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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from_______________to_______________
Commission File Number: 33-87902
33-87902-01
33-87902-02
ESI Tractebel Funding Corp.
North Jersey Energy Associates, A Limited Partnership
Northeast Energy Associates, A Limited Partnership
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(Exact Name of Registrant as Specified in its Charter)
Delaware 04-3255377
New Jersey 04-2955646
Massachusetts 04-2955642
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(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization Identification No.)
c/o FPL Energy, Inc.
700 Universe Blvd.
Juno Beach, Florida 33408
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(Address of Principal Executive Offices) (Zip Code)
(561) 691-7171
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(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
8.43% Senior Secured Notes due 2000, Series A
9.16% Senior Secured Notes due 2002, Series A
9.32% Senior Secured Bonds due 2007, Series A
9.77% Senior Secured Bonds due 2010, Series A
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.[X]
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ESI TRACTEBEL FUNDING CORP.
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1997
INDEX
PART I Page Number
Items 1, 2 and 3. Business, Properties and Legal Proceedings............. 2
Item 4. Submission of Matters to Vote of Security Holders...... 60
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters..................................... 60
Item 6. Selected Financial Data................................. 60
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 62
Item 8 Financial Statements and Supplementary Data............. 67
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure..................... 68
PART III
Item 10. Directors and Executive Officers of the Registrants..... 68
Item 11. Executive Compensation.................................. 71
Item 12. Security Ownership of Certain Beneficial Owners and
Management.............................................. 72
Item 13 Certain Relationships and Related Transactions.......... 73
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K..................................... 74
Signatures.............................................. 85
Defined Terms........................................... A-1
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This Annual Report on Form 10-K is filed in respect of three Registrants:
ESI Tractebel Funding Corp. ("ESI Tractebel Funding"), Northeast Energy
Associates, A Limited Partnership ("NEA") and North Jersey Energy Associates, A
Limited Partnership ("NJEA"). NEA and NJEA are from time to time referred to
herein as the "Partnerships." Other capitalized terms used herein shall have the
meaning provided in Appendix A unless the context requires otherwise.
SAFE HARBOR STATEMENT UNDER THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 (Reform Act), ESI Tractebel Funding and the
Partnerships are hereby filing cautionary statements identifying important
factors that could cause the Partnerships' actual results to differ materially
from those projected in forward-looking statements (as such term is defined in
the Reform Act) of the Partnerships made by or on behalf of the Partnerships
which are made in this Form 10-K, in presentations, in response to questions or
otherwise. Any statements that express, or involve discussions as to,
expectations, beliefs, plans, objectives, assumptions or future events or
performance (often, but not always, through the use of words or phrases such as
will likely result, are expected to, will continue, is anticipated, estimated,
projection, outlook) are not statements of historical facts and may be
forward-looking. Forward-looking statements involve estimates, assumptions, and
uncertainties that could cause actual results to differ materially from those
expressed in the forward-looking statements. Accordingly, any such statements
are qualified in their entirety by reference to, and are accompanied by, the
following important factors that could cause the Partnerships' actual results to
differ materially from those contained in forward-looking statements of the
Partnerships made by or on behalf of the Partnerships.
Any forward-looking statement speaks only as of the date on which such
statement is made, and the Partnerships undertake no obligation to update any
forward-looking statement or statements to reflect events or circumstances after
the date on which such statement is made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time and it is not
possible for management to predict all of such factors, nor can it assess the
impact of each such factor on the business or the extent to which any factor, or
combination of factors, may cause actual results to differ materially from those
contained in any forward-looking statements.
Some important factors that could cause actual results or outcomes to
differ materially from those discussed in the forward-looking statements include
prevailing governmental policies and regulatory actions, with respect to allowed
rates of return, industry and rate structure, acquisition and disposal of assets
and facilities, operation and construction of plant facilities, and present or
prospective competition.
The business and profitability of the Partnerships are also influenced by
economic and geographic factors including political and economic risks, changes
in and compliance with environmental and safety laws and policies, weather
conditions, population growth rates and demographic patterns, competition for
retail and wholesale customers, pricing and transportation of commodities,
market demand for energy from plants or facilities, changes in tax rates or
policies or in rates of inflation, unanticipated development project delays or
changes in project costs, unanticipated changes in operating expenses and
capital expenditures, capital market conditions, competition for new energy
development opportunities, and legal and administrative proceedings (whether
civil, such as environmental, or criminal) and settlements.
All such factors are difficult to predict, contain uncertainties which may
materially affect actual results, and are beyond the control of the
Partnerships.
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PART I
ITEMS 1, 2 AND 3. BUSINESS, PROPERTIES AND LEGAL PROCEEDINGS
Business
The Partnerships and the Partners
Northeast Energy, LP ("NE LP"), a limited partnership jointly owned by
subsidiaries of ESI Energy, Inc. ("ESI Energy") and Tractebel Power, Inc.
("Tractebel Power"), owns a one percent (1%) general partner interest and a
ninety-eight percent (98%) limited partner interest in each of NEA and NJEA.
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").
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.
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").
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FPL Group Capital, a wholly-owned subsidiary of FPL Group, holds the
capital stock of FPL Energy and provides most of the funding for the operating
subsidiaries of FPL Group other than FPL. The business activities of these
companies primarily consist of investments in non-utility energy projects and
agricultural operations.
Tractebel Power is a direct, wholly-owned subsidiary of Tractebel Inc.
("Tractebel"), which in turn is a direct, wholly-owned subsidiary of Tractebel,
S.A. ("Tractebel Belgium"), a global energy and environmental services business
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.
ESI Tractebel Funding Corp.
ESI Tractebel Funding is a Delaware corporation formerly known as IEC
Funding Corp. that was established in 1994 solely for the purpose of issuing
debt securities in connection with the financing of the Partnerships. It is a
pass-through entity and does not have any operations. ESI Tractebel Funding
issued the Project Securities, the proceeds of which were originally used by ESI
Tractebel Funding to acquire certain outstanding bank debt of the Partnerships
and to lend additional funds to the Partnerships. The Project Securities are
guaranteed by the Partnerships. The terms of the Partnerships' obligations to
ESI Tractebel Funding (the "Loans") are identical to the terms of the Project
Securities. The Loans and the related collateral rights are the only assets of
ESI Tractebel Funding.
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 are scheduled to expire in September 2016 and the sixth is scheduled
to expire in September 2021.
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The Projects were developed and are operated as Qualifying Facilities
("QFs") under the Public Utility Regulatory Policies Act of 1978 and the
regulations promulgated thereunder ("PURPA") by the Federal Energy Regulatory
Commission ("FERC"). The Projects must satisfy certain annual operating and
efficiency standards, as well as ownership requirements, to maintain QF status,
which exempts the Projects from certain federal and state regulations. To date,
both Projects have satisfied these standards, and NE LP expects that they will
continue to do so.
Steam generated by the NEA Project is sold to NECO-Bellingham, Inc.
("NECO"), a special-purpose subsidiary of a privately held company based in
Texas, for use by a carbon dioxide plant located adjacent to the NEA Project
(the "Carbon Dioxide Plant"). The Carbon Dioxide Plant is owned by NEA and
leased to NECO. The steam generated by the NJEA Project is sold to Hercules,
Incorporated ("Hercules") for use by Hercules' Parlin, New Jersey plant.
Approximately 80% of the natural gas that fuels the Projects is supplied to
the Projects pursuant to long-term gas supply agreements with ProGas Limited of
Alberta, Canada ("ProGas") and, in the case of the NJEA Project, also 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.
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 affecting the Projects, see
"-Regulation" and "SUMMARY OF PRINCIPAL PROJECT AGREEMENTS."
4
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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. 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 (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. 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 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
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 and (iv) upon the substitution of
Substitute Letters of Credit, 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 Reserve Fund.
The 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
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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.
Cogeneration
Cogeneration is a power production technology that provides for the
sequential generation of two or more useful forms of energy from a single
primary fuel source. The Projects use natural gas to produce electricity and
useful thermal energy in the form of steam. Cogeneration has an inherent
economic advantage over the conventional production of electricity alone because
cogeneration facilities more efficiently convert the energy contained in the
input fuel source to a useful energy output.
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.
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Purchaser's
Nominal Expiration
Entitlement Of Contract
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NEA Project:
Boston Edison I Power
Purchase Agreement........ 135MW 46% September 15, 2016
Boston Edison II
Power Purchase Agreement.. 84 39 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
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 NEA Project, by
the NEA Second Mortgage. A positive balance in an Energy Bank represents a
liability of the applicable Partnership to the applicable Power Purchaser that
will be reduced by subsequent sales of electric power to such Power Purchaser to
the extent that, in later periods, PPA Avoided Costs are above the contract
rate. Under certain circumstances (in particular, following an early termination
of a Power Purchase Agreement resulting (i) in the case of the Boston Edison I
Power Purchase Agreement, from an Event of Default by NEA (which includes the
failure to deliver a minimum quantity of electricity equal to approximately 50%
of historical levels for two consecutive years) and (ii) in the case of the
Montaup Power Purchase Agreement, from NEA's insolvency or bankruptcy or NEA's
failure to generate electricity at an annual capacity factor of 60% or higher
for two successive years) such liability, if any, must be repaid in cash. The
Energy Bank balances under the JCP&L Power Purchase Agreement and the Boston
Edison II Power Purchase Agreement have been reduced to zero and, consequently,
the Energy Bank provisions set forth in such Power Purchase Agreements have
terminated. As of December 31, 1997, the Energy Bank liability under the Montaup
Power Purchase Agreement was approximately $27,055,000. The Energy Bank Balance
under the Boston Edison I Power Purchase Agreement was approximately
$144,526,000 as of December 31, 1997 and is projected to decrease to zero by
2007. 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.
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
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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, 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.
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.
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.
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. 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."
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Although it is expected that the Projects will use natural gas almost
exclusively, the NEA Project's air quality permit allows the NEA Project to burn
Number 2 fuel oil for up to 1,440 turbine generating hours per year (equivalent
to approximately 60 days per year, assuming one turbine is burning oil and
operating at base load) in the event of certain curtailments in the gas supplies
for the NEA Project, and the NEA Project has a 2.3 million gallon fuel tank for
storage of approximately a nine-day supply (assuming only one turbine is burning
oil) of Number 2 fuel oil as a back-up fuel. There is no fixed-price fuel
purchase agreement for the purchase or delivery of Number 2 fuel oil. To date,
the NEA Project has not been operated using Number 2 fuel oil (except for
testing purposes). Use of Number 2 fuel oil would result in the suspension of
NEA's sales of steam to NECO. See "SUMMARY OF PRINCIPAL PROJECT AGREEMENTS--
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 1997, expressed as a percentage of the total gas requirement for each
Project and for the combined total gas requirement for both Projects.
Natural Gas Consumption for the Projects
For the year ended December 31, 1997
Sources of
Gas Consumed
by the NEA NJEA Total Contract
Projects (Bef) (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 Supply 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
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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 1997 was $3.52 per 1,000 pounds. NE LP expects to renew the
NECO Lease and the NEA Steam Sales Agreement with NECO following its scheduled
expiration in 2007. In the event that such renewal is not obtained, NE LP
expects that NEA, as owner of the Carbon Dioxide Plant, will be successful in
replacing NECO with another steam purchaser.
NECO's ability to pay for steam depends upon its successful operation of
the Carbon Dioxide Plant and the performance by NECO's two carbon dioxide
customers described below. The NEA Steam Sales Agreement permits NECO to defer
payment for all or a portion of the steam it takes if, after deferring its
payments under the NECO Lease, NECO's monthly expenses still exceed its monthly
revenues. In addition, NEA has agreed with NECO's two carbon dioxide customers
that if NECO fails to satisfy its obligations under the Carbon Dioxide Sales
Agreements described below, NEA will, within 45 days after receipt of notice
from such customer, terminate the NECO Lease, also terminating the NEA Steam
Sales Agreement, and will replace NECO as lessee. For more detailed summaries of
the NEA Steam Sales Agreement and the NECO Lease, See "SUMMARY OF PRINCIPAL
PROJECT AGREEMENTS -- Steam Sales Agreements -- NEA."
In addition to steam, the NEA Project provides exhaust gas from the
combustion turbines to the Carbon Dioxide Plant for use as a feedstock. Only the
exhaust from burning natural gas (and not Number 2 fuel oil) can be used for
carbon dioxide production. The Carbon Dioxide Plant can be run at full
operational output provided that at least one combustion turbine is run on gas
only. Under the Long-term Gas Arrangements, it is expected that there will be
sufficient natural gas to run at least one turbine year-round in this manner.
NEA will be obligated to pay liquidated damages to NECO if the NEA Project fails
to provide exhaust gas from at least one turbine running only on natural gas for
at least approximately 80% of the available hours per year. 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."
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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 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."
Seasonal Factors
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 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.
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Competition
Recent regulatory change has created additional competition in the form of
wholesale "power marketers" that engage in purchase and resale transactions
between power producers and power distributors. The resultant increased
competition has reduced the price utilities are willing to pay to independent
power producers for electrical capacity and energy. Although the output of the
Projects is substantially all committed under the Power Purchase Agreements,
these factors may adversely affect the price payable under certain Power
Purchase Agreements tied to actual Avoided Cost of the purchasing utility, as
well as the price, if any, NJEA could obtain for merchant sales of power output
in excess of the output under contract to JCP&L. (250 MW of a theoretical yearly
average potential output of 290 MW is under contract.)
Employees
None of the Partnerships, ESI Tractebel Funding or the Partners have any
employees. Pursuant to the Administrative Services Agreement, ESI Northeast
Energy GP, Inc. ("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 RELATIONSHIPS AND RELATED TRANSACTIONS."
Legal Proceedings
Neither Partnership nor ESI Tractebel Funding is involved in any material
legal proceedings.
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 Residences
properties(3)........ Residences 27,000
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.
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The NEA Site, the NEA Project, the Carbon Dioxide Plant and all other
related improvements and fixtures on the NEA Site owned by NEA are subject to
the NEA Project Mortgage. The NEA Site and the NEA Project are also subject to
the NEA Second Mortgage. The NJEA Site, the NJEA Project and all other related
improvements and fixtures on the NJEA Site owned by NJEA are subject to the NJEA
Project Mortgage. The residential properties referred to in the chart above are
subject to the NEA Additional Properties Mortgage.
Regulation
Energy Regulation
PURPA
PURPA provides an electric generating project with rate and regulatory
incentives if the project is a QF. Under PURPA, a cogeneration facility is a QF
if (i) the facility sequentially produces both electricity and a useful thermal
energy output during any calendar year which constitutes at least 5% of its
total energy output and which is used for industrial, commercial, heating or
cooling purposes, (ii) during any calendar year the sum of the useful power
output of the facility plus one-half of its useful thermal energy output equals
or exceeds 42.5% of the total energy input of natural gas and oil, or, in the
event that the facility's useful thermal energy output is less than 15% of the
facility's total energy output, such sum equals or exceeds 45% of such total
energy input and (iii) the facility is not more than 50% owned, directly or
indirectly, by an electric utility, electric utility holding company or any
combination of the above.
Under PURPA, QFs receive two primary benefits. First, PURPA exempts QFs
from the Public Utility Holding Company Act of 1935 ("PUHCA"), most provisions
of the Federal Power Act (the "FPA") and certain state laws relating to
financial, organization and rate regulation. Second, FERC's regulations
promulgated under PURPA require (i) that electric utilities purchase electricity
generated by QFs, construction of which commenced on or after November 9, 1978,
at a price based on the purchasing utility's full Avoided Costs, and (ii) that
the utilities sell supplementary, back-up, maintenance and interruptible power
to QFs on a just and reasonable and nondiscriminatory basis. PURPA defines
"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.
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NE LP expects the Projects to continue to meet all of the criteria required
for certification as QFs under PURPA. If either Project were to fail to meet
such criteria, the related Partnership and, by virtue of the Partnerships'
common Partners, the other Partnership may become subject to regulation as a
public utility company or its equivalent under PUHCA, the FPA and state utility
laws. Certain of the Power Purchase Agreements require that the applicable
Partnership use its best efforts to maintain QF status, and others may be
terminated or be subject to price renegotiation if QF status is lost. In
addition, each of the O&M Agreements may be suspended by the Operator if the
applicable Project is operated in a manner likely to result in the loss of QF
status, and if such potential loss is certified by an independent engineer. See
"SUMMARY OF PRINCIPAL PROJECT AGREEMENTS -- Operations and Maintenance
Agreements."
