AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON AUGUST 5, 1998
REGISTRATION NO. 333-52397
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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AMENDMENT NO. 2
TO
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
(STATE OF INCORPORATION) (PRIMARY STANDARD INDUSTRIAL
CLASSIFICATION CODE NUMBER)
65-0827005
(I.R.S. EMPLOYER
IDENTIFICATION NUMBER)
------------------------
NORTHEAST ENERGY, LP
(EXACT NAME OF CO-REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 4911
(STATE OR OTHER JURISDICTION OF (PRIMARY STANDARD INDUSTRIAL
INCORPORATION OR ORGANIZATION) CLASSIFICATION CODE NUMBER)
65-0811248
(I.R.S. EMPLOYER
IDENTIFICATION NUMBER)
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700 UNIVERSE BLVD.
JUNO BEACH, FLORIDA 33408-2683
(561) 691-7171
(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.
700 UNIVERSE BLVD.
JUNO BEACH, FLORIDA 33408-2683
(561) 691-7171
(NAME, ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER,
INCLUDING AREA CODE, OF AGENT FOR SERVICE)
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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. / /
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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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SUBJECT TO COMPLETION, DATED AUGUST 5, 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.
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Payment of principal and interest fully and 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. As of March 31, 1998, the aggregate
principal amount of senior debt of NE LP to which the New Securities and the
Bond Guaranty were effectively subordinated was approximately $490,286,720. ESI
Tractebel Acquisition's obligations to make payment on the Securities are fully
and unconditionally guaranteed by NE LP (the 'Bond Guaranty'). In addition, the
Securities are secured by, among other things, a perfected, first priority
pledge by NE LP and Northeast Energy, LLC of their respective limited partner
interests in Northeast Energy Associates, A Limited Partnership ('NEA') and
North Jersey Energy Associates, A Limited Partnership ('NJEA') and a second
priority pledge by NE LP of its general partner interest in NEA and NJEA, which
in each case will include, among other things, all of their rights to receive
distributions from NEA and NJEA. See 'Description of Securities.'
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
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.
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SEE 'RISK FACTORS' ON PAGE 19 FOR A DESCRIPTION OF CERTAIN RISKS THAT SHOULD
BE CONSIDERED BY PURCHASERS OF THE NEW SECURITIES.
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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
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.
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 concerning the provisions of any document filed as an exhibit are of
necessity brief descriptions thereof and in each instance reference is made to
the copy of the document filed as an exhibit to the Registration Statement, each
such statement being qualified in its entirety by this 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.
i
SUMMARY
This Prospectus contains certain statements that are 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, 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. Holders of Old
Securities desiring to participate in the Exchange Offer are cautioned that
reliance on any forward-looking statement involves risks and uncertainties and
that, although the Partnerships believe that the assumptions on which the
forward-looking statements contained herein are based are reasonable, any of
those assumptions could prove to be inaccurate, and as a result, the
forward-looking statements based on those assumptions also could be incorrect.
The uncertainties in this regard include, but are not limited to, those
identified herein under 'Risk Factors.' In light of these and other
uncertainties, the inclusion of a forward-looking statement herein should not be
regarded as a representation by either ESI Tractebel Acquisition, NE LP or the
Partnerships that ESI Tractebel Acquisition's, NE LP's or the Partnerships'
plans and objectives will be achieved.
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 $535 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
1
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
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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 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 14, 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').
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.
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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
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 March 31, 1998, 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
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.
4
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.'
5
OWNERSHIP STRUCTURE
Flow Chart of the ownership structure
showing the relationship among ESI Tractebel
Acquisition, NE LP and the Partnerships.
[GRAPHIC OMITTED]
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
7
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 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
8
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.'
9
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 Registration
Statement is not declared effective 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.................................. The New Securities will be fully and unconditionally guaranteed by NE
LP. NE LP will guarantee that the principal of, premium, if any, and
interest on and Registration Default Damages, if any, with respect to
the New Securities will be promptly paid in full when due, whether at
maturity, by acceleration, redemption or otherwise, and interest on
the overdue principal of and interest on the New Securities, if any,
will be promptly paid in full.
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
10
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.
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
11
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' 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
12
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').
RISK FACTORS
See 'Risk Factors' for a discussion of certain factors including, among
other things, (i) substantial leverage, (ii) holding company structure, (iii)
dependence upon operations of projects and (iv) 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. Neither Deloitte &
Touche LLP nor PricewaterhouseCoopers LLP has either examined or compiled the
Projections contained in Appendix B, and accordingly, neither Deloitte & Touche
LLP nor PricewaterhouseCoopers LLP expresses an opinion or any other form of
assurance with respect thereto. The Deloitte & Touche LLP reports and the
PricewaterhouseCoopers LLP report included in this Prospectus relate solely to
NE LP, ESI Tractebel Acquisition, ESI GP, Tractebel GP and the Partnerships'
respective historical financial information. They do 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.
13
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 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.'
14
Subject to the information contained, and assumptions made, in the Fuel
Consultant's Report, the Fuel Consultant has expressed the following
conclusions:
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.'
15
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
HISTORICAL
Presented below is the summary historical financial data of the
Partnerships, NE LP and ESI Tractebel Acquisition at the dates and for the
periods indicated. The summary historical combined statement of operations data
and statement of cash flows data of the Partnerships 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 of the Partnerships 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 of
the Partnerships for the three-month periods ended March 31, 1997 and March 31,
1998 are derived from the unaudited combined financial statements of the
Partnerships which, in the opinion of the Partnerships' management, include all
adjustments, consisting of normal recurring adjustments, necessary for a fair
presentation and are included elsewhere in this Prospectus. The summary
historical statement of operations data, balance sheet data and statement of
cash flows data of NE LP and ESI Tractebel Acquisition for the three-month
period ended March 31, 1998 are derived from the unaudited financial statements
of NE LP and ESI Tractebel Acquisition included elsewhere in this Prospectus.
The summary historical balance sheet data of NE LP and ESI Tractebel Acquisition
at December 31, 1997 and January 12, 1998, respectively, are derived from the
audited balance sheets included elsewhere in this Prospectus. The summary
historical unaudited financial data of NE LP and ESI Tractebel Acquisition, in
the opinion of their respective management, include all adjustments, consisting
of normal recurring adjustments, necessary for a fair presentation. The summary
historical 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,' the financial statements of NE
LP and ESI Tractebel Acquisition and related notes thereto, and the audited
combined financial statements of the Partnerships and related notes thereto
included elsewhere in this Prospectus.
PRO FORMA
Because NE LP and ESI Tractebel Acquisition were formed November 21, 1997
and January 12, 1998, respectively, they had no activity for the year ended
December 31, 1997 or for any prior period. As a result, the summary NE LP pro
forma financial information as of December 31, 1997 gives effect to the
Acquisitions and the Offering 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 contained
in 'Unaudited Pro Forma Statements of Operations.' The summary NE LP pro forma
financial information for the three-month period ended March 31, 1998 includes
the Acquisitions and the Offering, and is based on the historical financial
statements of NE LP, under the assumptions and adjustments set forth in the
notes accompanying the unaudited pro forma financial statements contained in
'Unaudited Pro Forma Statements of Operations,' NE LP has accounted for the
Acquisitions as a purchase for financial reporting purposes. The summary NE LP
pro forma statements of operations data for the year ended December 31, 1997 and
for the three-month period ended March 31, 1998 assume that the Acquisitions and
the Offering were consummated on January 1, 1997.
The summary ESI Tractebel Acquisition pro forma financial information as of
December 31, 1997 gives effect to the Offering, under the assumptions and
adjustments set forth in the notes accompanying the unaudited pro forma
financial statements contained in 'Unaudited Pro Forma Statements of
Operations,' even though ESI Tractebel Acquisition was not in existence and had
no activity as of December 31, 1997. The summary ESI Tractebel Acquisition pro
forma financial information for the three-month period ended March 31, 1998
includes the Offering and is based on the historical financial statements of ESI
Tractebel Acquisition under the assumptions and adjustments set forth in the
notes accompanying the unaudited pro forma financial statements contained in
'Unaudited Pro Forma Statements of Operations.' The summary NE LP and ESI
Tractebel Acquisition pro forma financial information should be read in
conjunction with the notes accompanying the unaudited pro forma financial
statements contained in 'Unaudited Pro Forma Statements of Operations,' the
historical combined financial statements of the Partnerships and related notes
thereto and the historical financial statements of NE LP and ESI Tractebel
Acquisition and related notes thereto included elsewhere in this Prospectus. The
summary pro forma 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.
16
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
(IN THOUSANDS OF DOLLARS)
PARTNERSHIPS COMBINED
----------------------------------------------------------------------------
THREE
MONTHS
ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
-------------------------------------------------------------- ---------
1993(8) 1994 1995 1996 1997 1997
-------- -------- -------- -------- -------- ---------
STATEMENT OF OPERATIONS DATA:
Total revenues............................... $238,826 $238,712 $280,549 $272,262 $312,154 $ 82,336
Operating income............................. $ 46,882 $ 54,176 $ 86,097 $ 71,279 $ 94,013 $ 27,720
Net income (loss)............................ $ (1,261) $(16,916)(2) $ 26,857 $ 9,924 $ 36,673 $ 13,052
BALANCE SHEET DATA:
Total assets................................. $546,484 $650,027 $617,034 $566,534 $541,545 $594,238
-------- -------- -------- -------- -------- ---------
-------- -------- -------- -------- -------- ---------
Loans payable and other liabilities.......... $483,626 $587,459 $559,558 $533,091 $508,166 $545,533
Energy Bank liabilities(9)................... 111,398 155,496 188,053 220,922 230,565 223,132
-------- -------- -------- -------- -------- ---------
Total liabilities......................... 595,024 742,955 747,611 754,013 738,731 768,665
Partners' equity (deficit)................... (48,540) (92,928) (130,577) (187,479) (197,186) (174,427)
-------- -------- -------- -------- -------- ---------
Total liabilities and partners' equity
(deficit)............................... $546,484 $650,027 $617,034 $566,534 $541,545 $594,238
-------- -------- -------- -------- -------- ---------
-------- -------- -------- -------- -------- ---------
STATEMENT OF CASH FLOWS DATA:
Non-cash charges and Energy Bank
accruals(3)................................. $ 69,955 $ 70,745 $ 59,766 $ 60,220 $ 36,798 $ 9,019
Extraordinary loss on extinguishment of
debt(10).................................... -- 13,937 -- -- -- --
Change in future obligations under interest
rate swap agreements........................ -- 6,425(10) (2,771) (1,632) (1,133) (325)
Change in working capital.................... 455 (5,828) (12,622) 6,514 9,837 20,340
Net income (loss)............................ (1,261) (16,916) 26,857 9,924 36,673 13,052
-------- -------- -------- -------- -------- ---------
Net cash provided by operating
activities(4)............................... $ 69,149 $ 68,363 $ 71,230 $ 75,026 $ 82,175 $ 42,086
-------- -------- -------- -------- -------- ---------
-------- -------- -------- -------- -------- ---------
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 $ 401
Distributions to partners.................... $ 10,878 $ 27,472 $ 64,506 $ 66,826 $ 46,380 $ --
Ratio of earnings to fixed charges(5)........ -- -- 1.38 1.14 1.54 1.77
PREDECESSOR SUCCESSOR
JANUARY 1 JANUARY 14
THROUGH THROUGH
JANUARY 13, MARCH 31,
----------- ----------
1998 1998(6)
----------- ----------
STATEMENT OF OPERATIONS DATA:
Total revenues............................... $13,109 $ 74,739
Operating income............................. $ 4,929 $ 23,081
Net income (loss)............................ $ 2,909 $ 10,022
BALANCE SHEET DATA:
Total assets................................. $1,491,274
----------
----------
Loans payable and other liabilities.......... $ 869,027
Energy Bank liabilities(9)................... 171,371
----------
Total liabilities......................... 1,040,398
Partners' equity (deficit)................... 450,876
----------
Total liabilities and partners' equity
(deficit)............................... $1,491,274
----------
----------
STATEMENT OF CASH FLOWS DATA:
Non-cash charges and Energy Bank
accruals(3)................................. $ 911 $ 9,858
Extraordinary loss on extinguishment of
debt(10).................................... -- --
Change in future obligations under interest
rate swap agreements........................ -- (218)
Change in working capital.................... (2,388) 14,011
Net income (loss)............................ 2,909 10,022
----------- ----------
Net cash provided by operating
activities(4)............................... $ 1,432 $ 33,673
----------- ----------
----------- ----------
Principal payments on debt................... $ -- $ --
Interest paid................................ $ -- $ --
Distributions to partners.................... $ -- $ 104,920
Ratio of earnings to fixed charges(5)........ 2.20 1.73
ESI TRACTEBEL
NE LP ACQUISITION
-------------------------------------------------------------- ----------------
DECEMBER 31, 1997 MARCH 31, 1998 JANUARY 12, 1998
--------------------------- ------------------------------ ----------------
HISTORICAL PRO FORMA(1) HISTORICAL(7) PRO FORMA(1) HISTORICAL
---------- ------------ ------------- ------------ ----------------
STATEMENT OF OPERATIONS DATA:
Total revenues................. $-- $312,154 $ 74,739 $ 87,848 $--
Operating income............... -- $ 74,289 $ 22,808 $ 27,130 --
Net income (loss).............. -- $ (6,194) $ 7,626 $ 6,894 --
BALANCE SHEET DATA:
Total assets................... -- $ 1,498,932 --
-- --
-- --
-------------
-------------
Loans payable and other
liabilities................... -- $ 1,092,145 --
Energy Bank liabilities(9)..... -- 171,371 --
-- --
-------------
Total liabilities........... -- 1,263,516 --
Partners'/Stockholders'
equity........................ -- 235,416 --
-- --
-------------
Total liabilities and
partners'/stockholders'
equity.................... -- $ 1,498,932 --
-- --
-- --
-------------
-------------
STATEMENT OF CASH FLOWS DATA:
Non-cash charges and Energy
Bank accruals(3).............. $ 10,203
Change in future obligations
under interest rate swap
agreements.................... (218)
Change in working capital...... 14,989
Net income..................... 7,626
-------------
Net cash provided by operating
activities(4)................. $ 32,600
-------------
-------------
Principal payments on debt..... --
Interest paid.................. --
Distributions to partners...... $ 307,619
Ratio of earnings to fixed
charges(5).................... -- -- 1.48 1.33
DECEMBER 31, 1997 MARCH 31, 1998
----------------- ---------------------------
PRO FORMA(1) HISTORICAL PRO FORMA(1)
----------------- ---------- ------------
STATEMENT OF OPERATIONS DATA:
Total revenues................. -- -- --
Operating income............... -- -- --
Net income (loss).............. $ 9 $ 2 $ 3
BALANCE SHEET DATA:
Total assets................... $ 222,203
----------
----------
Loans payable and other
liabilities................... $ 222,201
Energy Bank liabilities(9)..... --
----------
Total liabilities........... 222,201
Partners'/Stockholders'
equity........................ 2
----------
Total liabilities and
partners'/stockholders'
equity.................... $ 222,203
----------
----------
STATEMENT OF CASH FLOWS DATA:
Non-cash charges and Energy
Bank accruals(3).............. $ (2)
Change in future obligations
under interest rate swap
agreements.................... --
Change in working capital...... --
Net income..................... 2
----------
Net cash provided by operating
activities(4)................. $ --
----------
----------
Principal payments on debt..... --
Interest paid.................. --
Distributions to partners...... --
Ratio of earnings to fixed
charges(5).................... 1.00 1.00 1.00
(Footnotes on next page)
17
(Footnotes from previous page)
- ------------------
(1) See 'Unaudited Pro Forma Statements of Operations.'
(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 above-market contracts, debt issuance costs, gain on
the Offering interest rate hedge, noncapitalizable acquisition 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 from continuing operations 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 the Partnerships for 1993 and 1994 and NE LP pro forma
December 31, 1997 were inadequate to cover fixed charges. The coverage
deficiencies for the Partnerships during 1993 and 1994 and NE LP pro forma
December 31, 1997 are $1.261 million, $2.979 million and $6.194 million,
respectively.
(6) Reflects the combined results of the Partnerships from January 14, 1998
through March 31, 1998, subsequent to the Acquisitions ('Successor') which
reflects a new basis for certain assets and liabilities.
(7) Includes the results of the Partnerships subsequent to the Acquisitions.
(8) 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.
(9) 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.'
(10) 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.
18
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 March 31, 1998, ESI Tractebel Acquisition had total
indebtedness of approximately $220 million, representing the aggregate principal
amount of the Securities. On March 31, 1998, NE LP had total indebtedness
including current portion of $881,658,000 (of which $220,000,000 consisted of
the non-current portion of its Note relating to the Securities, $490,287,000
consisted of the Partnerships' loan payable to a related party and $171,371,000
consisted of Energy Bank balances) and Partners' equity of $235,416,000. 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,' 'Summary Historical and Pro
Forma 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', 'Description of Securities--Repurchase at the
Option of Holders Upon a Change of Control' and '--Outstanding Project
Indebtedness.'
HOLDING COMPANY STRUCTURE
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
19
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.
DEPENDENCE UPON OPERATIONS OF PROJECTS
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.'
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
20
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
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 $144,051,000 and
$27,320,000, respectively, as of March 31, 1998. 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
21
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 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.
22
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 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
23
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
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
24
Partnerships until the gas storage volumes are replenished. Curtailment of
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
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
25
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
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.
26
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.
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.'
27
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. PricewaterhouseCoopers LLP has neither examined nor compiled the
Projections contained in Exhibit B, and accordingly, PricewaterhouseCoopers LLP
does not express an opinion or any other form of assurance with respect thereto.
The PricewaterhouseCoopers 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.'
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.'
28
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 $535 million equity
contribution that was used to finance the cost of the Acquisitions.
UNAUDITED PRO FORMA STATEMENTS OF OPERATIONS
On January 14, 1998, ESI Energy, and certain of its wholly-owned
subsidiaries, and Tractebel Power, and certain of its wholly-owned subsidiaries,
joined together through common ownership of NE LP to acquire two
previously-existing partnerships that owned power plants in Massachusetts and
New Jersey. See 'Summary--The Project Partnerships, The Projects and The
Partners.' The Acquisitions have been accounted for using the purchase method of
accounting as cash was exchanged for the existing partnership interests. The
purchase price of approximately $535 million and direct costs of the acquisition
of approximately $10 million have been preliminarily allocated to the fair value
of the net assets acquired and the impacts thereof have been included in the
accompanying unaudited pro forma statements of operations. Management does not
expect the final allocation to differ materially. Pro forma balance sheets have
not been provided since the transactions have been included in the March 31,
1998 unaudited balance sheets of ESI Tractebel Acquisition and NE LP included
elsewhere in this Prospectus.
Additionally, ESI Energy and certain of its wholly-owned subsidiaries and
Tractebel Power joined together to form ESI Tractebel Acquisition, a special
purpose entity created for the issuance of securities to fund a portion of the
Acquisitions (the 'Offering'). See 'Summary--The Securities and the Use of
Proceeds'. The unaudited pro forma statements of operations also include the
impacts of the $220 million proceeds from the Offering on February 12, 1998, and
the approximate $7 million costs of issuing the Old Securities.
The NE LP Unaudited Pro Forma Statements of Operations for the year ended
December 31, 1997 and three-month period ended March 31, 1998 assume that the
Acquisitions and the Offering were consummated on January 1, 1997. The ESI
Tractebel Acquisition Unaudited Pro Forma Statements of Operations for the year
ended December 31, 1997 and three-month period ended March 31, 1998 assume that
the Offering was consummated on January 1, 1997. The adjustments contained in
the NE LP Unaudited Pro Forma Statements of Operations and the ESI Tractebel
Acquisition Unaudited Pro Forma Statements of Operations do not give effect to
any nonrecurring costs directly associated with the Acquisitions and the
Offering that might be incurred within the next twelve months. Further, the
Unaudited Pro Forma Statements of Operations do not give effect to any potential
cost savings and synergies that could result from the Acquisitions such as those
described under 'Certain Transactions.' The pro forma statements include the
fees associated with the New Fuel Agreements, the New O&M Agreements, and the
New Administrative Service Agreement, as these agreements were entered into in
contemplation of the Acquisitions. In addition, management fees historically
paid by the Partnerships to the prior management/owners of the Partnerships have
been removed from the pro forma statements as such fees either will be replaced
by the previously mentioned agreements or, to the extent they are continued,
would be paid to NE LP and thus eliminated from NE LP's consolidated statements
of operations. The unaudited pro forma statements of operations have been
prepared for informational purposes only and are not necessarily indicative of
the actual or future results of operations that would have been achieved had the
Acquisitions and the Offering occurred at the dates assumed. The unaudited pro
forma statements of operations should be read in conjunction with the historical
combined financial statements of the Partnerships and related notes thereto and
with the historical financial statements of NE LP and ESI Tractebel Acquisition
and related notes thereto included elsewhere in this Prospectus.
29
NE LP
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) 131,530
900(B)
Operation and maintenance...................................... 25,689 (4,687)(C) 22,502
1,500(D)
Depreciation and amortization.................................. 24,992 (3,228)(E) 72,067
50,303(F)
General and administrative expenses............................ 15,984 (1,060)(G) 11,766
600(H)
(3,758)(I)
------------ ------------ -----------
Total operating costs and expenses........................ 218,141 19,724 237,865
------------ ------------ -----------
Operating income.......................................... 94,013 (19,724) 74,289
------------ ------------ -----------
Other (income) expenses:
Amortization of financing costs................................ 2,163 (2,163)(J) 605
605(K)
Interest expense............................................... 47,673 17,578(L) 65,251
Interest expense on Energy Bank balances....................... 17,435 -- 17,435
Interest income................................................ (9,931) 7,123(M) (2,808)
------------ ------------ -----------
Total other expenses, net................................. 57,340 23,143 80,483
------------ ------------ -----------
Net income (loss)......................................... $ 36,673 $(42,867) $ (6,194)
------------
------------ ------------ -----------
------------ -----------
- ------------------
(1) Power sales to utilities are net of change in Energy Bank principal
balances. 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.
(Footnotes continued on next page)
30
(Footnotes continued from previous page)
(A) To reflect amortization of $333.544 million of the purchase price allocated
to the above-market Long-term Gas Supply Agreements with ProGas. The ProGas
Agreements are being amortized on a straight-line basis over 16 years, the
remaining contract period.
(B) To reflect $900,000 of fuel management fees associated with the Fuel
Management Agreements. The Fuel Management Agreements provide for a $900,000
fee collectively, per annum, to the fuel manager, an affiliate of FPL
Energy, adjusted annually based on the producer price index.
(C) To reflect amortization of $18.749 million of the purchase price allocated
to the above-market NEA and NJEA O&M Agreements with Westinghouse Services,
the Operator. The above-market O&M Agreements are being amortized on a
straight-line basis over 4 years, the remaining contract period.
(D) To reflect $1.5 million of New O&M Fees associated with the New O&M
Agreements. The New O&M Agreements provide for a $1.5 million fee
collectively, per annum, to the New Operator, an affiliate of NE LP,
adjusted annually based on the producer price index.
(E) To reflect straight-line depreciation over the remaining life of the assets,
ranging from 3 to 34 years, of $513.066 million of the purchase price
allocated to the property, plant and equipment.
(F) To reflect amortization over remaining contract periods, ranging from 14 to
24 years, of $888.756 million of the purchase price allocated to the 6
Power Purchase Agreements. Amortization is provided on a straight-line
basis or matched to fixed scheduled price increases under the Power
Purchase Agreements, as applicable.
(G) Payments made to Westinghouse that could be earned if certain targeted heat
rates were achieved in future periods were recorded as a prepaid asset prior
to the Acquisitions in the amount of $3.653 million at January 1, 1997. This
prepaid asset was determined to be of no value subsequent to the
Acquisitions, therefore $1.060 million amortization of such prepaid asset
has been removed.
(H) To reflect $600,000 of Administrative Services Fees associated with the
Administrative Services Agreement. The Administrative Services Agreement
provides for a $600,000 fee collectively, per annum, to ESI GP, the
administrative general partner of NE LP, adjusted annually based on the
producer price index.
(I) To remove the management fees of $3.758 million paid to the prior
management/owners of the Partnerships.
(J) To remove the amortization of financing costs eliminated from the
Partnerships' books pursuant to application of purchase accounting.
(K) To reflect amortization of debt issuance costs of $6.663 million over 14
years, using the effective interest method.
(L) To reflect the interest expense associated with the Note Payable to ESI
Tractebel Acquisition of $220 million at an interest rate of 7.99%.
(M) To remove the interest income associated with the cash and investments that
were released from the Debt Service Reserve Fund and the Energy Bank Cash
Collateral Proceeds upon completion of the Acquisitions. With the consent of
the holders of the Project Securities, the Project Indenture was amended to
permit substitution of a guaranty and new letters of creditfor the cash
collateral previously held by the Partnerships. In connection with the
Acquisitions, the Original Project Indenture was amended by a Second
Supplemental Trust. The amendment permitted (i) the Acquisitions and (ii)
upon substitution of a guaranty and substitute letter of credit, the release
directly to the Partners of amounts held as collateral for the Energy Bank
liabilities and amounts in the Debt Service Reserve Fund for the Project
Securities. These transactions were contemplated as part of the
Acquisitions. On January 21, 1998 the funds in the Debt Service Reserve Fund
were released and distributed to NE LP, and on February 3, 1998 the cash
collateral proceeds were released and distributed to NE LP, who in turn
distributed the funds to its partners.
31
NE LP
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
FOR THE THREE MONTH PERIOD ENDED MARCH 31, 1998
PRO FORMA
----------------------------------------------------------
ACQUISITIONS
AND
NE LP PARTNERSHIPS OFFERING NE LP
HISTORICAL JANUARY1-13, 1998(A) ADJUSTMENTS AS ADJUSTED
---------- --------------------- --------------- -----------
(IN THOUSANDS OF DOLLARS)
Revenue:
Power sales to utilities(1).................. $ 73,596 $12,911 $ -- $86,507
Steam sales.................................. 1,143 198 -- 1,341
---------- ---------- --------------- -----------
Total revenues.......................... 74,739 13,109 -- 87,848
---------- ---------- --------------- -----------
Costs and expenses:
Cost of power and steam sales................ 29,517 5,774 (728)(B) 34,591
28(C)
Operation and maintenance.................... 4,738 974 (164)(D) 5,596
48(E)
Depreciation and amortization................ 15,508 894 (140)(F) 18,017
1,755(G)
General and administrative expenses.......... 2,168(2) 538 (37)(H) 2,514
(21)(I)
(134)(J)
---------- ---------- --------------- -----------
Total operating costs and expenses...... 51,931 8,180 607 60,718
---------- ---------- --------------- -----------
Operating income........................ 22,808 4,929 (607) 27,130
---------- ---------- --------------- -----------
Other (income) expense:
Amortization of financing costs.............. 72 69 (69)(K) 151
79(L)
Interest expense-debt........................ 11,896 1,723 2,344(M) 15,963
Interest expense on energy bank balances..... 3,867 630 -- 4,497
Interest income.............................. (653) (402) 680(N) (375)
---------- ---------- --------------- -----------
Total other expenses, net............... 15,182 2,020 3,034 20,236
---------- ---------- --------------- -----------
Net income.............................. $ 7,626 $ 2,909 $(3,641) $ 6,894
---------- ---------- --------------- -----------
---------- ---------- --------------- -----------
- ------------------
(1) See Note 1 to NE LP Unaudited Pro Forma Statement of Operations for the
Year Ended December 31, 1997.
(2) Includes $274 thousand of non-recurring, non-capitalizable acquisition
costs.
(A) Adjust to include the Partnerships' historical activity from January 1, 1998
to January 13, 1998, the date prior to the date of consummation of the
Acquisitions.
(B) To reflect amortization of $333.544 million of the purchase price allocated
to the above-market Long-term Gas Supply Agreements with ProGas. The ProGas
Agreements are being amortized on a straight-line basis over 16 years, the
remaining contract period.
(C) To reflect fuel management fees associated with the Fuel Management
Agreements. The Fuel Management Agreements provide for a $900,000 fee
collectively, per annum, to the fuel manager, an affiliate of FPL Energy,
adjusted annually based on the producer price index.
(Footnotes continued on next page)
32
(Footnotes continued from previous page)
(D) To reflect amortization of $18.749 million of the purchase price allocated
to the above market NEA and NJEA O&M Agreements with Westinghouse Services,
the Operator. The above market O&M contracts are being amortized on a
straight-line basis over 4 years, the remaining contract period.
(E) To reflect New O&M Fees associated with the New O&M Agreements. The New O&M
Agreements provide for a $1.5 million fee collectively, per annum, to the
New Operator, an affiliate of NE LP, adjusted annually based on the producer
price index.
