-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, EvffLGmqdVSi9CIyV7acN5oC8ghZaj7TcZSrefr58+NTPz8ggrAtXq8dh4KXrSsc tRJm2mq2FUadO+oILS2SCw== 0001024739-98-000796.txt : 19980812 0001024739-98-000796.hdr.sgml : 19980812 ACCESSION NUMBER: 0001024739-98-000796 CONFORMED SUBMISSION TYPE: S-4/A PUBLIC DOCUMENT COUNT: 4 FILED AS OF DATE: 19980811 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: ESI TRACTEBEL ACQUISITION CORP CENTRAL INDEX KEY: 0001059027 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 650811248 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: S-4/A SEC ACT: SEC FILE NUMBER: 333-52397 FILM NUMBER: 98681804 BUSINESS ADDRESS: STREET 1: 11760 US HIGHWAY ONE STREET 2: SUITE 600 CITY: NORTH PALM BEACH STATE: FL ZIP: 33408 BUSINESS PHONE: 5616913500 MAIL ADDRESS: STREET 1: 11760 US HIGHWAY ONE STREET 2: SUITE 600 CITY: PALM BEACH STATE: FL ZIP: 33408 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHEAST ENERGY LP CENTRAL INDEX KEY: 0001059025 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 650811248 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: S-4/A SEC ACT: SEC FILE NUMBER: 333-52397-01 FILM NUMBER: 98681805 BUSINESS ADDRESS: STREET 1: 11760 US HIGHWAY ONE STREET 2: SUITE 600 CITY: NORTH PALM BEACH STATE: FL ZIP: 33408 BUSINESS PHONE: 5616913500 MAIL ADDRESS: STREET 1: 11760 US HIGHWAY ONE STREET 2: SUITE 600 CITY: PALM BEACH STATE: FL ZIP: 33408 S-4/A 1 AMENDMENT NO. 3 TO FORM S-4 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON AUGUST 11, 1998 REGISTRATION NO. 333-52397 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------ AMENDMENT NO. 3 TO FORM S-4 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 ------------------------ 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)
------------------------ 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) ------------------------ 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 ------------------------ 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. / / ------------------------ 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. ================================================================================ SUBJECT TO COMPLETION, DATED AUGUST 11, 1998 PROSPECTUS OFFER TO EXCHANGE 7.99% SERIES B SECURED BONDS DUE 2011 FOR ALL OUTSTANDING 7.99% SERIES A SECURED BONDS DUE 2011 OF ESI TRACTEBEL ACQUISITION CORP. ------------------------ Payment of principal and interest 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. ------------------------ SEE 'RISK FACTORS' ON PAGE 19 FOR A DESCRIPTION OF CERTAIN RISKS THAT SHOULD BE CONSIDERED BY PURCHASERS OF THE NEW SECURITIES. ------------------------ THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. The date of this Prospectus is , 1998 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 2 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. 3 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 state regulatory 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. The Company originally estimated the Administrative Services Fees to be $171,000 for the first quarter of 1998. The historical amount is being adjusted to reflect the actual amount of $150,000 stipulated in the final Administrative Services Agreement. (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. 61 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 62 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 63 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. 64 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. 65 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. 66 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 67 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. 68 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. 69 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 70 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. 71 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. 72 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. 73 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 74 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 75 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 77 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 80 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 82 275 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. 83 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 84 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 85 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. 86 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, 87 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. 88 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
90 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.' 91 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. 92 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. 93 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. 101 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. 104 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 106 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; 107 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. 108 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 109 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 110 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 111 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. 112 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 113 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. 114 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 115 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; 116 (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 117 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. 118 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 119 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 120 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. 121 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. 122 '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. 124 '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. 125 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. 126 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. 130 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. 134 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, 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; A-2 (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 A-3 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 A-4 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. A-5 '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. A-7 '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. A-8 '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. A-9 '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. A-10 '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). A-11 '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. A-12 '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. A-13 '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. A-14 '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 A-15 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. A-16 '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. A-17 '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 i SL-5171 - -------------------------------------------------------------------------------- BELLINGHAM AND SAYREVILLE COGENERATION FACILITIES DUE DILIGENCE REVIEW CONTENTS
SECTION PAGE - ---------------------------------------------------------------------------------------------------------- ---- ES EXECUTIVE SUMMARY...................................................................................... ES-1 Technical Review of the Cogeneration Facilities...................................................... ES-2 Technical Review of the Bellingham Carbon Dioxide Plant.............................................. ES-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