PUHCA
PUHCA provides that any corporation, partnership or other entity or
organized group that owns, controls or holds power to vote 10% or more of the
outstanding voting securities of a "public utility company" or a company that is
a "holding company" of a "public utility company" is subject to registration
with the SEC and to regulation under PUHCA, unless exempted by Commission rule,
regulation or order. An entity may also be deemed to be a holding company if the
Commission determines, after providing notice and an opportunity for hearing
that such entity exercises a controlling influence over the management or
policies of any public utility or holding company as to make it necessary or
appropriate in the public interest or for the protection of investors or
consumers that such entity be regulated as a holding company. Unless an
exemption is obtained, PUHCA requires registration for a holding company of a
public utility company, and requires a public utility holding company to limit
its utility operations to a single integrated utility system and to divest any
other operations not functionally related to the operation of the utility
system. In addition, a public utility company that is a subsidiary of a
registered holding company under PUHCA is subject to financial and
organizational regulation, including approval by the Commission of its financing
transactions.
The Energy Policy Act of 1992 (the "Policy Act") contains amendments to
PUHCA that may allow the Partnerships to operate their businesses without
becoming subject to PUHCA in the event that either Project loses its status as a
QF. Under the Policy Act, a company engaged exclusively in the business of
owning and/or operating one or more facilities used for the generation of
electric energy exclusively for sale at wholesale may be exempted from PUHCA. To
qualify for such an exemption, a company must apply to FERC for a determination
of eligibility, pursuant to implementing rules promulgated by FERC. Obtaining
this exemption may require amendments to or replacements of 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.
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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.
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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.
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.
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In the Spring of 1996, FERC also issued its Order No. 889. This order
requires utilities owning transmission facilities to adopt procedures for an
open-access same-time information system ("OASIS") that will make available, on
a real-time basis, pertinent information concerning each transmission utility's
services. The order also promulgated standards of conduct to ensure that the
utilities functionally separate their transmission and wholesale power merchant
functions to prevent self-dealing.
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.
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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.
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 on or before March 1, 1998.
Commonwealth, Montaup and Boston Edison are all in various stages of
divestiture.
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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. The
DTE is required to approve any plan for recovery of such costs and to issue a
finding 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 market value 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 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.
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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.
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).
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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.
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
NE LP believes that as of the date of this report 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.
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The 1990 Amendments also require each state to implement an operating
permit program that incorporates all of a facility's Clean Air Act requirements
into a single permit and that includes sufficient monitoring requirements to
ensure compliance. In addition, states are authorized to impose fees of at least
$25 per ton of air pollutants emitted by a facility, even if such emissions are
within permitted limits. The Departments of Environmental Protection for each of
New Jersey and Massachusetts are currently reviewing the operating permit
applications for the NJEA Project, the NEA Project and the Carbon Dioxide Plant,
respectively.
SUMMARY OF PRINCIPAL PROJECT AGREEMENTS
The following is a summary of selected provisions of certain principal
agreements related to the Projects and is not considered to be a full statement
of the terms of such agreements. Accordingly, the following summaries are
qualified by reference to each agreement and are subject to the terms of the
full text of each agreement. Unless otherwise stated, any reference in this
summary to any agreement shall mean such agreement and all schedules, exhibits
and attachments thereto as amended, supplemented or otherwise modified and in
effect as of the date hereof.
Power Purchase Agreements
NEA Power Purchase Agreements
Boston Edison I Power Purchase Agreement
The Power Purchase Agreement entered into by NEA and Boston Edison as of
April 1, 1986 (the "Boston Edison I Power Purchase Agreement"), provides for the
sale to Boston Edison of 46% of the net power actually generated by the NEA
Project.
Term. The Boston Edison I Power Purchase Agreement extends for an initial
term of 25 years expiring September 15, 2016, subject to earlier termination in
accordance with its terms. Following the initial term, Boston Edison has the
right to extend the Boston Edison I Power Purchase Agreement for an additional
five years upon six months written notice. Following any such renewal, the
Boston Edison I Power Purchase Agreement will remain in effect until terminated
by either party by giving the other party six month's written notice of such
termination.
Purchase and Delivery. Pursuant to the Boston Edison I Power Purchase
Agreement, NEA is obligated to deliver to Boston Edison, and Boston Edison is
obligated to accept, a portion of the available capacity and hourly generation
of the NEA Project equal to the ratio of 135 MW to the Net Electrical Capability
(as defined herein) of 290 MW of the NEA Project multiplied by 100% of the
available capacity and hourly generation of the NEA Project, or 46% of the net
power actually generated. Plant output is dependent, among other things, on
ambient temperatures, and is therefore subject to some variation. Whenever the
NEA Project is operating above or below its Net Electrical Capability of 290 MW,
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.
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Curtailment. Boston Edison has the right under the Boston Edison I Power
Purchase Agreement to refuse power from the NEA Project for up to 200 hours per
year (in addition to its other curtailment rights described below). Boston
Edison also has the right to interrupt, reduce or refuse to purchase electric
energy and NEA has the right to interrupt, reduce or refuse to deliver electric
energy in order to install equipment, make inspections or perform maintenance
and repairs. In addition, Boston Edison has the right to curtail or interrupt
the taking of electric energy for as long as reasonably necessary in the event
of an emergency.
Interconnection. NEA has agreed to secure and pay all expenses of
interconnection for the delivery of electrical energy at the delivery point.
While Boston Edison may, at its option (subject to certain conditions), enter
into transmission and interconnection agreements if necessary to ensure
continued transmission and delivery of electrical energy, the expense and the
risk of loss of such transmission are to be borne by NEA. All necessary
interconnection agreements have been entered into. See "-Boston Edison
Interconnection Agreement" below.
Pricing. The Boston Edison I Power Purchase Agreement provides for a fixed
capacity payment of 1.04 cents per kWh for all power delivered to Boston Edison
plus an energy payment per kWh delivered equal to a percentage of the
"Qualifying Facility Power Purchase Rate," which is a rate determined under
Massachusetts law. It has been agreed that this percentage shall be 80% in each
contract year through 2003, 75% from 2004 through 2007, 80% from 2008 through
2010, 85% in 2011 and 90% thereafter. If Boston Edison elects to exercise its
right to extend the Boston Edison I Power Purchase Agreement, the energy payment
for the period of any such extension will be 100% of the Qualifying Facility
Power Purchase Rate. The Boston Edison I Power Purchase Agreement further
provides that the minimum total payment for both energy and capacity to be
received by NEA (in all cases whether or not such minimum amount is greater than
the applicable percentage of the "Qualifying Facility Power Purchase Rate")
shall not be less than 7.50 cents per kWh through 1997, after which the minimum
payment becomes 6.50 cents per kWh until the end of the initial term. There is
no minimum for any extension period. In 1997 the price per kWh was 7.50 cents.
If, due to transmission constraints, Boston Edison must purchase power from NEA
rather than a lower priced source, the purchase price for such power will be the
lower price Boston Edison was forced to forego. However, such substitute rate is
only available for up to 100 hours in any contract year.
Energy Bank. The Boston Edison I Power Purchase Agreement provides for a
special account referred to as the Energy Bank or Balance Account, and the
Energy Bank balances therein are to be increased or decreased based upon a
formula that prices power delivered to Boston Edison at its projected avoided
cost, which is determined by reference to a fixed schedule specifying dollar
amounts per kWh sold for each year of the Boston Edison I Power Purchase
Agreement. As of December 31, 1997, the Energy Bank balance under the Boston
Edison I Power Purchase Agreement was approximately $144,526,000 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."
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Sale of Power to Other Purchasers. The Boston Edison I Power Purchase
Agreement contains a "most-favored nation" clause specifying that if any of the
Commonwealth Power Purchase Agreements and the Montaup Power Purchase Agreement
are amended or if NEA enters into any additional power purchase agreements, and
Boston Edison believes the terms of such amendment or such power purchase
agreement are more favorable to the applicable third party than the terms of the
Boston Edison I Power Purchase Agreement are to Boston Edison, NEA shall make
such terms available to Boston Edison for the remaining term of the Boston
Edison I Power Purchase Agreement, provided Boston Edison accepts the other
substantive terms of such amendment or power purchase agreement. Pursuant to a
Consent and Agreement, dated as of June 28, 1989, and confirmed in a
Confirmation Agreement, dated September 16, 1994, subject to conditions
contained therein, Boston Edison has irrevocably waived its rights to invoke the
"most-favored nation" clause. NEA may not enter into any contract for the sale
of electricity from any addition to or expansion of the NEA Project or from any
other electricity generation facilities located at the NEA Site unless it first
offers Boston Edison an amount of electricity proportionate to its then current
entitlement on substantially the same business terms specified in any proposal
or letter of intent with the applicable third party and Boston Edison does not
accept such terms.
Right of First Offer. Other than in connection with the financing or
refinancing of the NEA Project, or with the sale of equity participations in the
form of partnership interests or otherwise, NEA has agreed under the Boston
Edison I Power Purchase Agreement that if it desires to sell all or any portion
of the NEA Project, it will first offer the terms of such sale to Boston Edison,
which will have 60 days to respond to such offer. If Boston Edison declines the
offer, NEA, will be free to offer the same terms to any third party, but in the
event that an agreement is reached with such third party on terms more favorable
than those proposed to Boston Edison, NEA is obligated to offer such terms to
Boston Edison. The right of first offer is subject to adjustments proportionate
to increases in entitlements of Commonwealth and Montaup.
Qualifying Facility Status. The Boston Edison I Power Purchase Agreement
does not require that the NEA Project's QF status be maintained. However, NEA
has warranted to Boston Edison that NEA will use its best efforts to maintain
the NEA Project's QF status.
Events of Default and Remedies; Termination. The occurrence of any one or
more of the following events constitutes an event of default under the Boston
Edison I Power Purchase Agreement and may result in termination of the Boston
Edison I Power Purchase Agreement and the exercise of other remedies by the
non-defaulting party: (i) the dissolution or liquidation of either party; (ii)
failure by either party to perform or observe any of the material terms of the
Boston Edison I Power Purchase Agreement, where such failure has not been cured
within 45 days of notice thereof by the non-defaulting party or, where cure is
not practicable within 45 days, cure has not been undertaken within 45 days and
completed within a reasonable period not to exceed two years; (iii) certain
events of bankruptcy or insolvency; (iv) the failure of NEA to deliver at least
591.3 million kWh of electricity per year (equivalent to 135 MW at 50% capacity
factor annually) to Boston Edison in each of two consecutive contract years,
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.
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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.
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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,
amounts on deposit in 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.
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.
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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.
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.
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Contract Security. To secure its performance under the Commonwealth I Power
Purchase Agreement (as well as the other NEA Power Purchase Agreements), NEA has
granted Commonwealth, Boston Edison and Montaup the NEA Second Mortgage on the
NEA Site and the NEA Project, subordinated only to the rights of the Project
Secured Parties pursuant to the NEA Project Mortgage and certain replacements
thereof. In addition, NEA has granted Commonwealth an unsubordinated declaration
of easements, encumbering the NEA Project for the term of the Commonwealth 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.
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.
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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.
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Transmission. Under the Commonwealth I Power Purchase Agreement, NEA bears
all risk and expenses with respect to the provision of transmission services to
Commonwealth for the term of the contract.
Qualifying Facility Status. Commonwealth's obligations under the
Commonwealth II Power Purchase Agreement were initially conditioned upon the NEA
Project's being certified as a QF on the in-service date, which condition was
satisfied. NEA has agreed to use its best efforts to maintain such status, and
in the event that the NEA Project's QF status is revoked, NEA has agreed to use
its best efforts to regain the certification and both parties have agreed to
continue to purchase and sell power on the terms set forth in the Commonwealth
II Power Purchase Agreement (including those relating to price).
Montaup Power Purchase Agreement
The Power Purchase Agreement entered into by NEA and Montaup as of October
17, 1986 (the "Montaup Power Purchase Agreement") provides for the sale to
Montaup of approximately 9% of the net power actually generated by the NEA
Project.
Term. The Montaup Power Purchase Agreement extends for an initial term of
30 years expiring September 15, 2021, subject to earlier termination in
accordance with its terms. The Montaup Power Purchase Agreement will remain in
effect thereafter until either party terminates the contract by giving the other
party six months' written notice of such termination.
Purchase and Delivery. Pursuant to the Montaup Power Purchase Agreement,
NEA is obligated to deliver to Montaup, and Montaup is obligated to accept, a
portion of the available capacity and hourly generation of the NEA Project equal
to the ratio of 25 MW to the Net Electrical Capability of 290 MW 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.
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Pricing. The Montaup Power Purchase Agreement provides for an energy
payment per kWh for all power delivered to Montaup equal to 75% of Montaup's
Qualifying Facility Power Purchase Rate (described below) in each year through
2000 and at least 75% but no more than 95% of such rate thereafter, dependent
upon the balance in the Energy Bank in such year, together with an average fixed
capacity payment of 1.04 cents per kWh, which is not subject to adjustment
provided that peak-hour availability remains in excess of 80%. The Montaup Power
Purchase Agreement further provides that the minimum rate to be received by NEA
is 6.50 cents per kWh through 2000, after which no minimum rate applies. The
foregoing rates are payable in respect of 99% of the kilowatt hours delivered by
NEA for sale to Montaup under the Montaup Power Purchase Agreement. Montaup's
Qualifying Facility Power Purchase Rate is a rate determined under state law
based on Montaup's Avoided Cost of power production. If, due to transmission
constraints, Montaup must purchase power from NEA rather than a lower priced
source, then the purchase price for such power will be the lower price Montaup
was forced to forego. However, this substitute rate is only available for up to
100 hours annually. During 1997, the payment per kWh under the Montaup Power
Purchase Agreement was 6.5 cents.
Energy Bank Liability and Support. The Montaup Power Purchase Agreement
provides for an Energy Bank, and the Energy Bank balance under the Montaup Power
Purchase Agreement will be increased to the extent that the price paid by
Montaup exceeds the greater of (i) Montaup's Qualifying Facility Power Purchase
Rate and (ii) an Energy Bank floor rate. The Energy Bank floor rate is specified
pursuant to a fixed schedule. Positive Energy Bank balances are reduced to the
extent payments to NEA are less than the foregoing Energy Bank rates. Positive
balances are subject to interest each month at the prime rate as established
from time to time by the First National Bank of Boston. As of December 31, 1997
the Energy Bank balance under the contract was approximately $27,055,000. The
Montaup Power Purchase Agreement requires NEA to deliver a letter of credit to
Montaup securing the payment of positive Energy Bank balances. However, the face
amount of the letter of credit is not required to exceed $12.656 million or (if
less) the remaining Energy Bank balance.
Contract Security. To secure its performance under the Montaup Power
Purchase Agreement, NEA has granted Montaup (as well as other NEA Power
Purchasers), the NEA Second Mortgage, subordinated only to the rights of the
Project Secured Parties pursuant to the NEA Project Mortgage and certain
replacements thereof. In addition, NEA has granted Montaup an unsubordinated
Declaration of Easements, encumbering the NEA Project for the life of the
Montaup Power Purchase Agreement. This declaration provides Montaup with limited
access to the NEA Project and obligates any subsequent owner of the NEA Project
to sell Montaup in contract entitlement. See "--Accommodation Agreement" below.
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.
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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.
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.
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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.
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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 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.
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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.
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.
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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.
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Operation. The Carbon Dioxide Plant is operated by Westinghouse Services
pursuant to a separate operating agreement between Westinghouse Services and
NECO.
Rent. The basic rent payable by NECO to NEA pursuant to the NECO Lease is
$100,000 per month and is subject to adjustment based upon the monthly profits
or losses realized by NECO in connection with the operation of the Carbon
Dioxide Plant.
Right of First Refusal. Absent an event of default under the NECO Lease,
NECO has a right of first refusal with respect to any sale of the Carbon Dioxide
Plant.
Event of Loss. Under the NECO Lease, NECO is required to pay to NEA, as
promptly as practicable and in any event within five days following the receipt
of insurance proceeds with respect to the occurrence of an event of loss (as
defined in the NECO Lease) with respect to the Carbon Dioxide Plant, an amount
equal to the sum of (a) any insurance proceeds so received plus (b) any rent
accrued but unpaid plus (c) any amount payable under the NEA Steam Sales
Agreement accrued but unpaid.
NJEA Steam Sales Agreement
The NJEA Project sells steam to Hercules pursuant to the Industrial Steam
Sales Contract dated as of June 5, 1990 between NJEA and Hercules (the "NJEA
Steam Sales Agreement"). The NJEA Steam Sales Agreement provides for the sale by
NJEA to Hercules of up to an annualized maximum of 205,000 pounds of steam per
hour when both gas turbines at the NJEA Project are fully operational and up to
a maximum of 100,000 pounds of steam per hour when only one gas turbine is fully
operational.