(F) To reflect straight-line depreciation over the remaining life of the
assets, ranging from 3 to 34 years, of $513.066 million of the purchase
price allocated to the property, plant and equipment.
(G) To reflect amortization over contract periods, ranging from 14 to 24 years,
of $888.756 million of the purchase price allocated to the 6 Power Purchase
Agreements. Amortization is provided on a straight-line basis or matched to
fixed scheduled price increases under the Power Purchase Agreements, as
applicable.
(H) Payments made to Westinghouse that could be earned if certain targeted heat
rates were achieved in future periods were recorded as a prepaid asset prior
to the Acquisitions in the amount of $3.653 million at January 1, 1997. This
prepaid asset was determined to be of no value subsequent to the
Acquisitions, therefore $37,000 amortization of such prepaid asset has been
removed.
(I) To reflect Administrative Services Fees associated with the Administrative
Services Agreement. The Administrative Services Agreement provides for a
$600,000 fee collectively, per annum, to ESI GP, the administrative general
partner of NE LP, adjusted annually based on the producer price index.
(J) To remove management fees paid to the prior management/owners of the
Partnerships prior to the Acquisitions, as new agreements were entered into
in contemplation of the Acquisition.
(K) To remove the amortization of financing costs eliminated from the
Partnerships' books pursuant to application of purchase accounting.
(L) To reflect amortization of debt issuance costs of $6.663 million over 14
years, using the effective interest method.
(M) To reflect additional interest expense associated with the Note Payable to
ESI Tractebel Acquisition of $220 million at an interest rate of 7.99%
executed on February 19, 1998.
(N) To remove the interest income associated with the cash and investments that
were released from the Debt Service Reserve Fund through January 21, 1998
and the Energy Bank Cash Collateral Proceeds through February 3, 1998 upon
completion of the Acquisitions. With the consent of the holders of the
Project Securities, the Project Indenture was amended to permit substitution
of a guaranty and new letters of credit for the cash collateral previously
held by the Partnerships. See 'Summary--Outstanding Project Indebtedness.'
In connection with the Acquisitions, the Original Project Indenture was
amended by a Second Supplemental Trust. The amendment permitted (i) the
Acquisitions and (ii) upon substitution of a guaranty and substitute letter
of credit, the release directly to the Partners of amounts held as
collateral for the Energy Bank liabilities and amounts in the Debt Service
Reserve Fund for the Project Securities. These transactions were
contemplated as part of the Acquisitions. On January 21, 1998 the funds in
the Debt Service Reserve Fund were released and distributed to NE LP, and on
February 3, 1998 the cash collateral proceeds were released and distributed
to NE LP, who in turn distributed the funds to its partners.
33
ESI TRACTEBEL ACQUISITION
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1997
PRO FORMA
ACTUAL ADJUSTMENTS PRO FORMA
-------- ----------- -------------
(IN THOUSANDS OF DOLLARS)
Total revenues................................................... $ -- $ -- $ --
-------- ----------- -------------
Other income (expense):
Interest income................................................ -- 17,578(A) 17,578
Interest expense............................................... -- (17,578)(B) (17,578)
Amortization................................................... -- 14(C) 14
-------- ----------- -------------
Income before taxes.............................................. -- 14 14
Income tax expense............................................... -- 5(D) 5
-------- ----------- -------------
Net income................................................ $ -- $ 9 $ 9
-------- ----------- -------------
-------- ----------- -------------
- ------------------
(A) To reflect the interest income, calculated at 7.99% of $220 million, through
December 31, 1997 giving effect to the consummation of the Offering on
January 1, 1997. The terms of the Note from NE LP are substantially
identical to the terms of the Old Securities.
(B) To reflect the interest expense, calculated at 7.99% of $220 million,
through December 31, 1997 giving effect to the consummation of the Offering
on January 1, 1997.
(C) To reflect amortization of $14 thousand of deferred revenue resulting from
the gain on a forward rate agreement entered into by ESI Tractebel
Acquisition with Goldman Sachs Capital Markets, L.P. ('GSCM') in connection
with the Offering. The forward rate agreement established a hypothetical
interest rate for the Securities prior to the Offering (the "Hypothetical
Rate") and required a payment to be made by GSCM to ESI Tractebel
Acquisition or from ESI Tractebel Acquisition to GSCM depending on the
spread between the Hypothetical Rate and the actual interest rate borne by
the Securities (the "Actual Rate"). The gain of $152,000 resulted from the
Actual Rate being higher than the Hypothetical Rate. The Hypothetical Rate
was 5.445% for $150 million aggregate principal amount of the Securities
and 5.558% for $70 million aggregate principal amount of the Securities.
(D) Income tax at rate of 34%.
34
ESI TRACTEBEL ACQUISITION
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
FOR THE THREE MONTH PERIOD ENDED MARCH 31, 1998
PRO FORMA
ACTUAL ADJUSTMENTS PRO FORMA
------- ----------- -------------
(IN THOUSANDS OF DOLLARS)
Total revenues..................................................... $ -- $ -- $ --
------- ----------- -------------
Other income (expense):
Interest income.................................................. 2,051 2,344(A) 4,395
Interest expense................................................. (2,051) (2,344)(B) (4,395)
Amortization..................................................... 2 2(C) 4
------- ----------- -------------
Income before taxes................................................ 2 2 4
Income tax expense................................................. -- 1(D) 1
------- ----------- -------------
Net income.................................................. $ 2 $ 1 $ 3
------- ----------- -------------
------- ----------- -------------
- ------------------
(A) To reflect the interest income, calculated at 7.99% of $220 million, through
March 31, 1998 giving effect to the consummation of the Offering on January
1, 1997. The terms of the Note from NE LP are substantially identical to the
terms of the Old Securities.
(B) To reflect the interest expense, calculated at 7.99% of $220 million,
through March 31, 1998 giving effect to the consummation of the Offering on
January 1, 1997.
(C) To reflect the amortization of $2 thousand of deferred revenue resulting
from the gain on a forward rate agreement entered into by ESI Tractebel
Acquisition with GSCM in connection with the Offering. The forward rate
agreement established a Hypothetical Rate for the Securities prior to the
Offering and required a payment to be made by GSCM to ESI Tractebel
Acquisition or from ESI Tractebel Acquisition to GSCM depending on the
spread between the Hypothetical Rate and the Actual Rate. The gain of
$152,000 resulted from the Actual Rate being higher than the Hypothetical
Rate. The Hypothetical Rate was 5.445% for $150 million aggregate principal
amount of the Securities and 5.558% for $70 million aggregate principal
amount of the Securities.
(D) Income tax at rate of 34%.
35
SELECTED HISTORICAL FINANCIAL DATA
The selected historical 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 PricewaterhouseCoopers LLP,
independent accountants. The selected historical financial data of the
Partnerships 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. The
selected historical and combined financial data of the Partnerships as of and
for the three months ended March 31, 1997 and 1998 have been derived from the
Partnerships' combined unaudited financial statements included elsewhere in this
Prospectus, which have been prepared on a basis substantially consistent with
the audited financial statements and, in the opinion of Partnerships'
management, include the purchase accounting adjustments and all other
adjustments, consisting only of normal recurring adjustments, necessary for a
fair presentation of the information set forth herein. The selected historical
financial data of NE LP and ESI Tractebel Acquisition as of and for the
three-month period ended March 31, 1998 have been derived from the unaudited
financial statements included elsewhere in this Prospectus, which have been
prepared on a basis substantially consistent with the audited financial
statements and in the opinion of NE LP's and ESI Tractebel Acquisition's
management, include the purchase accounting adjustments and all other
adjustments, consisting only of normal recurring adjustments necessary for a
fair presentation of the information set forth therein. The results for the
three-month period ended March 31, 1998 are not necessarily indicative of the
results expected for the year ending December 31, 1998 or for any subsequent
period. The selected historical balance sheets of NE LP and ESI Tractebel
Acquisition at December 31, 1997 and January 12, 1998, respectively, have been
derived from the audited balance sheets included in this Prospectus. This data
should be read in conjunction with, and is qualified by reference to, the
Partnerships' audited and unaudited combined financial statements and related
notes thereto, NE LP's and ESI Tractebel Acquisition's audited and unaudited
financial statements, respectively, and related notes thereto, included
elsewhere in this Prospectus, and 'Management's Discussion and Analysis of
Financial Condition and Results of Operations.'
PARTNERSHIPS COMBINED
--------------------------------------------------------------------------------
THREE
MONTHS PREDECESSOR
ENDED JANUARY
YEARS ENDED DECEMBER 31, MARCH 31, 1-13
---------------------------------------------------- ----------- -----------
1993(1) 1994 1995 1996 1997 1997 1998
-------- -------- -------- -------- -------- ----------- -----------
(IN THOUSANDS)
--------------------------------------------------------------------------------
STATEMENT OF OPERATIONS DATA:
Revenue:
Power sales to utilities net of Energy
Bank
changes(2).............................. $234,142 $234,933 $276,022 $267,789 $307,530 $ 81,035 $12,911
Steam sales............................... 4,684 3,779 4,527 4,473 4,624 1,301 198
-------- -------- -------- -------- -------- ----------- -----------
Total revenue....................... 238,826 238,712 280,549 272,262 312,154 82,336 13,109
-------- -------- -------- -------- -------- ----------- -----------
Costs and expenses:
Cost of power and steam sales............. 132,580 128,402 132,839 138,727 151,476 38,248 5,774
Operation and maintenance................. 20,283 20,808 24,699 22,854 25,689 6,765 974
Depreciation and amortization............. 24,919 24,314 24,904 24,978 24,992 6,250 894
General and administrative expenses....... 14,162 11,012 12,010 14,424 15,984 3,353 538
-------- -------- -------- -------- -------- ----------- -----------
Total operating costs and
expenses.......................... 191,944 184,536 194,452 200,983 218,141 54,616 8,180
-------- -------- -------- -------- -------- ----------- -----------
Operating income.......................... 46,882 54,176 86,097 71,279 94,013 27,720 4,929
-------- -------- -------- -------- -------- ----------- -----------
Other (income) expenses:
Amortization of financing costs........... 2,599 2,333 2,305 2,373 2,163 559 69
Interest expense.......................... 38,992 38,068 50,930 49,841 47,673 12,038 1,723
Interest expense on Energy Bank
balances................................ 7,252 11,676 16,657 19,675 17,435 4,260 630
Interest income........................... (700) (1,656) (10,652) (10,534) (9,931) (2,189) (402)
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 14,668 2,020
-------- -------- -------- -------- -------- ----------- -----------
(Loss) income before extraordinary item... (1,261) (2,979) 26,857 9,924 36,673 13,052 2,909
Extraordinary item:
Loss on extinguishment of debt(3)......... -- 13,937 -- -- -- -- --
-------- -------- -------- -------- -------- ----------- -----------
Net income (loss).......................... $ (1,261) $(16,916) $ 26,857 $ 9,924 $ 36,673 $ 13,052 $ 2,909
-------- -------- -------- -------- -------- ----------- -----------
-------- -------- -------- -------- -------- ----------- -----------
Distributions to partners.................. $ 10,878 $ 27,472 $ 64,506 $ 66,826 $ 46,380 $ -- $ --
Ratio of earnings to fixed charges(4)...... -- -- 1.38 1.14 1.54 1.77 2.20
SUCCESSOR
JANUARY 14-
MARCH 31,
-----------
1998(5)
-----------
STATEMENT OF OPERATIONS DATA:
Revenue:
Power sales to utilities net of Energy
Bank
changes(2).............................. $ 73,596
Steam sales............................... 1,143
-----------
Total revenue....................... 74,739
-----------
Costs and expenses:
Cost of power and steam sales............. 29,517
Operation and maintenance................. 4,738
Depreciation and amortization............. 15,508
General and administrative expenses....... 1,895
-----------
Total operating costs and
expenses.......................... 51,658
-----------
Operating income.......................... 23,081
-----------
Other (income) expenses:
Amortization of financing costs........... --
Interest expense.......................... 9,845
Interest expense on Energy Bank
balances................................ 3,867
Interest income........................... (653)
Expense related to future obligations
under interest rate swap
agreements(3)........................... --
-----------
Total other expenses................ 13,059
-----------
(Loss) income before extraordinary item... 10,022
Extraordinary item:
Loss on extinguishment of debt(3)......... --
-----------
Net income (loss).......................... $ 10,022
-----------
-----------
Distributions to partners.................. $ 104,920
Ratio of earnings to fixed charges(4)...... 1.73
36
NE LP ESI TRACTEBEL ACQUISITION
--------------------------- ---------------------------
THREE MONTHS THREE MONTHS
YEAR ENDED ENDED PERIOD ENDED ENDED
DECEMBER 31, MARCH 31, JANUARY 12, MARCH 31,
1997 1998(6) 1998 1998
------------ ------------ ------------ ------------
STATEMENT OF OPERATIONS DATA:
Revenue:
Power sales to utilities net of Energy Bank changes(2)................. $ -- $ 73,596 $ -- $ --
Steam sales............................................................ -- 1,143 -- --
------------ ------------ ------------ ------------
Total revenue.................................................... -- 74,739 -- --
------------ ------------ ------------ ------------
Costs and expenses:
Cost of power and steam sales.......................................... -- 29,517 -- --
Operation and maintenance.............................................. -- 4,738 -- --
Depreciation and amortization.......................................... -- 15,508 -- --
General and administrative expenses.................................... -- 2,168 -- --
------------ ------------ ------------ ------------
Total operating costs and expenses............................... -- 51,931 -- --
------------ ------------ ------------ ------------
Operating income....................................................... -- 22,808 -- --
------------ ------------ ------------ ------------
Other (income) expenses:
Amortization of debt expense........................................... -- 72 -- --
Interest expense....................................................... -- 11,896 -- 2,051
Interest expense on Energy Bank balances............................... -- 3,867 -- --
Interest income........................................................ -- (653) -- (2,053)
------------ ------------ ------------ ------------
Total other (income) expenses.................................... -- 15,182 -- (2)
------------ ------------ ------------ ------------
Income before extraordinary item....................................... -- 7,626 -- 2
Extraordinary item:
------------ ------------ ------------ ------------
Net income............................................................. -- $ 7,626 -- $ 2
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Distributions to partners............................................... -- $307,619 -- $ --
Ratio of earnings to fixed charges(4)................................... N/A 1.48 N/A 1.00
Pro forma ratio of earnings to fixed charges(4)......................... -- 1.33 1.00 1.00
PARTNERSHIPS COMBINED
---------------------------------------------------------------------------
AS OF
AS OF DECEMBER 31, MARCH 31,
------------------------------------------------------------ ----------
1993(1) 1994 1995 1996 1997 1998
-------- -------- -------- -------- -------- ----------
(IN THOUSANDS)
BALANCE SHEET DATA:
Working capital...................................... $ 19,754 $ 74,145 $ 71,975 $ 58,846 $ 63,715 $ 51,343
Total assets......................................... 546,484 650,027 617,034 566,534 541,545 1,491,274
Total loans payable.................................. 465,458 560,000 539,566 514,362 490,287 490,287
Energy Bank balances(2).............................. 111,398 155,496 188,053 220,922 230,565 171,371
Partners' (deficit)/equity........................... (48,540) (92,928) (130,577) (187,479) (197,186) 450,876
ESI TRACTEBEL ACQUISITION
NE LP -------------------------
--------------------------- AS OF
AS OF AS OF AS OF MARCH
DECEMBER 31, MARCH 31, JANUARY 12, 31,
1997 1998 1998 1998
------------ ---------- ------------ --------
(IN THOUSANDS)
BALANCE SHEET DATA:
Working capital...................................................... $ -- $ 49,292 $ -- $ --
Total assets......................................................... -- 1,498,932 -- 222,203
Total loans payable.................................................. -- 710,287 -- 220,000
Energy Bank balances(2).............................................. -- 171,371 -- --
Partners'/stockholders' equity....................................... -- 235,416 -- 2
- ------------------
(1) 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.
(2) 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.'
(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 from continuing operations 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
Partnerships' earnings for 1993 and 1994 were inadequate to cover fixed
charges. The coverage deficiencies during 1993 and 1994 were $1.261 million
and $2.979 million, respectively. The NE LP pro forma earnings for 1997 were
inadequate to cover fixed charges. The coverage deficiency was $6.194
million.
(5) Reflects the combined results of the Partnerships from January 14, 1998
through March 31, 1998, subsequent to the Acquisitions, which reflects a new
basis for certain assets and liabilities.
(6) Includes the results of the Partnerships subsequent to the Acquisitions.
37
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 AND THE OFFERING
On January 14, 1998, pursuant to a Purchase Agreement, dated as of November
21, 1997, all of the partnership interests in the Partnerships were acquired by
the Partners (NE LP and NE LLC) from the Sellers. The Partners are owned by
direct subsidiaries of ESI Energy and Tractebel Power. See 'Summary--The
Partners.'
The Acquisitions were accounted for using the purchase method of
accounting. The consideration, paid in cash, to acquire the interests in the
Partnerships of approximately $545 million including approximately $10 million
of acquisition costs, was allocated to the assets and liabilities acquired
based on their fair values. Accordingly, the financial statements for periods
prior to January 14, 1998 are not comparable to or indicative of results for
any period following the Acquisitions.
In connection with the Acquistions, the Sanwa Credit Agreement, Sanwa
Letters of Credit and the Sanwa Working Capital Facility were terminated and
such agreements and the Debt Service Reserve Fund were replaced with Substitute
Letters of Credit. In addition, the Cash Collateral Proceeds related to the
Energy Bank Letters of Credit was released in exchange for a guaranty by one of
the acquiring entities (the 'FPL Group Capital Guaranty'). Because of the
reduction in cash held by the Partnerships, future interest income is expected
to be less than amounts recorded in prior periods. The Power Purchase Agreements
were not affected by the transactions and contracts with third parties to
provide fuel and operations and maintenance (O&M) services remain in place for,
16 and 4 years, respectively. The Projects are operated and maintained by
Westinghouse Services, a subsidiary of Westinghouse Electric. On November 15,
1997, Westinghouse Electric announced that it intended to sell certain of its
industrial businesses, including the business of Westinghouse Services, to
Siemens AG. Each of the Partnerships is a party to a new Fuel Management
Agreement with an affiliate of ESI Energy. Each of the Partnerships is also a
party to a new O&M Agreement with ESI Operating Services, Inc. (the
38
'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. The Partnerships do
not anticipate a material adverse effect related to this potential change in
service provider.
On February 12, 1998, ESI Tractebel Acquisition issued $220 million of
7.99% Secured Bonds Due 2011. The proceeds from the sale of the Securities were
loaned to NE LP, evidenced by the Note with substantially identical terms as the
Securities, for the purpose of reimbursing certain of the partners of NE LP for
a portion of the original $535 million equity contribution that was used to
finance the cost of the Acquisitions. Distributions by NE LP to its partners
totaled $307.619 million through March 31, 1998.
Partnership operations are expected to provide funds for repayment of the
Securities. Distributions from the Partnerships are only allowed following
satisfaction of debt service requirements of previously existing debt. The
Securities are nonrecourse to NE LP's partners, but the interests in the
Partnerships serve as a guaranty. The Securities will rank senior to all
subordinated indebtedness and rank evenly with all senior indebtedness that ESI
Tractebel Acquisition incurs in the future.
Payments in respect to 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 the Partnerships, including the guarantee by the Partnerships of
the Project Indebtedness.
RESULTS OF OPERATIONS
FOR THE PARTNERSHIPS FOR THE THREE MONTH PERIOD ENDED MARCH 31, 1997
Revenues................................................................. $82,336
Operating income......................................................... $27,720
Net income............................................................... $13,052
Revenues for the first quarter 1997 totaled $82.3 million and were
comprised of $81.0 million of power sales to utilities and $1.3 million of steam
sales. Power sales to utilities reflects changes in utility energy bank balances
which are determined in accordance with scheduled or specified rates under
certain power purchase contracts.
Fuel expense of $38.2 million includes fuel purchased for the Partnerships
and fixed and variable costs associated with delivery and use of the fuel for
operations.
O&M expenses of $6.8 million are comprised of Westinghouse (the O&M
provider) fees and site utility expenses, as well as performance bonuses and
heat rate bonuses payable under the Bellingham and Sayreville O&M agreements.
Depreciation and amortization of $6.3 million is comprised of depreciation
for the cogeneration and carbon dioxide facilities.
General and administrative expenses of $3.4 million are comprised primarily
of management fees.
Interest expense is comprised primarily of interest on notes payable to IEC
Funding Corp. ($12.0 million) and interest on energy bank balances ($4.3
million).
Interest income of $2.2 million reflects cash balances earning investment
income.
FOR THE PARTNERSHIPS FOR THE PERIOD FROM JANUARY 1, 1998 TO JANUARY 13, 1998
(PRE-ACQUISITION)
Revenues for the thirteen-day period totaled $13.1 million and were
comprised of $12.9 million of power sales to utilities and $200 thousand of
steam sales. Power sales to utilities reflects changes in utility energy bank
balances which are determined in accordance with scheduled or specified rates
under certain power purchase contracts.
Fuel expense of $5.8 million includes fuel purchased for the Partnerships
and the fixed and variable costs associated with the delivery and use of the
fuel for operations.
O&M expenses of $974 thousand are comprised of Westinghouse (the O&M
provider) fees and site utility expenses.
Depreciation and amortization of $894 thousand is comprised of depreciation
for the cogeneration and carbon dioxide facilities.
General and administrative expenses of $538 thousand are comprised
primarily of management fees.
Interest expense is comprised primarily of interest on notes payable to IEC
Funding Corp. ($1.7 million) and interest on energy bank balances ($630
thousand).
Interest income reflects cash balances earning investment income.
Subsequent to January 14, 1998, the date of the Acquisitions, the basis of
presentation of the results of operations for the Partnerships on a going
forward basis was changed to reflect the basis of presentation used by NE LP.
39
FOR NE LP FOR THE THREE MONTHS ENDED MARCH 31, 1998
The following narrative explains NE LP's operations for the three months
ended March 31, 1998 which primarily reflect the operations of the Partnerships
subsequent to the Acquisitions on January 14, 1998 through March 31, 1998 and
the related allocation of the purchase price.
Revenues for the period which represent those of the Partnerships
subsequent to the Acquisitions on January 14, 1998, totaled $74.7 million and
were comprised of $73.6 million of power sales to utilities and $1.1 million of
steam sales. Power sales to utilities reflects changes in utility energy bank
balances of $4.0 million which are determiend in accordance with scheduled or
specified rates under certain power purchase contracts.
Fuel expense of $29.5 million is comprised of $34.0 million of fuel
purchased for the Partnerships and the fixed and variable costs associated with
the delivery and use of the fuel for operations. These fuel costs are offset by
$4.5 million of deferred credit amortization for fuel contracts as a result of
the purchase price allocation of the Acquisitions.
O&M expenses are comprised of Westinghouse (the O&M provider) fees and site
expenses ($5.7 million) offset by $1.0 million of deferred credit amortization
for O&M contracts as a result of the purchase price allocation of the
Acquisitions.
Depreciation and amortization is comprised of $4.7 million of depreciation
for the cogeneration and carbon dioxide facilities and $10.8 million of
amortization of the power purchase contracts as a result of the purchase price
allocation of the Acquisitions.
General and administrative expenses are comprised primarily of management
and professional fees of $1.1 million and site expenses of $700 thousand.
Interest expense is comprised primarily of interest of the Partnerships on
notes payable to ESI Tractebel Funding Corp. ($9.8 million) and interest on
energy bank balances ($3.9 million). Interest expense also includes interest of
approximately $2.1 million on the note payable to ESI Tractebel Acquisition
subsequent to February 19, 1998.
Interest income reflects cash balances earning investment income and
reflects the impact of the release and distribution of the Debt Service Reserve
Fund on January 21, 1998 and Energy Bank Collateral Proceeds on February 3,
1998.
FULL YEAR RESULTS
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.
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.
40
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. This receivable
is related to an amount due from a Power Purchase Utility, which was in dispute.
This receiveable resulted from energy production above the amounts specified in
a related Power Purchase Agreement and is being disputed by the purchasing
utility. 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 $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
41
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.
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 March 31, 1998, the Partnerships' cash and cash equivalents totaled
approximately $60.5 million, as compared to $61.2 million at December 31, 1997.
The decrease in cash and cash equivalents was the net effect of $35.1 million
provided by operations and $69.1 million from the release of restricted cash
collateral offset by $104.9 million in distributions to Partners.
As of March 31, 1998, 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.
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,
42
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.
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 and the
three months ended March 31, 1998.
DECEMBER 31, 1995 DECEMBER 31, 1996 DECEMBER 31, 1997 MARCH 31, 1998
----------------- ----------------- ----------------- -----------------
Notional Amount..................... $27,596,000 $20,335,000 $12,940,000 $12,940,000
Fair value (liability)(1)........... $(3,654,000) $(2,022,000) $ (889,000) $ (671,000)
Net Effect of Swaps on Interest
Expense (2)....................... $ (486,000) $ 137,000 $ 103,000 $ (21,000)
- ------------------
(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.
43
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.
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
THREE
MONTHS
ENDED
FOR THE YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------- ---------
1995 1996 1997 1998
--------- ---------- ---------- ---------
Net gain/(loss) included in cost of power
and steam sales............................................ $(448,000) $5,246,000 $3,990,000 $14,500
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.'
44
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.
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
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
45
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.'
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
46
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 Project is dependent upon three electrical energy purchasers for
sales of substantially all of the electricity produced by the NEA Project, one
natural gas supplier, ProGas, 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. See 'Risk Factors--Dependence Upon Third
Parties.
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.
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.
47
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.'
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.
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 then revenues from steam sales. In
addition, the NJEA Project is dependent upon two natural gas suppliers, ProGas
and PSE&G, for substantially all natural gas required to operate the NJEA
Project. The NJEA Project is dependent upon Hercules for steam sales. NJEA's
steam sales depend upon the continuing operation and viability of the Hercules
plant. 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. See 'Dependence Upon Third Parties.'
48
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.
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.'
49
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.
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
ENTITLEMENT EXPIRATION
---------------- 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,
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
50
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 March 31, 1998, the Energy Bank
liability under the Montaup Power Purchase Agreement was approximately
$27,320,000 and under the Boston Edison I Power Purchase Agreement was
approximately $144,051,000, net of purchase accounting adjustments made in
connection with the Acquisitions. 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.'
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
51
(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
NEA
(BEF)
-------------- NJEA TOTAL CONTRACT
SOURCES OF GAS CONSUMED CONTRACT BY THE PROJECTS (BEF) (BEF) EXPIRATION
- ------------------------------------------------------ -------------- -------------- ----------
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
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.
52
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. Such liquidated
damages for each hour of shortfall shall be 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.
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. 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 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
53
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:
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.
54
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
'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
55
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 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.
56
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
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
57
also promulgated standards of conduct to ensure that the utilities functionally
separate their transmission and wholesale power merchant functions to prevent
self-dealing.
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
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.
58
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
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
59
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.'
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).
60
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
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. 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.
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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,
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
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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 March 31, 1998, the Energy Bank balance under the Boston Edison
I Power Purchase Agreement was approximately $144,051,000 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.'
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
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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, 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.
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.
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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.
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.
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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
'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.
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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.
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
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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 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 March 31, 1998 the
Energy Bank balance under the contract was approximately $27,320,000. 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.
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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.
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
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
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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
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.
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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.
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.
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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.
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.
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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
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
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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
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
Facility experiences certain
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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
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
76
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.
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
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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 22degreesF 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 14degrees 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
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:
78
MAXIMUM DAILY CONTRACT
GAS TRANSPORTER AND AGREEMENTS QUANTITY EXPIRATION DATE
- ----------------------------------------------------------------- ---------------------- ----------------------
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.
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
Rate Schedule GSS-11 Dth
79
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
Rate Schedule GSS-11 Dth
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
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circumstances, to reimburse excess fuel costs and (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
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
81
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,
(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
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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
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.
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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
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
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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 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
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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 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.
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,
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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
$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.
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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.
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
89
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.
MANAGEMENT
DIRECTORS OF ESI TRACTEBEL ACQUISITION
NAME AGE AFFILIATION
- --------------------------------------------------------- --- --------------------------------
Glenn E. Smith........................................... 40 FPL Energy--Vice President
Timothy R. Dunne......................................... 46 Tractebel Power--Senior Vice
President
Paul J. Cavicchi......................................... 45 Tractebel Power--Executive Vice
President
Glenn E. Smith was appointed to the Board of Directors of ESI Tractebel
Acquisition in January 1998. Mr. Smith joined ESI Energy in June 1997 as its
Vice President of Project Development and is currently a Vice President of FPL
Energy. From May 1995 until joining ESI Energy, Mr. Smith was the Director of
Business Development of Nations Energy Corporation where he directed greenfield
project development and investment in operating energy assets. From August 1992
until May 1995, Mr. Smith was Vice President of BOT Financial Corp. He holds a
B.S. degree from Pennsylvania State University.