- -------------------------------------------------------------------------------- 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.............................................................................................. 2-13 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................................................................................. 6-7 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 iii SL-5171 - -------------------------------------------------------------------------------- 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........................................................ 7-4 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 - -------------------------------------------------------------------------------- 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 SL-5171 - -------------------------------------------------------------------------------- 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 ES-3 SL-5171 - -------------------------------------------------------------------------------- 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 ES-4 SL-5171 - -------------------------------------------------------------------------------- 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. B-8 ES-5 SL-5171 - -------------------------------------------------------------------------------- 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
- -------------------------------------------------------------------------------- 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-9 1-1 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-10 1-2 SL-5171 - -------------------------------------------------------------------------------- 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. B-11 1-3 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-12 1-4 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-13 1-5 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-14 2-1 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-15 2-2 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-16 2-3 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-17 2-4 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-18 2-5 SL-5171 - -------------------------------------------------------------------------------- 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 2-6 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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 2-7 SL-5171 - -------------------------------------------------------------------------------- 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 2-8 SL-5171 - -------------------------------------------------------------------------------- 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 2-9 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-23 2-10 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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 2-11 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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 2-12 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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 2-13 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-27 2-14 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-28 3-1 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-29 3-2 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- This document contains information that is confidential and proprietary to Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or released to any third party without the prior written consent of S&L. Copyright Sargent & Lundy 1998; all rights reserved. B-30 3-3 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- This document contains information that is confidential and proprietary to Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or released to any third party without the prior written consent of S&L. Copyright Sargent & Lundy 1998; all rights reserved. B-31 4-1 SL-5171 - -------------------------------------------------------------------------------- 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
- -------------------------------------------------------------------------------- This document contains information that is confidential and proprietary to Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or released to any third party without the prior written consent of S&L. Copyright Sargent & Lundy 1998; all rights reserved. B-32 4-2 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- This document contains information that is confidential and proprietary to Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or released to any third party without the prior written consent of S&L. Copyright Sargent & Lundy 1998; all rights reserved. B-33 4-3 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- This document contains information that is confidential and proprietary to Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or released to any third party without the prior written consent of S&L. Copyright Sargent & Lundy 1998; all rights reserved. B-34 4-4 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- This document contains information that is confidential and proprietary to Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or released to any third party without the prior written consent of S&L. Copyright Sargent & Lundy 1998; all rights reserved. B-35 4-5 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- This document contains information that is confidential and proprietary to Sargent & Lundy (S&L). It shall not be reproduced in whole or in part or released to any third party without the prior written consent of S&L. Copyright Sargent & Lundy 1998; all rights reserved. B-36 5-1 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-37 5-2 SL-5171 - -------------------------------------------------------------------------------- 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)
- -------------------------------------------------------------------------------- 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-38 5-3 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-39 5-4 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-40 5-5 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-41 6-1 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-42 6-2 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-43 6-3 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-44 6-4 SL-5171 - -------------------------------------------------------------------------------- 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.' - -------------------------------------------------------------------------------- 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-45 6-5 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-46 6-6 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-47 6-7 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-48 6-8 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-49 7-1 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-50 7-2 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-51 7-3 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-52 7-4 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-53 7-5 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-54 7-6 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-55 7-7 SL-5171 - -------------------------------------------------------------------------------- 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; - -------------------------------------------------------------------------------- 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-56 7-8 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-57 7-9 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-58 7-10 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-59 7-11 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-60 7-12 SL-5171 - -------------------------------------------------------------------------------- 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.' - -------------------------------------------------------------------------------- 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-61 7-13 SL-5171 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- 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-62 7-14 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-63 7-15 SL-5171 - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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-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 FINAL REPORT - -------------------------------------------------------------------------------- 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