Term. The NJEA Steam Sales Agreement extends for a term of 20 years
expiring August 13, 2011, subject to automatic renewal for two consecutive
five-year terms unless either party to the agreement gives written notice of its
intent not to renew at least two years before the expiration of the then-current
term.
Price. The monthly floor price payable by Hercules to NJEA for steam
delivered under the NJEA Steam Sales Agreement is $2.50 per thousand pounds of
steam, subject to monthly escalation (which began in September, 1991) based on a
national coal price index. After Hercules has purchased steam amounting to
205,000 pounds per hour on an annualized basis or purchased more than 230,000
pounds of steam per hour in any given hour, Hercules also is required to pay the
fuel costs associated with the production of additional steam, payable within 20
days of receipt of NJEA's invoice.
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.
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Events of Default and Remedies. Events of default by Hercules under the
NJEA Steam Sales Agreement include (i) failure to pay bills for steam when due
within 30 days of notice of such failure, (ii) fraudulent use of meters which
continues for 90 days after notice thereof and (iii) breach of any other
material obligation under the NJEA Steam Sales Agreement which continues
unremedied for 90 days after notice thereof. NJEA may terminate the NJEA Steam
Sales Agreement in the event of any such event of default. Events of default by
NJEA under the NJEA Steam Sales Agreement include (i) fraudulent use of meters
and failure to cure within 90 days following notice thereof, (ii) failure to
deliver on an annual average basis a minimum of 85% of the total steam used by
Hercules in its Parlin plant, (iii) more than five total forced outages
resulting in total loss of steam production for more than 15 minutes in any full
calendar year and (iv) more than 15 partial forced outages resulting in a loss
of 10% of steam production of more than 15 minutes in any full calendar year. In
the event NJEA fails to deliver at least 85% of Hercules' steam requirement,
NJEA is required to reimburse Hercules for up to $800,000 of Hercules' cost of
making replacement steam. In the event that there are more than five total
outages or more than 15 partial outages in a year, including those due to force
majeure, NJEA is required to pay Hercules $40,000 per total forced outage and
$5,000 per partial forced outage up to a maximum of $200,000 annually.
Gas Purchase Agreements
NEA ProGas Agreement
Quantities. The Gas Purchase Contract dated as of May 12, 1988 and amended
as of April 17, 1989, June 23, 1989, November 1, 1991 and June 30, 1993 between
NEA and ProGas (the "NEA ProGas Agreement") provides for the sale by ProGas to
NEA of 49,560 Mcf of natural gas per day, with an equivalent heating value of at
least 48,817 Dth (the "Daily NEA Quantity"). If NEA fails to take 75% of the
annualized Daily NEA Quantity in any contract year, then NEA is required to
purchase additional gas in the following contract year to make up any such
deficiency. If NEA fails to purchase such required quantities in any year,
ProGas has the right to bill NEA monthly for interest at the rate of the
then-current Canadian Imperial Bank of Commerce prime rate plus 2% on the
contract price that would have been payable in respect of the shortfall amount.
Further, following any such year in which NEA fails to take such percentage of
the annualized Daily NEA Quantity, ProGas has the right to renegotiate the Daily
NEA Quantity unless NEA was unable to take the required amount due to the
temporary inability of the NEA Project to utilize the gas supplies. If NEA
requests volumes in excess of the Daily NEA Quantity, ProGas may accommodate
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.
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Term. The term of the NEA ProGas Agreement is 22 years expiring November 1,
2013. The final seven years of this term constitutes an extension of the
original 15 year term which has been agreed to by the parties and approved by
the producers and Canadian regulatory authorities.
Delivery Point. Gas delivered by ProGas under the NEA ProGas Agreement is
delivered to the Import Point at Niagara Falls, Ontario/Niagara Falls, New York.
For a description of transportation arrangements for such gas from the Import
Point to the NEA Project, see "--Gas Transportation and Storage Agreements"
below.
Price. The actual billings to NEA by ProGas are developed through the use
of a two-part rate structure, consisting of a monthly demand charge which is
subject to a commodity charge. The monthly demand charge is the product of the
average Daily NEA Quantity and the monthly demand rate where the monthly demand
rate is the sum of (i) the monthly demand toll per Mcf, as determined by
Canada's National Energy Board, charged to ProGas by TransCanada PipeLines
Limited, a Canadian Transporter ("TransCanada"), (ii) the monthly demand toll
per Mcf charged by NOVA Corporation of Alberta, also a Canadian Transporter, to
ProGas and (iii) the monthly demand toll per Mcf charged by ProGas as approved
by the Alberta Petroleum Marketing Commission. Payments pursuant to this monthly
demand charge are based on the anticipated Daily NEA Quantities under the NEA
ProGas Agreement. The monthly demand charge is payable regardless of the actual
volume of gas delivered.
The commodity charge is applied to volumes of gas actually delivered under
the NEA ProGas Agreement and is the difference between the unitized monthly
heating demand rate and the then applicable "base price" escalated from U.S.
$2.7665 per Dth as of January 1, 1990. The "base price," as theretofore
escalated, was further increased by $.038 per Mcf, effective December 1, 1994.
Escalation of the "base price" is determined by reference to the escalation
rates in the Power Purchase Agreements for both Projects. The "base price" for
approximately 70% of the contract quantities is escalated using the weighted
average of (I) the fixed escalators applicable to NEA's fixed price power sales
and (ii) the changes in fuel prices that determine escalation of price under
NEA's Avoided Cost contracts. No more than 150 MW of Avoided Cost sales are
included in this weighing at a price no lower than a floor price of 6.5 cents
per kWh. The remaining contract quantities, approximately 30%, have a "base
price" adjusted annually by the change in the cost of natural gas purchased by
New Jersey electric utilities as reported in FERC Form 423.
The price of gas sold pursuant to the NEA ProGas Agreement will be adjusted
in the event that (i) the NJEA Project has ceased to operate for a period of six
consecutive months and (ii) ProGas is not selling gas under the NJEA ProGas
Agreement on a monthly basis at least equal to 65% of the Daily NJEA Quantity
(as defined below). The price adjustment will be subject to an escalator based
on natural gas costs as determined by FERC and the pricing provisions contained
in the NJEA ProGas Agreement. In any contract year commencing on or after
November 1, 2001, the contract pricing also is subject to renegotiation or
arbitration if the contract prices do not track comparable long-term service
contracts then prevailing. Arbitration conducted between November 1, 2001 and
October 31, 2006 may result in an increase in the escalation of the "base
price," while arbitration conducted between November 1, 2006 and the end of the
term may result in an increase or decrease in the rate 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.
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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 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.
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<PAGE>
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.
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<PAGE>
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 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.
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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 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.
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<PAGE>
Service Interruption. PSE&G may interrupt sales and transportation service
to the NJEA Project on "peak days" when the mean daily temperature forecast for
Newark, New Jersey is 22 (degree) F or below. On such days, PSE&G may retain the
gas supplies tendered to it by NJEA. This occurred on 4 days during 1997. At
NJEA's election, PSE&G will offer Extended Gas Service on such days, unless the
mean daily temperature forecast is 14(degree) F or below. In the latter case
PSE&G may curtail all service to NJEA and the NJEA Project may not be able to
operate. This occurred on 2 days during 1997. The price of Extended Gas Service
is based upon the cost to PSE&G of propane supplies delivered to its processing
facilities plus a mark-up. During 1997, NJEA purchased 908,290 dekatherms of
Extended Gas Service supplies at an average price of $8.813 per dekatherm.
In exchange for the right to retain NJEA's gas supplies on those certain
peak days described above, PSE&G pays a demand charge to NJEA (the "Peak Gas
Service Credit") which is indexed to demand charges paid by NJEA for the
transportation and storage of its supplies in the U.S. The Peak Gas Service
Credit is subject to a floor of 37% of the PSE&G "service charge" and a cap of
68% of the "service charge." During 1997, PSE&G paid NJEA over $2 million in
Peak Gas Service Credits. In addition, PSE&G pays NJEA for gas retained
according to a formula which prices these supplies at the greater of (i) the
weighted average commodity cost of PSE&G for natural gas supplies purchased from
all sources, or (ii) an amount which is the lesser of the market price of fuel
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.
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NEA -- Transportation Agreements
Maximum Daily Contract
Gas Transporter and Agreements Quantity Expiration Date
- ------------------------------ -------- ---------------
CNG Transmission Corporation 48,817 Dth November 1, 2011
Firm Transportation Service
Agreement
Rate Schedule X-71
CNG Transmission Corporation 1,654 Dth Winter March 31, 1999
Service Agreement Applicable to 828 Dth Summer
Transportation of Natural Gas
Rate Schedule FT:
Transcontinental Gas Pipe Line 48,800 Mcf October 31 2006
Corporation
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 14,000 Dth March 31, 2012
Corporation
Service Agreement
Rate Schedule FTS-5
- -------------
(1) Includes an agreement for the transportation of natural gas held in storage.
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<PAGE>
NEA -- 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 22,019 Mcf October 31, 2006
Corporation
Firm Gas Transportation Agreement
Rate Schedule X-319
Public Service Electric & Gas 32,500 Dth August 12, 2011
Company
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 10,508 Dth March 31, 2012
Corporation
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 Injection: 10,000 Dth
to the Storage of Natural Gas Capacity: 1,400,000 Dth
Rate Schedule GSS-11
- ----------------------------
NJEA -- Storage Agreements
Maximum Daily Contract
Gas Transporter and Agreements Quantity Expiration Date
- ------------------------------ -------- ---------------
CNG Transmission Corporation Withdrawal: 10,508 Dth March 31, 2012
Service Agreement Applicable Injection: 7,506 Dth
to the Storage of Natural Gas Capacity: 1,050,800 Dth
Rate Schedule GSS-11
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Operations and Maintenance Agreements
NEA Operations and Maintenance Agreement
The Second Amended and Restated Operation and Maintenance Agreement for the
NEA Project dated as of June 28, 1989, as amended, between NEA and Westinghouse
Electric (the "NEA O&M Agreement"), provides for the operation and maintenance
by Westinghouse Services (the "Operator") of the NEA Project.
Term. The term of the NEA O&M Agreement extends for an initial term of 10
years expiring September 15, 2001. The Operator has agreed, pursuant to a letter
agreement with NEA dated as of June 23, 1993, to enter into a successor
agreement for a term of ten years at NEA's option, with payments to be made to
the Operator for certain services on either a firm-price basis, subject to
successful negotiation of terms by the parties, or a cost-plus basis. In the
event that the agreement is not extended on either basis, the Operator is to
provide assistance to effect a transition to a new service provider. Pursuant to
the New NEA O&M Agreement, the New Operator is providing certain services for
the NEA Project, and has agreed to replace Westinghouse Services as the operator
of the NEA Project upon the expiration or early termination of the NEA O&M
Agreement.
Basic Obligations. The Operator has agreed to provide all operations and
maintenance services, including scheduled all major maintenance and has agreed
to provide all personnel, spare parts and consumables necessary in order to
operate and maintain the NEA Project. Such services include all services
necessary or advisable to use, operate and maintain the NEA Project in good
operating condition and in compliance with (i) the NEA Project Documents, (ii)
all insurance policies relating to the NEA Project, (iii) the procedures
established in the operation and maintenance manuals provided pursuant to the
construction contract for the NEA Project, or applicable industry guidelines,
(iv) all applicable prudent industry practices and standards, (v) vendor and
manufacturer requirements or conditions, as applicable, (vi) the standards set
forth in the NEPOOL Agreement, (vii) the operating and maintenance procedures
established by the Operator in accordance with the NEA O&M Agreement and (viii)
any and all governmental approvals, licenses or permits associated with the NEA
Project. Substantive changes to the obligations of the Operator require consent
of NEA and of an independent engineer to a written "change order" request of the
Operator.
Compensation. For the initial term, NEA has agreed to pay the Operator a
monthly fee (the "NEA O&M Fee") of $435,417 (in 1990 dollars), subject to a
biannual adjustment each January and July calculated on the basis of certain
national indices for the cost of labor, materials and producer prices. The NEA
O&M Fee incurred during 1997 was $6,550,447 (excluding heat rate and performance
bonuses).
Performance Guarantees. The NEA O&M Agreement specifies certain guaranteed
performance levels for the NEA Project, including but not limited to (i)
guaranteed electrical output of approximately 290 MW of capacity, adjusted for
variations from standard operating conditions and excused downtime and by 3% per
annum for plant degradation, at 90% average availability, when the NEA Project
is being fueled by 100% pipeline quality natural gas, (ii) guaranteed electrical
output of approximately 290 MW of capacity, adjusted for variations from
standard operating conditions and excused downtime, at 83% for purposes of
liquidated damages calculations or 85% for purposes of bonus payments average
availability, when the NEA Project is burning a combination of natural gas and
fuel oil, (iii) guaranteed steam output of not less than 5% of the total energy
output of the NEA Project, with an affirmative obligation for the Operator to
correct any deficiency as NEA's sole remedy, (iv) guaranteed fuel consumption,
as adjusted to reflect variations from standard conditions, not in excess of
certain agreed upon levels with an affirmative obligation to correct
inefficiencies and, in certain circumstances, to reimburse excess fuel costs and
(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.
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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.
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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
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."
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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 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.
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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.
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.
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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
C)F status, the Operator may suspend its performance under the NJEA O&M
Agreement and find a replacement operator. See "Business -- Regulation -- Energy
Regulation."
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<PAGE>
New NEA and NJEA Operation and Maintenance Agreements
Each of The Operation and Maintenance Agreements, dated as of November 21,
1997 (the "New NEA O&M Agreement" and the "New NJEA O&M Agreement"), by and
between NE LP and ESI Operating Services, Inc. (the "New Operator"), provides
for the operation and maintenance by the New Operator of the NEA and NJEA
Projects respectively on the day following the expiration or early termination
of the NEA and NJEA O&M Agreements (each, an "Operating Period Commencement
Date"). Under the New NEA and NJEA O&M Agreements, the New Operator has agreed
to provide currently Oversight Services (defined below) and has agreed to
provide Transition Services (defined below), commencing ninety (90) days prior
to the applicable Operating Period Commencement Date (each, a "Transition
Services Commencement Date").
Term. The term of the New NEA and NJEA O&M Agreements extends for an
initial term of eighteen (18) years until January 14, 2016, subject to extension
by mutual agreement of the parties before six months preceding such expiration.
Oversight Services. The New Operator has agreed to provide certain
oversight services (the "Oversight Services") prior to the Operating Period
Commencement Date, including (i) reviewing certain Operator reports, proposed
changes in procedures, facility performance data, operating logs and records of
unplanned outages and annual generation forecasts, (ii) assessing NEA and NJEA
Site conditions on a quarterly basis, (iii) assessing the Operator's personnel,
policies, and procedures, (iv) analyzing all proposed capital expenditures for
the NEA and NJEA Project, (v) providing such technical support as reasonably
requested by NE LP and (vi) monitoring the Operator's activities during major
scheduled outages and major equipment overhauls.
Transition Services. On the Transition Period Commencement Date and until
the Operating Period Commencement Date, the New Operator has agreed to provide
certain transition services consisting of the review of existing maintenance and
operation records and the performance of all activities necessary to mobilize
its personnel (the "Transition Services"), including without limitation (i)
providing the necessary staff to operate and maintain the NEA and NJEA Projects
on the Operating Period Commencement Date, including relocation of such
personnel, review of personnel qualifications, recruiting and training, (ii)
preparing and submitting to NE LP (a) a transition plan and budget for the
orderly transition of operation and maintenance responsibilities for the NEA and
NJEA Projects, (b) an initial operation and maintenance plan for 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.
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<PAGE>
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.
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Termination. NE LP, may, by written notice to the New Operator, terminate
the New NEA and NJEA O&M Agreements if, prior to the Operating Period
Commencement Date, an independent engineer has not certified that the New
Operator is capable of operating the NEA and NJEA Projects in accordance with
Prudent Utility Practices. The New Operator may, by written notice to NE LP,
terminate the New NEA and NJEA O&M Agreements, if NE LP fails to make a payment
thereunder within 5 days after the same shall have become due. Either party may
terminate the New NEA and NJEA O&M Agreements by written notice if (i) the other
party defaults in the performance of any material term, covenant or obligation
contained in the New NEA and NJEA O&M Agreements and does not remedy such
default within 30 days after such party's receipt of the non-defaulting party's
written notice thereof to such party (or as soon as possible thereafter but in
any event within 180 days, if it cannot be reasonably accomplished in such 30
day period and the defaulting party has commenced all actions required to remedy
such default within such 30 day period and diligently thereafter pursues the
same to completion), (ii) certain bankruptcy or insolvency events as to the
other party occur, (iii) the NEA or the NJEA Project is destroyed or suffers
damage in excess of $100,000,000 and is not rebuilt and in commercial operation
within 24 months after such damage or destruction, (iv) the NEA or the NJEA
Project cannot be operated for a period of at least 18 consecutive months as a
result of a force majeure event, (v) the NEA or the NJEA Project loses its QF
status or (vi) NE LP determines to permanently shut down the NEA or NJEA
Project.