Timothy R. Dunne was appointed to the Board of Directors of ESI Tractebel
Acquisition in January 1998. Mr. Dunne has been the Senior Vice President,
General Counsel and Secretary of Tractebel Power since 1995. In such capacity,
Mr. Dunne manages all of the legal services required by Tractebel Power and its
affiliates. Prior to joining Tractebel Power in 1990, Mr. Dunne acted as
in-house counsel for two major U.S. engineering and construction companies. He
holds a J.D. degree from the University of Toledo and M.S. and B.S. degrees from
the University of Notre Dame.
Paul J. Cavicchi was appointed to the Board of Directors of ESI Tractebel
Acquisition in January 1998. Mr. Cavicchi has been an Executive Vice President
of Tractebel Power since 1995. In such capacity, Mr. Cavicchi supervises and
directs business development for energy asset investments in North America.
Prior to joining Tractebel Power in 1995, Mr. Cavicchi served as a General
Manager for American Tractebel, Inc., an affiliate of Tractebel Power. He holds
an M.B.A. degree from the University of Virginia, an M.S. degree from the
University of Massachusetts and a B.S. degree from Tufts University.
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--Vice President
Scot C. Hathaway............................................. 46 FPL Energy--Director, Fuels and Business
Management
Eric M. Heggeseth............................................ 46 Tractebel Power--Vice President
W.E. (Wes) Schattner......................................... 45 Tractebel Power--Executive Vice
President
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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 June 30, 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., 700 Universe Blvd., Juno Breach, 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 June 30, 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.
TITLE OF NAME AND ADDRESS OF AMOUNT AND NATURE 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., 700 Universe Blvd., Juno 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
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.'
ESI Tractebel Acquisition believes that each of the transactions set forth
above were entered into on terms no less favorable than could typically be
obtained from independent third parties possessing similar expertise and
resources.
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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.
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
94
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 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,
95
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.
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
96
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 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.
97
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'.
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 tendered in proper
form for transfer
98
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 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;
99
(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:
Deliver to:
State Street Bank and Trust Company
Exchange Agent:
BY HAND DELIVERY: BY OVERNIGHT COURIER BY MAIL:
- ------------------------------------ ------------------------------------ ------------------------------------
State Street Bank and State Street Bank and State Street Bank and
Trust Company Trust Company 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.
100
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 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.
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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 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
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
102
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.
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 March 31, 1998, NE LP had
approximately $881,658,000 of Indebtedness outstanding. See 'Risk
Factors--Holding Company Structure' 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
103
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.
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.
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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 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
105
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.
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
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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.
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;
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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.
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.
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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 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
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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
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
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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.
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 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
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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.'
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.
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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.
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
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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.
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.
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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.
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
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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 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;
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(iv) waive a Default or Event of Default in the payment of principal of or
premium, if any, or interest or Registration Default 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, 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
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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.
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.
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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-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
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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 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
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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.
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.
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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 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.
'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.'
123
'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 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.
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'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.
'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 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 March 31,
1998, 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 March 31, 1998.
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.
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.
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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 $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
127
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.
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,
128
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 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.
129
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.
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.
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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.'
CERTAIN FEDERAL TAX CONSIDERATIONS
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 is a U.S. Holder
or Non-U.S. Holder. The terms 'U.S. Holder' and 'Non-U.S. Holder' refer,
respectively, to holders of Securities that are or are not classified as United
States persons for United States federal income and estate tax purposes. 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. This discussion is based upon the United States federal tax law
now in effect, which is subject to change, possibly retroactively. The tax
treatment of the holders of the Securities may vary depending upon their
particular situations. 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 U.S. Holder of that U.S. Holder or a Non-U.S. Holder
of that Non-U.S. Holder are not discussed. 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.
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.
U.S. HOLDERS
Interest
Interest paid by ESI Tractebel Acquisition to a U.S. Holder will generally
be taxable as ordinary interest income in accordance with the U.S. Holder's
method of tax accounting at the time that such interest is accrued or (actually
or constructively) received.
131
Disposition of Securities
In general, a U.S. Holder will recognize gain or loss upon the sale,
redemption, retirement or other disposition of the Security measured by the
difference between the amount of cash and fair market value of other property
received (except to the extent attributable to the payment of accrued interest)
and the U.S. Holder's adjusted tax basis in the Security. A U.S. Holder's
adjusted tax basis in a Security generally will equal the cost of the Security
to the U.S. Holder, less any principal payments received by such U.S. Holder
with respect to the Security. Any portion of the amount realized on the sale or
other disposition of a Security that represents accrued but unpaid interest will
be treated as a payment of such interest. With respect to non-corporate U.S.
Holders, the gain or loss on such disposition of Securities will be a long-term
capital gain or loss taxed if Securities have been held at the time of such
disposition as capital assets for more than one year but not more than 18 months
at a rate no highter than 28% or if held more than 18 months at a rate no higher
than 20% and as a short term capital gain or loss if the Securites have been
held for not more than 12 months.
NON-U.S. HOLDERS
Interest
Interest paid by ESI Tractebel Acquisition to a Non-U.S. Holder will not be
subject to United States federal income or withholding tax if such Non-U.S.
Holder has no connection with 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-U.S. Holder and such
Non-U.S. 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; (iii) 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 (iv)
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-U.S. 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-U.S. Holder or (ii) in the case of a Non-U.S. 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-U.S. Holder for United
States federal estate tax purposes.
INFORMATION REPORTING AND BACKUP WITHHOLDING
U.S. HOLDERS
In general, information reporting to the Internal Revenue Service will
apply to payments with respect to the Securities and certain sales of the
Securities. The payor will be required to withhold backup withholding at a 31%
rate (i) if the U.S. Holder fails to provide a taxpayer identification number or
otherwise establish exemption from backup withholding, (ii) the Internal Revenue
Service notifies the payor that the taxpayer identification number is incorrect
or (iii) there has been a failure to certify that the U.S. Holder is not subject
to backup withholding. Generally, amounts paid as backup withholding will be a
credit against the U.S. Holders' federal income tax.
132
NON-U.S. HOLDERS
In the case of payments of interest to Non-U.S. 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-U.S. 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.
Backup withholding is not an additional tax. Any amounts withheld under the
backup withholding rules may be refunded or credited against the Non-U.S.
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. U.S. AND NON-U.S. HOLDERS SHOULD CONSULT THEIR OWN TAX
ADVISERS WITH RESPECT TO THE IMPACT, IF ANY, OF THE NEW FINAL REGULATIONS.
THE EXCHANGE OFFER
The exchange of New Securities for Old Securities will not be a taxable
event to U.S. and Non-U.S. 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.
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
133
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.
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 PricewaterhouseCoopers LLP, independent accountants, given on the authority
of said firm as experts in auditing and accounting.
The balance sheets of ESI Tractebel Acquisition as of January 12, 1998, and
NE LP, ESI GP, and Tractebel GP as of December 31, 1997 included in this
Prospectus have been audited by Deloitte & Touche LLP, independent auditors, as
stated in their reports appearing in the registration statement, and are
included in reliance upon the reports of such firm given upon their authority as
experts in accounting and auditing.
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.
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INDEX TO FINANCIAL STATEMENTS
PAGE
----
Northeast Energy Associates, A Limited Partnership, and North Jersey Energy Associates,
A Limited Partnership
Report of Independent Accountants........................................................................ F-3
Combined Balance Sheet at December 31, 1996 and 1997..................................................... F-4
Combined Statement of Operations for the years ended December 31, 1995, 1996 and 1997.................... F-5
Combined Statement of Partners' Deficit for the years ended December 31, 1994, 1995, 1996 and 1997....... F-6
Combined Statement of Cash Flows for the years ended December 31, 1995, 1996 and 1997.................... F-7
Notes to Combined Financial Statements................................................................... F-9
Combined Balance Sheet at March 31, 1998 (unaudited)..................................................... F-22
Combined Statements of Operations for the Period from January 14, 1998 to March 31, 1998 (unaudited), the
Period from January 1, 1998 to January 13, 1998 (unaudited) and the Three Months Ended March 31, 1997
(unaudited)........................................................................................... F-23
Combined Statements of Cash Flows for the Period from January 14, 1998 to March 31, 1998 (unaudited) the
Period from January 1, 1998 to January 13, 1998 (unaudited) and the Three Months Ended March 31, 1997
(unaudited)........................................................................................... F-24
Notes to Combined Financial Statements (unaudited)....................................................... F-25
Northeast Energy, LP
Independent Auditors' Report............................................................................. F-27
Balance Sheet at December 31, 1997....................................................................... F-28
Notes to Balance Sheet................................................................................... F-29
Consolidated Balance Sheet at March 31, 1998 (unaudited)................................................. F-31
Consolidated Statements of Operations for the Period ended March 31, 1998 (unaudited).................... F-32
Consolidated Statement of Cash Flows for the Period ended March 31, 1998 (unaudited)..................... F-33
Notes to Consolidated Financial Statements (unaudited)................................................... F-34
ESI Tractebel Acquisition Corp.
Independent Auditors' Report............................................................................. F-43
Balance Sheet at January 12, 1998........................................................................ F-44
Notes to Balance Sheet................................................................................... F-45
Balance Sheet at March 31, 1998 (unaudited).............................................................. F-46
Statement of Operations for the Period ended March 31, 1998 (unaudited).................................. F-47
Statement of Cash Flows for the Period ended March 31, 1998 (unaudited).................................. F-48
Notes to Financial Statements (unaudited)................................................................ F-49
ESI Northeast Energy GP, Inc.*
Independent Auditors' Report............................................................................. F-51
Balance Sheet at December 31, 1997....................................................................... F-52
Notes to Balance Sheet................................................................................... F-53
Balance Sheet at March 31, 1998 (unaudited).............................................................. F-54
Notes to Balance Sheet (unaudited)....................................................................... F-55
F-1
Tractebel Northeast Generation GP, Inc.*
Independent Auditors' Report............................................................................. F-57
Balance Sheet at December 31, 1997....................................................................... F-58
Notes to Balance Sheet................................................................................... F-59
Balance Sheet at March 31, 1998 (unaudited).............................................................. F-60
Notes to Balance Sheet (unaudited)....................................................................... F-61
* These balance sheets are provided because each of the entities is a general
partner of NE LP.
F-2
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 (appearing on
pages F-3 through F-19) 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-3
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
Due from related party.................................................................. 142 114
Fuel inventories........................................................................ 5,410 4,752
Prepaid expenses and other current assets............................................... 2,566 3,052
-------- --------
Total current assets...................................................................... 101,650 103,157
-------- --------
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.............................................................................. $566,534 $541,545
-------- --------
-------- --------
LIABILITIES AND PARTNERS' DEFICIT
Current liabilities:
Current portion of loans payable--ESI Tracetebel Funding Corp.
(formerly IEC Funding Corp.)......................................................... $ 24,075 $ 21,563
Accounts payable........................................................................ 14,528 15,450
Due to related party.................................................................... -- 71
Other accrued expenses.................................................................. 2,179 1,469
Future obligations under interest rate swap agreements.................................. 2,022 889
-------- --------
Total current liabilities................................................................. 42,804 39,442
-------- --------
Loans payable--ESI Tracetebel Funding Corp. (formerly IEC Funding Corp.).................. 490,287 468,724
Amounts due utilities for energy bank balances............................................ 220,922 230,565
-------- --------
Total non-current liabilities............................................................. 711,209 699,289
-------- --------
Total liabilities......................................................................... 754,013 738,731
-------- --------
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................................................... $566,534 $541,545
-------- --------
-------- --------
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 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-5
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-6
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,
----------------------------------
1995 1996 1997
-------- --------- ---------
(IN THOUSANDS)
Increase (Decrease) in Cash and Cash Equivalents
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-7
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,
----------------------------------
1995 1996 1997
-------- --------- ---------
(IN THOUSANDS)
Increase (Decrease) in Cash and Cash Equivalents
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 amounts due from related parties................... 146 (142) 28
(Increase) decrease in fuel inventories................................... -- (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............................. 394 186 (710)
Increase (decrease) in amounts due to related parties..................... 111 (111) 71
(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-8
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 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.
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.
F-9
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES--(CONTINUED)
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
The Partnerships utilize hedge accounting for interest rate swap agreements
when such agreements reduce the Partnership's exposure to interest rate risk,
and are designated as and effective as economic hedges. 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 that are unconditionally guaranteed, jointly and
severally by the Partnerships, 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.
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
F-10
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES--(CONTINUED)
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.
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).
F-11
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
4. COGENERATION FACILITIES AND CARBON DIOXIDE FACILITY--(CONTINUED)
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. The energy
bank liabilities are secured by a second mortgage on the NEA site and
facilities. For certain agreements requiring the establishment of energy banks,
the Partnerships are required to provide collateral based on energy bank
balances (Note 6). Amounts recorded in the energy banks may be required to be
repaid in later periods.
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 1990, NEA entered into the Amended and Restated NEA Steam Sales
Agreement with a processor and seller of carbon dioxide ('NECO'). The Amended
and Restated NEA Steam Sales Agreement has an initial term of 15 years, expiring
June 1, 2007, with automatic extension for any renewal period elected under the
NECO
F-12
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
4. COGENERATION FACILITIES AND CARBON DIOXIDE FACILITY--(CONTINUED)
Lease (described below). 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.
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
NECO (the 'NECO Lease'). The NECO Lease can be extended at the option of NECO
for up to four consecutive five year periods. 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 NECO $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,
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
F-13
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
4. COGENERATION FACILITIES AND CARBON DIOXIDE FACILITY--(CONTINUED)
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
------------ ------------
------------ ------------
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).
F-14
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
5. LOANS PAYABLE--(CONTINUED)
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.
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.
F-15
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
5. LOANS PAYABLE--(CONTINUED)
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.
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 base 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 in addition to the fees described
above, 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--(CONTINUED)
6. COMMITMENTS AND CONTINGENCIES--(CONTINUED)
The total amount paid in connection with the operation and maintenance
agreements were $18,481,000, $17,512,000 and $20,488,000 in 1995, 1996, and
1997, respectively.
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.
Common costs are allocated evenly between the Partnerships. Management believes
this allocation methodology is reasonable. The average annual balances due from
(to) the general partner for NEA and NJEA were $22,000 and $(4,500),
respectively, in 1995; $(25,500) and $41,000, respectively, in 1996; and
$(16,500) and $109,000,
F-17
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
8. OTHER RELATED PARTY TRANSACTIONS--(CONTINUED)
respectively, in 1997. Such amounts do not bear interest. The following
represents the activity between the Partnerships and the general partner for the
years ended December 31, 1995, 1996 and 1997:
NEA NJEA
---------- ----------
For the year ended December 31, 1995:
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
---------- ----------
---------- ----------
For the year ended December 31, 1997:
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
---------- ----------
---------- ----------
The Partnerships made direct or indirect payments to the general partner
(excluding ratable distributions by the Partnerships to their Partners)
aggregating approximately $6,480,000 during the year ended December 31, 1995,
$8,719,000 during the year ended December 31, 1996 and $8,655,000 during the
year ended December 31, 1997.
Fees payable by the Partnerships are limited to the management costs
permitted under the trust indenture governing the Securities (the 'Project
Indenture'), which consists of two components: (i) out-of-pocket costs
F-18
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
8. OTHER RELATED PARTY TRANSACTIONS--(CONTINUED)
payable to third parties (including allocated rent and independent legal,
consulting and accounting fees and including salary and related benefits of
individuals) and (ii) 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 clause (i) 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 (ii) for the years ended December 31, 1996 and 1997 were
approximately $3,688,000 and $3,758,000, respectively, and are subject to
escalation as set forth in the Project Indenture.
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. In the event other parties to these instruments fail to perform in
accordance with the contract terms, the Partnerships would incur an estimated
accounting loss, as measured by the fair value of these instruments at December
31, 1996 and 1997, of $1,671,000 and $2,527,000, respectively. Any such loss of
value would be realized through the then-current market rates in future periods.
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 -- --
F-19
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
9. FINANCIAL INSTRUMENTS--(CONTINUED)
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
CARRYING CARRYING
FAIR VALUE AMOUNT FAIR 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.
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 $535 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
F-20
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
10. SUBSEQUENT EVENTS--(CONTINUED)
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
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED BALANCE SHEET
(THOUSANDS OF DOLLARS)
(UNAUDITED)
MARCH 31,
1998
----------
ASSETS
Current assets:
Cash and cash equivalents......................................................................... $ 60,544
Accounts receivable............................................................................... 41,964
Fuel inventories.................................................................................. 1,452
Prepaid expenses and other current assets......................................................... 884
----------
Total current assets........................................................................... 104,844
----------
Cogeneration facilities and carbon dioxide facility (net of accumulated depreciation of $4,685)..... 508,366
Power purchase contracts (net of accumulated amortization of $10,818)............................... 877,938
Other assets........................................................................................ 126
----------
Total non-current assets....................................................................... 1,386,430
----------
Total assets................................................................................. $1,491,274
----------
----------
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Current portion of notes payable--ESI Tractebel Funding Corp...................................... $ 21,563
Accounts payable.................................................................................. 14,427
Accrued interest payable.......................................................................... 11,674
Other accrued expenses............................................................................ 5,837
----------
Total current liabilities...................................................................... 53,501
----------
Deferred credit--O&M and fuel contracts............................................................. 346,802
Notes payable--ESI Tractebel Funding Corp........................................................... 468,724
Amounts due utilities for energy bank balances...................................................... 171,371
----------
Total non-current liabilities.................................................................. 986,897
----------
Total liabilities.............................................................................. 1,040,398
----------
Partners' equity:
General partner................................................................................... 4,508
Limited partners.................................................................................. 446,368
----------
Total partners' equity......................................................................... 450,876
----------
Commitments and contingencies (Note 3)
Total liabilities and partners' equity.............................................................. $1,491,274
----------
----------
The accompanying notes are an integral part of this financial statement.
F-22
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENTS OF OPERATIONS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
PERIOD FROM
PERIOD FROM JANUARY 1, THREE MONTHS
JANUARY 14, 1998 TO ENDED
1998 TO JANUARY 13, MARCH 31,
MARCH 31, 1998 1997
1998 (PRIOR BASIS) (PRIOR BASIS)
----------- ------------- -------------
Revenues................................................................. $74,739 $13,109 $82,336
----------- ------------- -------------
Costs and expenses:
Fuel................................................................... 29,517 5,774 38,248
Operation and maintenance.............................................. 4,738 974 6,765
Depreciation and amortization.......................................... 15,508 894 6,250
General and administrative............................................. 1,895 538 3,353
----------- ------------- -------------
Total costs and expenses.......................................... 51,658 8,180 54,616
----------- ------------- -------------
Operating income......................................................... 23,081 4,929 27,720
----------- ------------- -------------
Other expense (income):
Interest expense....................................................... 13,712 2,422 16,857
Interest income........................................................ (653) (402) (2,189)
----------- ------------- -------------
Total other expense (income)--net................................. 13,059 2,020 14,668
----------- ------------- -------------
Net income............................................................... $10,022 $ 2,909 $13,052
----------- ------------- -------------
----------- ------------- -------------
The accompanying notes are an integral part of these financial statements.
F-23
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENTS OF CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
PERIOD FROM
PERIOD FROM JANUARY 1, THREE MONTHS
JANUARY 14, 1998 TO ENDED
1998 TO JANUARY 13, MARCH 31,
MARCH 31, 1998 1997
1998 (PRIOR BASIS) (PRIOR BASIS)
----------- ------------- -------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income............................................................. $ 10,022 2,909 $13,052
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation and amortization....................................... 15,508 894 6,250
Amortization of fuel and O&M contracts.............................. (5,492) -- --
(Increase) decrease in assets:
Accounts receivable............................................... 2,077 (10,005) 2,374
Fuel inventories.................................................. 2,789 511 4,124
Prepaid expenses and other current assets......................... 4,348 (122) 1,047
Other assets...................................................... -- 37 (199)
Increase (decrease) in liabilities:
Accounts payable.................................................. (5,865) 4,842 (420)
Accrued interest payable.......................................... 9,951 1,723 11,953
Other accrued expenses............................................ 711 626 1,461
Future obligations under interest rate swap agreements............ (218) -- (325)
Amounts due utilities for energy bank balances.................... (158) (52) 2,210
Other............................................................... -- 69 559
----------- ------------- -------------
Net cash provided by operating activities.............................. 33,673 1,432 42,086
----------- ------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures................................................... -- -- (154)
----------- ------------- -------------
Net cash used in investing activities.................................. -- -- (154)
----------- ------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Release of restricted cash collateral.................................. 69,156 -- --
Distributions to partners.............................................. (104,920) -- --
----------- ------------- -------------
Net cash used in financing activities.................................. (35,764) -- --
----------- ------------- -------------
Net increase (decrease) in cash and cash equivalents..................... (2,091) 1,432 41,932
Cash and cash equivalents at beginning of period......................... 62,635 61,203 49,861
----------- ------------- -------------
Cash and cash equivalents at end of period............................... $ 60,544 $62,635 $91,793
----------- ------------- -------------
----------- ------------- -------------
Supplemental disclosures of cash flow information:
Cash paid for interest................................................. $ -- $ -- $ 401
----------- ------------- -------------
----------- ------------- -------------
Supplemental schedule of noncash investing and financing activities:
See Note 1 and Note 2--Basis of Presentation concerning new basis of
accounting subsequent to January 13, 1998
The accompanying notes are an integral part of these financial statements.
F-24
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
In the opinion of the Partnerships' management all adjustments (consisting
only of normal recurring accruals) necessary to present fairly the financial
position as of March 31, 1998 and the results of operations and cash flows for
the three months ended March 31, 1998 and 1997 have been made. Certain amounts
included in the prior period's financial statements have been reclassified to
conform to the current year's presentation. The results of operations for an
interim period may not give a true indication of results for the year. These
financial statements should be read in conjunction with the Partnerships'
financial statements including related footnotes thereto for the year ended
December 31, 1997 included elsewhere in this Prospectus.
1. THE ACQUISITION
On January 14, 1998, pursuant to a purchase agreement dated November 21,
1997, the Partnerships were acquired by Northeast Energy, LP (a Delaware limited
partnership) and Northeast Energy, LLC (a Delaware limited liability company)
(collectively, the Partners). The Partners purchased their interests from
Intercontinental Energy Corporation and from certain individuals. The Partners
are owned by direct subsidiaries of ESI Energy, Inc. and Tractebel Power, Inc.
ESI Energy, Inc. is wholly-owned by FPL Energy, Inc. which is an indirect
wholly-owned subsidiary of FPL Group, Inc., a New York Stock Exchange company.
Tractebel Power, Inc. is a direct wholly-owned subsidiary of Tractebel, Inc.
which is a direct wholly-owned subsidiary of Tractebel, S.A., a Belgian energy
and environmental services business. Each of the Partnerships was formed in 1986
to develop, construct, own, operate and manage a 300 megawatt gas-fired
combined-cycle cogeneration facility.
The acquisition of the Partnerships was accounted for using the purchase
method of accounting and is subject to the provisions of the Securities and
Exchange Commission's Staff Accounting Bulletin No. 54 and the rules of pushdown
accounting, which gave rise to the new basis of accounting. The net amount paid
to acquire the interests in the Partnerships of approximately $545 million,
including approximately $10 million of acquisition costs, was allocated to the
assets and liabilities acquired based on their fair values.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation--The Partnerships' balance sheets as of March 31,
1998 and the statements of operations and cash flows for the period from January
14, 1998 to March 31, 1998 are reported under the new basis of accounting
described above. The Partnerships' statements of operations and cash flows for
the period from January 1, 1998 to January 13, 1998 and for the three months
ended March 31, 1997 represent historical financial data of the Partnerships
prior to the Acquisitions.
The following is a summary of the Partnerships' assets acquired and
liabilities assumed in the Acquisitions which were pushed down to the
Partnerships (thousands of dollars):
Assets:
Current assets...................................................................................... $114,554
Restricted cash..................................................................................... $ 69,156
Cogeneration facilities and carbon dioxide facility................................................. $513,066
Power purchase contracts............................................................................ $888,756
Other assets........................................................................................ $ 126
Liabilities:
Current liabilities................................................................................. $ 47,338
Operations and maintenance (O&M) contracts.......................................................... $ 18,749
Fuel contracts...................................................................................... $333,544
Energy bank balances................................................................................ $171,530
Notes payable....................................................................................... $468,723
Carrying values of current assets, restricted cash and current liabilities
were considered to closely approximate fair value and were not adjusted. Power
purchase contracts were assigned a value based on the estimated amount to be
received over the contract period in excess of an independent appraiser's
assessment of market rates for power, discounted to the date of acquisition. The
cogeneration facilities and carbon dioxide
F-25
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(UNAUDITED)
facility were initially assigned value based on an assessment of current
replacement cost for similar capacity, without the acquired power purchase
agreements. In accordance with Accounting Principles Board Opinion No. 16, the
values assigned to these long-lived assets were reduced by the net excess of the
fair values of all assets acquired over the purchase price. O&M and fuel
contract obligations were determined based on expected cash flows during the
contract periods compared to estimated cash flows for similar services if
contracted for currently, discounted to the date of acquisition. Notes payable
include the previously-existing debt of NEA and NJEA that was considered to
approximate market value. Energy bank balances were assigned a value
representing the estimated present value of future payments to utilities in
connection with certain existing power purchase agreements.
The following unaudited pro forma information has been prepared assuming
that the Acquisitions had occurred at the beginning of the periods presented
(thousands of dollars).
THREE MONTHS THREE MONTHS
ENDED ENDED
MARCH 31, MARCH 31,
1998 1997
------------ ------------
Revenues............................................................................ $ 87,848 $ 82,336
Operating income.................................................................... $ 27,280 $ 22,600
Net income.......................................................................... $ 11,690 $ 6,624
Cogeneration Facilities and Carbon Dioxide Facility--Cogeneration
facilities and the carbon dioxide facility were carried at historical cost prior
to January 14, 1998. Effective January 14, 1998, all facilities were revalued as
a result of applying the purchase method of accounting mentioned above. Prior to
January 14, 1998, the facilities were being depreciated on a straight-line
method over the estimated life of each facility of 20 years. Subsequent to
January 13, 1998, the facilities are being depreciated over their revised
estimated lives of 34 years.
Power Purchase/O&M/Fuel Contracts--Effective January 14, 1998, power
purchase contracts, O&M contracts and fuel contracts which were determined to be
in excess of prevailing rates for similar contracts were adjusted as a result of
applying the purchase method of accounting mentioned above. These contracts are
amortized over the estimated lives of the power purchase contracts of 14 to 24
years, the O&M contracts of 4 years and the fuel contracts of 16 years.
Amounts Due Utilities for Energy Bank Balances--Effective January 14, 1998,
amounts due utilities for energy bank balances were adjusted to fair value as a
result of applying the purchase method of accounting mentioned above.
3. COMMITMENTS AND CONTINGENCIES
Subsequent to the Acquisitions on January 14, 1998, certain credit
arrangements were terminated and replaced with new letters of credit and a
guaranty to satisfy requirements in certain Power Purchase Agreements.
Specifically, the new Energy Bank Letters of Credit were issued in face amounts
of $12,656,000 and $54,000,000. The $12,656,000 Letter of Credit expires on
December 31, 1998 and can be drawn upon on one occasion in the event that the
Montaup Power Purchase Agreement has terminated at a time when there was a
positive Energy Bank balance existing in favor of Montaup. The $54,000,000
Letter of Credit expires on December 31, 1998 and can be drawn upon in multiple
drawings in the event the Boston Edison I Power Purchase Agreement has
terminated at the time when there was a positive Energy Bank balance existing in
favor of Boston Edison. The guaranty was made by FPL Group Capital Inc. (the
'Guarantor') in favor of the Project Trustee. The Guarantor unconditionally and
irrevocably guarantees the payment of an amount equal to 50% of the Debt Service
Reserve Requirement with respect to the Project Securities. The guaranty expires
on December 31, 1998 but is automatically extended for successive one-year
periods unless the Guarantor gives notice that it will not renew. Once the new
credit arrangements were in place, cash of approximately $69.2 million (plus
approximately $2.5 million in accrued interest) was released and distributed to
the Partners. Additionally, new letters of credit were issued in substitution
for cash on deposit in Partnership trust accounts and approximately $33.2
million in cash was released and distributed to the Partners.
F-26
INDEPENDENT AUDITORS' REPORT
Northeast Energy, LP:
We have audited the accompanying balance sheet of Northeast Energy, LP (the
'Partnership') as of December 31, 1997. This financial statement is the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on this financial statement based on our audit.