- -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page ii C-2 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 1 C-3 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 2 C-4 FINAL REPORT - -------------------------------------------------------------------------------- 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; - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 3 C-5 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 4 C-6 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 5 C-7 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 6 C-8 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 7 C-9 FINAL REPORT - -------------------------------------------------------------------------------- 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). - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 8 C-10 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 9 C-11 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 10 C-12 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 11 C-13 FINAL REPORT - -------------------------------------------------------------------------------- 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) - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 12 C-14 FINAL REPORT - -------------------------------------------------------------------------------- -- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 13 C-15 FINAL REPORT - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- Benjamin Schlesinger and Associates, Inc. Page 14 C-16 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. - -------------------------------------------------------------------------------- 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. - -------------------------------------------------------------------------------- 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 D-3 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; D-4 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 D-5 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). D-6 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. 3 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 10, 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. 3 TO THE REGISTRATION STATEMENT ON FORM S-4 HAS BEEN SIGNED BY THE FOLLOWING PERSONS IN THE CAPACITIES INDICATED ON AUGUST 10, 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. 3 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 10, 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. 3 TO THE REGISTRATION STATEMENT ON FORM S-4 HAS BEEN SIGNED BY THE FOLLOWING PERSONS IN THE CAPACITIES INDICATED ON AUGUST 10, 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. EX-5.1 2 OPINION OF ORRICK, HERRINGTON & SUTCLIFFE LLP EXHIBIT 5.1 [Orrick, Herrington & Sutcliffe LLP Letterhead] August 4, 1998 ESI Tractebel Acquisition Corp. Northeast Energy, LP 11760 US Highway One Suite 600 North Palm Beach, Florida 33408 Re: ESI Tractebel Acquisition Corp. Northeast Energy, LP Exchange Offer Registration Statement on Form S-4 Ladies and Gentlemen: We have acted as counsel for ESI Tractebel Acquisition Corp., a Delaware corporation (the "Company") and Northeast Energy, LP, a Delaware limited partnership (the "Guarantor") in connection with the filing by the Company and the Guarantor with the Securities and Exchange Commission (the "Commission") pursuant to the Securities Act of 1933, as amended, of a Registration Statement on Form S-4 (File No. 333-52397) and amendments thereto (as so amended, the "Registration Statement"), relating to the Company's proposed offer (the "Exchange Offer") to exchange its 7.99% Series B Secured Bonds Due 2011 (the "New Securities") which are being registered pursuant to the Registration Statement and which are to be fully and unconditionally guaranteed (the "Guaranty") as to the payment of principal and interest by the Guarantor, for an equal principal amount of the Company's outstanding 7.99% Series A Secured Bonds Due 2011 (the "Old Securities"), pursuant to a Prospectus (the "Prospectus") contained in the Registration Statement. We have examined instruments, documents, and records which we deemed relevant and necessary for the basis of our opinion hereinafter expressed. In such examination, we have assumed the following: (a) the authenticity of original documents and the genuineness of all signatures; (b) the conformity to the originals of all documents submitted to us as copies; and (c) the truth, accuracy, and completeness of the information, representations, and warranties contained in the records, documents, instruments, and certificates we have reviewed. Based on such examination, we are of the opinion as follows: 1. The Company is a corporation validly existing and in good standing under the laws of the State of Delaware. 2. The Guarantor is a limited partnership duly formed, validly existing and in good standing under the laws of the State of Delaware. 3. The Guarantor has the limited partnership power and authority to execute and deliver the Guaranty and has duly executed and delivered the Guaranty. 4. The New Securities, when duly authenticated in accordance with the provisions of the Indenture, and when issued and delivered in exchange for Old Securities pursuant to the Exchange Offer as described in the Registration Statement, will constitute legal, valid and binding obligations of the Company entitled to the benefits of the Indenture. 5. When the New Securities are duly authenticated in accordance with the provisions of the Indenture and issued and delivered in exchange for Old Securities pursuant to the Exchange Offer as described in the Registration Statement, the Guaranty with respect thereto will constitute a legal, valid and binding obligation of the Guarantor enforceable in accordance with its terms. Our opinion that any document is valid, binding or enforceable in accordance with its terms is qualified as to: (a) limitations imposed by bankruptcy, insolvency, reorganization, arrangement, fraudulent conveyance, moratorium, or other laws relating to or affecting the rights of creditors generally; (b) general principles of equity, including without limitation, concepts of materiality, reasonableness, good faith and fair dealing, and the possible unavailability of specific performance or injunctive relief, regardless of whether such enforceability is considered in a proceeding in equity or at law; and (c) rights to indemnification and contribution which may be limited by applicable law or equitable principles. We hereby consent to the filing of this opinion as an exhibit to the Registration Statement on Form S-4 and to the use of our name wherever it appears in said Registration Statement. In giving such consent, we do not consider that we are "experts" within the meaning of such term as used in the Securities Act of 1933, as amended, or the rules and regulations of the Securities and Exchange Commission issued thereunder with respect to any part of the Registration Statement, including this opinion, as an exhibit or otherwise. Very truly yours, /s/ ORRICK, HERRINGTON & SUTCLIFFE LLP ORRICK, HERRINGTON & SUTCLIFFE LLP EX-23.2 3 CONSENT OF INDEPENDENT ACCOUNTANTS EXHIBIT 23.2 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the use in the Prospectus constituting part of this Registration Statement on Form S-4 of ESI Tractebel Acquisition Corp. of our report dated March 24, 1998 relating to the combined financial statements of Northeast Energy Associates, A Limited Partnership, and North Jersey Energy Associates, A Limited Partnership, which appear in such Prospectus. We also consent to the references to us under the headings "Experts" and "Selected Historical Financial Data" in such Prospectus. However, it should be noted that PricewaterhouseCoopers LLP has not prepared or certified such "Selected Historical Financial Data." PricewaterhouseCoopers LLP Boston, Massachusetts August 10, 1998 EX-23.5 4 INDEPENDENT AUDITORS' CONSENT EXHIBIT 23.5 INDEPENDENT AUDITORS' CONSENT We consent to the use in this Registration Statement of ESI Tractebel Acquisition Corp. and Northeast Energy, LP on Amendment No. 3 to Form S-4 of our reports on ESI Tractebel Acquisition Corp., Northeast Energy, LP, ESI Northeast Energy GP, Inc., and Tractebel Northeast Generation GP, Inc., dated July 13, 1998, appearing in the Prospectus, which is part of this Registration Statement. We also consent to the reference to us under the heading 'Experts' in such Prospectus. DELOITTE & TOUCHE LLP West Palm Beach, Florida August 10, 1998 -----END PRIVACY-ENHANCED MESSAGE-----