Assignment
Neither party may assign or otherwise convey its rights under the New NEA
and NJEA O&M Agreements, without the prior written consent of the other party
(such consent not unreasonably withheld), except that NE LP has agreed to assign
its rights and obligations under the New NEA O&M Agreement to NEA upon the later
to occur of (i) the applicable Operating Period Commencement Date and (ii) the
execution and delivery by NEA of a counterpart of the New NEA O&M Agreement to
NE LP and the New Operator and except that NE LP has agreed to assign its rights
and obligations under the New NJEA O&M Agreement to NJEA upon the later to occur
of the (i) applicable Operating Period Commencement Date and (ii) the execution
and delivery by NJEA of a counterpart of the New NJEA O&M Agreement to NE LP and
the New Operator.
Accommodation Agreement
NEA, Chase, as agent for the Original Banks, and the NEA Power Purchasers
have entered into an Accommodation Agreement dated as of June 28, 1989 (the
"Accommodation Agreement") confirming the NEA Power Purchase Agreements and the
declaration of easements, covenants, and restrictions giving the NEA Power
Purchasers certain rights in the event that possession of the NEA Project is
obtained by or transferred to a third party pursuant to an exercise of remedies
under the Project Security Documents, and subordinating the rights of the NEA
Power Purchasers under the NEA Second Mortgage on the NEA Project to those of
the financial institutions party to the Original Project Credit Agreement (as
defined herein) under the NEA Project Mortgage. In connection with the issuance
of the Original Project Securities, each of the NEA Power Purchasers affirmed
the Accommodation Agreement and agreed that the NEA Second Mortgage will be
subordinated to the NEA Project Mortgage.
In addition, the Collateral Agent has confirmed to the NEA Power Purchasers
that the rights granted to the NEA Power Purchasers under the Accommodation
Agreement described above, are in full force and effect with respect to the
Collateral Agent, including the rights granted to the NEA Power Purchasers under
the Declaration. As a result (i) if the Collateral Agent or any Project Secured
Party acquires possession of the NEA Project or the NEA Site, or NEA's interest
therein, pursuant to the exercise of rights or remedies under the Project
Security Documents, or otherwise, then it will be required, among other things,
to use reasonable efforts to perform or cause to be performed the obligations of
NEA under the NEA Power Purchase Agreements subject to certain conditions, and
to honor the Declaration, (ii) if the Collateral Agent or a Project Secured
Party transfers the NEA Project or the NEA Site pursuant to a foreclosure sale
or otherwise, it must require any prospective transferee to honor the NEA Power
Purchase agreement and the declaration of easements, covenants, and restrictions
and (iii) in the event of a casualty to the NEA Project, the Collateral Agent
and the Project Secured Parties will allow the application of Loss Proceeds (as
defined herein) to the repair or restoration of the NEA Project in accordance
with certain provisions specified in the Accommodation Agreement.
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Boston Edison Interconnection Agreement
The Amended and Restated Interconnection Agreement between Boston Edison
and NEA, dated September 24, 1993 (the "Boston Edison Interconnection
Agreement") provides for the electrical interconnection between the NEA Project
and Boston Edison's high voltage transmission line on its Right-of-Way No. 13.
This interconnection is used for the delivery of electricity to Boston Edison,
Montaup and Commonwealth pursuant to the NEA Power Purchase Agreements.
Term. The Boston Edison Interconnection Agreement will remain in effect
until the termination date of the latest to terminate of the NEA Power Purchase
Agreements. Boston Edison and NEA have agreed to remain interconnected during
the term of the Boston Edison Interconnection Agreement, so long as they can do
so without significant service disruptions and imminent danger to life or
property. An interruption of the interconnection for any of these reasons shall
continue only for so long as is reasonably necessary.
Operation and Maintenance. Each of NEA and Boston Edison owns and maintains
the respective facilities that it has constructed pursuant to the terms of the
Boston Edison Interconnection Agreement. Boston Edison and NEA have agreed to
operate the interconnection in accordance with NEPOOL's rules and requirements.
If NEPOOL ceases to establish such rules and requirements, the parties have
agreed to operate interconnection in compliance with requirements of Boston
Edison, provided that such requirements are reasonable and consistent with the
NEPOOL rules and requirements previously in effect. Boston Edison has the sole
right to schedule maintenance (routine or emergency) for its transmission lines
and other interconnection facilities used for the NEA Project. Boston Edison has
agreed to perform such maintenance and NEA has agreed to pay Boston Edison the
cost thereof. NEA has sole responsibility for operating and maintaining its
transmission lines and interconnection facilities at its own expense.
Payment. NEA has agreed to (i) pay or reimburse Boston Edison for all
engineering, design and construction costs incurred by Boston Edison in
providing the electrical interconnection, including a percentage of costs
attributable to indirect engineering and corporate overhead and (ii) reimburse
Boston Edison for all operation and maintenance expenses and all taxes
associated with Boston Edison's interconnection facilities used by the NEA
Project. If at any time FERC approves a tariff of Boston Edison applicable to
the interconnection services provided under the Boston Edison Interconnection
Agreement, such tariff shall be used to determine payments and compensation in
lieu of the payment terms contained in the agreement.
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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, 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.
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<PAGE>
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.
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.
58
<PAGE>
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
59
<PAGE>
to NE LP, terminate the Administrative Services Agreement if NE LP (i) fails to
make any payment under the Administrative Services Agreement within 5 days after
the same shall have become due or (ii) materially defaults in the performance of
any material term, covenant or agreement contained therein and does not remedy
such default within thirty days after NE LP's receipt of ESI GP's written notice
thereof to the Partnership (or within 180 days, if it cannot be reasonably
accomplished in such thirty day period and the Partnership shall have commenced
all actions required to remedy such default within such thirty day period).
Either party may terminate the Administrative Services Agreement by written
notice to the other party (but only with the concurrence of ESI GP in the case
of termination by NE LP) if (i) the other party is in bankruptcy or makes a
general assignment for the benefit of creditors; (ii) proceedings are commenced
or steps taken for the appointment of a receiver, custodian, liquidator, trustee
or similar person with respect to all or a substantial portion of the other
party's property; or (iii) any proceedings are commenced or steps taken by any
creditor, regulatory agency or other person relating to the reorganization,
arrangement, adjustment composition, liquidation, dissolution, winding up,
custodianship or other similar relief with respect to such other party.
PART II
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
This item is not applicable to ESI Tractebel Funding or the Partnerships.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
This item is not applicable to ESI Tractebel Funding or the Partnerships.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected combined financial data for
Northeast Energy Associates, A Limited Partnership and North Jersey Energy
Associates, A Limited Partnership for each of the five years in the period ended
December 31, 1997 and selected financial data for ESI Tractebel Funding for the
period from inception (November 3, 1994) to December 31, 1994 and for each of
the three years in the period ended December 31, 1997. The selected combined
financial data for the Partnerships have been derived from the Partnerships'
audited combined financial statements and the selected financial data for ESI
Tractebel Funding have been derived from ESI Tractebel Funding's audited
financial statements. This data should be read in conjunction with "FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS."
60
<PAGE>
<TABLE>
<CAPTION>
Partnerships Combined
----------------------------------------------------------
Years Ended December 31,
----------------------------------------------------------
1993 1994 1995 1996 1997
---- ---- ---- ---- ----
(In thousands)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Power sales to utilities(1) $234,142 $234,933 $276,022 $267,789 $307,530
Steam sales 4,684 3,779 4,527 4,473 4,624
-------- -------- -------- -------- --------
Total revenues $238,826 $238,712 $280,549 $272,262 $312,154
-------- -------- -------- -------- --------
Costs and expenses:
Costs of power and steam 132,580 128,402 132,839 138,727 151,476
Operation and maintenance 20,283 20,808 24,699 22,854 25,689
Depreciation 24,919 24,314 24,904 24,978 24,992
General and administrative 14,162 11,012 12,010 14,424 15,984
-------- -------- -------- -------- --------
Total operating costs
and expenses 191,944 184,536 194,452 200,983 218,141
-------- -------- -------- -------- --------
Operating income 46,882 54,176 86,097 71,279 94,013
Other (income) expense:
Amortization of financing
costs 2,599 2,333 2,305 2,373 2,163
Interest expense 38,992 38,068 50,930 49,841 47,673
Interest expense on energy
bank balance(1) 7,252 11,676 16,657 19,675 17,435
Interest income (700) (1,656) (10,652) (10,534) (9,931)
Expense related to future
obligations under interest
rate swap agreements -- 6,734 -- -- --
-------- -------- -------- -------- --------
Total other expense 48,143 57,155 59,240 61,355 57,340
-------- -------- -------- -------- --------
(Loss) income before
extraordinary item (1,261) (2,979) 26,857 9,924 36,673
Extraordinary item
Loss on extinguishment
of debt(3) -- 13,937 -- -- --
-------- -------- -------- -------- --------
Net (loss) income $ (1,261) $(16,916) $ 26,857 $ 9,924 $ 36,673
======== ======== ======== ======== ========
Ratio of earnings to fixed charges(6) -- -- 1.38 1.14 1.54
</TABLE>
<TABLE>
<CAPTION>
ESI Tractebel Funding Corp.
---------------------------------------------
For the period
from inception
(Nov. 3, 1994) Years Ended December 31,
to December 31, -------------------------
1994 1995 1996 1997
---- ---- ---- ----
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Power sales to utilities $ -- $ -- $ -- $ --
Steam sales -- -- -- --
------ ------- -------- ---------
Total revenues $ -- $ -- $ -- $ --
------ ------- -------- ---------
Costs and expenses:
Costs of power and steam -- -- -- --
Operation and maintenance -- -- -- --
Depreciation -- -- -- --
General and administrative -- -- -- --
------ ------- -------- ---------
Total operating costs
and expenses -- -- -- --
------ ------- -------- ---------
Operating income -- -- -- --
Other (income) expense:
Amortization of financing
costs -- -- -- --
Interest expense 4,305 51,084 49,404 47,303
Interest expense on energy
bank balance -- -- -- --
Interest income (4,305) (51,084) (49,404) (47,303)
Expense related to future
obligations under interest
rate swap agreements -- -- -- --
------ ------- -------- ---------
Total other expense -- -- -- --
------ ------- -------- ---------
(Loss) income before
extraordinary item -- -- -- --
Extraordinary item
Loss on extinguishment
of debt(3) -- -- -- --
------ ------- -------- ---------
Net (loss) income $ -- $ -- $ -- $ --
====== ======= ======== =========
Ratio of earnings to fixed charges 1.0 1.0 1.0 1.0
</TABLE>
<TABLE>
<CAPTION>
Partnerships Combined ESI Tractebel Funding Corp.
-------------------------------------------------------- ---------------------------------------
December 31, December 31,
-------------------------------------------------------- ---------------------------------------
1993 1994 1995 1996 1997 1994 1995 1996 1997
---- ---- ---- ---- ---- ---- ---- ---- ----
(In thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital $ 19,754 $ 74,145 $ 71,975 $ 58,846 $ 63,715 $ 1 $ 1 $ 1 $ 1
Total assets 546,484 650,027 617,034 566,534 541,545 560,145 539,567 514,363 490,288
Total loans payable(2)(5) 465,458 560,000 539,566 514,362 490,287 560,000 539,566 514,362 490,287
Energy Bank balances(4) 111,398 155,496 188,053 220,922 230,565 -- -- -- --
Partners' deficit/Stockholders'
equity (48,540) (92,928) (130,577) (187,479) (197,186) 1 1 1 1
</TABLE>
- -------------------------
(1) Power sales to utilities are net of change in Energy Bank principal
balance. Energy Bank principal balances represent cumulative payments made
to the Partnerships by Power Purchasers under certain Power Purchase
Agreements in excess of rates scheduled or specified 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.
(2) On December 1, 1994, the Partnerships refinanced their existing borrowings
by means of a placement of securities to institutional investors as
defined in Rule 144A of the Securities Act of 1933, as described in Note 5
of Notes to Combined Financial Statements.
(3) In connection with the refinancing, total unamortized financing costs
related to the Project Loan and Credit Agreement were written off during
1994, as described in Note 5 of Notes to Combined Financial Statements.
(4) Energy Bank principal balances plus accrued interest thereon.
(5) Loans payable balances at December 31, 1994, 1995, 1996 and 1997 represent
loans payable to ESI Tractebel Funding Corp. ESI Tractebel Funding Corp.,
formerly known as IEC Funding Corp., is a Delaware corporation established
in 1994 for the purpose of issuing debt securities for the financing of
the Partnerships.
(6) 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.
61
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with
the Combined Financial Statements of the Partnerships and the notes thereto
included elsewhere herein.
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 "SUMMARY OF PRINCIPAL PROJECT AGREEMENTS --
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
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 "Business -- The
Partnerships and 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.
In connection with the Acquisitions, 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 "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.
Results of Operations
The following table sets forth the combined results of the Partnerships'
operations and the percentage of gross operating revenues and receipts
represented by certain components of operating costs and income for the three
years ended December 31, 1997.
62
<PAGE>
Years Ended December 31,
-----------------------------------------------------
1995 1996 1997
---- ---- ----
Gross operating
revenues and
receipts(1)........... $296,449 100% $285,456 100% $304,363 100%
Operating costs......... 157,538 53% 161,581 57% 177,165 58%
Depreciation............ 24,904 8% 24,978 9% 24,992 8%
General and
administrative........ 12,010 4% 14,424 5% 15,984 5%
-------- -------- --------
Operating income
plus Energy Bank
accruals(1)........... 101,997 34% 84,473 30% 86,222 29%
-------- -------- --------
Amortization of
financing costs...... 2,305 1% 2,373 1% 2,163 1%
Interest expense(2).... 50,930 17% 49,841 17% 47,673 16%
Interest income........ (10,652) (4%) (10,534) (4%) (9,931) (3%)
-------- ------- --------
Net income (loss)
plus Energy Bank
accruals and
interest thereon..... $ 59,414 $42,793 $46,317
======== ======= =======
- ----------
(1) Gross operating revenue and receipts represents total revenues plus (less),
as applicable, annual change in Energy Bank principal balances.
(2) Interest expense excludes interest on Energy Bank principal balances.
Calendar Year 1997 Compared to Calendar Year 1996
Gross Operating Revenue and Receipts. Gross operating revenue and receipts
for the year ended December 31, 1997 of $304.4 million increased by $18.9
million (6.6%) as compared to the year ended December 31, 1996. This increase
was primarily due to higher generation and increased prices. The increase in
generation was primarily a result of no scheduled major maintenance outages at
the NEA Project (during the second quarter of 1996 a major inspection and
maintenance program, scheduled at five year intervals, was conducted at the NEA
Project) and fewer curtailment hours requested by JCP&L.
Operating Costs. Cost of power and steam sales was $151.5 million, or 49.8%
of gross operating revenue and receipts for the year ended December 31, 1997 as
compared to $138.7 million, or 48.6% of gross operating revenues and receipts
for the year ended December 31, 1996. The increased cost is primarily due to
price increases under a fuel supply contract that services both facilities.
Partially offsetting the increase in natural gas prices was a reduction in
extended gas services rights exercised by a NJEA fuel supplier during the first
quarter of 1997 as compared to 1996.
Operation and maintenance (O&M) costs increased $2.8 million (12.4%) as
compared to the same period in 1996. The primary cause of the increased cost was
the performance bonus (which is directly related to higher generation) payable
to the Operator under the NEA O&M Agreement. Escalation of the O&M Agreement of
approximately 4% also contributed to the increased costs.
General and Administrative Expenses. General and administrative expenses
for the year ended December 31, 1997 increased $1.6 million or 11% as compared
to the year ended December 31, 1996. The primary cause for this increase was the
write-off of approximately $1.5 million in accounts receivable. This receivable
is related to an amount due from a Power Purchase Utility, which was in dispute.
This receivable 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.
63
<PAGE>
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. During 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 1997 totaled
approximately $9.9 million as compared to approximately $10.5 million in 1996,
decreasing $.6 million. As discussed below, interest income is expected to
decrease materially beginning in 1998.