We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the balance sheet is free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the balance sheet. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall balance sheet presentation. We believe that our audit
of the balance sheet provides a reasonable basis for our opinion.
In our opinion, such balance sheet presents fairly, in all material respects,
the financial position of the Partnership as of December 31, 1997 in conformity
with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Certified Public Accountants
West Palm Beach, Florida
July 13, 1998
F-27
NORTHEAST ENERGY, LP
BALANCE SHEET
(THOUSANDS OF DOLLARS)
DECEMBER 31, 1997
-----------------
ASSETS
TOTAL ASSETS............................................................... $--
---
---
LIABILITIES AND PARTNERS' EQUITY
TOTAL LIABILITIES.......................................................... $--
PARTNERS' EQUITY........................................................... --
---
TOTAL...................................................................... $--
---
---
The accompanying notes are an integral part of this financial statement.
F-28
NORTHEAST ENERGY, LP
NOTES TO BALANCE SHEET
DECEMBER 31, 1997
1. NATURE OF BUSINESS
Northeast Energy, LP (NE LP), a Delaware limited partnership, was formed on
November 21, 1997 for the purpose of acquiring ownership interests in electric
power generation stations. NE LP also formed a wholly-owned entity, Northeast
Energy, LLC (NE LLC, and together with NE LP, the Partners) to assist in such
acquisitions. The Partners are owned by direct subsidiaries of ESI Energy, Inc.
(ESI GP and ESI Northeast Energy LP, Inc.) and Tractebel Power, Inc. (Tractebel
Northeast Generation GP, Inc. and Tractebel Associates Northeast LP, Inc.). ESI
Energy, Inc. is wholly owned by FPL Energy, Inc., which is an indirect wholly
owned subsidiary of FPL Group, Inc., a New York Stock Exchange company.
Tractebel Power, Inc. is a direct wholly owned subsidiary of Tractebel, Inc.
which is a direct wholly owned subsidiary of Tractebel, S.A., a Belgian energy
and environmental services business.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates in Financial Statement Preparation--The preparation of
financial statements in conformity with generally accepted accounting principles
requires 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 amount of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
3. SUBSEQUENT EVENTS
On January 14, 1998, the Partners purchased all of the interests in two
existing limited partnerships, Northeast Energy Associates, A Limited
Partnership (NEA) and North Jersey Energy Associates, A Limited Partnership
(NJEA, and together with NEA, the Partnerships). NE LP holds a one percent (1%)
general partner and ninety-eight percent (98%) limited partner interest in the
Partnerships; NE LLC holds the remaining one percent (1%) limited partner
interest.
The Partnerships were formed in 1986 to develop, finance, construct, own,
manage and operate two separate 300 megawatt natural gas-fired combined-cycle
cogeneration facilities. 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. The Partnerships operate in the independent
power industry, and have been granted permission by the Federal Energy
Regulatory Commission to operate the Projects as qualifying facilities defined
in the Public Utility Regulatory Policies Act and as defined in federal
regulations.
In connection with the acquisition of the Partnerships' interests, an
existing special purpose funding corporation was acquired and its name changed
from IEC Funding Corp. to ESI Tractebel Funding Corp. This entity previously
issued debt which was registered with the Securities and Exchange Commission in
an exchange offer and repayment of this debt is secured by the assets of NEA and
NJEA.
Additionally, as a means of funding portions of the purchase price of the
acquisition of the Partnerships, ESI Tractebel Acquisition Corp. (a Delaware
corporation) was formed and is jointly owned by Tractebel Power and a
wholly-owned subsidiary of ESI Energy. On February 12, 1998, ESI Tractebel
Acquisition Corp. issued $220 million of debt securities and loaned the proceeds
to NE LP. The proceeds of the loan were distributed to ESI Energy and Tractebel
Power. Repayment of the debt securities is expected from distributions from the
Partnerships and is guaranteed by all interests in the Partnerships.
Capital contributions by the Partners of NE LP through March 31, 1998 were
$535.412 million. Distributions by NE LP to the Partners through March 31, 1998
were $307.619 million.
The Acquisitions were accounted for using the purchase method of
accounting. The purchase price of approximately $535 million, paid in cash, and
direct costs of the acquisition of approximately $10 million have
F-29
NORTHEAST ENERGY, LP
NOTES TO BALANCE SHEET
DECEMBER 31, 1997--(CONTINUED)
been allocated to the net assets acquired based on fair values. The following is
a summary of the fair values of assets acquired and liabilities assumed in the
Acquisitions based on a preliminary allocation of the purchase price (thousands
of dollars):
Assets:
Current assets.......................................................... $114,554
Restricted cash......................................................... $ 69,156
Cogeneration facilities and carbon dioxide facility..................... $513,066
Power purchase contracts................................................ $888,756
Other assets............................................................ $ 126
Liabilities:
Current liabilities..................................................... $ 47,338
Operations and maintenance (O&M) contracts.............................. $ 18,749
Fuel contracts.......................................................... $333,544
Notes payable........................................................... $468,724
Energy bank balances.................................................... $171,530
Carrying values of current assets, restricted cash and current liabilities
were considered to closely approximate fair value and were not adjusted. Power
purchase contracts were assigned a value based on the estimated amount to be
received over the contract period in excess of an independent appraiser's
assessment of market rates for power, discounted to the date of acquisition. The
cogeneration facilities and carbon dioxide facility were initially assigned
value based on an assessment of current replacement cost for similar capacity,
without the acquired power purchase agreements. In accordance with Accounting
Principles Board Opinion No. 16, the values assigned to these long-lived assets
were reduced by the net excess of the fair values of all assets acquired over
the purchase price. O&M and fuel contract obligations were determined based on
expected cash flows during the contract periods compared to estimated cash flows
for similar services if contracted for currently, discounted to the date of
acquisition. Notes payable include the previously-existing debt of NEA and NJEA
that was considered to approximate market value. Energy bank balances were
assigned a value representing the estimated present value of future payments to
utilities in connection with certain existing power purchase agreements.
F-30
NORTHEAST ENERGY, LP
CONSOLIDATED BALANCE SHEET
(THOUSANDS OF DOLLARS)
(UNAUDITED)
MARCH 31, 1998
--------------
ASSETS
Current assets:
Cash and cash equivalents....................................................................... $ 61,611
Accounts receivable............................................................................. 41,964
Fuel inventories................................................................................ 1,452
Prepaid expenses and other current assets....................................................... 884
--------------
Total current assets......................................................................... 105,911
--------------
Deferred debt issuance costs (net)................................................................ 6,591
Cogeneration facilities and carbon dioxide facility (net of accumulated depreciation of $4,685)... 508,366
Above-market power purchase contracts (net of accumulated amortization of $10,818)................ 877,938
Other fixed assets................................................................................ 126
--------------
Total non-current assets..................................................................... 1,393,021
--------------
Total assets................................................................................. $1,498,932
--------------
--------------
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Current portion of loans payable--ESI Tractebel Funding Corp.................................... $ 21,563
Accounts payable................................................................................ 2,086
Accrued interest payable........................................................................ 13,725
Due to related parties.......................................................................... 1,557
Other accrued expenses.......................................................................... 17,017
Future obligations under interest rate swap agreements.......................................... 671
--------------
Total current liabilities.................................................................... 56,619
--------------
Non-current liabilities
Above market O&M contracts...................................................................... 17,741
Above market fuel contracts..................................................................... 329,061
Loans payable--ESI Tractebel Funding Corp....................................................... 468,724
Loans payable--ESI Tractebel Acquisition Corp................................................... 220,000
Amounts due utilities for energy bank balances.................................................. 171,371
--------------
Total non-current liabilities................................................................ 1,206,897
--------------
Total liabilities............................................................................ 1,263,516
--------------
Partners Equity:
General Partners................................................................................ 4,708
Limited Partners................................................................................ 230,708
--------------
Total partners' equity....................................................................... 235,416
--------------
Commitments and contingencies (Note 7)
Total liabilities and partners' equity....................................................... $1,498,932
--------------
--------------
The accompanying notes are an integral part of these consolidated financial
statements.
F-31
NORTHEAST ENERGY, LP
CONSOLIDATED STATEMENT OF OPERATIONS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
PERIOD ENDED
MARCH 31, 1998
--------------
Revenue
Power sales to utilities........................................................................ $ 73,596
Steam sales..................................................................................... 1,143
--------------
Total revenue................................................................................ 74,739
--------------
Costs and expenses
Fuel............................................................................................ 29,517
Operation and maintenance....................................................................... 4,738
Depreciation and amortization................................................................... 15,508
General and administrative...................................................................... 2,168
--------------
Total costs and expenses..................................................................... 51,931
--------------
Operating income........................................................................... 22,808
--------------
Other expense, net
Amortization of debt issue cost................................................................. 72
Interest expense--debt.......................................................................... 15,763
Interest income................................................................................. (653)
--------------
Total other expense, net..................................................................... 15,182
--------------
Net income................................................................................. $ 7,626
--------------
--------------
The accompanying notes are an integral part of these consolidated financial
statements.
F-32
NORTHEAST ENERGY, LP
CONSOLIDATED STATEMENT OF CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
PERIOD ENDED
RECONCILIATION OF NET INCOME TO NET CASH MARCH 31,
PROVIDED BY (USED IN) OPERATING ACTIVIITES 1998
------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income........................................................................................ $ 7,626
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization.................................................................. 15,508
Amortization of above market contracts......................................................... (5,492)
Amortization of debt issue costs............................................................... 72
Non-capitalizable acquisition costs............................................................ 273
(Increase) decrease in assets:
Accounts receivable............................................................................ 2,077
Fuel inventories............................................................................... 2,789
Prepaid expenses and other current assets...................................................... 4,348
Increase (decrease) in liabilities:
Accounts payable............................................................................... (7,455)
Accrued interest payable....................................................................... 12,002
Due to related parties......................................................................... 1,557
Other accrued expenses......................................................................... (329)
Future obligations under interest rate swap agreements......................................... (218)
Amounts due utilities for energy bank balances................................................. (158)
------------
Net cash provided by operating activities.................................................... 32,600
------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition purchase price of NEA and NJEA, net of $62,635 cash acquired.......................... (483,140)
------------
Net cash used in investing activities........................................................ (483,140)
------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Capital contributions from partners............................................................... 535,412
Release of restricted cash collateral............................................................. 69,156
Proceeds from loan by ESI Tractebel Acquisition Corp.............................................. 215,202
Distributions to partners......................................................................... (307,619)
------------
Net cash provided by financing activities.................................................... 512,151
------------
Net increase in cash and cash equivalents........................................................... 61,611
Cash and cash equivalents at beginning of period.................................................... --
------------
Cash and cash equivalents at end of period.......................................................... $ 61,611
------------
------------
Supplemental disclosure of noncash investing and financing activities:
See Note 1 and Note 2--Basis of presentation concerning new basis of accounting subsequent to
January 13, 1998
The accompanying notes are an integral part of these consolidated financial
statements.
F-33
NORTHEAST ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. NATURE OF BUSINESS
Northeast Energy, LP (NE LP), a Delaware limited partnership, was formed on
November 21, 1997 for the purpose of acquiring ownership interests in electric
power generation stations, and is jointly owned by subsidiaries of ESI Energy,
Inc. (ESI Energy) and Tractebel Power, Inc. (Tractebel Power). NE LP also formed
a wholly-owned entity, Northeast Energy, LLC (NE LLC, and together with NE LP,
the Partners) to assist in such acquisitions.
On January 14, 1998, the Partners purchased all of the interests in two
existing limited partnerships, Northeast Energy Associates, A Limited
Partnership (NEA) and North Jersey Energy Associates, A Limited Partnership
(NJEA, and together with NEA, the Partnerships). NE LP holds a one percent (1%)
general partner and ninety-eight percent (98%) limited partner interest in the
Partnerships; NE LLC holds the remaining one percent (1%) limited partner
interest. See Note 2 for additional information relating to the acquisitions.
The Partnerships were formed in 1986 to develop, finance, construct, own,
manage and operate two separate 300 megawatt natural gas-fired combined-cycle
cogeneration facilities. 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. The Partnerships operate in the independent
power industry, and have been granted permission by the Federal Energy
Regulatory Commission to operate the Projects as qualifying facilities defined
in the Public Utility Regulatory Policies Act and as defined in federal
regulations.
In connection with the acquisition of the Partnerships' interests, an
existing special purpose funding corporation was acquired and its name changed
from IEC Funding Corp. to ESI Tractebel Funding Corp. The entity previously
issued debt which was registered with the Securities and Exchange Commission in
an exchange offer and repayment of this debt is secured by the assets of NEA and
NJEA.
Additionally, as a means of funding portions of the purchase price of the
acquisition of the Partnerships, ESI Tractebel Acquisition Corp. (a Delaware
corporation) was formed and is jointly owned by Tractebel Power and a
wholly-owned subsidiary of ESI Energy. On February 12, 1998, ESI Tractebel
Acquisition Corp. issued $220 million of debt securities and loaned the proceeds
to NE LP. The proceeds of the offering were distributed to ESI Energy and
Tractebel Power. Repayment of the debt is expected from distributions from the
Partnerships and is guaranteed by all interests in the Partnerships. See Note 4
for additional information.
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
sub-funds have been fully funded, as described in the trust indenture.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation--The accompanying consolidated financial statements
include the accounts of the Partnerships subsequent to the Acquisitions, as they
are indirectly wholly-owned by NE LP. All material intercompany transactions
have been eliminated in consolidation.
Acquisitions--On January 14, 1998, the Partners acquired all of the
interests in NEA and NJEA for $545 million, including approximately $10 million
of acquisition costs (the Acquisitions). The Acquisitions were accounted for
using the purchase method of accounting. The purchase price has been allocated
based on fair value to the net assets of the Partnerships.
F-34
NORTHEAST ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(UNAUDITED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES--(CONTINUED)
The following is a summary of the fair values of assets acquired and
liabilities assumed in the Acquisitions based on a preliminary allocation of the
purchase price (thousands of dollars):
Assets:
Current assets.................................................................... $ 114,554
Restricted cash................................................................... $ 69,156
Cogeneration facilities and carbon dioxide facility............................... $ 513,066
Power purchase contracts.......................................................... $ 888,756
Other assets...................................................................... $ 126
Liabilities:
Current liabilities............................................................... $ 47,338
Operations and maintenance (O&M) contracts........................................ $ 18,749
Fuel contracts.................................................................... $ 333,544
Notes payable..................................................................... $ 468,724
Energy bank balances.............................................................. $ 171,530
Subsequent to March 31, 1998, the purchase price was reduced by
approximately $1 million.
Carrying values of current assets, restricted cash and current liabilities
were considered to closely approximate fair value and were not adjusted. Power
purchase contracts were assigned a value based on the estimated amount to be
received over the contract period in excess of an independent appraiser's
assessment of market rates for power, discounted to the date of acquisition.
Cogeneration facilities and carbon dioxide facility were initially assigned
value based on an assessment of current replacement cost for similar capacity,
without the acquired power purchase agreements. In accordance with Accounting
Principles Board Opinion No. 16, the values assigned to these long-lived assets
were reduced by the net excess of the fair value of all assets acquired over the
purchase price. O&M and fuel contract obligations were determined based on
expected cash flows during contract periods compared to estimated cash flows for
similar services if contracted for currently, discounted to the date of
acquisition. Notes payable include the previously existing debt of the
Partnerships that was considered to approximate market value. Energy bank
balances were assigned a value representing estimated present value of future
payments to utilities in connection with certain existing power purchase
agreements.
The following unaudited pro forma information has been prepared assuming
that the Acquisitions and the $220 million loan described in Note 1 above had
occurred at the beginning of the period presented (thousands of dollars):
PERIOD ENDED
MARCH 31, 1998
--------------
Revenues...................................................................... $ 87,848
Operating income.............................................................. $ 27,404
Net income.................................................................... $ 7,168
Cash--Investments purchased with an original maturity of three months or
less are considered cash equivalents. Excess cash is invested in high-grade
money market accounts and commercial paper and are subject to minimal credit and
market risk. At March 31, 1998, the recorded amount of cash approximates its
fair value.
Accounts Receivable and Revenue--Accounts receivable primarily consist of
receivables from three Massachusetts utilities and one New Jersey utility for
electricity delivered and sold under six power purchase agreements. Prices are
based on initial floor prices per kilowatt hour, subject to adjustment based on
actual volumes of electricity purchased, escalation factors and other
conditions.
F-35
NORTHEAST ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(UNAUDITED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES--(CONTINUED)
Revenue is recognized in accordance with the Emerging Issues Task Force
Issue No. 91-6, Revenue Recognition of Long-Term Power Sales Contracts. Revenue
is recognized based on power delivered at rates stipulated in power purchase
agreements, except that revenue is deferred to the extent that stipulated rates
are in excess of amounts, either scheduled or specified, in the agreements to
the extent the Partnerships have an obligation to repay such excess. The amount
deferred is reflected as amounts due utilities for energy bank balances on the
consolidated balance sheet. Revenue from steam sales is recognized upon
delivery.
Cogeneration Facilities, Carbon Dioxide Facility and Other
Assets--Effective January 14, 1998, all facilities were revalued as a result of
applying the purchase method of accounting mentioned above. The facilities and
other fixed assets are depreciated using the straight-line method over the
estimated useful life of 34 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.
Power Purchase Contracts--Effective January 14, 1998, power purchase
contracts which were determined to be in excess of prevailing rates for similar
contracts were adjusted as a result of applying the purchase method of
accounting mentioned above. These contracts are being amortized over contract
periods, ranging from 14 to 24 years, on a straight-line basis or matched to
fixed scheduled price increases under the Power Purchase Agreements, as
applicable.
O&M Contracts--Effective January 14, 1998, O&M contracts which were
determined to be in excess of prevailing rates for similar contracts were
adjusted as a result of applying the purchase method of accounting mentioned
above. The above market O&M contracts are being amortized on a straight-line
basis over the remaining terms of the contracts, 4 years.
Fuel Contracts--Effective January 14, 1998, fuel contracts which were
determined to be in excess of prevailing rates for similar contracts were
adjusted as a result of applying the purchase method of accounting mentioned
above. The above market fuel contracts are being amortized on a straight-line
basis over 16 years, the remaining contract periods.
Amounts Due Utilities for Energy Bank Balances--Effective January 14, 1998,
amounts due utilities for energy bank balances were adjusted to the present
value of estimated future payments.
Interest Rate Swaps--Interest rate swaps that do not qualify for hedge
accounting are recorded at fair value, with changes in the fair value recognized
currently in income. See Note 6 for further disclosure regarding interest rate
swap agreements.
Natural Gas Hedging Instrument--Premiums paid for natural gas call options
are deferred within other current assets and recognized in income in conjunction
with the underlying natural gas purchases. Gains and losses on natural gas
purchase swap agreements are recognized as adjustments to the 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 delivery. The net gain/(loss) included in the cost of power
and steam sales resulting from the gas purchase options, swap agreements and
forward purchases was $14,300 for the period ended March 31, 1998. See Note 6
for further disclosure regarding natural gas hedging instructions.
Deferred Debt Issuance Costs--Deferred debt issuance costs are being
amortized over the approximate 14-year term of the notes payable using the
interest method.
Income taxes--Partnerships are not taxable entities for Federal and state
income tax purposes. As such, no provision has been made for income taxes since
such taxes, if any, are the responsibilities of the individual partners.
F-36
NORTHEAST ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(UNAUDITED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES--(CONTINUED)
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, the disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
3. COGENERATION FACILITIES, POWER PURCHASE AGREEMENTS, AND CARBON DIOXIDE
FACILITY
Cogeneration Facilities--The cogeneration facilities have maximum output
capacities of any combination of electricity and steam equivalent to
approximately 600 MW in the aggregate. The facility owned by NEA is constructed
on four parcels of land in Bellingham, Massachusetts. Three parcels were
acquired under various purchase and sale agreements and the remaining parcel was
acquired under a 26 year operating lease in 1986. The lease may be extended for
another 25 years at the option of NEA. See Note 7 for further discussion of
lease payments under the operating lease. The facility owned by NJEA is
constructed on two parcels of land acquired under various purchase and sale
agreements.
Power Purchase Agreements--In 1986, NEA entered into five power purchase
agreements with three major Massachusetts utilities to sell approximately 290 MW
at initial floor prices per kilowatt (kWh) subject to adjustment based on actual
volumes purchased, escalation factors, and other conditions. Performance under
certain of these 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 purchase agreements have initial 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' account receivables 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 March 31, 1998. During the period
ended 1998, revenue from two different utilities accounted for approximately
44.6% and 41.8% of power sales to utilities.
On November 25, 1997, the Massachusetts legislature passed a comprehensive
electric deregulation bill to establish a comprehensive framework for the
restructuring of the electric utility industry. 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.
Energy Bank Balances--Certain agreements require the establishment of
energy banks to record cumulative payments made by the utilities in excess of
avoided cost rates scheduled or specified in such agreements. One of the
resulting energy banks is non-interest bearing, however, the remaining energy
banks bear interest at various rates specified in the agreements. Amounts
recorded in two of the energy banks will be required to be repaid to the extent
that, in later periods, PPA Avoided Costs are above the contracts rate. The
balances of two energy banks are secured by the NEA Second Mortgage and letters
of credit have been established for two other energy banks (Note 7).
Steam Sales Agreements and Carbon Dioxide Facility--In order for the
Partnerships' facilities to maintain qualifying facility status, the facilities
are required to generate five percent of total energy output as steam for sale
to unrelated third parties. In 1990, NEA entered into the Amended and Restated
NEA Steam Sales Agreement with a processor and seller of carbon dioxide. The
Amended and Restated NEA Steam Sales Agreement extends for the same terms as
that of the NECO-Bellingham, Inc. (NECO) lease, with automatic extension for any
renewal period under the NECO lease. Pursuant to this agreement, NEA sells all
the steam generated by the Bellingham facility at a price that fluctuates based
on changes in the price of a specified grade of fuel oil.
F-37
NORTHEAST ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(UNAUDITED)
3. COGENERATION FACILITIES, POWER PURCHASE AGREEMENTS, AND CARBON DIOXIDE
FACILITY--(CONTINUED)
In conjunction with this contract, NEA constructed a carbon dioxide
facility and, in 1989, entered into a 16-year agreement to lease the facility to
the steam user. Base rent under the lease is $100,000 per month, adjusted by the
operating results of the facility 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.
In 1989, NJEA entered into a 20 year steam sales contract with a steam user
adjacent to the Sayerville facility. Under this agreement, NJEA sells a
specified maximum quantity of steam at a floor price that 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 contract with ProGas Limited (ProGas) and Public Service Electric
and Gas Company (PSE&G). Various pipeline companies provide transportation of
the natural gas. 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, and the initial 15-year terms were
extended an additional seven years effective in 1994. The maximum total volumes
of gas to be delivered under the ProGas contracts are approximately 48,800 and
22,000 MMBtu per day for NEA and NJEA, respectively. The contract price,
including transportation, of the ProGas supply delivered to the import point is
determined with reference to a 'base price' in 1990, re-determined annually
thereafter based on specified inflation indices. The PSE&G contract commenced in
1991, and provides for the sale and delivery to NJEA of 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 reserve certain pipeline transportation capacity,
and are made regardless of the facilities' specified fuel requirements in any
month and regardless of whether the facilities utilize the capacity reserved.
This demand charge totaled approximately $10.7 million in the period ended March
31, 1998. In the event 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 is
stored on site for contingency supply for the facility.
4. LOANS PAYABLE
In 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). In 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 1,
IEC Funding Corp. changed its name to ESI Tractebel Funding Corp. Interest rates
on the Securities range from 8.43% to 9.77%. Final maturity dates of the
Securities are from 2000 to 2010.
F-38
NORTHEAST ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(UNAUDITED)
4. LOANS PAYABLE--(CONTINUED)
Interest on the Securities is payable semiannually on each June 30 and
December 30. Principal repayments 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
The Securities are not subject to optional redemption but are subject to
mandatory redemption in certain limited circumstances involving the occurrence
of an event loss, as defined in the trust indenture, for which the Partnerships
fail to or are unable to restore a facility.
The proceeds from the sale of the Securities were used to purchase the
notes outstanding under the original loan and credit agreement and to make loans
to the Partnerships. In connection these two transactions, the notes outstanding
under the loan and credit agreements were surrendered and new notes of the
Partnership 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 and are payable solely from the
collateral pledged as security.
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 partner distributions can be made. Cash within these
funds can be drawn currently if funds in the Partnerships' other cash accounts
are insufficient to meet operational cash requirements.
The trust indenture also contains certain restrictions on activities of the
Partnerships, including the incurrence of additional indebtedness or liens,
partnership distributions, cancellation of certain agreements, the execution of
mergers, consolidations and asset sales. The Partnerships are allowed to enter
into revolving credit agreements of up to $20 million for working capital
requirements. Subsequent to the acquisition on January 14, 1998, the existing
working capital facility was terminated.
Under the terms of the original loan and credit agreement, the Partnerships
were required to enter into interest rate swap agreements providing for the
payments on a notional principal amount 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. The original specified notional
principal amount declines periodically until the scheduled expiration of the
swaps in 1999. The Partnerships are jointly and severally liable under these
agreements. As a result of the refinancing described above, the original
interest swap agreements no longer qualify as hedges, and are recorded at fair
value. Changes in fair value are recognized in the combined statement of
operations. See Note 6 for information regarding fair value of financial
instruments.
On February 12, 1998, ESI Tractebel Acquisition Corp., issued $220,000,000
of 7.99% Secured Bonds Due 2011, (the 'Old Securities'), the proceeds of which
were loaned to NE LP, evidenced by a promissory note (the
F-39
NORTHEAST ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(UNAUDITED)
4. LOANS PAYABLE--(CONTINUED)
'Note') with substantially identical terms as the Old Securities, for the
purpose of reimbursing certain of ESI Energy's and Tractebel Power's
subsidiaries for a portion of the original $545 million equity contribution that
was used to finance the cost of the Acquisitions. A Form S-4 has been filed with
the Securities and Exchange Commission in connection with an exchange offer in
which the Old Securities may be exchanged for New Securities which are
registered under the Securities Act of 1933. Such New Securities will have
substantially identical terms as the Old Securities.
Interest on the above Old Securities is payable semiannually on each June
30 and December 30, commencing on the first such date to occur after the
exchange is effective. Interest accrued during the period ended March 31, 1998
and at March 31, 1998 was approximately $2.1 million. Principal repayments are
made annually commencing on June 30, 2002 and are in amounts stipulated in the
indenture. Future principal payments are as follows:
2002.......................................................................... $ 8,800,000
Thereafter.................................................................... 211,200,000
------------
$220,000,000
NE LP has unconditionally guaranteed the payment of the principal of,
premium, if any, interest and Registration Default Damages, if any, on the Old
Securities pursuant to the Bond Guaranty executed and delivered to the Trustee.
The Old Securities are payable solely from payments to be made by NE LP
under the Note and Bond Guaranty and from other moneys that may be available
from time to time in the accounts held by the Trustee and are not obligations of
the Partnerships. NE LP has a general obligation to make payments under the Note
and the Bond Guaranty. NE LP's only source of funds to make such payments is
distributions from the Partnerships. NE LP's obligations to make payments under
the Note are nonrecourse to the direct and indirect owners of NE LP (including
ESI Energy and Tractebel Power). Generally, neither the Partners nor any of the
direct or indirect owners of the Partners will be obligated to contribute
additional amounts if funds are insufficient for payment of debt service in
respect of the Old Securities. Payments with respect to the Note and, therefore,
in respect of the Old 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 New Notes.
5. RELATED PARTY INFORMATION
Administrative Service Agreements--In November 1997, NE LP entered into an
Administrative Services Agreement with ESI GP that provides for the performance
by ESI GP of management and administrative services of NE LP and the
Partnerships. The Administrative Service Agreement extends for a 20 year term,
and expires in 2018. NE LP has agreed to pay ESI GP a minimum of $600,000 per
year, and all out-of-pocket costs and expenses of performing the services under
the contract.
Operations and Maintenance Agreements--In November 1997, NE LP and ESI
Operating Services, Inc. (a wholly-owned subsidiary of ESI Energy, Inc.) entered
into new operations and maintenance agreements (New O&M Agreements) for the
operation and maintenance of the Partnerships on the day following the
expiration or early termination of the Westinghouse Agreement. The term of the
New O&M Agreements extend for an initial term of 18 years until January 14,
2016, subject to extension by mutual agreement of the parties before six months
preceding expiration. In connection with the New O&M Agreements, NE LP has
agreed to pay ESI Operating Services, Inc. all properly incurred costs and
expenses of providing the services and $750,000 per year, subject to certain
adjustments, for each Project.
