4.4 Sponsor Pledge Agreement dated as of February 19,
1998 by and among ESI Northeast Energy Acquisition
Funding, Inc., ESI Northeast Energy GP, Inc., ESI
Northeast Energy LP, Inc., Tractebel Northeast
Generation GP, Inc., Tractebel Associates
Northeast LP, Inc. and Tractebel Power, Inc. in
favor of State Street Bank and Trust Company as
trustee and collateral agent.
5.1** Opinion of Orrick, Herrington & Sutcliffe LLP.
10.1* Operation and Maintenance Agreement dated as of
November 21, 1997 by and between Northeast Energy,
LP, a Delaware limited partnership and ESI
Operating Services, Inc.
10.2* Operation and Maintenance Agreement dated as of
November 21, 1997 by and between Northeast Energy,
LP, a Delaware limited partnership and ESI
Operating Services, Inc.
10.3* Fuel Management Agreement, dated as of January 20,
1998, by and between Northeast Energy, LP, a
Delaware limited partnership and ESI Northeast
Fuel Management, Inc., assigned by Northeast
Energy, LP to Northeast Energy Associates, a
limited partnership on January 20, 1998.
10.4* Fuel Management Agreement, dated as of January 20,
1998, effective retroactive to January 14, 1998,
by and between Northeast Energy, LP, a Delaware
limited partnership and ESI Northeast Fuel
Management, Inc.
10.5* Administrative Services Agreement dated as of
November 21, 1997 between Northeast Energy, LP, a
Delaware limited partnership and ESI Northeast
Energy GP, Inc.
10.6 Reimbursement Agreement, dated as of November 21,
1997, by and among FPL Group Capital, Inc.,
Tractebel Power, Inc. and Northeast Energy, LP, a
Delaware limited partnership
12.1 Statements regarding computation of Ratio of
Earnings to Fixed Charges
21.1 Subsidiary of Northeast Energy, LP
23.1** Consent of Orrick, Herrington & Sutcliffe LLP
(included as part of Exhibit 5.1)
23.2 Consent of Price Waterhouse LLP
23.3 Consent of Sargent & Lundy LLC
23.4 Consent of Benjamin Schlesinger and Associates,
Inc.
25 Statement of Eligibility on Form T-1 of the
Trustee.
27.1 Financial Data Schedule
99.1 Form of Letter of Transmittal
99.2 Form of Notice of Guaranteed Delivery
99.3 Form of Exchange Agency Agreement between ESI
Tractebel Acquisition Corp. and the Trustee
99.4 Form of letter to Brokers, Dealers, Commercial
Banks, Trust Companies and Other Nominees
- ----------
* Incorporated herein by reference from the Annual Report on Form 10-K filed by
ESI Tractebel Funding Corp., Northeast Associates, A Limited Partnership and
North Jersey Energy Associates, A Limited Partnership on March 27, 1998.
** To be filed by amendment.