Calendar Year 1996 Compared to Calendar Year 1995
Gross Operating Revenues and Receipts. Gross operating revenues and
receipts for the year ended December 31, 1996 of $285.5 million decreased by
$11.0 million (3.7%) as compared to the year ended December 31, 1995. This
decrease was primarily due to lower availability as a result of scheduled
maintenance outages. Availability was approximately 91% in 1996 versus
approximately 95% in 1995. During the second quarter of 1996 a major inspection
and maintenance program (scheduled at five-year intervals) took place at the NEA
Project. During the fourth quarter of 1996 a scheduled overhaul and inspection
took place at the NJEA Project. Power purchase rates, on a combined basis,
increased slightly over the prior year.
Operating Costs. Cost of power and steam sales was $138.7 million, or 48.6%
of gross operating revenues and receipts for the year ended December 31, 1996 as
compared to $132.8 million, or 44.8% of gross operating revenues and receipts in
the prior year. The increased costs were primarily attributable to increases in
fuel costs, including higher market prices of Spot Gas and additional charges
applicable under NJEA's extended gas service arrangement with a fuel supplier.
Extended gas service occurs when temperatures are below 22 degrees F. There were
sixteen such days during the first quarter of 1996 compared with four days in
the first quarter of 1995. A portion of these increases was offset by gains on
natural gas swap agreements (which were entered into in an attempt to limit
exposure to market price fluctuations).
Operation and maintenance expenses in 1996 decreased by $1.8 million (7.5%)
as compared to 1995. This decrease was a result of a lower performance bonus
payable to the Operator in 1996 as a result of scheduled maintenance outages and
a 1995 water franchise fee. Offsetting these cost decreases were normal and
expected escalations under the O&M Agreements.
General and Administrative Expenses. General and administrative expenses in
1996 increased by $2.4 million (20.1%) as compared to 1995. The increase was
primarily due to increased management costs, insurance premiums and legal and
consulting costs related to potential industry restructuring.
Interest Expense and Interest Income. Interest expense for the year ended
December 31, 1996 decreased by $1.1 million (2.1%) as compared to the year ended
December 31, 1995. During 1995, the Partnerships' average amount of debt
outstanding was $554.9 million at an average rate of 9.23%. During 1996, the
Partnerships' average amount of debt outstanding was $533.3 million at an
average rate of 9.26%. Interest income in 1996 totaled $10.5 million as compared
to $10.7 million in 1995. This decrease was primarily a result of reduced cash
collateral being held in support of letters of credit.
64
<PAGE>
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 December 31, 1997, the Partnerships' cash and cash equivalents
totaled approximately $61.2 million, as compared to $49.9 million at December
31, 1996. The increase in cash and cash equivalents was the net effect of $82.2
million provided by operations, offset by investing and financing activities
including debt principal payments of $24.1 million and $46.4 million in
distributions to partners.
As of December 31, 1997, there were no outstanding loans under the Sanwa
Working Capital Facility. NE LP terminated the Sanwa Working Capital Facility
and the Sanwa Credit Agreement in February 1998. NE LP does not anticipate the
need to arrange for a new Working Capital Facility. Debt Service Reserve
Requirements were fully funded as of December 31, 1997.
Non-operating income for periods prior to the Acquisitions included
investment income received from the Cash Collateral Proceeds that secured the
Partnerships' obligations to Sanwa Bank under the Sanwa Credit Agreement and
investment income received from investments in the Debt Service Reserve Fund
held by the Project Trustee. As permitted under the Project Indenture, NE LP in
January 1998, arranged for the release of, and distributed to the Partners, cash
in the amount of $33,270,000 from the Debt Service Reserve Fund following the
issuance of Substitute Letters of Credit by BankBoston and Bank Brussels
Lambert. In February 1998, NE LP also arranged for the release of cash in the
amount of $69,156,000, 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.
65
<PAGE>
Working Capital Facility. The Project Indenture permits the Partnerships to
enter into revolving credit arrangements from time to time with financial
institutions with maximum available borrowings of up to $20 million to provide
for the working capital requirements of the Partnerships (the "Working Capital
Facility"). Pursuant to the Sanwa Credit Agreement, the Partnerships entered
into the Sanwa Working Capital Facility, which provided for maximum available
borrowings of up to $15 million subject to a borrowing base calculated based on
outstanding receivables and fuel. The Sellers have advised NE LP that the
Working Capital Facility has never been utilized. In February 1998, NE LP
terminated the Working Capital Facility and the Sanwa Credit Agreement and does
not anticipate the need to arrange for a new Working Capital Facility.
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. 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 1.5% 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 table sets 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.
66
<PAGE>
<TABLE>
<CAPTION>
December 31, 1995 December 31, 1996 December 31, 1997
----------------- ----------------- -----------------
<S> <C> <C> <C>
Notional Amount............ $27,596,000 $20,335,000 $12,940,000
Fair value (liability)(1).. $(3,654,000) $(2,022,000) $ (889,000)
Net Effect of Swaps on
Interest Expense(2)...... $ (486,000) $ 137,000 $ 103,000
</TABLE>
- ----------
(1) The estimated fair value of each existing Swap is the estimated amount that
the applicable Swap Bank would receive to terminate such Swap at the
respective dates, taking into account current interest rates and the
current creditworthiness of the Swap counter-parties.
(2) Represents the net effect of the Swaps on the interest expenses in the
statement of operations. The interest expense on the Swaps is reduced by
the change in the fair value of the Swaps.
Natural Gas Hedging Instruments
Approximately 20% of the fuel supply for the Projects must be provided from
sources other than the Long-term Gas Arrangements. To mitigate the price risk
associated with spot purchases of natural gas, the Partnerships may, from time
to time, enter into certain hedging transactions either through public exchanges
such as the NYMEX, or by means of over-the-counter transactions with specific
counterparties pursuant to the Fuel Management Agreements or otherwise. These
hedging transactions include (a) natural gas call options that give the
Partnerships the right, but not the obligation, to purchase specified quantities
of natural gas at a predetermined price, (b) gas purchase swap agreements that
require the Partnerships to pay a fixed price in return for a variable price on
a notional specified quantity of natural gas, and (c) forward purchases of
natural gas.
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 gain/(loss) included in cost power
and steam sales.......................... $(448,000) $5,246,000 $3,990,000
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.
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 "Business -- Regulation -- Utility
Industry Restructuring."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The combined financial statements of the Partnerships and the financial
statements of ESI Tractebel Funding are filed as part of this Form 10-K and are
set forth on pages F-1 to F-27.
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<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Directors and Executive Officers Until January 14, 1998
Directors and Executive Officers of IEC
All management functions of the Partnerships are the responsibility of IEC.
The following table sets forth the names, ages and positions of the directors
and executive officers of IEC and their positions with IEC.
NAME AGE POSITION
---- --- --------
Stephen B. Roy 51 President and Director
Peter A. Roy 47 Executive Vice President and Director
Jane L. Roy 42 Executive Vice President,
Treasurer, Chief Financial Officer and
Director
Ellen S. Roy 38 Senior Vice President, Clerk and Director
Luciano Lauretti 35 Senior Vice President
Maureen P. Herbert 39 Vice President
George Briden 45 Vice President
Bruce A. Herzfelder 38 Senior Vice President
Leah Taylor Roy 37 Vice President
James Blakey 45 Vice President and General Counsel
Stephen R. Pritchard 40 Vice President
Stephen B. Roy has been President of IEC since it was formed in March,
1986. From 1973 to 1986, he held construction and management positions in
various predecessor companies and, among other things, was responsible for work
on the Doha West Power Station in Kuwait. He holds a B.A. degree from Harvard
University and an M.B.A. degree from Harvard Business School.
Peter A. Roy has been an Executive Vice President of IEC since it was
formed in March, 1986. From 1974 to 1986, he held several positions in various
predecessor companies, where he was responsible for marketing and daily
operations. He attended Harvard University from 1971 to 1974.
Jane L. Roy has been Vice President, Chief Financial Officer and Treasurer
of IEC since it was formed in March, 1986. In 1992 she became an Executive Vice
President. From 1984 to 1986, Ms. Roy worked for The Chase Manhattan Bank, N.A.
where she was an Assistant Treasurer. She holds a B.A. degree from Harvard
University and an M.P.A. degree from Harvard University's John F. Kennedy School
of Government.
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<PAGE>
Ellen S. Roy has been a Vice President of IEC since it was formed in March,
1986 and is responsible for managing government relations. In 1996 she became a
Senior Vice President. Prior to joining IEC, Ms. Roy worked at Prudential
Venture Capital, Inc. She holds a B.A. degree from Harvard University, an M.P.P.
degree from Harvard University's John F. Kennedy School of Government and an
M.B.A. degree from Massachusetts Institute of Technology.
Luciano Lauretti has been a Vice President of IEC since 1990. In 1996 he
became a Senior Vice President. From 1989 to 1990, Mr. Lauretti was an officer
in Corporate Finance at Manufacturers Hanover Trust Company. Prior to 1988 he
was an associate in corporate lending for The Chase Manhattan Bank, N.A. He
holds a B.A. degree in Economics from Universidade de Sao Paulo and an M.B.A.
degree from Columbia University.
Maureen P. Herbert joined IEC in 1987 and served as Controller until 1991,
at which time she became Vice President of Finance. Prior to joining IEC, Ms.
Herbert was a senior consultant at Price Waterhouse. Ms. Herbert is a Certified
Public Accountant and holds a B.S. degree in accounting and finance from
Northeastern University.
George Briden joined IEC in 1990 and served as Fuel Supply Manager until
1991, at which time he became a Vice President of Fuel Supply. From 1989 to
1990, Mr. Briden was employed by Equitrans, Inc., where he directed gas supply
acquisitions. He holds a B.A. degree in economics from Michigan State University
and a Ph.D. degree in economics from Brown University.
Bruce A. Herzfelder has been a Vice President of IEC since 1991. In 1996 he
became a Senior Vice President. From 1988 to 1991, he was an associate at the
New York law firm of Davis, Polk & Wardwell. Prior to that, he clerked for a
judge on the U.S. Court of Appeals. He holds a B.A. degree from Harvard
University and a J.D. and an M.B.S. degree from the University of Chicago. He is
a member of the bar in Massachusetts and New York.
Leah Taylor Roy has been a Vice President of IEC since 1992. From 1986 to
1992, Ms. Roy was a consultant at McKinsey & Company. Ms. Roy holds a B.C.
degree from the University of Toronto and an M.P.P. degree from Harvard
University's John F. Kennedy School of Government.
James Blakey joined IEC in 1992 and served as Corporate Counsel until 1995,
at which time he became Vice President and General Counsel. From 1976 to 1992,
Mr. Blakey was associated with the New York law firm of Kronish, Lieb, Weiner &
Hellman, becoming a partner in 1987. Mr. Blakey holds an A.B. degree from
Dartmouth College and a J.D. degree from Boston University. He is a member of
the bar in Massachusetts, New York and Connecticut.
Stephen R. Pritchard joined IEC in 1994 and served as Operations Manager
until 1995, at which time he became Vice President of Operations. From 1981 to
1994, Mr. Pritchard held several responsible positions for the design,
operations and maintenance of fossil power plants at Baltimore Gas and Electric
Company. Mr. Pritchard holds a B.S. -- Mechanical Engineering degree from
Northeastern University and an M.B.A. degree from Loyola College. He is a
registered Professional Engineer in the State of Maryland.
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<PAGE>
Directors are elected annually and each elected director holds office until
a successor is elected. The Board of Directors consists of three persons:
Stephen B. Roy, Peter A. Roy and Ellen S. Roy. Officers are chosen from time to
time by vote of the Board of Directors.
Certain Relationships. Stephen, Peter, Jane and Ellen Roy are siblings.
Peter, Jane and Ellen Roy are married, respectively, to Leah Taylor Roy, Luciano
Lauretti and Bruce Herzfelder.
Directors and Executive Officers of IEC Funding Corp.
The following table sets forth the names, ages and positions of the
directors and executive officers of IEC Funding Corp. and their positions with
IEC Funding Corp. Directors are elected annually and each elected director holds
office until a successor is elected. Officers are chosen from time to time by
vote of the Board of Directors.
NAME AGE POSITION
---- --- --------
Stephen B. Roy 51 President, Assistant Treasurer, Assistant
Secretary and Director
Ellen S. Roy 38 Vice President, Secretary, Assistant
Treasurer and Director
Jane L. Roy 42 Vice President, Treasurer, Assistant
Secretary and Director
Peter A. Roy 47 Vice President, Assistant Secretary
and Assistant Treasurer
Maureen P. Herbert 39 Vice President
James Blakey 45 Vice President and General Counsel
For biographical information on each of the above listed persons, see
"Management -- Directors and Executive Officers of IEC.
Directors and Executive Officers Since January 14, 1998
All management functions of ESI Tractebel Funding and 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
---- --- -----------
*Glenn E. Smith 40 FPL Energy--Vice President
Kenneth P. Hoffman 46 FPL Energy--Vice President
*Timothy R. Dunne 46 Tractebel Power--Senior Vice President
*Paul J. Cavicchi 45 Tractebel Power--Executive Vice President
- ----------
*Subsequent to the filing of Form 10-K for the fiscal year ended December 31,
1997, such individuals left the Management Committee of NE LP and Scot C.
Hathaway, Eric M. Heggeseth and W. E. (Wes) Schattner were appointed.
70
<PAGE>
Glenn E. Smith was appointed to the NE LP Management Committee by ESI GP in
November, 1997. 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.
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.
Timothy R. Dunne was appointed to the NE LP Management Committee by
Tractebel GP in November, 1997. 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 NE LP Management Committee by
Tractebel GP in November, 1997. 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.
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, and ESI Tractebel Funding. See "SUMMARY OF PRINCIPAL PROJECT
AGREEMENTS -- Administrative Services Agreement."
ITEM 11. EXECUTIVE COMPENSATION
None of the executive officers or directors of ESI Tractebel Funding
received any compensation for his or her services during 1997. The members of
the Management Committee of NE LP are not entitled to any direct compensation
from ESI Tractebel Funding or the Partnerships. The directors and executive
officers of IEC were compensated by IEC and were not entitled to any direct
compensation from the Partnerships. IEC was paid a management fee by the
Partnerships and NE LP is to be paid a management fee by the Partnerships, as
described under "CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS -- Management
Costs."
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<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The following table sets forth as of March 25, 1998, the direct and
indirect partnership interests in the Partnerships.
<TABLE>
<CAPTION>
Name and Address of Nature of
Title of Class Beneficial Owner Beneficial Ownership Percentage Interest
- -------------- ---------------- -------------------- -------------------
<S> <C> <C> <C>
General and Limited Northeast Energy LP(1)(2) General Partner 98%LP
Partnership Interest 1%GP
Limited Partnership Northeast Energy LLC(1)(2) Limited Partner 1%LP
Interest
General Partnership ESI GP(1)(2) General Partner in 1%GP
Interest Northeast Energy LP
General Partnership Tractebel GP(3)(4) General Partner in 1%GP
Interest Northeast Energy LP
Limited Partnership ESI LP(1)(2) Limited Partner in 49%LP
Interest Northeast Energy LP
Limited Partnership Tractebel LP(3)(4) Limited Partner in 49%LP
Interest Northeast Energy LP
</TABLE>
- ----------
(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 Beach, Florida
33408.
(2) ESI GP and ESI LP are wholly-owned, direct subsidiaries of ESI Energy. ESI
Energy is a wholly-owned, indirect subsidiary of FPL Group, Inc.
(3) The address for each of Tractebel GP and Tractebel LP is c/o Tractebel
Power, Inc., 1177 West Loop South, Suite 900, Houston, Texas 77027.
(4) Tractebel GP and Tractebel LP are wholly-owned, direct subsidiaries of
Tractebel Power. Tractebel Power is a wholly-owned, indirect subsidiary of
Tractebel, S.A.
The following table sets forth as of March 25, 1998, the number of shares
and percentage owned of ESI Tractebel Funding's voting securities beneficially
owned by each Person known by ESI Tractebel Funding to be the beneficial owner
of more than five percent (5%) of ESI Tractebel Funding's voting securities.
<TABLE>
<CAPTION>
Name and Address of Amount and Nature of
Title of Class Beneficial Owner Beneficial Ownership Percent of Class
- -------------- ---------------- -------------------- ----------------
<S> <C> <C> <C>
Common Stock ESI Northeast Energy 3,750 37.5%
Funding, Inc.(1)
Common Stock Tractebel Power, 3,750 37.5%
Inc.(1)
Common Stock Broad Street 2,500 25.0%
Contract Services,
Inc.(2)
</TABLE>
- ----------
(1) The address for ESI Northeast Energy 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.