F-40
NORTHEAST ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(UNAUDITED)
5. RELATED PARTY INFORMATION--(CONTINUED)
Fuel Management Agreements--On January 20, 1998, NE LP entered into Fuel
Management Agreements with ESI Northeast Fuel Management, Inc. (an affiliate of
ESI Energy) for the management of all natural gas or fuel oil, transportation
and storage agreements, and the location and purchase of any additional required
natural gas or fuel oil for the Partnerships. The Fuel Management Agreements
extend for twenty-five years, and expire in 2023. In connection with the Fuel
Management Agreements, NEA and NJEA have each agreed to pay ESI Northeast Fuel
Management, Inc. a minimum management fee of $450,000 per year, and all properly
incurred costs and expenses of performing the fuel management services.
Accrued expenses under the Administrative Service Agreement, the New O&M
Agreements, and the Fuel Management Agreements were $695,000 for the period
ended March 31, 1998.
Amounts due to related parties at March 31, 1998 are as follows:
Due to general partners................................................... $ 881,658
Due to other related parties.............................................. $ 675,121
The average balances due to related parties did not vary materially from
the amounts indicated above.
6. FINANCIAL INSTRUMENTS
The Partnerships have made use of derivative financial instruments to hedge
their exposure to fluctuations in both interest rates and the 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 of 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.
The prices received by the Partnerships for power sales under their
long-term 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 or by means of
over-the-counter transactions with specific counterparties. The Partnerships
hedge purchases of natural gas through the use of natural gas call options,
natural gas purchase swap agreements that require the Partnerships to pay a
fixed price (absolutely or within a specified range) in return for a variable
price on specified notional quantities of natural gas, and forward purchases of
natural gas.
The Partnerships control the credit risk arising from these instruments
through credit approvals, limits, and monitoring. The Partnerships do not
normally require collateral or other security to support financial instruments
with credit risks.
As discussed in Note 5, NE LP entered into Fuel Management Agreements with
ESI Northeast Fuel Management, Inc. (an affiliate of ESI Energy) for the
management of all natural gas or fuel oil, transportation and storage
agreements, and the location and purchase of any additional required natural gas
or fuel oil for the Partnerships.
7. COMMITMENTS AND CONTINGENCIES
Energy Bank and Loan Collateral--Subsequent to the Acquisitions on January
14, 1998, certain credit arrangements were terminated and replaced with new
letters of credit and a guarantee to satisfy requirements in certain Power
Purchase Agreements. Specifically, the new Energy Bank Letters of Credit were
issued in face amounts of $12,656,000 and $54,000,000. The $12,656,000 Letter of
Credit expires on December 31, 1998 and can be drawn upon on one occasion in the
event that the Montaup Power Purchase Agreement has terminated at a time when
there was a positive Energy Bank balance existing in favor of Montaup. The
$54,000,000 Letter of Credit expires on December 31, 1998 and can be drawn upon
in multiple drawings in the event the Boston Edison I Power Purchase Agreement
has terminated at the time when there was a positive Energy Bank balance
existing in favor of Boston Edison. The guaranty was made by FPL Group Capital
Inc. (the 'Guarantor') in favor of the Project Trustee. The Guarantor
unconditionally and irrevocably guarantees the payment of an amount equal to 50%
of the Debt Service Reserve Requirement with respect to the Project Securities.
The guaranty expires on December 31, 1998 but is automatically extended for
successive one-year periods unless the Guarantor gives notice that it will not
renew. Once the new credit arrangements were in place, cash of approximately
$69.2 million (plus approximately $2.5 million in accrued interest) was released
and distributed to the Partners.
F-41
NORTHEAST ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(UNAUDITED)
7. COMMITMENTS AND CONTINGENCIES--(CONTINUED)
Additionally, new letters of credit were issued in substitution of cash on
deposit in Partnership trust accounts and approximately $33.2 million in cash
was released and distributed to the Partners.
Operation and Maintenance of the Cogeneration Facilities--In 1989, the
Partnerships entered into two separate ten year operation and maintenance
agreements with Westinghouse Services, a subsidiary of Westinghouse Electric,
for an aggregate annual consideration of approximately $11,100,000, subject to
changes in specified indices. Under these agreements, the Partnerships are
required to pay the operation and maintenance contractor a bonus payable
annually over the term of the agreements, based on operating performance. The
Parnerships incurred $4.2 million for O&M and bonus expenses for the period
ended March 31, 1998. On November 15, 1997 Westinghouse Electric announced that
it intended to sell certain of its industrial businesses, including the business
of Westinghouse Services, to Siemens, A.G. Each of the Partnerships is a party
to a New O&M Agreement 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. The Partnerships do not
anticipate a material adverse effect related to this potential change in service
provider.
Operating Lease--Lease payments under the operating lease for land for the
NEA Project 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
------------
------------
Lease expense under this agreement for the period ended March 31, 1998 was
$40,000.
F-42
INDEPENDENT AUDITORS' REPORT
ESI Tractebel Acquisition Corp.:
We have audited the accompanying balance sheet of ESI Tractebel Corp, (the
'Company') as of January 12, 1998. This financial statement is the
responsibility of the Company's management. Our responsibility is to express an
opinion on this financial statement based on our audit.
We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the balance sheet is free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the balance sheet. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall balance sheet presentation. We believe that our audit
of the balance sheet provides a reasonable basis for our opinion.
In our opinion, such balance sheet presents fairly, in all material respects,
the financial position of the Company as of January 12, 1998 in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Certified Public Accountants
West Palm Beach, Florida
July 13, 1998
F-43
ESI TRACTEBEL ACQUISITION CORP.
BALANCE SHEET
(THOUSANDS OF DOLLARS)
JANUARY 12, 1998
----------------
ASSETS
TOTAL ASSETS.................................................................................... $ --
----------------
----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
TOTAL LIABILITIES............................................................................... $ --
----------------
STOCKHOLDERS' EQUITY:
Common stock, par value $.01, 100 shares authorized and subscribed............................ --
Subscriptions receivable...................................................................... --
----------------
Total stockholders' equity................................................................. --
----------------
TOTAL........................................................................................... $ --
----------------
----------------
The accompanying notes are an integral part of this financial statement.
F-44
ESI TRACTEBEL ACQUISITION CORP.
NOTES TO BALANCE SHEET
JANUARY 12, 1998
1. NATURE OF BUSINESS
ESI Tractebel Acquisition Corp., a Delaware corporation (the 'Company') was
formed on January 12, 1998 as a special purpose funding corporation for the
purpose of issuing the securities (the 'Securities') described in Note 3. The
common stock is jointly owned by ESI Northeast Energy Acquisition Funding, Inc.
(ESI NE Acquisition Funding) and Tractebel Power, Inc. (Tractebel Power). The
Company acts as agent of Northeast Energy, LP (NE LP) with respect to the
Securities and holds itself out as agent of NE LP in all dealings with third
parties relating to the Securities.
NE LP, a Delaware limited partnership, was formed on November 21, 1997 for
the purpose of acquiring ownership interests in electric power generation
stations, and is jointly owned by subsidiaries of ESI Energy, Inc. (ESI Energy)
and Tractebel Power, Inc. (Tractebel Power). ESI Energy, Inc. is wholly-owned by
FPL Energy, Inc., which is an indirect wholly-owned subsidiary of FPL Group,
Inc., a New York Stock Exchange company. Tractebel Power, Inc. is a direct
wholly-owned subsidiary of Tractebel, Inc., which is a direct wholly-owned
subsidiary of Tractebel, S.A., a Belgian energy and environmental services
business. NE LP also formed a wholly-owned entity, Northeast Energy. LLC (NE LLC
and together with NE LP, the Partners) to assist in such acquisitions.
On January 14, 1998, the Partners purchased (the 'Acquisitions') all of the
interests in two existing limited partnerships, Northeast Energy Associates, A
Limited Partnership (NEA) and North Jersey Energy Associates, A Limited
Partnership (NJEA, and together with NEA, the Partnerships).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation--The balance sheet is at January 12, 1998, date of
formation of the Company.
Use of Estimates--The preparation of financial statements in conformity
with generally accepted accounting principles requires 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 amount of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
3. SUBSEQUENT EVENTS
On February 12, 1998 ESI Tractebel Acquisition Corp. issued $220 million of
7.99% Secured Bonds Due 2011.
The proceeds from the sale of the Securities were loaned to NE LP,
evidenced by a promissory note (the Note) with substantially identical terms as
the Securities, for the purpose of reimbursing certain of the partners of NE LP
for a portion of the original $545 million equity contribution that was used to
finance the cost of the Acquisitions.
Partnership operations are expected to provide funds for repayment of the
Securities. Distributions from the Partnerships are only allowed following
satisfaction of debt service requirements of previously existing debt. The
Securities are nonrecourse to the partners, but interests to the Partnerships
serve as a guaranty. The Securities will rank senior to all subordinated
indebtedness and rank evenly with all senior indebtedness that the Company
incurs in the future.
Payments in respect to 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 the Partnerships, including the guarantee by the Partnerships of
the Partnership indebtedness.
In January 1998, the Company made use of a derivative financial instrument
to hedge its exposure to fluctuations in the interest rate associated with the
placement of the Old Securities by entering into a fixed interest rate hedge.
The financial instrument was settled on February 17, 1998 and qualified for
hedge accounting. The gain resulting from the hedge was $151,582 and is being
amortized into income using the effective interest method.
F-45
ESI TRACTEBEL ACQUISITION CORP.
BALANCE SHEET
(THOUSANDS OF DOLLARS)
(UNAUDITED)
MARCH 31,
1998
---------
ASSETS
Current assets:
Interest receivable--NE LP notes.................................................................... $ 2,051
---------
Total current assets............................................................................. 2,051
Due from affiliated party............................................................................. 152
Notes receivable from NE LP........................................................................... 220,000
---------
Total assets..................................................................................... $ 222,203
---------
---------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Interest payables--securities....................................................................... $ 2,051
---------
Total current liabilities........................................................................ 2,051
Deferred revenue--interest rate hedge................................................................. 150
Securities payable.................................................................................... 220,000
---------
Total liabilities................................................................................ 222,201
Stockholders' equity:
Common Stock, par value $.01, 100 shares authorized, 20 shares issued............................... --
Subscriptions receivable............................................................................ --
Retained earnings................................................................................... 2
---------
Total stockholders' equity....................................................................... 2
---------
Total liabilities and stockholders' equity....................................................... $ 222,203
---------
---------
The accompanying notes are an integral part of the financial statements.
F-46
ESI TRACTEBEL ACQUISITION CORP.
STATEMENT OF OPERATIONS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
PERIOD ENDED
MARCH 31,
1998
------------
Interest income--NE LP.............................................................................. $2,053
Interest expense.................................................................................... 2,051
------------
Net income..................................................................................... $ 2
------------
------------
The accompanying notes are an integral part of the financial statements.
F-47
ESI TRACTEBEL ACQUISITION CORP.
STATEMENT OF CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
PERIOD ENDED
MARCH 31,
1998
------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................................................................ $ 2
Adjustments to reconcile net income to net cash provided by operating activities
Amortization of deferred gain on interest rate hedge........................................... (2)
------------
Net cash provided by operating activities.................................................... --
------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Loan to NE LP..................................................................................... (215,202)
------------
Net cash used in investing activities........................................................ (215,202)
------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of debt securities....................................................................... 215,050
Proceeds from interest rate hedge................................................................. 152
------------
Net cash provided by financing activities.................................................... 215,202
------------
Net increase (decrease) in cash and cash equivalents................................................ --
Cash at beginning of period......................................................................... --
------------
Cash at end of period............................................................................... $ --
------------
------------
The accompanying notes are an integral part of the financial statements.
F-48
ESI TRACTEBEL ACQUISITION CORP.
NOTES TO FINANCIAL STATEMENTS
MARCH 31, 1998
(UNAUDITED)
1. NATURE OF BUSINESS
ESI Tractebel Acquisition Corp., a Delaware corporation (the 'Company') was
formed on January 12, 1998 as a special purpose funding corporation for the
purpose of issuing the Securities described in Note 3. The common stock is
jointly owned by ESI Northeast Energy Acquisition Funding, Inc. (ESI NE
Acquisition Funding) and Tractebel Power, Inc. (Tractebel Power). The Company
acts as agent of Northeast Energy, LP (NE LP, a Delaware limited partnership)
with respect to the Securities and holds itself out as agent of NE LP in all
dealings with third parties relating to the Securities.
NE LP was formed on November 21, 1997 for the purpose of acquiring
ownership interests in electric power generation stations, and is jointly owned
by subsidiaries of ESI Energy, Inc. (ESI Energy) and Tractebel Power, Inc.
(Tractebel Power). NE LP also formed a wholly-owned entity, Northeast Energy,
LLC (NE LLC, and together with NE LP, the Partners) to assist in such
acquisitions.
On January 14, 1998, the Partners purchased all of the interests in two
existing limited partnerships, Northeast Energy Associates, A Limited
Partnership (NEA) and North Jersey Energy Associates, A Limited Partnership
(NJEA, and together with NEA, the Partnerships).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates--The preparation of financial statements in conformity
with generally accepted accounting principles requires 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 amount of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
3. THE SECURITIES
On February 12, 1998, the Company executed 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:
MARCH 31,
1998
------------
7.99% Secured Bonds Due 2011.................................................. $220,000,000
The Company has 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 ('Old Securities') listed above are to be exchanged
for a new issue of securities (the 'New Securities' and together with the Old
Securities, the 'Securities'). The New Securities will have terms identical to
the Old Securities.
Interest on the Securities is payable semiannually on each June 30 and
December 30, commencing on the first such date to occur after the exchange is
effective. Principal repayments are made annually commencing on June 30, 2002
and are in amounts stipulated in the indenture. Future principal payments are as
follows:
2002.......................................................................... $ 8,800,000
Thereafter.................................................................... 211,200,000
------------
$220,000,000
------------
------------
The Securities are subject to optional redemption after June 30, 2008 and
are subject to extraordinary mandatory redemption in certain limited
circumstances as defined in the trust indenture.
The proceeds from the sale of the Old Securities were loaned to NE LP,
evidenced by a promissory note (the Note) with substantially identical terms as
the Old Securities, for the purpose of reimbursing certain of the
F-49
ESI TRACTEBEL ACQUISITION CORP.
NOTES TO FINANCIAL STATEMENTS
MARCH 31, 1998--(CONTINUED)
(UNAUDITED)
3. THE SECURITIES--(CONTINUED)
partners of NE LP for a portion of the original $545 million equity contribution
that was used to finance the cost of the Acquisitions.
The Old Securities and the Securities to be issued in the exchange offer
are unconditionally guaranteed by NE LP.
The Securities are payable solely from payments to be made by NE LP under
the Note and from distributions from the Partnerships. NE LP's obligations to
make payments under the Note are nonrecourse to the direct and indirect owners
of NE LP. Generally, neither the Partners nor any of the direct or indirect
owners of the Partners will be obligated to contribute additional funds if there
is insufficient money for payment of debt service in respect of the Securities.
Payments with respect to 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 the Partnerships, including the guarantee by the Partnerships of
the Partnership indebtedness.
Repayment of the Securities is guaranteed by all interest in the
Partnerships. The Securities will rank senior to all subordinated indebtedness
and rank evenly with all senior indebtedness that the Company incurs in the
future.
4. FINANCIAL INSTRUMENTS
In January 1998, the Company made use of a derivative financial instrument
to hedge its exposure to fluctuations in the interest rate associated with the
placement of the Old Securities by entering into a fixed interest rate hedge.
The financial instrument was settled on February 17, 1998 and qualified for
hedge accounting. The gain resulting from the hedge was $151,582 and is being
amortized into income using the effective interest method.
The Company does not normally require collateral or other security to
support financial instruments with credit risks.
F-50
INDEPENDENT AUDITORS' REPORT
ESI Northeast Energy, GP, Inc.:
We have audited the accompanying balance sheet of ESI Northeast Energy GP, Inc.
(the 'Company') as of December 31, 1997. This financial statement is the
responsibility of the Company's management. Our responsibility is to express an
opinion on this financial statement based on our audit.
We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the balance sheet is free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the balance sheet. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall balance sheet presentation. We believe that our audit
of the balance sheet provides a reasonable basis for our opinion.
In our opinion, such balance sheet presents fairly, in all material respects,
the financial position of the Company as of December 31, 1997 in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Certified Public Accountants
West Palm Beach, Florida
July 13, 1998
F-51
ESI NORTHEAST ENERGY GP, INC.
BALANCE SHEET
(THOUSANDS OF DOLLARS)
DECEMBER 31, 1997
-----------------
ASSETS
TOTAL ASSETS............................................................... $ --
-----------------
-----------------
LIABILITIES AND STOCKHOLDER'S EQUITY
TOTAL LIABILITIES.......................................................... $ --
STOCKHOLDER'S EQUITY
-----------------
Common Stock, par value $.01, 1,000 shares authorized and subscribed..... --
Subscriptions receivable................................................. --
-----------------
Total stockholder's equity............................................ --
-----------------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY................................. $ --
-----------------
-----------------
The accompanying notes are an integral part of this financial statement.
F-52
ESI NORTHEAST ENERGY GP, INC.
NOTES TO BALANCE SHEET
DECEMBER 31, 1997
1. NATURE OF BUSINESS
ESI Northeast Energy GP, Inc. (ESI GP) was formed on November 13, 1997 for
the purpose of investing in Northeast Energy, LP (NE LP).
NE LP, a Delaware limited partnership, was formed on November 21, 1997 for
the purpose of acquiring ownership interests in electric power generation
stations, and is jointly owned by subsidiaries of ESI Energy, Inc. (ESI Energy)
and Tractebel Power, Inc. (Tractebel Power). NE LP also formed a wholly-owned
entity, Northeast Energy, LLC (NE LLC and together with NE LP, the Partners) to
assist in such acquisitions.
From November 17, 1997 (date of inception) through December 31, 1997, ESI
GP had no operations or transactions, thus no statement of operations or cash
flows has been presented for this period.
The partners of NE LP share profits and losses and have interests in assets
and liabilities and cash flows in proportion to their tax basis capital
accounts.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates--The preparation of financial statements in conformity
with generally accepted accounting principles requires 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 amount of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
3. SUBSEQUENT EVENTS
On January 14, 1998, pursuant to a purchase agreement dated November 21,
1997, the Partnerships were acquired by NE LP and Northeast Energy, LLC (NE LLC)
(a Delaware limited liability company) (collectively, the 'Partners'). The
Partners purchased their interests from Intercontinental Energy Corporation and
from certain individuals. The Partners are owned by direct subsidiaries of ESI
Energy, Inc. (ESI GP and ESI Northeast Energy LP, Inc.) and Tractebel Power,
Inc. (Tractebel Northeast Generation GP, Inc. and Tractebel Associates Northeast
LP, Inc.). ESI Energy, Inc. is wholly owned by FPL Energy, Inc., which is an
indirect wholly owned subsidiary of FPL Group, Inc., a New York Stock Exchange
company. Tractebel Power, Inc. is a direct wholly owned subsidiary of Tractebel,
Inc. which is a direct wholly owned subsidiary of Tractebel, S.A., a Belgian
energy and environmental services business. 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.
The acquisition of the Partnerships was accounted for using the purchase
method of accounting. The consideration, paid in cash, to acquire the interests
in the Partnerships of approximately $545 million including approximately $10
million of acquisition costs, was allocated to the assets and liabilities
acquired based on their fair values.
On February 12, 1998, ESI Tractebel Acquisition Corp., a Delaware
corporation, issued $220,000,000 of 7.99% Secured Bonds Due 2011, (the 'Old
Securities'), the proceeds of which were loaned to NE LP, evidenced by a
promissory note with substantially identical terms as the Old Securities, for
the purpose of reimbursing certain of ESI Energy's and Tractebel Power's
subsidiaries for a portion of the original $545 million equity contribution that
was used to finance the cost of the Acquisitions.
ESI GP contributed $5.354 million in cash to NE LP on January 14, 1998, the
acquisition date. ESI GP received cash distributions of $3.987 million from NE
LP subsequent to January 14, 1998.
F-53
ESI NORTHEAST ENERGY GP, INC.
BALANCE SHEET
(UNAUDITED)
(THOUSANDS OF DOLLARS)
MARCH 31,
1998
--------------
ASSETS
Current assets:
Due from related parties.................................................... $ 95
-------
Total current assets.......................................................... 95
-------
Other assets:
Investment in limited partnership........................................... 1,446
-------
Total other assets............................................................ 1,446
-------
Total assets.................................................................. $1,541
-------
-------
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Due to related parties...................................................... $ 47
Deferred taxes.............................................................. 18
-------
Total current liabilities..................................................... 65
-------
Total liabilities............................................................. 65
-------
Stockholder's equity:
Common Stock, par value $.01, 1,000 shares authorized and issued............ 0
Paid in capital............................................................. 1,367
Retained earnings........................................................... 109
-------
Total stockholder's equity.......................................... 1,476
-------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY.................................... $1,541
-------
-------
The accompanying notes are an integral part of this financial statement.
F-54
ESI NORTHEAST ENERGY GP, INC.
NOTES TO BALANCE SHEET
MARCH 31, 1998
(UNAUDITED)
1. NATURE OF BUSINESS
ESI Northeast Energy GP, Inc. (ESI GP) was formed on November 13, 1997 for
the purpose of investing in Northeast Energy, LP (NE LP).
NE LP, a Delaware limited partnership, was formed on November 21, 1997 for
the purpose of acquiring ownership interests in electric power generation
stations, and is jointly owned by subsidiaries of ESI Energy, Inc. (ESI Energy)
and Tractebel Power, Inc. (Tractebel Power). NE LP also formed a wholly-owned
entity, Northeast Energy, LLC (NE LLC and together with NE LP, the Partners) to
assist in such acquisitions.
The partners of NE LP share profits and losses and have interests in assets
and liabilities and cash flows in proportion to their tax basis capital
accounts.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates--The preparation of financial statements in conformity
with generally accepted accounting principles requires 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 amount of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Basis of Presentation--The investment in Northeast Energy, LP is accounted
for on an equity basis and accordingly, income includes ESI GP's share of NE
LP's income.
3. INVESTMENT IN LIMITED PARTNERSHIP
On January 14, 1998, pursuant to a purchase agreement dated November 21,
1997, the Partnerships were acquired by NE LP and Northeast Energy, LLC (NE LLC)
(a Delaware limited liability company) (collectively, the 'Partners'). The
Partners purchased their interests from Intercontinental Energy Corporation and
from certain individuals. The Partners are owned by direct subsidiaries of ESI
Energy, Inc. (ESI GP, 1%, and ESI Northeast Energy LP, Inc., 49%) and Tractebel
Power, Inc. (Tractebel Northeast Generation GP, Inc., 1%, and Tractebel
Associates Northeast LP, Inc., 49%). ESI Energy, Inc. is wholly owned by FPL
Energy, Inc., which is an indirect wholly owned subsidiary of FPL Group, Inc., a
New York Stock Exchange company. Tractebel Power, Inc. is a direct wholly owned
subsidiary of Tractebel, Inc. which is a direct wholly owned subsidiary of
Tractebel, S.A., a Belgian energy and environmental services business.
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.
The acquisition of the Partnerships was accounted for using the purchase
method of accounting. The consideration, paid in cash, to acquire the interests
in the Partnerships of approximately $545 million including approximately $10
million of acquisition costs, was allocated to the assets and liabilities
acquired based on their fair values.
On February 12, 1998, ESI Tractebel Acquisition Corp., a Delaware
corporation, issued $220,000,000 of 7.99% Secured Bonds Due 2011, (the 'Old
Securities'), the proceeds of which were loaned to NE LP, evidenced by a
promissory note with substantially identical terms as the Old Securities, for
the purpose of reimbursing certain of ESI Energy's and Tractebel Power's
subsidiaries for a portion of the original $545 million equity contribution that
was used to finance the cost of the Acquisitions.
ESI GP contributed $5.354 million in cash to NE LP on January 14, 1998, the
acquisition date. ESI GP received cash distributions of $3.987 million from NE
LP subsequent to January 14, 1998.
F-55
4. STOCKOLDER'S EQUITY
During the three months ended March 31, 1998, ESI GP issued 1,000 shares of
common stock, par value $.01, for $10, received capital contributions from its
stockholder of $5.354 million and distributed capital to its stockholder of
$3.987 million.
5. RELATED PARTY TRANSACTIONS
Due from Northeast Energy, LP............................................................. $95,168
Due to ESI Energy, Inc. .................................................................. $45,321
Due to FPL International.................................................................. $ 1,624
Subsequent to the acquisitions, ESI GP entered into the Administrative
Services Agreement with NE LP to provide certain services to assist the
management committee of NE LP with the management and administration of NE LP
and the Partnerships. The Administrative Services Agreement has a 20 year term,
and expires in 2018. NE LP has agreed to pay ESI Northeast Energy GP a minimum
of $600,000 per year, and all out-of-pocket costs and expenses of performing its
services under the contract.
Due to ESI Energy, Inc. represents estimated income taxes payable to FPL
Group, Inc. ESI GP is included in the consolidated federal income tax return
filed by FPL Group, Inc.
F-56
INDEPENDENT AUDITORS' REPORT
Tractebel Northeast Generation GP, Inc.
We have audited the accompanying balance sheet of Tractebel Northeast Generation
GP, Inc. (the 'Company') as of December 31, 1997. This financial statement is
the responsibility of the Company's management. Our responsibility is to express
an opinion on this financial statement based on our audit.
We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the balance sheet is free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the balance sheet. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall balance sheet presentation. We believe that our audit
of the balance sheet provides a reasonable basis for our opinion.
In our opinion, such balance sheet presents fairly, in all material respects,
the financial position of the Company at December 31, 1997 in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas
July 13, 1998
F-57
TRACTEBEL NORTHEAST GENERATION GP, INC.
BALANCE SHEET
(THOUSANDS OF DOLLARS)
DECEMBER 31,
1997
------------
ASSETS
TOTAL ASSETS.................................................................... $ --
---
---
LIABILITIES AND STOCKHOLDER'S EQUITY
TOTAL LIABILITIES............................................................... $ --
---
STOCKHOLDER'S EQUITY:
Common stock, par value $1.00, 1,000 shares authorized and subscribed......... 1
Subscriptions receivable...................................................... (1)
Total stockholder's equity................................................. --
---
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY...................................... $ --
---
---
The accompanying notes are an integral part of this financial statement.
F-58
TRACTEBEL NORTHEAST GENERATION GP, INC.
NOTES TO BALANCE SHEET
DECEMBER 31, 1997
1. ORGANIZATION AND BUSINESS
Tractebel Northeast Generation GP, Inc. ('Tractebel GP') was formed on
November 17, 1997 under the laws of the State of Delaware as a special purpose
corporation for the purpose of participating as a one percent (1%) general
partner in Northeast Energy, LP, ('NE LP'). Tractebel GP is a wholly owned
subsidiary of Tractebel Power, Inc.
NE LP, a Delaware limited partnership, was formed on November 21, 1997 for
the purpose of the acquisition of two previously-existing limited partnerships,
Northeast Energy Associates, a Limited Partnership, and North Jersey Energy
Associates, a Limited Partnership (together, the 'Partnerships') that own
combined-cycle generation power plants.
From November 17, 1997 (date of inception) through December 31, 1997,
Tractebel GP had no operations or transactions, thus no statement of operations
or cash flows has been presented for this period. In January 1998, Tractebel GP
received $1,000 for payment of the subscriptions receivable.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates in Financial Statement Preparation--The preparation of
financial statements in conformity with generally accepted accounting principles
requires 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 amount of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Basis of Presentation--The investment in Northeast Energy, LP is accounted
for on an equity basis and accordingly, income includes Tractebel GP's share of
NE LP's income.
3. SUBSEQUENT EVENTS
On January 14, 1998, pursuant to a purchase agreement dated November 21,
1997, the Partnerships were acquired by NE LP and Northeast Energy, LLC ('NE
LLC') (a Delaware limited liability company) (collectively, the 'Partners'). The
Partners purchased their interests from Intercontinental Energy Corporation and
from certain individuals. The Partners are owned by direct subsidiaries of ESI
Energy, Inc. (ESI GP and ESI Northeast Energy LP, Inc.) and Tractebel Power,
Inc. (Tractebel Northeast Generation GP, Inc. and Tractebel Associates Northeast
LP, Inc.). ESI Energy, Inc. is wholly owned by FPL Energy, Inc., which is an
indirect wholly owned subsidiary of FPL Group, Inc., a New York Stock Exchange
company. Tractebel Power, Inc. is a direct wholly owned subsidiary of Tractebel,
Inc. which is a direct wholly owned subsidiary of Tractebel, S.A., a Belgian
energy and environmental services business. 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.