(2) Broad Street Contract Services, Inc. is located at Two Wall Street, New
York, New York 10005 and is the nominee for the Project Trustee for the
purpose of providing an independent director.
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<PAGE>
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Management Costs
The Partnerships made direct or indirect payments to IEC and the Sponsor
Members (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 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."
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<PAGE>
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 Funding believes that each of the transactions set forth
above were entered into on terms as fair as those that could be obtained from
independent third parties.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements
Northeast Energy Associates, A Limited Partnership and North Jersey
Energy Associates, A Limited Partnership
Report of Independent Accountants
Combined Balance Sheet at December 31, 1996 and 1997
Combined Statement of Operations for the years ended December 31, 1995,
1996 and 1997
Combined Statement of Partners' Deficit for the years ended December
31, 1995, 1996 and 1997
Combined Statement of Cash Flows for the years ended December 31, 1995,
1996 and 1997
Notes to Combined Financial Statements
ESI Tractebel Funding Corp.
Report of Independent Accountants
Balance Sheet at December 31, 1996 and 1997
Statement of Operations for the years ended December 31, 1995, 1996 and
1997
Statement of Cash Flows for the years ended December 31, 1995, 1996 and
1997
Notes to Financial Statements
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<PAGE>
2. Financial Statement Schedules
Financial statement schedules are omitted because they are not
applicable or the required information is shown in the financial
statements or the notes thereto.
3. Exhibits
Exhibit No. Description
----------- -----------
3.1* Certificate of Incorporation of ESI Tractebel Funding Corp.
(formerly IEC Funding Corp.)
3.1.1***** Certificate of Amendment of Certificate of Incorporation of
IEC Funding Corp as filed with the Secretary of State of the
State of Delaware on February 3, 1998
3.2***** By-laws of ESI Tractebel Funding Corp.
3.3***** Amended and Restated Certificate of Limited Partnership of
Northeast Energy Associates, A Limited Partnership, as filed
with the Secretary of State of the Commonwealth of
Massachusetts on March 31, 1986, as amended and restated on
January 9, 1987 and November 6, 1987, as further amended on
July 6, 1989 and as amended and restated on February 16,
1998
3.4***** Amended and Restated Certificate of Limited Partnership of
North Jersey Energy Associates, A Limited Partnership, as
filed with the Secretary of State of the State of New Jersey
on November 3, 1986, as amended and restated on January 14,
1987, June 25, 1987, March 4, 1988 and February 16, 1998
3.5* Certificate of Incorporation of Intercontinental Energy
Corporation, a Massachusetts corporation ("IEC"), the sole
general partner of the Partnerships (the "General Partner")
3.6* By-laws of the General Partner
3.7***** Amended and Restated Agreement of Limited Partnership of
Northeast Energy Associates, A Limited Partnership, dated as
of November 21, 1997
3.8***** Amended and Restated Agreement of Limited Partnership of
North Jersey Energy Associates, A Limited Partnership, dated
as of November 21, 1997
3.9***** 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
75
<PAGE>
3.10***** Agreement of Limited Partnership of Northeast Energy, LP, a
Delaware limited partnership, dated as of November 21, 1997
4.1* Trust Indenture dated as of November 15, 1994, among the
Partnerships, IEC Funding and State Street Bank and Trust
Company, a Massachusetts banking corporation, as trustee
(the "Trustee")
4.2* First Supplemental Indenture dated as of November 15, 1994,
among the Partnerships, IEC Funding and the Trustee,
including forms of the Securities
4.3* Credit Agreement dated as of December 1, 1994, among the
Partnerships, each of the financial institutions referred to
therein as a "Bank" (and collectively referred to as the
"Banks") and Sanwa Bank Limited, New York Branch ("Sanwa"),
as issuing bank (in such capacity, the "Issuing Bank") and
as agent for the Banks and the Issuing Bank (in such
capacity, the "Agent")
4.4* Collateral Agency Agreement dated as of December 1, 1994
(the "Collateral Agency Agreement"), among the Partnerships,
IEC Funding, the Trustee, Sanwa, the Swap Providers (as
defined therein) and State Street Bank and Trust Company, as
Collateral Agent (in such capacity, the "Collateral Agent")
4.5* Amended and Restated Project Loan and Credit Agreement dated
as of December 1, 1994, between the Partnerships and IEC
Funding
4.6* Partnerships' Guarantee Agreement dated as of December 1,
1994, between the Partnerships and the Trustee
4.7* Registration Rights Agreement dated as of November 21, 1994,
among the Partnerships, IEC Funding, Chase Securities, Inc.,
Merrill Lynch, Pierce Fenner & Smith, Incorporated and
Salomon Brothers, Inc.
4.8* Pledge, Trust and Intercreditor Agreement dated as of
December 1, 1994 (the "Pledge, Trust and Intercreditor
Agreement"), among the Partnerships, Sanwa, as "Bank Agent,"
as a "Bank" and as a "Letter of Credit Bank" (each as
defined therein), Sanwa Bank Trust Company of New York, as
trustee, the Collateral Agent and the Trustee
4.9* Assignment and Security Agreement dated as of December 1,
1994, between IEC Funding and the Collateral Agent
4.10* Amended and Restated Assignment and Security Agreement dated
as of December 1, 1994, between the Partnerships, the
General Partner and the Collateral Agent
4.11* Amended and Restated Assignment and Security Agreement dated
as of December 1, 1994, between NEA and the Collateral Agent
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<PAGE>
4.12* Amended and Restated Assignment and Security Agreement dated
as of December 1, 1994, between NJEA and the Collateral
Agent
4.13* Amended and Restated Mortgage, Assignment of Rents, Security
Agreement and Fixture Filing dated as of December 1, 1994,
made by NEA in favor of the Collateral Agent
4.14* Amended and Restated Mortgage, Assignment of Rents, Security
Agreement and Fixture Filing (Additional Properties) dated
as of December 1, 1994, made by NEA in favor of the
Collateral Agent
4.15* Amended and Restated Indenture of Mortgage, Assignment of
Rents, Security Agreement and Fixture Filing dated as of
December 1, 1994, made by NJEA in favor of the Collateral
Agent
4.16* Amended and Restated Stock Pledge Agreement dated as of
December 1, 1994, between NJEA and the Collateral Agent
4.17* Assignment of Mortgage dated as of December 1, 1994, between
The Chase Manhattan Bank (National Association) (the
"Existing Agent") and the Collateral Agent with respect to
the Bellingham Mortgage dated as of June 28, 1989
4.18* Assignment of Mortgage dated as of December 1, 1994, between
the Existing Agent and the Collateral Agent with respect to
the Bellingham Mortgage dated August 10, 1989
4.19* Assignment of Mortgage dated as of December 1, 1994, between
the Existing Agent and the Collateral Agent with respect to
the Sayreville Mortgage dated June 28, 1989
4.20* Assignment of Security Agreements dated as of December 1,
1994, among the Existing Agent, the Collateral Agent, the
Partnerships, IEC Funding and the General Partner
4.21* Stock Pledge Agreement dated as of December 1, 1994, among
Broad Street Contract Services, Inc., Stephen B. Roy, Ellen
S. Roy, Jane L. Roy, Peter A. Roy, the Partnerships and the
Collateral Agent
4.22***** Second Supplemental Trust Indenture dated as of January 14,
1998 among IEC Funding Corp., Northeast Energy Associates, A
Limited Partnership, North Jersey Energy Associates, A
Limited Partnership and State Street Bank and Trust Company,
as trustee.
4.23***** Amendment to Amended and Restated Assignment and Security
Agreement by and between NEA, NJEA, IEC and State Street
Bank and Trust Company dated as of January 14, 1998
77
<PAGE>
4.24***** Termination of Pledge, Trust and Intercreditor Agreement
dated as of January 30, 1998 among NJEA, NEA, the Sanwa
Bank, Limited, New York Branch, as "Bank Agent," Sanwa Bank
Trust Company of New York, as trustee and State Street Bank
and Trust Company, as Collateral Agent and the Bond Trustee
10.1* Accommodation Agreement dated as of June 28, 1989, between
NEA, Boston Edison Company, a Massachusetts corporation
("BECO"), Commonwealth Electric Company, a Massachusetts
corporation ("Commonwealth"), Montaup Electric Company, a
Massachusetts corporation ("Montaup"), and The Chase
Manhattan Bank (National Association)
10.2.1* Amended and Restated Operation and Maintenance Agreement
dated as of June 28, 1989 (the "Sayreville O&M Agreement"),
between NJEA and Westinghouse Electric Corporation, a
Pennsylvania company ("Westinghouse")
10.2.2* Letter Agreement regarding the Sayreville Heat Rate dated
June 23, 1993, between NJEA and Westinghouse
10.2.3* Letter Agreement regarding extension of the Sayreville O&M
Agreement dated June 23, 1993, between Westinghouse and NJEA
10.2.4* Second Amended and Restated Operation and Maintenance
Agreement dated as of June 28, 1989 (the "Bellingham O&M
Agreement"), between NEA and Westinghouse
10.2.5* Letter Agreement regarding the Bellingham Heat Rate dated
June 23, 1993, between NEA and Westinghouse
10.2.6* Letter Agreement regarding extension of the Bellingham O&M
Agreement dated June 23, 1993, between NEA and Westinghouse
10.2.7** Amendment No. 1 to the Bellingham O&M Agreement, dated as
of May 1, 1995, by and between NEA and Westinghouse
10.3.1* Power Purchase Agreement dated as of April 1, 1986 (the
"BECO I Power Purchase Agreement"), between NEA and BECO
10.3.2* First Amendment to the BECO I Power Purchase Agreement dated
as of June 8, 1987, between BECO and NEA
10.3.3* Second Amendment to the BECO I Power Purchase Agreement
dated as of June 21, 1989, between BECO and NEA
10.3.4* Power Purchase Agreement dated as of January 28, 1988 (the
"BECO II Power Purchase Agreement"), between NEA and BECO
10.3.5* First Amendment to the BECO II Power Purchase Agreement
dated as of June 21, 1989, between NEA and BECO
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<PAGE>
10.3.6* Power Sale Agreement dated as of November 26, 1986 (the
"Commonwealth I Power Purchase Agreement"), between NEA and
Commonwealth
10.3.7* First Amendment to the Commonwealth I Power Purchase
Agreement dated as of August 15, 1988, between Commonwealth
and NEA
10.3.8* Second Amendment to the Commonwealth I Power Purchase
Agreement dated as of January 1, 1989, between Commonwealth
and NEA
10.3.9* Power Sale Agreement dated as of August 15, 1988 (the
"Commonwealth II Power Purchase Agreement"), between NEA and
Commonwealth
10.3.10* First Amendment to the Commonwealth II Power Purchase
Agreement dated as of January 1, 1989, between NEA and
Commonwealth
10.3.11* Power Purchase Agreement dated as of October 17, 1986 (the
"Montaup Power Purchase Agreement"), between NEA and Montaup
10.3.12* First Amendment to the Montaup Power Purchase Agreement
dated as of June 28, 1989, between Montaup and NEA
10.3.13* 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")
10.3.14* First Amendment to the JCP&L Power Purchase Agreement dated
as of June 16, 1989, between JCP&L and NJEA
10.4.1* Firm Transportation Service Agreement dated as of February
28, 1994, among CNG Transmission Corporation, a Delaware
corporation ("CNG"), NEA, ProGas U.S.A., Inc., a Delaware
corporation ("ProGas USA") and ProGas Limited, a Canadian
corporation ("ProGas")
10.4.2* Firm Gas Transportation Agreement (Rate Schedule X-320)
dated as of February 27, 1991, between NEA and
Transcontinental Gas Pipe Line Corporation, a Delaware
corporation ("Transco")
10.4.3* Rate Schedule X-35 Firm Gas Transportation Agreement dated
as of October 1, 1993, between NEA and Algonquin Gas
Transmission Company, a Delaware corporation ("Algonquin")
10.4.4* Service Agreement for Rate Schedule FTS-5 dated as of
February 16, 1994, between NEA and Texas Eastern
Transmission Corporation, a Delaware corporation ("Texas
Eastern")
10.4.5* ProGas/TransCanada NE Assignment Agreement dated as of July
30, 1993, between ProGas and TransCanada Pipelines Limited,
an Ontario corporation ("TransCanada")
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10.4.6* Northeast Gas Substitution Agreement dated as of
July 30, 1993, among ProGas, NEA and TransCanada
10.4.7* Northeast Notice and Consent dated as of July 30, 1993,
among NEA, ProGas and TransCanada
10.4.8* ProGas NE Producer Assignment Agreement dated as
of July 30, 1993, between ProGas and TransCanada
10.4.9* Firm Transportation Service Agreement dated as of February
28, 1994, among CNG, NJEA, ProGas USA and ProGas
10.4.10* Firm Gas Transportation Agreement (Rate Schedule X-319)
dated as of February 27, 1991, between Transco and NJEA
10.4.11* Service Agreement for Rate Schedule FTS-5 dated as of
February 16, 1994, between Texas Eastern and NJEA
10.4.12* ProGas/TransCanada NJ Assignment Agreement dated as of July
30, 1993, between ProGas and TransCanada
10.4.13* North Jersey Gas Substitution Agreement dated as of July 30,
1993, among ProGas, NJEA and TransCanada
10.4.14* North Jersey Notice and Consent dated as of July 30, 1993,
among NJEA, ProGas and TransCanada
10.4.15* ProGas NJ Producer Assignment dated as of July 30, 1993,
between ProGas and TransCanada
10.4.16* Gas Purchase and Sales Agreement dated as of May 4, 1989
(the "PSE&G Agreement"), between NJEA and Public Service
Electric and Gas Company, a New Jersey corporation ("PSE&G")
10.5.1* Service Agreement Applicable to the Storage of Natural Gas
Under Rate Schedule GSS-II dated as of September 30, 1993,
between CNG and NEA
10.5.2* Service Agreement Applicable to the Storage of Natural Gas
Under Rate Schedule GSS-II dated as of September 30, 1993,
between CNG and NJEA
10.5.3** Service Agreement Applicable to Transportation of Natural
Gas under Rate Schedule FT dated as of February 1, 1996, by
and between CNG and NEA
10.5.4** Service Agreement Applicable to Transportation of Natural
Gas under Rate Schedule FT dated as of February 1, 1996, by
and between CNG and NJEA
10.6.1* Gas Purchase Contract dated as of May 12, 1988 (the
"Bellingham ProGas Agreement"), between ProGas and NEA
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10.6.2* First Amending Agreement to the Bellingham ProGas Agreement
dated as of April 17, 1989, between ProGas and NEA
10.6.3* Second Amending Agreement to the Bellingham ProGas Agreement
dated as of June 23, 1989, between ProGas and NEA
10.6.4* Amending Agreement to the ProGas Agreements (as defined
below) dated as of November 1, 1991, between ProGas, NEA and
NJEA
10.6.5* Third Amending Agreement to the Bellingham ProGas Agreement
dated as of July 30, 1993, between ProGas and NEA
10.6.6* Letter Agreement regarding the Bellingham ProGas Agreement
dated as of September 14, 1992, between ProGas and NEA
10.6.7* Letter Agreement regarding the Bellingham ProGas Agreement
dated as of July 30, 1993, between ProGas and NEA
10.6.8* 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
10.6.9* First Amending Agreement to the Sayreville ProGas Agreement
dated April 17, 1989, between ProGas and NJEA
10.6.10* Second Amending Agreement to the Sayreville ProGas Agreement
dated June 23, 1989, between ProGas and NJEA
10.6.11* Third Amending Agreement to the Sayreville ProGas Agreement
dated July 30, 1993, between ProGas and NJEA
10.6.12* 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
10.6.13* Letter Agreement regarding the Sayreville ProGas Agreement
dated July 30, 1993, between ProGas and NJEA
10.7.1* Amended and Restated Steam Sales Agreement dated as of
December 21, 1990, between NEA and NECO-Bellingham, Inc., a
Massachusetts corporation ("NECO")
10.7.2* Industrial Steam Sales Contract dated as of June 5, 1989,
between NJEA and Hercules Incorporated, a Delaware
corporation ("Hercules")
10.8.1* Letter agreement regarding Bellingham Project power
transmission arrangements dated June 29, 1989, between NEA
and BECO
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10.8.2* Letter agreement regarding Bellingham Project power
transmission arrangements dated June 6, 1989, between NEA
and Commonwealth
10.8.3* Letter agreement regarding Bellingham Project power
transmission arrangements dated June 28, 1989, between NEA
and Montaup
10.9* Amended and Restated Interconnection Agreement dated as of
September 24, 1993, between BECO and NEA
10.10.1* Amended and Restated Lease Agreement dated as of December
21, 1990, between NEA and NECO
10.10.2* Carbon Dioxide Agreement dated as of December 21, 1990,
between NECO and Praxair, Inc., as successor to Liquid
Carbonic Carbon Dioxide Corporation ("Praxair")
10.10.3* BOC Gases Carbon Dioxide Agreement dated as of December
21, 1990, between NECO and the BOC Gases of the BOC Group,
Inc., a Delaware corporation (BOC Gases)
10.10.4* Assignment and Security Agreement dated as of December 1,
1991, between NECO and NEA
10.10.5*** Operation and Maintenance Agreement by and between
NECO-Bellingham, Inc. as Lessee and Westinghouse Operating
Services Company, Inc. as Operator for the Bellingham
Project Carbon Dioxide Recovery Facility dated as of May
1, 1995
10.10.5.1**** Guaranty of Contract for Operation and
Maintenance dated May 12, 1995 by Westinghouse Electric
10.10.6* Licensing Agreement for the Fluor Daniel Carbon Dioxide
Recovery Process dated as of June 28, 1989, between Fluor
Daniel Inc., a California corporation ("Fluor Daniel"),
and NEA
10.11.1* Ground Lease Agreement dated as of June 28, 1989, between
NJEA and IEC Urban Renewal Corporation, a New Jersey
corporation ("URC")
10.11.2* Agreement of Sublease dated as of June 28, 1989, between
URC and NJEA
10.11.3* Lease of Property dated as of June 1, 1986, between
Prestwich Corporation and the General Partner
10.12.1* Investment Agreement dated as of December 1, 1994, between
Sanwa and Sanwa Bank Trust Company of New York, as trustee
under the Pledge, Trust and Intercreditor Agreement
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10.12.2* Investment Agreement dated as of December 1, 1994, between
Sanwa and Sanwa Bank Trust Company of New York, as trustee
under the Pledge, Trust and Intercreditor Agreement
10.13* Agreement between the Water and Sewer Commissioners of the
Town of Bellingham and NEA dated as of December 13, 1988
and December 30, 1988, respectively
10.14* Mortgage, Assignment of Rents, Security Agreement and
Fixture Filing dated June 29, 1989, by NEA in favor of BECO,
Commonwealth and Montaup
10.15*** Declaration of Easements, Covenants, and Restrictions dated
as of June 28, 1989 by NEA
10.16***** 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.
10.17***** 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.
10.18***** 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
10.19***** 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.
10.20***** Administrative Services Agreement dated as of November 21,
1997 between Northeast Energy, LP, a Delaware limited
partnership and ESI Northeast Energy GP, Inc.
12* Statements regarding computation of ratios
12.1 Statements regarding computation of Ratio of Earnings to
Fixed Charges
21.1* Subsidiary of North Jersey Energy Associates, A Limited
Partnership.
27.1***** Financial Data Schedule - ESI Tractebel Funding Corp.
27.2***** Financial Data Schedule - Northeast Energy Associates
27.3***** Financial Data Schedule - North Jersey Energy Associates
- -------------------
* 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 on February 9, 1995, as amended.
** Incorporated herein by reference from the Annual Report on Form 10-K filed
by IEC Funding and the Partnerships on April 1, 1996.
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*** Incorporated herein by reference from the Quarterly Report on Form 10-Q
filed by IEC Funding and the Partnerships on November 14, 1996.
**** Incorporated herein by reference from the Annual Report on Form 10-K filed
by IEC Funding and the Partnerships on March 31, 1997.
***** Previously filed with Form 10-K for the year ended December 31, 1997 on
March 22, 1998.
(b) Reports On Form 8-K:
On December 2, 1997, IEC Funding Corp. and the Partnerships filed a
report on Form 8-K dated December 2, 1997, in connection with the
Acquisitions covering Item 5 (Other Events).
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, ESI Tractebel Funding Corp., has duly caused this report
to be signed on its behalf by the undersigned hereunto duly authorized in the
City of North Palm Beach, State of Florida, on August 10, 1998.
ESI TRACTEBEL FUNDING CORP.
By: /s/ Glenn E. Smith
-----------------------
Glenn E. Smith
Vice President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on August 10, 1998.
Signature Title
--------- -----
/s/ Glenn E. Smith
- ------------------------------ Vice President
Glenn E. Smith
(Principal Executive Officer)
/s/ Peter D. Boylan
- ------------------------------ Treasurer
Peter D. Boylan
(Principal Financial and
Accounting Officer)
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, North Jersey Energy Associates, A Limited Partnership, has
duly caused this report to be signed on its behalf by the undersigned hereunto
duly authorized in the City of North Palm Beach, State of Florida on August 10,
1998.
NORTH JERSEY ENERGY ASSOCIATES,
A LIMITED PARTNERSHIP
By: NORTHEAST ENERGY LP, as
General Partner
By: ESI NORTHEAST ENERGY GP,
INC., as General Partner
By: /s/ Glenn E. Smith
-------------------------
Glenn E. Smith
Vice President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on August 10, 1998.
Signature Title
--------- -----
/s/ Glenn E. Smith
- ------------------------------- Vice President
Glenn E. Smith
(Principal Executive Officer)
/s/ Peter D. Boylan
- ------------------------------- Treasurer
Peter D. Boylan
(Principal Financial and
Accounting Officer)
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Northeast Energy Associates, A Limited Partnership, has
duly caused this report to be signed on its behalf by the undersigned hereunto
duly authorized in the City of North Palm Beach, State of Florida on August 10,
1998.
NORTHEAST ENERGY ASSOCIATES,
A LIMITED PARTNERSHIP
By: NORTHEAST ENERGY, LP, as
General Partner
By: ESI NORTHEAST ENERGY GP,
INC., as General Partner
By: /s/ Glenn E. Smith
-------------------------
Glenn E. Smith
Vice President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on August 10, 1998.
Signature Title
--------- -----
/s/ Glenn E. Smith
- ----------------------------- Vice President
Glenn E. Smith
(Principal Executive Officer)
/s/ Peter D. Boylan
- ----------------------------- Treasurer
Peter D. Boylan
(Principal Financial and
Accounting Officer)
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APPENDIX A
Defined Terms
Unless the context requires otherwise, any reference in this Form 10-K to
any agreement shall mean such agreement and all schedules, exhibits and
attachments thereto as amended, supplemented or otherwise modified and in effect
from time to time. Unless otherwise stated, any reference in this Form 10-K to
any person or entity shall include its successors and assignees and, in the case
of any government authority, any entity succeeding to its functions and
capacities. All terms defined herein used in the singular shall have the same
meanings when used in the plural and vice versa.
"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.
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"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.
"BankBoston" means BankBoston, N.A.
"BOC Gases" means the BOC Cases Division of the BOC Group, Inc., a Delaware
corporation.
"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.
"Btu" means British thermal units, a unit of energy.
"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.
"Clean Air Act" means the Federal Clean Air Act of 1955, as amended.
"CNG" means CNG Transmission Corporation, a Delaware corporation.
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"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.
"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.
"CRSS" means CRSS, Inc.
"Daily NEA Quantity" means 48,817 Dth of natural gas.
"Daily NJEA Quantity" means 22,019 Dth of natural gas.
"Debt" of any Person, as defined in the Project Indenture, means (i) all
obligations of such Person for borrowed money, (ii) all obligations of such
Person evidenced by bonds, debentures, notes or other similar instruments, (iii)
all obligations of such Person to pay the deferred purchase price of property or
services, (iv) all obligations under capital leases of such Person, (v) all Debt
of others secured by a Lien on any asset of such Person, whether or not such
Debt is assumed by such Person (vi) all Debt of others to the extent guaranteed
by such Person, (vii) all obligations under letters of credit issued for the
account of such Person, (viii) all obligations of such Person under trade or
bankers' acceptances and (ix) all obligations of such Person under agreements
providing for interest rate swaps, collars or caps.
"Debt Service 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
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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.
"Dollars" and "$" means lawful money of the United States.
"DTE" means Department of Telecommunications and Energy.
"Energy Bank" or "Energy Bank Obligations" means an account recording the
liability of a Partnership to a Power Purchaser representing cumulative payments
made to such Partnership by such Power Purchaser under the applicable Power
Purchase Agreement in excess of such Power Purchaser's Avoided Costs, determined
in accordance with such Power Purchase Agreement.
"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.
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"ESI LP" means ESI Northeast Energy LP, Inc., a Florida 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.
"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(o)F and 14(o)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.
"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 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.
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"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.
"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 the Issuer, NE LP, ESI Tractebel Funding or a
Partnership or, where the context requires, by any other Person party to a
Project Document.
"Government Authority" means any United States federal, state, municipal,
local, territorial or other governmental subdivision, department, commission,
board, bureau, agency, regulatory authority, instrumentality, judicial or
administrative body, domestic or foreign.
"Government Rule" means any statute, law, regulation, ordinance, rule,
judgment, order, decree, permit, concession, grant, franchise, code, license,
directive, guideline, policy or rule of common law, requirement of, or other
governmental restriction or any judicial or administrative order, consent decree
or judgement or similar form of decision of or determination by, or any
interpretation or administration of any of the foregoing by, any Government
Authority, whether now or hereafter in effect.
"GSR Deficiency", as defined in the Project Indenture, is now zero.
"Guaranty", as defined in the Project Indenture, by any Person means any
guaranty, surety, bond or other obligation, contingent or otherwise, of such
Person directly or indirectly guaranteeing in any manner any Debt or other
obligation of any other Person and, without limiting the generality of the
foregoing, any obligation, direct or indirect, contingent or otherwise, of such
Person: (i) to purchase or pay (or advance or supply funds for the purchase or
payment of) such Debt or other
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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.
"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.
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"ISO Conditions" means a temperature of 59 degrees F and an atmospheric
pressure of 29.92 inches of mercury absolute (i.e. sea level).
"JCP&L" means Jersey Central Power & Light Company, a New Jersey corporation.
"JCP&L Power Purchase Agreement" means the Power Purchase Agreement dated as
of October 22, 1987, between NJEA and JCP&L, as amended.
"Kilowatt" or "KW" means one thousand watts.
"Kilowatt-hours" or "kWh" means a unit of electrical energy equal to one
kilowatt of power supplied or taken from an electric circuit steadily for one
hour.
"Lien", as defined in the Project Indenture, means, with respect to any
property of any Person, any mortgage, lien, pledge, charge, lease, easement,
servitude, right of others or security interest or encumbrance of any kind in
respect of such property of such Person.
"Limited Partner" means NE LLC.
"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
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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, 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(o)F and at a pressure of
14.73 pounds per square inch absolute.
"Medway Substation" means the Medway Substation of Boston Edison, located in
Medway, Massachusetts.
"Megawatt" or "MW" means one million watts.
"Megawatt hour" or "MWH" means one thousand kilowatt-hours.
"MMBtu" means one million Btus.
"Montaup" means Montaup Electric Company, a Massachusetts corporation.
"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.
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"Moody's" means Moody's Investors Service, Inc.
"MOR Deficiency," as defined in the Project Indenture, means, as of any date
of determination subsequent to the first Monthly Transfer Date in calendar year
2001, the excess, if any, of (a) the aggregate Monthly MOR Contribution Amounts
for all prior Monthly Transfer Dates over (b) the excess (if any) of (i) the
aggregate amount of all prior transfers to the Major Overhaul Reserve Fund over
(ii) the aggregate amount of all withdrawals from the Major Overhaul Reserve
Fund made on or prior to such date of determination other than pursuant to the
Project Indenture; provided, that the amount of any MOR Deficiency (i) shall be
reduced by the amount of Major Overhaul Expenses previously paid by the
Partnerships from funds other than disbursements from the Major Overhaul Reserve
Fund, (ii) shall be subject to adjustment as provided in the Project Indenture
and (iii) shall be equal to zero as of any date of determination prior to the
first Monthly Transfer Date in calendar year 2001.
"MOU" means Memorandum of Understanding.
"NationsBank" means NationsBank of Texas.
"NE LLC" means Northeast Energy, LLC, a Delaware limited liability company.
"NE LP" means Northeast Energy, LP, a Delaware limited partnership.
"NE LP Partnership Agreement" means the Agreement of Limited Partnership of
Northeast Energy, LP, dated as of November 21, 1997, by and among ESI GP, ESI
LP, Tractebel GP and Tractebel LP.
"NEA" means Northeast Energy Associates, A Limited Partnership, a
Massachusetts limited partnership.
"NEA Additional Properties Mortgage" means the Amended and Restated Mortgage,
Assignment of Rents, Security Agreement and Fixture Filing (Additional
Properties) granted by NEA to the Collateral Agent with respect to certain real
estate owned by NEA adjacent to the NEA Site.
"NEA Fuel Management Agreement" means the Fuel Management Agreement, dated as
of January 20, 1998 (effective retroactively to January 14, 1998) by and between
the Fuel Manager and NE LP, assigned by NE LP to NEA on January 20, 1998.
"NEA Fuel Management Fee" means $450,000, as compensation for certain fuel
management services for the NEA Project pursuant to the NEA Fuel Management
Agreement.
"NEA Gas Agreements" means the NEA ProGas Agreement, the NEA Gas
Transportation Agreements and the NEA Gas Storage Agreement.
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"NEA Gas Storage Agreement" means the Service Agreement Applicable to the
Storage of Natural Gas Under Rate Schedule GSS-II dated as of September 30,
1993, between CNG and NEA, as amended by the parties and in respect of changes
in FERC approved
tariffs.
"NEA Gas Supply Agreement" means the NEA ProGas Agreement.
"NEA Gas Transportation Agreements" means collectively, the Firm
Transportation Service Agreement dated as of February 28, 1994, among CNG, NEA,
ProGas and ProGas U.S.A., Inc., the Firm Gas Transportation Agreement (Rate
Schedule X-320) dated February 27, 1991, between Transco and NEA, the Rate
Schedule X-35 Firm Gas Transportation Agreement dated October, 1993, between
Algonquin and NEA and the Service Agreement for Rate Schedule FTS-5 dated
February 16, 1994, between Texas Eastern and NEA, each as amended by the parties
and in respect of changes in FERC approved tariffs.
"NEA O&M Agreement" means the Second Amended and Restated Operations and
Maintenance Agreement dated as of June 28, 1989, between NEA and the Operator
(as successor to Westinghouse Electric).
"NEA O&M Fee" means the monthly fee required to be paid by NEA to the Operator
pursuant to the NEA O&M Agreement.
"NEA Partnership Agreement" means the Amended and Restated Agreement of
Limited Partnership of Northeast Energy Associates, A Limited Partnership, dated
as of November 21, 1997 by and between NE LP and NE LLC.
"NEA Power Purchase Agreements" means the Boston Edison I Power Purchase
Agreement, the Boston Edison II Power Purchase Agreement, the Commonwealth I
Power Purchase Agreement, the Commonwealth II Power Purchase Agreement and the
Montaup Power Purchase Agreement.
"NEA Power Purchasers" means Boston Edison, Commonwealth and Montaup.
"NEA ProGas Agreement" means the Gas Purchase Contract dated as of May 12,
1988, between NEA and ProGas, as amended.
"NEA Project" means the nominal 300 MW natural gas-fired combined cycle
cogeneration facility owned by NEA located on the NEA Site, including all
electrical and steam generating components, and all electrical, steam and
natural gas interconnection facilities and structures, associated materials,
handling and environmental equipment and ancillary structures, equipment and
systems.
"NEA Project Documents" means, individually and collectively, certain existing
agreements and documents specified in the Project Indenture (which include the
NEA Power Purchase Agreements, the NEA Gas Agreements, the NEA Steam Sales
Agreement and the NECO Lease), as any of the same may from time to time be
amended, modified or supplemented together with all Additional Project Documents
(as defined in the Project Indenture) to which NEA is a party or which relate to
all or any part of the NEA Project as to the Carbon Dioxide Plant.
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"NEA Project Mortgage" means the Amended and Restated Mortgage, Assignment of
Rents, Security Agreement and Fixture Filing granted by NEA to the Collateral
Agent with respect to the NEA Site and all related improvements and fixtures
thereon owned by
NEA.
"NEA Second Mortgage" means the Mortgage, Assignment of Rents, Security
Agreement and Fixture Filing dated as of June 28, 1989, by NEA in favor of
Boston Edison, Commonwealth and Montaup securing the performance by NEA of its
obligations under each of the NEA Power Purchase Agreements.
"NEA Site" means the approximately 44-acre site on the upper Charles River in
the town of Bellingham, Massachusetts, on which the NEA Project and the Carbon
Dioxide Plant are located.