The acquisition of the Partnerships was accounted for using the purchase
method of accounting. The consideration, paid in cash, to acquire the interests
in the Partnerships of approximately $545 million including approximately $10
million of acquisition costs, was allocated to the assets and liabilities
acquired based on their fair values.
Tractebel GP contributed $5.354 million in cash to NE LP on January 14,
1998, the acquisition date. Tractebel GP received cash distributions of $2.165
million from NE LP subsequent to January 14, 1998.
F-59
TRACTEBEL NORTHEAST GENERATION GP, INC.
BALANCE SHEET
(UNAUDITED)
(THOUSANDS OF DOLLARS)
MARCH 31,
1998
---------
ASSETS
Current assets:
Cash............................................................................. $ 1
---------
Total current assets............................................................... 1
---------
Other assets:
Investment in limited partnership................................................ 3,225
---------
Total other assets................................................................. 3,225
---------
TOTAL ASSETS....................................................................... $ 3,226
---------
---------
LIABILITIES AND STOCKHOLDER'S EQUITY
TOTAL LIABILITIES.................................................................. $ --
---------
STOCKHOLDER'S EQUITY:
Common stock, par value $1.00, 1,000 shares authorized and subscribed............ 1
Paid in capital.................................................................. 3,149
Retained earnings................................................................ 76
---------
Total stockholder's equity.................................................... 3,226
---------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY......................................... $ 3,226
---------
---------
The accompanying notes are an integral part of this financial statement.
F-60
TRACTEBEL NORTHEAST GENERATION GP, INC.
NOTES TO BALANCE SHEET
MARCH 31, 1998
(UNAUDITED)
1. ORGANIZATION AND BUSINESS
Tractebel Northeast Generation GP, Inc. ('Tractebel GP') was formed on
November 17, 1997 under the laws of the State of Delaware as a special purpose
corporation for the purpose of participating as a one percent (1%) general
partner in Northeast Energy, LP, ('NE LP'). Tractebel GP is a wholly owned
subsidiary of Tractebel Power, Inc.
NE LP, a Delaware limited partnership, was formed on November 21, 1997 for
the purpose of the acquisition of two previously-existing limited partnerships,
Northeast Energy Associates, a Limited Partnership, and North Jersey Energy
Associates, a Limited Partnership (together, the 'Partnerships') that own
combined-cycle generation power plants.
The partners of NE LP share profits and losses and have interests in assets
and liabilities and cash flows in proportion to their tax basis capital
accounts.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates in Financial Statement Preparation--The preparation of
financial statements in conformity with generally accepted accounting principles
requires 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 amount of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Basis of Presentation--The investment in Northeast Energy, LP is accounted
for on an equity basis and accordingly, income includes Tractebel GP's share of
NE LP's income.
3. INVESTMENT IN LIMITED PARTNERSHIP
On January 14, 1998, pursuant to a purchase agreement dated November 21,
1997, the Partnerships were acquired by NE LP and Northeast Energy, LLC ('NE
LLC') (a Delaware limited liability company) (collectively, the 'Partners'). The
Partners purchased their interests from Intercontinental Energy Corporation and
from certain individuals. The Partners are owned by direct subsidiaries of ESI
Energy, Inc. (ESI GP, 1%, and ESI Northeast Energy LP, Inc., 49%) and Tractebel
Power, Inc. (Tractebel Northeast Generation GP, Inc., 1%, and Tractebel
Associates Northeast LP, Inc., 49%). ESI Energy, Inc. is wholly owned by FPL
Energy, Inc., which is an indirect wholly owned subsidiary of FPL Group, Inc., a
New York Stock Exchange company. Tractebel Power, Inc. is a direct wholly owned
subsidiary of Tractebel, Inc. which is a direct wholly owned subsidiary of
Tractebel, S.A., a Belgian energy and environmental services business.
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.
The acquisition of the Partnerships was accounted for using the purchase
method of accounting. The consideration, paid in cash, to acquire the interests
in the Partnerships of approximately $545 million including approximately $10
million of acquisition costs, was allocated to the assets and liabilities
acquired based on their fair values.
Tractebel GP contributed $5.354 million in cash to NE LP on January 14,
1998, the acquisition date. Tractebel GP received cash distributions of $2.165
million from NE LP subsequent to January 14, 1998.
4. STOCKHOLDER'S EQUITY
During the three months ended March 31, 1998, Tractebel GP issued 1,000
shares of common stock, $1.00 par value, for $1,000, received capital
contributions from its stockholder of $5.354 million, and distributed capital to
its stockholder of $2.165 million.
F-61
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
A-1
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 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.
'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;
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(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.
'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
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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).
'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
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the applicable Power Purchase Agreement in excess of such Power Purchaser's
Avoided Costs, determined in accordance with such Power Purchase Agreement.
'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.
'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.
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'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.
'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
A-6
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.
'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.
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'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.
'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.
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'Montaup' means Montaup Electric Company, a Massachusetts corporation.
'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.
'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.
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'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 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.
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'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.
'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).
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'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.
'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.
'Offering' means the offering of the Old Securities described herein.
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'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.
'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.
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'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 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.
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'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.
'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
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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 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.
'PSE&G' means Public Service Electric and Gas Company, a New Jersey
corporation.
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'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.
'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.
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'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.
'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
A-18
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 (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.
A-19
'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.
'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.
'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-20
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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BELLINGHAM AND SAYREVILLE COGENERATION FACILITIES
DUE DILIGENCE REVIEW
CONTENTS
SECTION PAGE
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ES EXECUTIVE SUMMARY...................................................................................... ES-1
Technical Review of the Cogeneration Facilities...................................................... ES-2
Technical Review of the Bellingham Carbon Dioxide Plant.............................................. ES-2
Plant Performance Review............................................................................. ES-2
Operation and Maintenance Review..................................................................... ES-3
Pro Forma Financial Statement Review................................................................. ES-3
Permitting and Compliance Review..................................................................... ES-3
1 INTRODUCTION............................................................................................ 1-1
Ownership Structure.................................................................................. 1-1
The Sites............................................................................................ 1-1
The Cogeneration Plants.............................................................................. 1-2
The Bellingham Carbon Dioxide Plant.................................................................. 1-3
Auxiliary Plant Services............................................................................. 1-3
Objective of Review and Methodology.................................................................. 1-3
Summary.............................................................................................. 1-4
2 TECHNICAL REVIEW OF THE COGENERATION FACILITIES......................................................... 2-1
Westinghouse 501D5 Combustion Turbines............................................................... 2-1
Design Basis.................................................................................... 2-1
Operation and Maintenance....................................................................... 2-1
Heat Recovery Steam Generators....................................................................... 2-2
Design Basis.................................................................................... 2-2
Operation and Maintenance....................................................................... 2-3
Westinghouse Steam Turbines.......................................................................... 2-4
Design Basis.................................................................................... 2-4
Operation and Maintenance....................................................................... 2-5
Air-Cooled Condenser/Air Removal System.............................................................. 2-5
Design Basis.................................................................................... 2-5
Operation and Maintenance....................................................................... 2-5
Balance-of-Plant Equipment........................................................................... 2-6
Condensate System............................................................................... 2-6
Boiler Feedwater System......................................................................... 2-6
Demineralized Water Treatment System............................................................ 2-6
Fire Protection System.......................................................................... 2-7
Zero Discharge Wastewater Treatment System...................................................... 2-7
Summary......................................................................................... 2-7
Electrical Components and Systems.................................................................... 2-8
Bellingham Cogeneration Facility................................................................ 2-8
Sayreville Cogeneration Facility................................................................ 2-9
Plant Control System............................................................................ 2-10
Architectural/Civil/Structural Components and Systems................................................ 2-11
General Features of Both Facilities............................................................. 2-11
Bellingham Cogeneration Facility..................................................................... 2-12
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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-2
ii
SL-5171
- --------------------------------------------------------------------------------
BELLINGHAM AND SAYREVILLE COGENERATION FACILITIES
DUE DILIGENCE REVIEW
CONTENTS--(CONTINUED)
SECTION PAGE
- ---------------------------------------------------------------------------------------------------------- ----
Sayreville Cogeneration Facility..................................................................... 2-13
Summary.............................................................................................. 2-14
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.......................................................................... 3-2
CO2 Oil Separator............................................................................... 3-3
Summary.............................................................................................. 3-3
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................................................................................ 4-2
Availability......................................................................................... 4-3
Industry Averages............................................................................... 4-3
Station Performance............................................................................. 4-4
Summary.............................................................................................. 4-5
5 OPERATION AND MAINTENANCE REVIEW........................................................................ 5-1
Existing O&M Agreements.............................................................................. 5-1
Bellingham Facility............................................................................. 5-1
Sayreville Facility............................................................................. 5-2
Nonfuel O&M Expenses................................................................................. 5-3
Summary.............................................................................................. 5-5
6 PRO FORMA FINANCIAL PROJECTIONS REVIEW.................................................................. 6-1
Operational Assumptions.............................................................................. 6-1
Capacity........................................................................................ 6-2
Availability.................................................................................... 6-3
Heat Rate as Fuel Consumption per Kilowatt-Hour................................................. 6-3
Power Generation Revenues............................................................................ 6-4
Power Sales Prices.............................................................................. 6-4
Energy Banks.................................................................................... 6-4
Gross Steam Production Income................................................................... 6-5
Project Operating Costs......................................................................... 6-5
Financing Costs................................................................................. 6-6
Reserve Accounts................................................................................ 6-6
Base-Case Results.................................................................................... 6-7
Sensitivity Analyses................................................................................. 6-6
Sensitivity Case A: Increased Spot Gas Prices................................................... 6-7
Sensitivity Case B: Increased Inflation Rate.................................................... 6-7
Sensitivity Case C: Lower Station Availability.................................................. 6-7
Sensitivity Case D: Lower Fuel Efficiency....................................................... 6-7
Sensitivity Case E: No Merchant Power Sales..................................................... 6-7
- --------------------------------------------------------------------------------
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-3
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BELLINGHAM AND SAYREVILLE COGENERATION FACILITIES
DUE DILIGENCE REVIEW
CONTENTS--(CONTINUED)
SECTION PAGE
- ---------------------------------------------------------------------------------------------------------- ----
Summary.............................................................................................. 6-8
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.............................................................. 7-2
Air Pollution Control Permits................................................................... 7-2
Other Air Pollution Control Requirements........................................................ 7-2
Noise Guidelines Compliance..................................................................... 7-4
Airspace Obstruction Approval................................................................... 7-4
Wastewater Discharges........................................................................... 7-4
Water Withdrawal Permits........................................................................ 7-5
Solid and Hazardous Waste Disposal.............................................................. 7-5
Chemical and Petroleum Storage.................................................................. 7-6
Oil and Chemical Spill Response................................................................. 7-6
Wetlands and Floodplain Permits................................................................. 7-7
Zoning Approvals................................................................................ 7-7
Building Permits................................................................................ 7-8
Right-of-Way Permits............................................................................ 7-8
Future Environmental Regulations................................................................ 7-8
CO2 Plant--Air Permit........................................................................... 7-9
CO2 Plant--Chemical Spill Response.............................................................. 7-9
Sayreville Cogeneration Facility..................................................................... 7-9
Energy and Utility Approvals and Requirements................................................... 7-9
Soil and Groundwater Contamination.............................................................. 7-10
Air Pollution Control Permits................................................................... 7-10
Noise Levels.................................................................................... 7-12
Airspace Obstruction Approval................................................................... 7-12
Wastewater Discharges........................................................................... 7-12
Water Withdrawal Permits........................................................................ 7-13
Solid and Hazardous Waste Disposal.............................................................. 7-13
Chemical and Petroleum Storage.................................................................. 7-13
Oil and Chemical Spill Response................................................................. 7-14
Wetlands and Stream Encroachment Permits........................................................ 7-14
Zoning Approvals and Building Permits........................................................... 7-14
Future Environmental Regulations................................................................ 7-14
Summary.............................................................................................. 7-15
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-4
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.
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.
- --------------------------------------------------------------------------------
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
ES-2
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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 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.
- --------------------------------------------------------------------------------
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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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.
ANNUAL BOND DEBT
SERVICE COVERAGE RATIOS
MINIMUM AVERAGE
----------------------- -------
Base Case................................................... 2.25x 2.88x
Sensitivity Case A.......................................... 2.21x 2.87x
Sensitivity Case B.......................................... 2.17x 2.80x
Sensitivity Case C.......................................... 2.05x 2.65x
Sensitivity Case D.......................................... 1.88x 2.33x
Sensitivity Case E.......................................... 1.37x 2.59x
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.
- --------------------------------------------------------------------------------
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
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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.
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.
- --------------------------------------------------------------------------------
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 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
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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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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.
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.
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.
- --------------------------------------------------------------------------------
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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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%
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 and budgets, the performance history, the pro forma financial
statements, and the environmental permitting and compliance history for the
Bellingham and Sayreville cogeneration facilities.
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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 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
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.
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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 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.
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.
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.
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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 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.
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.
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
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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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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 degreesF
Low-pressure (LP) steam........................................ 185 psig 85-90 psig 400 degreesF
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 938degreesF. 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.
The root cause of this phenomenon has not been determined but may be a
combination of the following factors:
o flow-related design problems
o low carbon steel material
o boiler water chemistry
o 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
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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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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
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.
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
915degreesF, and the maximum capacity of the Sayreville steam turbine is 101,740
kW at 928 psig and 934degreesF. 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 405degreesF, and
steam for combustion turbine NOX control is extracted from the steam turbine at
approximately 325 psig and 700degreesF. 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.
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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
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.
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
90degreesF. Available engineering weather data, from various government data
sources, indicate that the dry bulb temperature in Massachusetts will equal or
exceed 90degreesF, 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
90degreesF, 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 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.
- --------------------------------------------------------------------------------
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-19
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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.
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.
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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-20
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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.
The fire protection systems at both the Bellingham and Sayreville plants
consist of the following subsystems:
o A water supply system for the fire hydrants, hose stations, and
sprinkler systems in the general areas of the plant.
o 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.
o 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.
o 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.
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.
- --------------------------------------------------------------------------------
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-21
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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-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.
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.
- --------------------------------------------------------------------------------
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-22
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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.
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
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This document contains information that is confidential and proprietary to
Sargent & Lundy (S&L). It shall not
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prior written consent of S&L.
Copyright Sargent & Lundy 1998; all rights reserved.
B-23
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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 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 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
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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-24
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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.
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:
o The Bellingham Cogeneration facility includes a carbon dioxide
plant.
o The Bellingham plant has oil burning capabilities with the required
fuel oil handling and storage facilities.
o 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.
o 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.
o 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.
o The foundation designs are somewhat different since the soil
conditions are different at the two sites.
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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-25
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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 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.
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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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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.
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.
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
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Sargent & Lundy (S&L). It shall not
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prior written consent of S&L.
Copyright Sargent & Lundy 1998; all rights reserved.
B-27
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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 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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be reproduced in whole or in part or released to any third party without the
prior written consent of S&L.
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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.
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 -17degreesF 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.
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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
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 272degreesF 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.
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.
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be reproduced in whole or in part or released to any third party without the
prior written consent of S&L.
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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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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.
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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:
o Performance and Reliability Test Procedures
o Performance Test Correction Curves
o Operation and Maintenance Agreements, including the Bellingham and
Sayreville heat rate revisions dated June 23, 1993
o Monthly Generation Reports
o Outage Reports (BEL 97-031, SVL-172)
o 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 (59degreesF 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.
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
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prior written consent of S&L.
Copyright Sargent & Lundy 1998; all rights reserved.
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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.
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
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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.
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
o 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.
o 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.
o 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.
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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.
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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prior written consent of S&L.
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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.
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
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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.
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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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.
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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.
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.
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prior written consent of S&L.
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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.
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
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
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Sargent & Lundy (S&L). It shall not
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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
-- 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
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prior written consent of S&L.
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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.
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.
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prior written consent of S&L.
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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.
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 5.5 MW
Steam Load........................................ 0.8 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 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
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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 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.
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
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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.
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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prior written consent of S&L.
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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.
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.
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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.
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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.
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.
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prior written consent of S&L.
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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 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.
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.
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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
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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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:
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.
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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.
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.
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.
- ------------------
* mmBtu=10(6) Btu
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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.
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.
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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.
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.
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.
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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.
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 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
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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.
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
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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.
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 ft 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.
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;
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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.
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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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.
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
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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.
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:
o Operating Limitations restrict the total annual natural gas fired in
the turbines to a maximum of 2.474 X 1013 Btu.
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be reproduced in whole or in part or released to any third party without the
prior written consent of S&L.
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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.
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.
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prior written consent of S&L.
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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.
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.
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
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provided. The most recent inspection certificate from the Bureau indicates
compliance with the New Jersey Uniform Fire Code and expires September 1, 1998.
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 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.
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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.
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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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-64
APPENDIX A
FINANCIAL PROJECTIONS FOR BASE CASE
B-65
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. Neither Deloitte &
Touche LLP nor PricewaterhouseCoopers LLP has either examined nor compiled the
Projects or any such assumptions and, accordingly, neither Deloitte & Touche LLP
nor PricewaterhouseCoopers LLP expresses any opinion or any other form of
assurance with respect thereto. The Deloitte & Touche LLP reports and the
PricewaterhouseCoopers LLP report included in the Prospectus relate solely to NE
LP, ESI Tractebel Acquisition, ESI GP, Tractebel GP and the Partnerships'
respective 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.
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.
B-66
NORTHEAST ENERGY, LP
SUMMARY OF UNDERLYING ASSUMPTIONS--(CONTINUED)
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.
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.
B-67
NORTHEAST ENERGY, LP
SUMMARY OF UNDERLYING ASSUMPTIONS--(CONTINUED)
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.
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.
B-68
NORTHEAST ENERGY, LP
SUMMARY OF UNDERLYING ASSUMPTIONS--(CONTINUED)
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.
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-69
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
-------- -------- -------- -------- -------- --------
NEA OPERATING RESULTS
Revenues
Boston Edison I................................... $ 73,649 $ 73,649 $ 74,415 $ 73,266 $ 68,288 $ 73,649
Boston Edison II.................................. 48,928 52,665 57,202 60,526 60,597 70,290
Commonwealth I.................................... 13,635 13,607 13,805 10,954 9,905 11,523
Commonwealth II................................... 12,153 13,081 14,207 15,033 15,051 17,458
Montaup........................................... 13,550 13,550 13,691 6,453 6,476 7,385
Merchant Sales.................................... 0 2,709 3,187 2,881 2,400 4,504
Steam............................................. 1,256 1,153 1,099 1,051 729 1,137
Interest Income................................... 404 404 481 552 479 518
-------- -------- -------- -------- -------- --------
Total Revenues.................................... $163,576 $170,819 $178,088 $170,717 $163,925 $186,465
Expenses
Operations and maintenance........................ $ 8,677 $ 8,998 $ 12,825 $ 10,180 $ 3,122 $ 7,987
Water costs and easement fee...................... 304 317 331 495 883 904
Insurance......................................... 887 912 937 964 991 1,017
G&A and Professional fees......................... 650 668 687 706 726 746
Property tax...................................... 3,601 3,712 3,824 3,936 4,049 4,154
Management fees................................... 2,026 2,083 2,141 2,201 2,263 2,324
Fuel management fee............................... 450 463 476 489 503 516
Gas Hedge & Peak Service Loss/(Savings)........... (4,158) (991) (1,011) (575) (753) (941)
Other............................................. 1,039 1,062 1,076 1,036 2,190 2,413
-------- -------- -------- -------- -------- --------
Non-fuel operating expense........................ $ 13,476 $ 17,223 $ 21,286 $ 19,433 $ 13,974 $ 19,121
Total fuel cost................................... 91,654 96,006 99,494 101,159 99,318 106,904
-------- -------- -------- -------- -------- --------
Total expenses.................................... $105,130 $113,229 $120,780 $120,592 $113,291 $126,025
Operating Cash Flow................................ $ 58,445 $ 57,590 $ 57,308 $ 50,125 $ 50,634 $ 60,441
NJEA OPERATING RESULTS
Revenues
JCP&L............................................. $142,607 $145,606 $148,580 $148,879 $147,531 $144,865
Merchant Sales.................................... 0 8,150 7,405 8,308 8,080 7,714
Steam............................................. 2,635 2,672 2,709 2,747 2,785 2,823
Interest Income................................... 284 284 306 389 476 396
-------- -------- -------- -------- -------- --------
Total Revenues.................................... $145,526 $156,711 $159,000 $160,322 $158,872 $155,797
Expenses
Operations and maintenance........................ $ 9,130 $ 9,336 $ 10,447 $ 11,539 $ 7,377 $ 3,412
Water costs and easement fee...................... 800 821 842 1,094 1,687 1,719
Insurance......................................... 748 769 790 812 835 858
G&A and Professional fees......................... 650 668 687 706 726 746
Property tax...................................... 866 867 868 870 871 872
Management fees................................... 2,026 2,083 2,141 2,201 2,263 2,324
Fuel management fee............................... 450 463 476 489 503 516
Gas Hedge & Peak Service Loss/(Savings)........... 0 0 0 0 0 0
Other............................................. 420 431 437 463 512 527
-------- -------- -------- -------- -------- --------
Non-fuel operating expense........................ $ 15,090 $ 15,438 $ 16,688 $ 18,174 $ 14,774 $ 10,973
Total fuel cost................................... 62,837 68,689 71,620 72,740 73,181 72,865
-------- -------- -------- -------- -------- --------
Total expenses.................................... $ 77,927 $ 84,127 $ 88,308 $ 90,914 $ 87,955 $ 83,838
Operating Cash Flow................................ $ 67,598 $ 72,584 $ 70,692 $ 69,408 $ 70,916 $ 71,959
COMBINED OPERATING RESULTS
Total Revenues..................................... $309,101 $327,530 $337,088 $331,039 $322,796 $342,262
Non-fuel operating expenses....................... 28,566 32,660 37,974 37,607 28,748 30,093
Total fuel cost................................... 154,491 164,696 171,114 173,899 172,499 179,769
-------- -------- -------- -------- -------- --------
Operating Cash Flow................................ $126,044 $130,174 $128,000 $119,533 $121,550 $132,400
Change in Working Capital......................... 10,097 3,005 1,401 (1,190) (1,200) 3,276
-------- -------- -------- -------- -------- --------
CASH AVAILABLE FOR DEBT SERVICE.................... $115,947 $127,169 $126,599 $120,723 $122,750 $129,124
Subordinated Management Fee........................ $ 1,649 $ 1,695 $ 1,742 $ 1,791 $ 1,841 $ 1,891
PROJECT SECURITIES
Principal......................................... 21,563 23,511 26,333 20,160 22,688 23,818
Interest.......................................... 45,327 43,468 41,426 39,300 37,396 35,264
PROJECT SECURITY DEBT SERVICE COVERAGE
Project Security debt service coverage*........... 1.76x 1.92x 1.89x 2.06x 2.07x 2.22x
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
THE BONDS
Principal......................................... 0 0 0 0 8,800 8,800
Interest.......................................... 15,381 17,578 17,578 17,578 17,402 16,699
DEBT SERVICE COVERAGES
Bond debt service coverage........................ 3.19x 3.42x 3.35x 3.49x 2.39x 2.75x
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
Minimum consolidated debt service coverage........ 1.41x
Average consolidated coverage..................... 1.57x
2004
--------
NEA OPERATING RESULTS
Revenues
Boston Edison I................................... $ 71,351
Boston Edison II.................................. 73,220
Commonwealth I.................................... 11,144
Commonwealth II................................... 18,186
Montaup........................................... 7,588
Merchant Sales.................................... 4,108
Steam............................................. 997
Interest Income................................... 541
--------
Total Revenues.................................... $187,135
Expenses
Operations and maintenance........................ $ 4,264
Water costs and easement fee...................... 925
Insurance......................................... 1,045
G&A and Professional fees......................... 766
Property tax...................................... 4,259
Management fees................................... 2,387
Fuel management fee............................... 530
Gas Hedge & Peak Service Loss/(Savings)........... (1,133)
Other............................................. 2,309
--------
Non-fuel operating expense........................ $ 15,350
Total fuel cost................................... 107,483
--------
Total expenses.................................... $122,833
Operating Cash Flow................................ $ 64,302
NJEA OPERATING RESULTS
Revenues
JCP&L............................................. $157,667
Merchant Sales.................................... 10,483
Steam............................................. 2,861
Interest Income................................... 378
--------
Total Revenues.................................... $171,389
Expenses
Operations and maintenance........................ $ 6,780
Water costs and easement fee...................... 1,751
Insurance......................................... 881
G&A and Professional fees......................... 766
Property tax...................................... 874
Management fees................................... 2,387
Fuel management fee............................... 530
Gas Hedge & Peak Service Loss/(Savings)........... 0
Other............................................. 548
--------
Non-fuel operating expense........................ $ 14,516
Total fuel cost................................... 80,026
--------
Total expenses.................................... $ 94,542
Operating Cash Flow................................ $ 76,847
COMBINED OPERATING RESULTS
Total Revenues..................................... $358,524
Non-fuel operating expenses....................... 29,866
Total fuel cost................................... 187,509
--------
Operating Cash Flow................................ $141,149
Change in Working Capital......................... 2,663
--------
CASH AVAILABLE FOR DEBT SERVICE.................... $138,486
Subordinated Management Fee........................ $ 1,942
PROJECT SECURITIES
Principal......................................... 28,564
Interest.......................................... 32,933
PROJECT SECURITY DEBT SERVICE COVERAGE
Project Security debt service coverage*........... 2.28x
Minimum Project Security debt service coverage....
Average Project Security debt service coverage....
DISTRIBUTIONS TO NE LP............................. $ 76,988
THE BONDS
Principal......................................... 8,800
Interest.......................................... 15,996
DEBT SERVICE COVERAGES
Bond debt service coverage........................ 3.10x
Minimum Bond debt service coverage................
Average Bond debt service coverage................
Consolidated coverage............................. 1.60x
Minimum consolidated debt service coverage........
Average consolidated coverage.....................
- ------------------
*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-70
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
-------- -------- -------- -------- -------- --------
NEA OPERATING RESULTS
Revenues
Boston Edison I.............................. $ 73,266 $ 73,649 $ 73,266 $ 68,288 $ 73,649 $ 71,351
Boston Edison II............................. 80,795 87,351 93,350 93,543 108,502 112,971
Commonwealth I............................... 11,908 12,267 12,421 11,288 13,078 12,684
Commonwealth II.............................. 20,068 21,696 23,186 23,234 26,949 28,059
Montaup...................................... 8,238 8,495 8,655 8,249 9,204 9,256
Merchant Sales............................... 3,863 5,122 4,647 3,831 7,157 6,475
Steam........................................ 1,170 1,232 1,234 855 1,334 1,170
Interest Income.............................. 439 480 578 514 519 514
-------- -------- -------- -------- -------- --------
Total Revenues................................ $199,746 $210,293 $217,337 $209,802 $240,393 $242,479
Expenses
Operations and maintenance................... $ 3,833 $ 6,174 $ 8,149 $ 3,646 $ 8,516 $ 3,601
Water costs and easement fee................. 946 967 988 1,009 1,030 1,052
Insurance.................................... 1,073 1,102 1,132 1,162 1,194 1,226
G&A and Professional fees.................... 786 808 829 852 875 898
Property tax................................. 4,362 4,464 4,564 4,661 4,756 4,846
Management fees.............................. 2,451 2,517 2,585 2,655 2,727 2,800
Fuel management fee.......................... 544 559 574 590 606 622
Gas Hedge & Peak Service Loss/(Savings)...... (1,155) (1,185) (1,215) (622) (886) (1,099)
Other........................................ 2,352 2,327 2,322 2,145 2,381 2,248
-------- -------- -------- -------- -------- --------
Non-fuel operating expense................... $ 15,192 $ 17,733 $ 19,928 $ 16,098 $ 21,198 $ 16,195
Total fuel cost.............................. 112,220 115,566 118,085 115,546 124,633 125,012
-------- -------- -------- -------- -------- --------
Total expenses............................... $127,411 $133,299 $138,013 $131,644 $145,830 $141,207
Operating Cash Flow........................... $ 72,335 $ 76,994 $ 79,325 $ 78,158 $ 94,562 $101,273
NJEA OPERATING RESULTS
Revenues
JCP&L........................................ $159,702 $162,480 $166,309 $164,315 $160,776 $175,260
Merchant Sales............................... 10,490 10,739 12,634 12,583 12,351 17,278
Steam........................................ 2,900 2,939 2,979 3,019 3,060 3,101
Interest Income.............................. 406 323 382 493 400 284
-------- -------- -------- -------- -------- --------
Total Revenues............................... $173,498 $176,481 $182,303 $180,410 $176,586 $195,922
Expenses
Operations and maintenance................... $ 4,759 $ 3,385 $ 7,447 $ 8,284 $ 3,658 $ 3,514
Water costs and easement fee................. 1,783 1,815 1,848 1,880 1,914 1,947
Insurance.................................... 905 929 954 980 1,006 1,034
G&A and Professional fees.................... 786 808 829 852 875 898
Property tax................................. 875 876 878 879 881 882
Management fees.............................. 2,451 2,517 2,585 2,655 2,727 2,800
Fuel management fee.......................... 544 559 574 590 606 622
Gas Hedge & Peak Service Loss/(Savings)...... 0 0 0 0 0 0
Other........................................ 564 575 585 598 617 588
-------- -------- -------- -------- -------- --------
Non-fuel operating expense................... $ 12,667 $ 11,464 $ 15,700 $ 16,718 $ 12,282 $ 12,287
Total fuel cost.............................. 82,196 84,596 87,376 87,445 86,461 94,569
-------- -------- -------- -------- -------- --------
Total expenses............................... $ 94,863 $ 96,060 $103,076 $104,163 $ 98,744 $106,855
Operating Cash Flow........................... $ 76,635 $ 80,421 $ 79,227 $ 76,247 $ 77,842 $ 89,067
COMBINED OPERATING RESULTS
Total Revenues................................ $373,244 $386,774 $399,641 $390,212 $416,979 $438,402
Non-fuel operating expenses.................. 27,859 29,197 35,629 32,816 33,480 28,481
Total fuel cost.............................. 194,415 200,162 205,460 202,990 211,094 210,581
-------- -------- -------- -------- -------- --------
Operating Cash Flow........................... $150,970 $157,414 $158,552 $154,405 $172,405 $190,340
Change in Working Capital.................... 2,416 2,233 2,088 (1,673) 4,568 3,603
-------- -------- -------- -------- -------- --------
CASH AVAILABLE FOR DEBT SERVICE............... $148,554 $155,182 $156,464 $156,078 $167,837 $186,737
Subordinated Management Fee................... $ 1,994 $ 2,048 $ 2,103 $ 2,160 $ 2,219 $ 2,278
PROJECT SECURITIES
Principal.................................... 45,349 52,641 54,021 51,801 54,616 65,223
Interest..................................... 29,880 25,484 20,545 15,504 10,374 4,779
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
THE BONDS
Principal.................................... 8,800 13,200 22,000 22,000 26,400 35,200
Interest..................................... 15,293 14,502 13,271 11,514 9,668 7,383
DEBT SERVICE COVERAGES
Bond debt service coverage................... 3.04x 2.78x 2.32x 2.65x 2.85x 2.74x
Consolidated coverage........................ 1.50x 1.47x 1.42x 1.55x 1.66x 1.66x
2011
--------
NEA OPERATING RESULTS
Revenues
Boston Edison I.............................. $ 73,266
Boston Edison II............................. 88,537
Commonwealth I............................... 13,423
Commonwealth II.............................. 30,972
Montaup...................................... 9,663
Merchant Sales............................... 18,416
Steam........................................ 1,374
Interest Income.............................. 404
--------
Total Revenues................................ $236,056
Expenses
Operations and maintenance................... $ 5,085
Water costs and easement fee................. 1,074
Insurance.................................... 1,260
G&A and Professional fees.................... 924
Property tax................................. 4,943
Management fees.............................. 2,879
Fuel management fee.......................... 639
Gas Hedge & Peak Service Loss/(Savings)...... (1,325)
Other........................................ 2,347
--------
Non-fuel operating expense................... $ 17,826
Total fuel cost.............................. 130,697
--------
Total expenses............................... $148,523
Operating Cash Flow........................... $ 87,533
NJEA OPERATING RESULTS
Revenues
JCP&L........................................ $113,850
Merchant Sales............................... 62,814
Steam........................................ 1,965
Interest Income.............................. 284
--------
Total Revenues............................... $178,913
Expenses
Operations and maintenance................... $ 6,869
Water costs and easement fee................. 1,982
Insurance.................................... 1,062
G&A and Professional fees.................... 924
Property tax................................. 884
Management fees.............................. 2,879
Fuel management fee.......................... 639
Gas Hedge & Peak Service Loss/(Savings)...... 0
Other........................................ 605
--------
Non-fuel operating expense................... $ 15,844
Total fuel cost.............................. 97,716
--------
Total expenses............................... $113,560
Operating Cash Flow........................... $ 65,353
COMBINED OPERATING RESULTS
Total Revenues................................ $414,969
Non-fuel operating expenses.................. 33,670
Total fuel cost.............................. 228,413
--------
Operating Cash Flow........................... $152,886
Change in Working Capital.................... (4,666)
--------
CASH AVAILABLE FOR DEBT SERVICE............... $157,552
Subordinated Management Fee................... $ 2,342
PROJECT SECURITIES
Principal.................................... 0
Interest..................................... 0
PROJECT SECURITY DEBT SERVICE COVERAGE
Project Security debt service coverage*......
DISTRIBUTION TO NE LP......................... $157,552
THE BONDS
Principal.................................... 66,000
Interest..................................... 3,955
DEBT SERVICE COVERAGES
Bond debt service coverage................... 2.25x
Consolidated coverage........................ 2.25x
- ------------------
*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-71
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-72
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 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% 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 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-73
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-74
APPENDIX B
FINANCIAL PROJECTIONS FOR SENSITIVITY CASES
B-75
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
PROJECTED 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-76
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
--------- --------- --------- --------- --------- --------- ---------
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......................... 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 2.69
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-77
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-78
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-79
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
-------- -------- -------- -------- -------- --------
NEA OPERATING RESULTS
Revenues
Boston Edison I................................ $ 73,649 $ 73,649 $ 74,415 $ 73,266 $ 68,288 $ 73,649
Boston Edison II............................... 48,928 52,665 57,202 60,526 60,597 70,290
Commonwealth I................................. 13,635 13,607 13,805 10,954 9,905 11,523
Commonwealth II................................ 12,153 13,081 14,207 15,033 15,051 17,458
Montaup........................................ 13,550 13,550 13,691 6,453 6,476 7,385
Merchant Sales................................. 0 2,709 3,187 2,881 2,400 4,504
Steam.......................................... 1,213 1,065 962 921 598 1,024
Interest Income................................ 505 505 605 699 605 674
-------- -------- -------- -------- -------- --------
Total Revenues................................. $163,634 $170,831 $178,076 $170,734 $163,919 $186,509
Expenses
Operations and maintenance..................... $ 8,753 $ 9,154 $ 13,220 $ 10,603 $ 3,206 $ 8,528
Water costs and easement fee................... 304 318 333 502 902 928
Insurance...................................... 897 933 971 1,009 1,050 1,092
G&A and Professional fees...................... 650 676 703 731 760 791
Property tax................................... 3,643 3,844 4,052 4,270 4,495 4,729
Management fees................................ 2,050 2,132 2,217 2,306 2,398 2,494
Fuel management fee............................ 450 468 487 506 526 547
Gas Hedge & Peak Service Loss/(Savings)........ (4,158) (991) (1,011) (575) (753) (941)
Other.......................................... 1,048 1,080 1,105 1,075 2,234 2,467
-------- -------- -------- -------- -------- --------
Non-fuel operating expense..................... $ 13,638 $ 17,615 $ 22,076 $ 20,426 $ 14,819 $ 20,635
Total fuel cost................................ 91,654 96,006 99,494 101,159 99,318 106,904
-------- -------- -------- -------- -------- --------
Total expenses................................. $105,292 $113,621 $121,571 $121,586 $144,137 $127,539
Operating Cash Flow............................. $ 58,342 $ 57,210 $ 56,504 $ 49,148 $ 49,783 $ 58,969
NJEA OPERATING RESULTS
Revenues
JCP&L.......................................... $142,607 $146,606 $148,580 $148,879 $147,531 $144,865
Merchant Sales................................. 0 8,150 7,405 8,308 8,080 7,714
Steam.......................................... 2,650 2,703 2,757 2,813 2,869 2,926
Interest Income................................ 355 355 383 493 611 516
-------- -------- -------- -------- -------- --------
Total Revenues................................. $145,612 $156,814 $159,126 $160,493 $159,090 $156,021
Expenses
Operations and maintenance..................... $ 9,215 $ 9,514 $ 10,766 $ 12,031 $ 7,776 $ 3,560
Water costs and easement fee................... 804 828 853 1,114 1,731 1,772
Insurance...................................... 757 787 818 851 885 920
G&A and Professional fees...................... 650 676 703 731 760 791
Property tax................................... 867 868 870 872 874 876
Management fees................................ 2,050 2,132 2,217 2,306 2,398 2,494
Fuel management fee............................ 450 468 487 506 526 547
Gas Hedge & Peak Service Loss/(Savings)........ 0 0 0 0 0 0
Other.......................................... 424 440 451 485 544 566
-------- -------- -------- -------- -------- --------
Non-fuel operating expense..................... $ 15,217 $ 15,713 $ 17,165 $ 18,896 $ 15,495 $ 11,527
Total fuel cost................................ 62,837 68,689 71,620 72,740 73,181 72,865
-------- -------- -------- -------- -------- --------
Total expenses................................. $ 78,054 $ 84,402 $ 88,785 $ 91,636 $ 88,676 $ 64,392
Operating Cash Flow............................. $ 67,558 $ 72,412 $ 70,341 $ 68,856 $ 70,414 $ 71,629
COMBINED OPERATING RESULTS
Total Revenues.................................. $309,246 $327,646 $337,202 $331,227 $323,009 $342,530
Non-fuel operating expenses.................... 28,855 33,327 39,242 39,323 30,313 32,163
Total fuel cost................................ 154,491 164,696 171,114 173,899 172,499 179,769
-------- -------- -------- -------- -------- --------
Operating Cash Flow............................. $125,900 $129,622 $126,846 $118,005 $120,197 $130,598
Change in Working Capital...................... 10,084 2,989 1,383 (1,193) (1,191) 3,272
-------- -------- -------- -------- -------- --------
CASH AVAILABLE FOR DEBT SERVICE................. $115,817 $126,634 $125,463 $119,198 $121,388 $127,326
Subordinated Management Fee..................... $ 1,668 1,735 1,804 1,876 1,951 2,029
PROJECT SECURITIES
Principal...................................... 21,563 23,511 26,333 20,160 22,688 23,818
Interest....................................... 45,327 43,468 41,426 39,300 37,396 35,264
PROJECT SECURITY DEBT SERVICE COVERAGE
Project Security debt service coverage*........ 1.76x 1.92x 1.88x 2.04x 2.05x 2.19x
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
THE BONDS
Principal...................................... 0 0 0 0 8,800 8,800
Interest....................................... 15,381 17,578 17,578 17,578 17,402 16,699
DEBT SERVICE COVERAGES
Bond debt service coverage..................... 3.18x 3.39x 3.28x 3.40x 2.34x 2.68x
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
Minimum consolidated debt service coverage..... 1.39x
Average consolidated coverage.................. 1.54x
2004
--------
NEA OPERATING RESULTS
Revenues
Boston Edison I................................ $ 71,351
Boston Edison II............................... 73,220
Commonwealth I................................. 11,144
Commonwealth II................................ 18,186
Montaup........................................ 7,588
Merchant Sales................................. 4,108
Steam.......................................... 886
Interest Income................................ 707
--------
Total Revenues................................. $187,190
Expenses
Operations and maintenance..................... $ 4,533
Water costs and easement fee................... 953
Insurance...................................... 1,135
G&A and Professional fees...................... 822
Property tax................................... 4,971
Management fees................................ 2,594
Fuel management fee............................ 569
Gas Hedge & Peak Service Loss/(Savings)........ (1,133)
Other.......................................... 2,374
--------
Non-fuel operating expense..................... $ 16,819
Total fuel cost................................ 107,483
--------
Total expenses................................. $124,302
Operating Cash Flow............................. $ 62,887
NJEA OPERATING RESULTS
Revenues
JCP&L.......................................... $157,667
Merchant Sales................................. 10,483
Steam.......................................... 2,985
Interest Income................................ 495
--------
Total Revenues................................. $171,630
Expenses
Operations and maintenance..................... $ 7,307
Water costs and easement fee................... 1,815
Insurance...................................... 957
G&A and Professional fees...................... 822
Property tax................................... 878
Management fees................................ 2,594
Fuel management fee............................ 569
Gas Hedge & Peak Service Loss/(Savings)........ 0
Other.......................................... 596
--------
Non-fuel operating expense..................... $ 15,538
Total fuel cost................................ 80,026
--------
Total expenses................................. $ 95,565
Operating Cash Flow............................. $ 76,065
COMBINED OPERATING RESULTS
Total Revenues.................................. $358,820
Non-fuel operating expenses.................... 32,358
Total fuel cost................................ 187,509
--------
Operating Cash Flow............................. $138,953
Change in Working Capital...................... 2,656
--------
CASH AVAILABLE FOR DEBT SERVICE................. $136,297
Subordinated Management Fee..................... 2,110
PROJECT SECURITIES
Principal...................................... 28,564
Interest....................................... 32,933
PROJECT SECURITY DEBT SERVICE COVERAGE
Project Security debt service coverage*........ 2.25x
Minimum Project Security debt service
coverage.....................................
Average Project Security debt service
coverage.....................................
DISTRIBUTION TO NE LP........................... $ 74,800
THE BONDS
Principal...................................... 8,800
Interest....................................... 15,996
DEBT SERVICE COVERAGES
Bond debt service coverage..................... 3.02x
Minimum Bond debt service coverage.............
Average Bond debt service coverage.............
Consolidated coverage.......................... 1.58x
Minimum consolidated debt service coverage.....
Average consolidated coverage..................
- ------------------
*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-80
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
------- -------- -------- -------- -------- --------
NEA OPERATING RESULTS
Revenues
Boston Edison I............................. $73,266 $ 73,649 $ 73,266 $ 68,288 $ 73,649 $ 71,351
Boston Edison II............................ 80,795 87,351 93,350 93,543 108,502 112,971
Commonwealth I.............................. 11,906 12,267 12,421 11,288 13,078 12,684
Commonwealth II............................. 20,068 21,696 23,186 23,234 26,949 28,059
Montaup..................................... 8,238 8,495 8,655 8,249 9,204 9,256
Merchant Sales.............................. 3,863 5,122 4,647 3,831 7,157 6,475
Steam....................................... 1,077 1,152 1,165 756 1,296 1,121
Interest Income............................. 567 627 770 678 689 681
------- -------- -------- -------- -------- --------
Total Revenues.............................. $199,780 $210,360 $217,460 $209,867 $240,525 $242,598
Expenses
Operations and maintenance.................. $ 4,104 $ 6,763 $ 9,130 $ 4,029 $ 9,782 $ 4,066
Water costs and easement fee................ 979 1,005 1,031 1,058 1,085 1,112
Insurance................................... 1,181 1,228 1,277 1,328 1,381 1,437
G&A and Professional fees................... 855 890 925 962 1,001 1,041
Property tax................................ 5,222 5,480 5,745 6,017 6,296 6,580
Management fees............................. 2,697 2,805 2,918 3,034 3,156 3,282
Fuel management fee......................... 592 616 640 666 693 720
Gas Hedge & Peak Service Loss/(Savings)..... (1,155) (1,185) (1,215) (622) (886) (1,099)
Other....................................... 2,429 2,416 2,424 2,260 2,511 2,393
------- -------- -------- -------- -------- --------
Non-fuel operating expense.................. $16,904 $ 20,048 $ 22,877 $ 18,734 $ 25,017 $ 19,531
Total fuel cost............................. 112,220 115,566 118,085 115,546 124,633 125,012
------- -------- -------- -------- -------- --------
Total expenses.............................. $129,124 $135,615 $140,961 $134,279 $149,650 $144,543
Operating Cash Flow.......................... $70,656 $ 74,745 $ 76,499 $ 75,588 $ 90,875 $ 98,056
NJEA OPERATING RESULTS
Revenues
JCP&L....................................... $159,702 $162,480 $166,309 $164,315 $160,776 $175,260
Merchant Sales.............................. 10,490 10,739 12,634 12,583 12,351 17,278
Steam....................................... 3,044 3,105 3,167 3,231 3,295 3,361
Interest Income............................. 536 418 506 671 535 363
------- -------- -------- -------- -------- --------
Total Revenues.............................. $173,772 $176,743 $182,617 $180,799 $176,957 $196,262
Expense
Operations and maintenance.................. $ 5,142 $ 3,650 $ 8,333 $ 9,402 $ 4,094 $ 3,969
Water costs and easement fee................ 1,858 1,901 1,946 1,991 2,036 2,082
Insurance................................... 996 1,035 1,077 1,120 1,165 1,211
G&A and Professional fees................... 855 890 925 962 1,001 1,041
Property tax................................ 880 882 885 887 890 892
Management fees............................. 2,697 2,805 2,918 3,034 3,156 3,282
Fuel management fee......................... 592 616 640 666 693 720
Gas Hedge & peak Service Loss/(Savings)..... 0 0 0 0 0 0
Other....................................... 620 640 660 683 712 695
------- -------- -------- -------- -------- --------
Non-fuel operating expense.................. $13,640 $ 12,421 $ 17,383 $ 18,745 $ 13,745 $ 13,893
Total fuel cost............................. 82,196 84,596 87,376 87,445 86,461 94,569
------- -------- -------- -------- -------- --------
Total expenses.............................. $95,836 $ 97,016 $104,759 $106,189 $100,206 $108,461
Operating Cash Flow.......................... $77,936 $ 79,727 $ 77,858 $ 74,610 $ 76,751 $ 87,801
COMBINED OPERATING RESULTS
Total Revenue................................ $373,552 $387,103 $400,076 $390,666 $417,482 $438,861
Non-fuel operating expenses................. 30,545 32,469 40,260 37,478 38,762 33,424
Total fuel cost............................. 194,415 200,162 205,460 202,990 211,094 219,581
------- -------- -------- -------- -------- --------
Operating Cash Flow.......................... $148,592 $154,472 $154,356 $150,198 $167,626 $185,856
Change in Working Capital................... 2,411 2,226 2,081 (1,689) 4,568 3,590
------- -------- -------- -------- -------- --------
CASH AVAILABLE FOR DEBT SERVICE.............. $146,181 $152,245 $152,276 $151,886 $163,058 $182,267
Subordinated Management Fee.................. 2,195 2,283 2,374 2,469 2,568 2,670
PROJECT SECURITIES
Principal................................... 45,349 52,641 54,021 51,801 54,616 65,223
Interest.................................... 28,880 25,484 20,545 15,504 10,374 4,779
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
THE BONDS
Principal................................... 8,800 13,200 22,000 22,000 26,400 35,200
Interest.................................... 15,293 14,502 13,271 11,514 9,668 7,383
DEBT SERVICE COVERAGES
Bond debt service coverage.................. 2.94x 2.68x 2.20x 2.52x 2.72x 2.64x
Consolidated coverage....................... 1.47x 1.44x 1.39x 1.51x 1.61x 1.62x
2011
--------
NEA OPERATING RESULTS
Revenues
Boston Edison I............................. $ 73,266
Boston Edison II............................ 88,537
Commonwealth I.............................. 13,423
Commonwealth II............................. 30,972
Montaup..................................... 9,663
Merchant Sales.............................. 18,416
Steam....................................... 1,363
Interest Income............................. 505
--------
Total Revenues.............................. $236,145
Expenses
Operations and maintenance.................. $ 5,868
Water costs and easement fee................ 1,140
Insurance................................... 1,494
G&A and Professional fees................... 1,082
Property tax................................ 6,868
Management fees............................. 3,413
Fuel management fee......................... 749
Gas Hedge & Peak Service Loss/(Savings)..... (1,325)
Other....................................... 2,507
--------
Non-fuel operating expense.................. $ 21,797
Total fuel cost............................. 130,697
--------
Total expenses.............................. $152,494
Operating Cash Flow.......................... $ 83,651
NJEA OPERATING RESULTS
Revenues
JCP&L....................................... $113,850
Merchant Sales.............................. 62,814
Steam....................................... 2,143
Interest Income............................. 355
--------
Total Revenues.............................. $179,161
Expense
Operations and maintenance.................. $ 7,988
Water costs and easement fee................ 2,129
Insurance................................... 1,260
G&A and Professional fees................... 1,082
Property tax................................ 895
Management fees............................. 3,413
Fuel management fee......................... 749
Gas Hedge & peak Service Loss/(Savings)..... 0
Other....................................... 723
--------
Non-fuel operating expense.................. $ 18,240
Total fuel cost............................. 97,716
--------
Total expenses.............................. $115,955
Operating Cash Flow.......................... $ 63,206
COMBINED OPERATING RESULTS
Total Revenue................................ $415,307
Non-fuel operating expenses................. 40,036
Total fuel cost............................. 228,413
--------
Operating Cash Flow.......................... $146,857
Change in Working Capital................... (4,691)
--------
CASH AVAILABLE FOR DEBT SERVICE.............. $151,548
Subordinated Management Fee.................. 2,777
PROJECT SECURITIES
Principal................................... 0
Interest.................................... 0
PROJECT SECURITY DEBT SERVICE COVERAGE
Project Security debt service coverage*.....
DISTRIBUTIONS TO NE LP....................... $151,548
THE BONDS
Principal................................... 66,000
Interest.................................... 3,955
DEBT SERVICE COVERAGES
Bond debt service coverage.................. 2.17x
Consolidated coverage....................... 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-81
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-82
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-83
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-84
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 2.62
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-85
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
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 projects should be read in conjunction with the attached
Summary of Underlying Assumptions.
B-86
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
-------- -------- -------- -------- -------- --------
NEA OPERATING RESULTS
Revenues
Boston Edison I................................ $ 73,649 $ 73,649 $ 74,415 $ 73,266 $ 68,288 $ 73,649
Boston Edison II............................... 48,928 52,665 57,202 60,526 60,597 70,290
Commonwealth I................................. 13,635 13,607 13,805 10,954 9,905 11,523
Commonwealth II................................ 12,153 13,081 14,207 15,033 15,051 17,458
Montaup........................................ 13,550 13,550 13,691 6,453 6,476 7,385
Merchant Sales................................. 0 2,709 3,187 2,881 2,400 4,504
Steam.......................................... 1,256 1,153 1,099 1,051 729 1,137
Interest Income................................ 404 404 481 552 479 518
-------- -------- -------- -------- -------- --------
Total Revenues................................. $163,576 $170,819 $178,088 $170,717 $163,925 $186,465
Expenses
Operations and maintenance..................... $ 8,677 $ 8,998 $ 12,825 $ 10,180 $ 3,122 $ 7,987
Water costs and easement fee................... 304 317 331 495 883 904
Insurance...................................... 887 912 937 964 991 1,017
G&A and Professional fees...................... 650 668 687 706 726 746
Property tax................................... 3,601 3,712 3,824 3,936 4,049 4,154
Management fees................................ 2,026 2,083 2,141 2,201 2,263 2,324
Fuel management fee............................ 450 463 476 489 503 516
Gas Hedge & Peak Service Loss/(Savings)........ (4,158) (991) (1,011) (575) (753) (941)
Other.......................................... 1,039 1,062 1,076 1,036 2,190 2,413
-------- -------- -------- -------- -------- --------
Non-fuel operating expense..................... $ 13,476 $ 17,223 $ 21,286 $ 19,433 $ 13,974 $ 19,121
Total fuel cost................................ 97,264 102,243 106,015 107,798 105,766 114,007
-------- -------- -------- -------- -------- --------
Total expenses................................. $110,740 $119,466 $127,301 $127,231 $119,740 $133,127
Operating Cash Flow............................. $ 52,835 $ 51,353 $ 50,787 $ 43,486 $ 44,185 $ 53,338
NJEA OPERATING RESULTS
Revenues
JCP&L.......................................... $142,607 $145,606 $148,580 $148,879 $147,531 $144,865
Merchant Sales................................. 0 8,150 7,405 8,308 8,080 7,714
Steam.......................................... 2,635 2,672 2,709 2,747 2,785 2,823
Interest Income................................ 284 284 306 389 476 396
-------- -------- -------- -------- -------- --------
Total Revenues................................. $145,526 $156,711 $159,000 $160,322 $158,872 $155,797
Expenses
Operations and maintenance..................... $ 9,130 $ 9,336 $ 10,447 $ 11,539 $ 7,377 $ 3,412
Water costs and easement fee................... 800 821 842 1,094 1,687 1,719
Insurance...................................... 748 769 790 812 835 858
G&A and Professional fees...................... 650 668 687 706 726 746
Property tax................................... 866 867 868 870 871 872
Management fees................................ 2,026 2,083 2,141 2,201 2,263 2,324
Fuel management fee............................ 450 463 476 489 503 516
Gas Hedge & Peak Service Loss/(Savings)........ 0 0 0 0 0 0
Other.......................................... 420 431 437 463 512 527
-------- -------- -------- -------- -------- --------
Non-fuel operating expense..................... $ 15,090 $ 15,438 $ 16,688 $ 18,174 $ 14,774 $ 10,973
Total fuel cost................................ 68,470 74,899 78,089 79,275 79,727 79,344
-------- -------- -------- -------- -------- --------
Total expenses................................. $ 83,560 $ 90,336 $ 94,777 $ 97,449 $ 94,501 $ 90,317
Operating Cash Flow............................. $ 61,966 $ 66,375 $ 64,223 $ 62,874 $ 64,371 $ 65,480
COMBINED OPERATING RESULTS
Total Revenues.................................. $309,101 $327,530 $337,088 $331,039 $322,796 $342,262
Non-fuel operating expenses.................... 28,566 32,660 37,974 37,607 28,748 30,093
Total fuel cost................................ 165,734 177,142 184,104 187,073 185,493 193,350
-------- -------- -------- -------- -------- --------
Operating Cash Flow............................. $114,801 $117,728 $115,011 $106,359 $108,556 $118,819
Change in Working Capital...................... 9,635 2,956 1,378 (1,198) (1,193) 3,252
-------- -------- -------- -------- -------- --------
CASH AVAILABLE FOR DEBT SERVICE................. $105,166 $114,772 $113,632 $107,557 $109,748 $115,567
Subordinated Management Fee..................... $ 1,649 1,695 1,742 1,791 1,841 1,891
PROJECT SECURITIES
Principal...................................... 21,563 23,511 26,333 20,160 22,688 23,818
Interest....................................... 45,327 43,468 41,426 39,300 37,396 35,264
PROJECT SECURITY DEBT SERVICE COVERAGE
Project Security debt service coverage*........ 1.60x 1.74x 1.70x 1.84x 1.86x 1.99x
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
THE BONDS
Principal...................................... 0 0 0 0 8,800 8,800
Interest....................................... 15,381 17,578 17,578 17,578 17,402 16,699
DEBT SERVICE COVERAGES
Bond debt service coverage..................... 2.49x 2.72x 2.61x 2.74x 1.90x 2.22x
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
Minimum consolidated debt service coverage..... 1.27x
Average consolidated debt coverage............. 1.41x
2004
--------
NEA OPERATING RESULTS
Revenues
Boston Edison I................................ $ 71,351
Boston Edison II............................... 73,220
Commonwealth I................................. 11,144
Commonwealth II................................ 18,186
Montaup........................................ 7,588
Merchant Sales................................. 4,108
Steam.......................................... 997
Interest Income................................ 541
--------
Total Revenues................................. $187,135
Expenses
Operations and maintenance..................... $ 4,264
Water costs and easement fee................... 925
Insurance...................................... 1,045
G&A and Professional fees...................... 766
Property tax................................... 4,259
Management fees................................ 2,387
Fuel management fee............................ 530
Gas Hedge & Peak Service Loss/(Savings)........ (1,133)
Other.......................................... 2,309
--------
Non-fuel operating expense..................... $ 15,350
Total fuel cost................................ 114,608
--------
Total expenses................................. $129,957
Operating Cash Flow............................. $ 57,177
NJEA OPERATING RESULTS
Revenues
JCP&L.......................................... $157,667
Merchant Sales................................. 10,483
Steam.......................................... 2,861
Interest Income................................ 378
--------
Total Revenues................................. $171,389
Expenses
Operations and maintenance..................... $ 6,780
Water costs and easement fee................... 1,751
Insurance...................................... 881
G&A and Professional fees...................... 766
Property tax................................... 874
Management fees................................ 2,387
Fuel management fee............................ 530
Gas Hedge & Peak Service Loss/(Savings)........ 0
Other.......................................... 548
--------
Non-fuel operating expense..................... $ 14,516
Total fuel cost................................ 87,191
--------
Total expenses................................. $101,707
Operating Cash Flow............................. $ 69,682
COMBINED OPERATING RESULTS
Total Revenues.................................. $358,524
Non-fuel operating expenses.................... 29,866
Total fuel cost................................ 201,798
--------
Operating Cash Flow............................. $126,860
Change in Working Capital...................... 2,634
--------
CASH AVAILABLE FOR DEBT SERVICE................. $124,225
Subordinated Management Fee..................... 1,942
PROJECT SECURITIES
Principal...................................... 28,564
Interest....................................... 32,933
PROJECT SECURITY DEBT SERVICE COVERAGE
Project Security debt service coverage*........ 2.05x
Minimum Project Security debt service
coverage.....................................
Average Project Security debt service
coverage.....................................
DISTRIBUTIONS TO NE LP.......................... $ 62,728
THE BONDS
Principal...................................... 5,500
Interest....................................... 15,996
DEBT SERVICE COVERAGES
Bond debt service coverage..................... 2.53x
Minimum Bond debt service coverage.............
Average Bond debt service coverage.............
Consolidated coverage.......................... 1.44x
Minimum consolidated debt service coverage.....
Average consolidated debt coverage.............
- ------------------
*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-87
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
-------- -------- -------- -------- -------- --------
NEA OPERATING RESULTS
Revenues
Boston Edison I................................ $ 73,226 $ 73,649 $ 73,266 $ 68,288 $ 73,649 $ 71,351
Boston Edison II............................... 80,795 87,351 93,350 93,543 108,502 112,971
Commonwealth I................................. 11,906 12,267 12,421 11,288 13,078 12,684
Commonwealth II................................ 20,068 21,696 23,186 23,234 26,949 28,059
Montaup........................................ 8,238 8,495 8,655 8,249 9,204 9,256
Merchant Sales................................. 3,863 5,122 4,647 3,831 7,157 6,475
Steam.......................................... 1,170 1,232 1,234 855 1,334 1,170
Interest income................................ 439 480 578 514 519 514
-------- -------- -------- -------- -------- --------
Total Revenues................................. $199,746 $210,293 $217,337 $209,802 $240,393 $242,479
Expenses
Operations and maintenance..................... $ 3,833 $ 6,174 $ 8,149 $ 3,646 $ 8,516 $ 3,601
Water costs and easement fee................... 946 967 988 1,009 1,030 1,052
Insurance...................................... 1,073 1,102 1,132 1,162 1,194 1,226
G&A and Professional fees...................... 786 808 829 852 875 898
Property tax................................... 4,362 4,464 4,564 4,661 4,756 4,846
Management fees................................ 2,451 2,517 2,585 2,655 2,727 2,800
Fuel management fee............................ 544 559 574 590 606 622
Gas Hedge & Peak Service Loss/(Savings)........ (1,155) (1,185) (1,215) (622) (886) (1,099)
Other.......................................... 2,352 2,327 2,322 2,145 2,381 2,248
-------- -------- -------- -------- -------- --------
Non-fuel operating expense..................... $ 15,192 $ 17,733 $ 19,928 $ 16,098 $ 21,198 $ 16,195
Total fuel cost................................ 119,736 123,329 126,024 123,220 133,031 133,406
-------- -------- -------- -------- -------- --------
Total expenses................................. $134,928 $141,062 $145,952 $139,317 $154,228 $149,601
Operating Cash Flow............................. $ 64,818 $ 69,231 $ 71,385 $ 70,485 $ 86,164 $ 92,879
NJEA OPERATING RESULTS
Revenues
JCP&L.......................................... $159,702 $162,480 $166,309 $164,315 $160,776 $175,260
Merchant Sales................................. 10,490 10,739 12,634 12,583 12,351 17,278
Steam.......................................... 2,900 2,939 2,979 3,019 3,060 3,101
Interest income................................ 406 323 382 493 400 284
-------- -------- -------- -------- -------- --------
Total Revenues................................. $173,498 $176,481 $182,303 $180,410 $176,586 $195,922
Expenses
Operations and maintenance..................... $ 4,759 $ 3,385 $ 7,447 $ 8,284 $ 3,658 $ 3,514
Water costs and easement fee................... 1,783 1,815 1,848 1,880 1,914 1,947
Insurance...................................... 905 929 954 980 1,006 1,034
G&A and Professional fees...................... 786 808 829 852 875 898
Property tax................................... 875 876 878 879 881 882
Management fees................................ 2,451 2,517 2,585 2,655 2,727 2,800
Fuel management fee............................ 544 559 574 590 606 622
Gas Hedge & Peak Service Loss/(Savings)........ 0 0 0 0 0 0
Other.......................................... 564 575 585 598 617 588
-------- -------- -------- -------- -------- --------
Non-fuel operating expense..................... $ 12,667 $ 11,464 $ 15,700 $ 16,718 $ 12,282 $ 12,287
Total fuel cost................................ 89,543 92,138 95,166 95,214 94,098 102,989
-------- -------- -------- -------- -------- --------
Total expenses................................. $102,210 $103,603 $110,866 $111,932 $106,380 $115,275
Operating Cash Flow............................. $ 71,288 $ 72,878 $ 71,437 $ 68,478 $ 70,206 $ 80,647
COMBINED OPERATING RESULTS
Total Revenues.................................. $373,244 $386,774 $399,641 $390,212 $416,979 $438,402
Non-fuel operating expenses.................... 27,859 29,197 35,629 32,816 33,480 28,481
Total fuel cost................................ 209,279 215,467 221,189 218,433 227,129 236,395
-------- -------- -------- -------- -------- --------
Operating Cash Flow............................. $136,106 $142,109 $142,823 $138,962 $156,370 $173,526
Change in Working Capital...................... 2,392 2,214 2,071 (1,661) 4,543 3,571
-------- -------- -------- -------- -------- --------
CASH AVAILABLE FOR DEBT SERVICE................. $133,714 $139,895 $140,752 $140,623 $151,827 $169,955
Subordinated Management Fee..................... 1,994 2,048 2,103 2,160 2,219 2,278
PROJECT SECURITIES
Principal...................................... 45,349 52,641 54,021 51,801 54,616 65,223
Interest....................................... 29,880 25,484 20,545 15,504 10,374 4,779
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
THE BONDS
Principal...................................... 8,800 13,200 22,000 22,000 26,400 35,200
Interest....................................... 15,293 14,502 13,271 11,514 9,668 7,383
DEBT SERVICE COVERAGES
Bond debt service coverage..................... 2.43x 2.23x 1.88x 2.19x 2.41x 2.35x
Consolidated coverage.......................... 1.35x 1.32x 1.28x 1.39x 1.50x 1.51x
2011
--------
NEA OPERATING RESULTS
Revenues
Boston Edison I................................ $ 73,286
Boston Edison II............................... 88,537
Commonwealth I................................. 13,423
Commonwealth II................................ 30,972
Montaup........................................ 9,663
Merchant Sales................................. 18,416
Steam.......................................... 1,374
Interest income................................ 404
--------
Total Revenues................................. $236,056
Expenses
Operations and maintenance..................... $ 5,085
Water costs and easement fee................... 1,074
Insurance...................................... 1,260
G&A and Professional fees...................... 924
Property tax................................... 4,943
Management fees................................ 2,879
Fuel management fee............................ 639
Gas Hedge & Peak Service Loss/(Savings)........ (1,325)
Other.......................................... 2,347
--------
Non-fuel operating expense..................... $ 17,826
Total fuel cost................................ 139,564
--------
Total expenses................................. $157,390
Operating Cash Flow............................. $ 78,666
NJEA OPERATING RESULTS
Revenues
JCP&L.......................................... $113,850
Merchant Sales................................. 62,814
Steam.......................................... 1,965
Interest income................................ 284
--------
Total Revenues................................. $178,913
Expenses
Operations and maintenance..................... $ 6,869
Water costs and easement fee................... 1,982
Insurance...................................... 1,062
G&A and Professional fees...................... 924
Property tax................................... 884
Management fees................................ 2,879
Fuel management fee............................ 639
Gas Hedge & Peak Service Loss/(Savings)........ 0
Other.......................................... 605
--------
Non-fuel operating expense..................... $ 15,844
Total fuel cost................................ 106,433
--------
Total expenses................................. $122,277
Operating Cash Flow............................. $ 56,636
COMBINED OPERATING RESULTS
Total Revenues.................................. $414,969
Non-fuel operating expenses.................... 33,670
Total fuel cost................................ 245,997
--------
Operating Cash Flow............................. $135,302
Change in Working Capital...................... (4,698)
--------
CASH AVAILABLE FOR DEBT SERVICE................. $140,000
Subordinated Management Fee..................... 2,342
PROJECT SECURITIES
Principal...................................... 0
Interest....................................... 0
PROJECT SECURITY DEBT SERVICE COVERAGE
Project Security debt service coverage*........
DISTRIBUTIONS TO NE LP.......................... $140,000
THE BONDS
Principal...................................... 66,000
Interest....................................... 3,955
DEBT SERVICE COVERAGES
Bond debt service coverage..................... 2.00x
Consolidated coverage.......................... 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-88
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-89
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-90
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-91
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
--------- --------- --------- --------- --------- --------- ---------
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 2.50
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-92
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-93
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-94
APPENDIX C
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.
- --------------------------------------------------------------------------------
Benjamin Schlesinger and Associates, Inc.
C-1
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TABLE OF CONTENTS
I. INTRODUCTION............................................................................................. 1
II. SUMMARY AND CONCLUSIONS.................................................................................. 2
III. NEA'S AND NJEA'S FUEL SUPPLY AND DELIVERY ARRANGEMENTS................................................... 5
A. Firm Gas Supply Arrangements.......................................................................... 5
1. ProGas.................................................................................. 5
2. PSE&G................................................................................... 8
B. Gas Storage Arrangements.............................................................................. 9
C. Firm Gas Transportation Arrangements.................................................................. 9
1. CNG..................................................................................... 10
2. Transco................................................................................. 10
3. TETCO................................................................................... 10
4. Algonquin (NEA only).................................................................... 10
5. PSE&G (NJEA only)....................................................................... 11
D. Peak Shaving Arrangements............................................................................. 11
1. NEA..................................................................................... 11
2. NJEA.................................................................................... 11
IV. ANALYSIS OF PRO FORMA GAS COSTS TO NEA/NJEA.............................................................. 12
V. ASSESSMENT OF NEA/NJEA'S NON-CONTRACT GAS PROCUREMENT.................................................... 13
VI. ANALYSIS OF POTENTIAL FUEL ISSUES........................................................................ 14
A. ProGas's lay-off gas responsibilities................................................................. 14
B. Continuation of interstate pipeline services beyond contract expiration............................... 15
C. Economic Risk of PSE&G Contract Termination in 2011................................................... 16
LIST OF EXHIBITS
Exhibit 1--NEA: Schematic of Firm Daily Contract Capacities.................................................... 2
Exhibit 2--NJEA: Schematic of Firm Daily Contract Capacities................................................... 2
Exhibit 3--Summary of NEA's and NJEA's Gas Supply and Transportation Portfolio................................. 3
Exhibit 4--NEA and NJEA Gas Supply Sources by Price Category: 10/95-9/97....................................... 4
Exhibit 5--TETCO Receipt/Delivery Points & MDQs................................................................ 10
Exhibit 6--Comparison of Henry Hub Gas Price Forecasts......................................................... 13
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
Appendix D: Summary of Project Indenture
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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 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.
- ------------------
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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EXHIBIT 1--NEA: SCHEMATIC OF FIRM DAILY CONTRACT CAPACITIES
[GRAPHIC OMITTED]
EXHIBIT 2--NJEA: SCHEMATIC OF FIRM DAILY CONTRACT CAPACITIES
[GRAPHIC OMITTED]
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.
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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 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;
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FINAL REPORT
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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. 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
- ------------------
2 Virtually all the projects' spot gas is consumed at NEA, as shown in Exhibit
4.
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FINAL REPORT
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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.
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
- ------------------
3 PSE&G's WACOG has averaged approximately 3.5% less than spot gas market
prices in the region since 1995.
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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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.
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:
- --------------------------------------------------------------------------------
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.
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
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 [{(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.
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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.
- --------------------------------------------------------------------------------
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:
- --------------------------------------------------------------------------------
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.
- --------------------------------------------------------------------------------
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.
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 22degreesF, PSE&G has an option
to interrupt the sales service. However, if the temperature is forecast to be
above 14degreesF, 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 14degreesF and 22degreesF
degrees.
- ------------------
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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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.
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.
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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.
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
NEA VOL. NJEA VOL.
RECEIPT/DELIVERY PTS. (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 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.
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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 22degreesF (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 14degreesF 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 14degreesF, 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 14degreesF 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 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 14degreesF
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 14degreesF 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
- ------------------
8 PSE&G cannot interrupt transportation service in March.
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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.
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.
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)
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-- 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.
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 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 days10 of CNG's winter period,
- ------------------
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.
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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.
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
- ------------------
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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Benjamin Schlesinger and Associates, Inc. Page 14
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FINAL REPORT
- --------------------------------------------------------------------------------
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 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/NJEA14--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
- ------------------
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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Benjamin Schlesinger and Associates, Inc. Page 15
C-17
FINAL REPORT
- --------------------------------------------------------------------------------
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 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 approved tariffs upon
expiration of its current contract
- ------------------
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.
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Benjamin Schlesinger and Associates, Inc. Page 16
C-18
FINAL REPORT
- --------------------------------------------------------------------------------
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 17
C-19
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%
C-20
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.
C-21
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 NEA and ProGas November 1, 2013 Two 5-year terms
Bellingham
- ------------------------------------------------------------------------------------------------------------------
3 Gas Purchase Contract for NJEA and ProGas November 1, 2013 Two 5-year terms
Sayreville
- ------------------------------------------------------------------------------------------------------------------
4 Amending Agreements for Gas NEA/NJEA and ProGas September 3, 2006 Two 5-year terms
Purchase 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 NEA, CNG, ProGas USA November 1, 2011 Shall not terminate until
Agreement and ProGas 7(b) authority received
- ------------------------------------------------------------------------------------------------------------------
2 Firm Transportation Service NJEA, CNG, ProGas USA November 1, 2011 Shall not terminate until
Agreement and ProGas 7(b) authority received
- ------------------------------------------------------------------------------------------------------------------
3 Service Agreement for Schedule NEA and Texas Eastern March 31, 2012 Year-to-Year
FTS-5
- ------------------------------------------------------------------------------------------------------------------
4 Service Agreement for Schedule NJEA and Texas Eastern March 31, 2012 Year-to-Year
FTS-5
- ------------------------------------------------------------------------------------------------------------------
5 Firm Gas Transportation Agreement NEA and Transco October 31, 2006 (15 years Year-to-Year
(Rate Schedule X-320) from agreement)
- ------------------------------------------------------------------------------------------------------------------
6 Firm Gas Transportation Agreement NJEA and Transco October 31, 2006 (15 years Year-to-Year
(Schedule X-319) 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 is single 8-year term
X-35)
- ------------------------------------------------------------------------------------------------------------------
9 Gas Purchase and Sale Agreement NJEA and PSE&G August 12, 2011 None
(NJEA and PSE&G)
- ------------------------------------------------------------------------------------------------------------------
Page B-1
C-22
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
($/MMBTU/MONTH)
- ------------------------------------------
Inflation: 2.8%
Escalation Factor: 1.4%
- ------------------------------------------
- ------------------------------------------------------------
SECTION 7(C) SECTION 7(C) PART 284
CONTRACT RATE PROFORMA RATE ROLLED-IN RATES
YEAR (DECLINING) (INCREASING) (INCREASING)
- ------------------------------------------------------------
1997 4.47 4.47 3.58
1998 4.41 4.53 3.63
1999 4.34 3.50 3.68
2000 4.28 3.55 3.73
2001 4.22 3.60 3.78
2002 4.16 3.65 3.83
2003 4.11 3.70 3.89
2004 4.05 3.75 3.94
2005 3.99 3.80 4.00
2006 3.94 3.86 4.05
2007 3.88 3.91 4.11
2008 3.83 3.97 4.17
2009 3.77 4.02 4.22
2010 3.72 4.08 4.28
2011 3.67 4.14 4.34
% difference from Proforma Rate in
2011: 0.0% 5.0%
% difference from Proforma Rate--Avg.
2007-2011: 0.0% 5.0%
- --------------------------------------------------------------------------------
Note: Excludes GRI and retainage charges.
C-23
APPENDIX C (CONT.)
COMPARISON OF CNG'S PART 284 AND SECTION 7(C) DEMAND CHARGES
($/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-24
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.
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
D-1
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
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
D-2
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.
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
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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 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;
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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 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).
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
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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
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).
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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).
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
D-7
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.
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
D-8
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,
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-9
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 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.
D-10
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
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.
D-11
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.
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
D-12
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
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.
D-13
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
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
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
D-14
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
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
D-15
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%;
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
D-16
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 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
D-17
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;
(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 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
D-18
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
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
D-19
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
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.
D-20
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
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
D-21
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); 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-22
- ------------------------------------------------------
------------------------------------------------------
- ------------------------------------------------------
------------------------------------------------------
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............................ i
Defined Terms.................................... i
Summary.......................................... 1
Summary Historical and Pro Forma Financial
Data........................................... 16
Risk Factors..................................... 19
Use of Proceeds.................................. 29
Unaudited Pro Forma Statements of Operations..... 29
Selected Historical Financial Data............... 36
Management's Discussion and Analysis of Financial
Condition and Results of Operations............ 38
Business......................................... 45
The Projects..................................... 45
Regulation....................................... 55
Summary of Principal Project Agreements.......... 61
Management....................................... 90
Executive Compensation........................... 92
Security Ownership of Certain Beneficial Owners
and Management................................. 92
Certain Transactions............................. 93
The Exchange Offer............................... 94
Description of Securities........................ 102
Outstanding Project Indebtedness................. 126
Certain Federal Tax Considerations............... 131
Plan of Distribution............................. 133
Legal Matters.................................... 134
Experts.......................................... 134
Trustee.......................................... 134
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.
$220,000,000
ESI TRACTEBEL
ACQUISITION CORP.
7.99% SERIES B SECURED BONDS DUE 2011
AS FULLY AND UNCONDITIONALLY
GUARANTEED BY
NORTHEAST ENERGY, LP
------------------------
PROSPECTUS
------------------------
, 1998
------------------------------------------------------
------------------------------------------------------
------------------------------------------------------
------------------------------------------------------
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF OFFICERS AND DIRECTORS.
ESI Tractebel Acquisition's Certificate of Incorporation states that ESI
Tractebel Acquisition shall, to the maximum extent permitted from time to time
under the law of the State of Delaware, indemnify and upon request shall advance
expenses to any person who is or was a party or is threatened to be made a party
to any threatened, pending or completed action, suit, proceeding or claim,
whether civil, criminal, administrative or investigative, by reason of the fact
that such person is or was or has agreed to be a director or officer of ESI
Tractebel Acquisition or while a director or officer is or was serving at the
request of ESI Tractebel Acquisition as a director, officer, partner, trustee,
employee or agent of any corporation, partnership, joint venture, trust or other
enterprise, including service with respect to employee benefit plans, against
expenses (including attorneys' fees and expenses), judgments, fines, penalties
and amounts paid in settlement incurred in connection with the investigation,
preparation to defend or defense of such action, suit, proceeding or claim;
provided, however, that the foregoing shall not require ESI Tractebel
Acquisition to indemnify or advance expenses to any person in connection with
any action, suit, proceeding, claim or counterclaim initiated by or on behalf of
such person. Such indemnification shall not be exclusive of other
indemnification rights arising under any bylaw, agreement, vote of directors or
stockholders or otherwise and shall inure to the benefit of the heirs and legal
representatives of such person. Any person seeking indemnification under this
paragraph shall be deemed to have met the standard of conduct required for such
indemnification unless the contrary shall be established. Any repeal or
modification of the foregoing provisions of this paragraph shall not adversely
effect any right or protection of a director or officer of ESI Tractebel
Acquisition with respect to any acts or omissions of such director or officer
occurring prior to such repeal or modification.
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. Financial Statement Schedules are omitted because they are not
applicable or the required information is included in the financial statements
and notes thereto.
ITEM 22. UNDERTAKINGS
(a) 'The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being
made, a post-effective amendment to this registration statement:
(i) To include any prospectus required by Section 10(a)(3) of the
Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after
the effective date of the registration statement (or the most recent
post-effective amendment thereof) which, individually or in the
aggregate, represent a fundamental change in the information set forth
in the registration statement. Notwithstanding the foregoing, any
increase or decrease in volume of securities offered (if the total
dollar value of securities offered would not exceed that which was
registered) and any deviation from the low or high end of the estimated
maximum offering range may be reflected in the form of prospectus filed
with the Commission pursuant to Rule 424(b) if, in the aggregate, the
changes in volume and price represent no more than 20 percent change in
the maximum aggregate offering price set forth in the 'Calculation of
Registration Fee' table in the effective registration statement.
II-1
(iii) To include any material information with respect to the plan
of distribution not previously disclosed in the registration statement
or any material change to such information in the registration
statement;'
'(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed
to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed
to be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the
termination of the offering.'
(b) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 (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.
(c) 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.
(d) The undersigned registrant hereby undertakes to supply by means of a
post-effective amendment all information concerning a transaction, and the
company being acquired involved therein, that was not the subject of and
included in the registration statement when it became effective.
II-2
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, AS AMENDED, THE
REGISTRANT HAS DULY CAUSED THIS AMENDMENT NO. 2 TO THE 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 AUGUST 4, 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 AMENDMENT
NO. 2 TO THE REGISTRATION STATEMENT ON FORM S-4 HAS BEEN SIGNED BY THE FOLLOWING
PERSONS IN THE CAPACITIES INDICATED ON AUGUST 4, 1998.
SIGNATURE TITLE
- ------------------------------------------ -------------------------------------------
/s/ GLENN E. SMITH Vice President and Director
- ------------------------------------------
Glenn E. Smith
(Principal Executive Officer)
* Treasurer
- ------------------------------------------
Peter D. Boylan
(Principal Financial and
Accounting Officer)
* Director
- ------------------------------------------
Timothy R. Dunne
* Director
- ------------------------------------------
Paul J. Cavicchi
* By: /s/ GLENN E. SMITH
- ------------------------------------------
Glenn E. Smith
Attorney-in-Fact
II-3
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, AS AMENDED, THE
REGISTRANT HAS DULY CAUSED THIS AMENDMENT NO. 2 TO THE 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 AUGUST 4, 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 AMENDMENT
NO. 2 TO THE REGISTRATION STATEMENT ON FORM S-4 HAS BEEN SIGNED BY THE FOLLOWING
PERSONS IN THE CAPACITIES INDICATED ON AUGUST 4, 1998.
SIGNATURE TITLE
- ------------------------------------------ -------------------------------------------
/s/ GLENN E. SMITH Vice President
- ------------------------------------------
Glenn E. Smith
(Principal Executive Officer)
/s/ PETER B. BOYLAN Treasurer
- ------------------------------------------
Peter D. Boylan
(Principal Financial and Accounting
Officer)
II-4
EXHIBIT INDEX
EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION PAGE NO.
- ----------- ------------------------------------------------------------------------------------------ -----------
***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.
**10.7 -- Power Purchase Agreement dated as of April 1, 1986 (the 'BECO I Power Purchase
Agreement'), between Northeast Energy Associates ('NEA') and Boston Edison Company
('BECO').
EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION PAGE NO.
- ----------- ------------------------------------------------------------------------------------------ -----------
**10.7.1 -- First Amendment to the BECO I Power Purchase Agreement dated as of June 8, 1987,
between BECO and NEA.
**10.7.2 -- Second Amendment to the BECO I Power Purchase Agreement dated as of June 21, 1989,
between BECO and NEA.
**10.8 -- Power Purchase Agreement dated as of January 28, 1988 (the 'BECO II Power Purchase
Agreement'), between NEA and BECO.
**10.8.1 -- First Amendment to the BECO II Power Purchase Agreement dated as of June 21, 1989,
between NEA and BECO.
**10.9 -- Power Sale Agreement dated as of November 26 ,1986 (the 'Commonwealth I Power
Purchase Agreement'), between NEA and Commonwealth.
**10.9.1 -- First Amendment to the Commonwealth I Power Purchase Agreement dated as of August
15, 1998, between Commonwealth and NEA.
**10.9.2 -- Second Amendment to the Commonwealth I Power Purchase Agreement dated as of January
1, 1989, between Commonwealth and NEA.
**10.10 -- Power Sale Agreement dated as of August 15, 1998 (the 'Commonwealth II Power
Purchase Agreement'), between NEA and Commonwealth.
**10.10.1 -- First Amendment to the Commonwealth II Power Purchase Agreement dated as of January
1, 1989, between NEA and Commonwealth.
**10.11 -- Power Purchase Agreement dated as of October 17, 1986 (the 'Montaup Power Purchase
Agreement'), between NEA and Montaup.
**10.11.1 -- First Amendment to the Montaup Power Purchase Agreement dated as of June 28, 1989,
between Montaup and NEA.
**10.12 -- Power Purchase Agreement dated as of October 22, 1987 (the 'JCP&L Power Purchase
Agreement'), between NJEA and Jersey Central Power & Light Company, a New Jersey
corporation ('JCP&L').
**10.12.1 -- First Amendment to the JCP&L Power Purchase Agreement dated as of June 16, 1989,
between JCP&L and NEA.
**10.13 -- Gas Purchase and Sales Agreement dated as of May 4, 1989 between NJEA and Public
Service Electric and Gas Company, a New Jersey corporation.
**10.14 -- Gas Purchase Contract dated as of May 12, 1988 (the 'Bellingham ProGas Agreement'),
between ProGas and NEA.
**10.14.1 -- First Amending Agreement to the Bellingham ProGas Agreement dated as of April 17,
1989, between ProGas and NEA.
**10.14.2 -- Second Amending Agreement to the Bellingham ProGas Agreement dated as of June 23,
1989, between ProGas and NEA.
**10.14.3 -- Amending Agreement to the ProGas Agreements (as defined below) dated as of November
1, 1991, between ProGas, NEA and NJEA.
**10.14.4 -- Third Amending Agreement to the Bellingham ProGas Agreement dated as of July 30,
1993, between ProGas and NEA.
**10.14.5 -- Letter Agreement regarding the Bellingham ProGas Agreement dated as of September 14,
1992, between ProGas and NEA.
**10.14.6 -- Letter Agreement regarding the Bellingham ProGas Agreement dated as of July 30,
1993, between ProGas and NEA.
**10.14.7 -- Gas Purchase Contract dated as of May 12, 1988 (the 'Sayreville ProGas Agreement,'
and together with the Bellingham ProGas Agreement, the 'ProGas Agreements'), between
ProGas and NJEA.
**10.14.8 -- First Amending Agreement to the Sayreville ProGas Agreement dated as of April 17,
1989, between ProGas and NJEA.
**10.14.9 -- Second Amending Agreement to the Sayreville ProGas Agreement dated June 23, 1989,
between ProGas and NJEA.
EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION PAGE NO.
- ----------- ------------------------------------------------------------------------------------------ -----------
**10.14.10 -- Third Amending Agreement to the Sayreville ProGas Agreement dated July 30, 1993,
between ProGas and NJEA.
**10.14.11 -- Letter Agreement regarding the Sayreville ProGas Agreement dated as of September 14,
1992, between ProGas and NJEA, as amended as of April 22, 1994 by Letter Agreement
between ProGas and NJEA.
**10.14.12 -- Letter Agreement regarding the Sayreville ProGas Agreement dated as of July 30,
1993, between ProGas and NEA.
**10.15 -- Amended and Restated Steam Sales Agreement dated as of December 21, 1990, between
NEA and NECO-Bellingham, Inc., a Massachusetts corporation ('NECO').
**10.16 -- Industrial Steam Sales Contract dated as of June 5, 1989, between NJEA and Hercules
Incorporated, a Delaware corporation.
**10.17 -- Carbon Dioxide Agreement, dated as of December 21, 1990, between NECO and Praxair,
Inc., as successor to Liquid Carbonic Carbon Dioxide Corporation.
**10.18 -- BOC Gases Carbon Dioxide Agreement dated as of December 21, 1990 between NECO and
BOC Gases of the BOC Group, Inc., a Delaware corporation.
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 PricewaterhouseCoopers LLP
***23.3 -- Consent of Sargent & Lundy LLC
***23.4 -- Consent of Benjamin Schlesinger and Associates, Inc.
23.5 -- Consent of Deloitte & Touche LLP
***24.1 -- Power of Attorney (contained on signature page)
***25 -- Statement of Eligibility on Form T-1 of the Trustee.
***27.1 -- Financial Data Schedule--ESI Tractebel Acquisition Corp.
***27.2 -- Financial Data Schedule--Northeast Energy, LP
***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.
** Incorporated herein by reference from the Registration Statement on Form
S-4, file no. 33-87902 filed with the Securities and Exchange Commission by
IEC Funding Corp. on February 9, 1995, as amended.
*** Previously filed.