"NEA Steam Sales Agreement" means the Amended and Restated Steam Sales
Agreement dated as of December 21, 1990, between NEA and NECO.
"NECO" means NECO-Bellingham, Inc., a special-purpose subsidiary of a
privately held company based in Houston.
"NECO Lease" means the Amended and Restated Lease dated as of December 21,
1990, between NEA and NECO.
"NEPOOL" means the New England Power Pool.
"NEPOOL Agreement" means the NEPOOL Agreement dated September 1, 1971.
"Net Electrical Capability" means the sum of the nameplate rating of the
generators for each Project, as designated by the manufacturer and expressed in
megawatts, less allowance for station service, at which such Project is designed
to operate continuously in a reasonable and prudent manner under ISO conditions
in accordance with good utility practice.
"New 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.
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"New O&M Agreements" means the New NEA O&M Agreement and the New NJEA O&M
Agreement.
"New O&M Fees" means the fees as compensation for the operation and
maintenance services for the Projects under the New O&M Agreements.
"New Operator" means ESI Operating Services, Inc., a Florida corporation.
"1990 Amendments" means the 1990 Amendments to the Federal Clean Air Act of
1955.
"NJBPU" means the New Jersey Board of Public Utilities.
"NJEA" means North Jersey Energy Associates, A Limited Partnership, a New
Jersey limited partnership.
"NJEA Fuel Management Agreement" means the Fuel Management Agreement, dated as
of January 20, 1998 (effective retroactively to January 14, 1998) by and between
the Fuel Manager and NE LP, assigned by NE LP to NJEA on January 20, 1998.
"NJEA Fuel Management Fee" means $450,000, as compensation for certain fuel
management services for the NJEA Project pursuant to the NJEA Fuel Management
Agreement.
"NJEA Gas Agreements" means, collectively, the NJEA ProGas Agreement, the
PSE&G Contract, the NJEA Gas Transportation Agreements and the NJEA Gas Storage
Agreement.
"NJEA Gas Storage Agreement" means the Service Agreement Applicable to the
Storage of Natural Gas Under Rate Schedule GSS-II dated as of September 30,
1993, between CNG and NJEA.
"NJEA Gas Supply Agreements" means, collectively, the NJEA ProGas Agreement
and the PSE&G Contract.
"NJEA Gas Transportation Agreements" means collectively, the Firm
Transportation Service Agreement dated as of February 28, 1994, among CNG, NJEA,
ProGas and ProGas U.S.A., Inc., the Firm Gas Transportation Agreement (Rate
Schedule X-319) dated February 27, 1991, between Transco and NJEA and the
Service Agreement for Rate Schedule FTS-5 dated February 16, 1994, between Texas
Eastern and NJEA, each as amended by the parties and in respect of changes in
FERC approved tariffs.
"NJEA O&M Agreement" means the Amended and Restated Operations and Maintenance
Agreement dated as of June 28, 1989, between NJEA and the Operator (as successor
to Westinghouse Electric).
"NJEA O&M Fee" means the monthly fee required to be paid by NJEA to the
Operator pursuant to the NJEA O&M Agreement.
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"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
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computed at the maximum amount thereof which could, at the time such agreement
is entered into, reasonably be expected to become due and payable.
"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.
"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
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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.
"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
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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.
"Policy Act" means the Energy Policy Act of 1992.
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"Power Purchase Agreements" means individually and collectively, the Boston
Edison I Power Purchase Agreement, the Boston Edison II Power Purchase
Agreement, the Commonwealth I Power Purchase Agreement, the Commonwealth II
Power Purchase Agreement, the Montaup Power Purchase Agreement and the JCP&L
Power Purchase Agreement, and any Additional Project Document (as defined in the
Project Indenture) (other than a Non-Material Project Document) providing for
the sale of electric energy or capacity from the Projects.
"Power Purchasers" means Boston Edison, Commonwealth, JCP&L and Montaup and
any other Person (other than the Partnerships) party to a Power Purchase
Agreement.
"Praxair" means Praxair, Inc., the successor to Liquid Carbonic Carbon Dioxide
Corporation.
"Principal Fund" means the Fund entitled "Principal Fund" described in, and
pursuant to the Project Indenture.
"ProGas" means ProGas Limited, an Alberta corporation.
"ProGas Agreement Expiration Date" means, with respect to each ProGas
Agreement, the later of (a) November 1, 2006 and (b) the scheduled expiration
date of such ProGas Agreement after giving effect to any Partial ProGas
Extension Events.
"ProGas Agreements" means the NEA ProGas Agreement and the NJEA ProGas
Agreement.
"Project Accounts" means the accounts entitled "Project Accounts" maintained
and used by the Project Trustee.
"Project Collateral," defined as "Collateral" in the Project Indenture, means,
collectively, all of the collateral mortgaged, pledged or assigned to the
Collateral Agent by any of ESI Tractebel Funding, each Partnership, NE LP, ESI
Funding and Tractebel Power, in each case pursuant to the granting and assigning
clauses of the applicable Project Security Documents.
"Project Credit Agreement" means the Amended and Restated Project Loan and
Credit Agreement, dated as of December 1, 1994, by and among ESI Tractebel
Funding and each of the Partnerships.
"Project Documents" means, collectively, the NEA Project Documents and the
NJEA Project Documents.
"Project Guaranty" means the guaranty agreement, by and among the Project
Trustee, NEA and NJEA, guaranteeing the obligations of ESI Tractebel Funding
under the Project Indenture.
"Project Indebtedness," as used in this Offering Circular 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.
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"Project Indenture" means the Trust Indenture dated as of November 15, 1994,
entered into by ESI Tractebel Funding, the Partnerships and the Project Trustee
providing for the issuance of the Project Securities, as supplemented by a First
Supplemental Trust Indenture, dated as of November 15, 1994, and as amended and
supplemented by the Second Supplemental Trust Indenture dated as of January 14,
1998.
"Project Letter of Credit Banks" means the financial institutions from time to
time parties to a Project Letter of Credit Facility.
"Project Letter of Credit Facility" means any agreement or agreements from
time to time in effect among the Partnerships and the Project Letter of Credit
Banks, and any replacements thereof which satisfies the requirements under the
Power Purchase Agreements, the Fluor Daniel Agreement and the Prestwich Lease
providing for the issuance of the Project Letters of Credit. No Letters of
Credit are currently outstanding in connection with the Fluor Daniel Agreement
or the Prestwich Lease.
"Project Letters of Credit" means the Letters of Credit securing the
Partnerships' obligations.
"Project Loans" means the loan made by ESI Tractebel Funding to each of the
Partnerships in connection with the Project Credit Agreement and the Project
Indenture.
"Project Notes" means (a) the promissory notes of the Partnerships issued to
ESI Tractebel Funding on December 1, 1994 pursuant to the Project Credit
Agreement, which notes were issued (x) to amend and restate the Original Project
Notes and (y) to evidence the Project Loans together with (b) any promissory
notes issued by the Partnerships to ESI Tractebel Funding subsequent to December
1, 1994 in accordance with the terms of the Project Credit Agreement.
"Project Partnership Agreements" means, collectively, the NEA Partnership
Agreement and the NJEA Partnership Agreement.
"Project Revenues," as defined in the Project Indenture means, for any period,
the sum of the following (without duplication) received by either of the
Partnerships, or credited to the account of either of the Partnerships as
described in clause (iii) below, on a cash basis during such period: (i) all
revenues 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
106
<PAGE>
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 8.43% Senior Secured Notes Due
2000, Series A, the 9.16% Senior Secured Notes Due 2002, Series A, the 9.32%
Senior Secured Bonds Due 2007, Series A and the 9.77% Senior Secured Bonds Due
2010, Series A 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. "PUHCA" means the Public Utility Holding Company Act of 1935, as
amended.
107
<PAGE>
"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.
"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
108
<PAGE>
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.
"S&P" means Standard & Poor's Ratings Services, a division of McGraw Hill.
"Sanwa Bank" means The Sanwa Bank, Limited, New York Branch.
"Sanwa Credit Agreement" means the Credit Agreement, dated as of December 1,
1994, by and among the Partnerships, Sanwa Bank as issuing bank and as agent,
and the other banks named therein.
"Sanwa Letter of Credit Banks" means the financial institutions from time to
time parties to the Sanwa Letter of Credit Facility,
"Sanwa Letters of Credit" means the letters of credit issued by the Sanwa
Letter of Credit Banks to secure the Partnerships' Energy Bank Obligations.
"Sanwa Working Capital Banks" means the financial institutions from time to
time parties to the Sanwa Working Capital Facility.
"Sanwa Working Capital Facility" means the Working Capital Facility provided
by the Sanwa Working Capital Banks pursuant to the Sanwa Credit Agreement.
"SEC" means the United States Securities and Exchange Commission.
"Second Supplemental Indenture" means the Second Supplemental Trust Indenture
dated as of January 14, 1998 among IEC Funding Corp., Northeast Energy
Associates, A Limited Partnership, North Jersey Energy Associates, A Limited
Partnership and State Street Bank and Trust Company.
"Securities Act" means the Securities Act of 1933, as amended.
"Sellers" means those Sellers identified on Schedule I to the Purchase
Agreement.
"Sponsors" means ESI Energy, Inc. and Tractebel Power, Inc.
"Sponsor Members" means individually and collectively, (i) each of John R. Roy
and Mary Lou Roy, (ii) any lineal descendant or any spouse of any of the
foregoing (excluding Jack Roy and his spouse and their lineal descendants and
their spouses) and (iii) the heirs, executors, legal representatives and
administrators of any of the foregoing.
"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
109
<PAGE>
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 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.
110
<PAGE>
"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
111
<PAGE>
such reduction to the applicable Tax Requirements shall occur if the entity on
which the tax is imposed is treated as a pass-through entity in such
jurisdiction.
"Texas Eastern" means Texas Eastern Transmission Line Corporation, a Delaware
corporation.
"Tractebel Belgium" means Tractebel S.A., a company organized under the laws
of Belgium.
"Tractebel GP" means Tractebel Northeast Generation GP, Inc., a Delaware
corporation.
"Tractebel LP" means Tractebel Associates Northeast LP, Inc., a Delaware
corporation.
"Tractebel Power" means Tractebel Power, Inc., a Delaware corporation.
"Tractebel" means Tractebel, Inc., a Delaware corporation.
"TransCanada" means Trans Canada Pipelines Limited, an Ontario corporation.
"Transco" means Transcontinental Gas Pipe Line Corporation, a Delaware
corporation.
"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
112
<PAGE>
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).
"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.
113
<PAGE>
Index to Financial Statements
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Page
----
<S> <C>
Northeast Energy Associates, A Limited Partnership, and North Jersey
Energy Associates, A Limited Partnership
Report of Independent Accountants................................................................... F-2
Combined Balance Sheet at December 31, 1996 and 1997................................................ F-3
Combined Statement of Operations for the years ended December 31, 1995,
1996 and 1997 ...................................................................................... F-4
Combined Statement of Partners' Deficit for the years ended December 31, 1995,
1996 and 1997 ...................................................................................... F-5
Combined Statement of Cash Flows for the years ended December 31, 1995,
1996 and 1997 ...................................................................................... F-6
Notes to Combined Financial Statements.............................................................. F-8
ESI Tractebel Funding Corp. (formerly IEC Funding Corp.)
Report of Independent Accountants .................................................................. F-21
Balance Sheet at December 31, 1996 and 1997......................................................... F-22
Statement of Operations for the years ended December 31, 1995, 1996 and 1997........................ F-23
Statement of Cash Flows for the years ended December 31, 1995, 1996 and 1997........................ F-24
Notes to Financial Statements....................................................................... F-25
</TABLE>
<PAGE>
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-20) present fairly, in all material respects, the financial
position of Northeast Energy Associates, A Limited Partnership, and North Jersey
Energy Associates, A Limited Partnership, at December 31, 1996 and 1997, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1997, in conformity with generally accepted
accounting principles. These financial statements are the responsibility of the
Partnerships' managements; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
Price Waterhouse LLP
Boston, Massachusetts
March 24, 1998
F-2
<PAGE>
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED BALANCE SHEET
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1996 1997
-------- --------
(IN THOUSANDS)
<S> <C> <C>
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 Tractebel 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 Tractebel 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
-------- --------
-------- --------
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE>
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------
1995 1996 1997
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
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
-------- -------- --------
-------- -------- --------
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE>
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENT OF PARTNERS' DEFICIT
<TABLE>
<CAPTION>
GENERAL LIMITED PARTNERS'
PARTNER PARTNERS DEFICIT
------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
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)
------- --------- ---------
------- --------- ---------
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE>
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------
1995 1996 1997
-------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
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
-------- --------- ---------
-------- --------- ---------
</TABLE>
Non-cash Investing Activities
In 1996 and 1997, total capitalized facility costs which were accrued at year
end for payment were approximately $165,000 and $240,000, respectively.
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE>
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP, AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENT OF CASH FLOWS--(CONTINUED)
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------
1995 1996 1997
-------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
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
-------- --------- ---------
-------- --------- ---------
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-7
<PAGE>
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-8
<PAGE>
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-9
<PAGE>
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-10
<PAGE>
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-11
<PAGE>
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-12
<PAGE>
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:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1996 1997
------------ ------------
<S> <C> <C>
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
------------ ------------
------------ ------------
</TABLE>
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:
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31,
- ----------------------------------------------------------
<S> <C>
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
------------
------------
</TABLE>
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-13
<PAGE>
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-14
<PAGE>
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-15
<PAGE>
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:
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31,
- ------------------------------------------------------------
<S> <C>
1998............................................... $ 189,000
1999............................................... 201,000
2000............................................... 213,000
2001............................................... 225,000
2002............................................... 237,000
Thereafter......................................... 2,760,000
----------
$3,825,000
----------
----------
</TABLE>
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-16
<PAGE>
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:
<TABLE>
<CAPTION>
NEA NJEA
---------- ----------
<S> <C> <C>
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
---------- ----------
---------- ----------
</TABLE>
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-17
<PAGE>
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.
<TABLE>
<CAPTION>
CONTRACT OR CONTRACT OR
NOTIONAL AMOUNT NOTIONAL AMOUNT
AT DECEMBER 31, AT DECEMBER 31,
1996 1997
-------------------------- --------------------------
$ MMBTU $ MMBTU
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
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 -- --
</TABLE>
F-18
<PAGE>
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:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------
1995 1996 1997
---------- ---------- ----------
<S> <C> <C> <C>
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
</TABLE>
The estimated fair value and related carrying amounts of certain financial
instruments is as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1996 DECEMBER 31, 1997
------------------------------ ------------------------------
RELATED RELATED
CARRYING CARRYING
FAIR VALUE AMOUNT FAIR VALUE AMOUNT
$ $ $ $
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
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) -- -- --
</TABLE>
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-19
<PAGE>
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-20
<PAGE>
Report of Independent Accountants
To the Stockholders of ESI Tractebel Funding Corp.
(formerly IEC Funding Corp.)
In our opinion, the accompanying balance sheet and the related statements of
operations and of cash flows present fairly, in all material respects, the
financial position of ESI Tractebel Funding Corp. (formerly IEC Funding Corp.)
(the Company) at December 31, 1996 and 1997, and the results of its operations
and its 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 Company's management; 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-21
<PAGE>
ESI TRACTEBEL FUNDING CORP.
(FORMERLY IEC FUNDING CORP.)
BALANCE SHEET
<TABLE>
<CAPTION>
December 31,
--------------------------
1996 1997
----------- ------------
(In thousands)
<S> <C> <C>
Assets
Current assets:
Cash $ 1 $ 1
Current portion of notes receivable from the Partnerships 24,075 21,563
----------- -----------
Total current assets 24,076 21,564
Notes receivable from Partnerships 490,287 468,724
----------- -----------
Total assets $ 514,363 $ 490,288
=========== ===========
Liabilities and Stockholders' Equity
Current liabilities:
Current portion of securities payable $ 24,075 $ 21,563
----------- -----------
Total current liabilities 24,075 21,563
Securities payable 490,287 468,724
----------- -----------
Total liabilities 514,362 490,287
Stockholders' equity:
Common stock, no par value, 10,000 shares authorized, issued and
outstanding 1 1
----------- -----------
Total liabilities and stockholders' equity $ 514,363 $ 490,288
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-22
<PAGE>
ESI TRACTEBEL FUNDING CORP.
(FORMERLY IEC FUNDING CORP.)
STATEMENT OF OPERATIONS
For the year ended
December 31,
-------------------------------------------------
1995 1996 1997
---- ---- ----
(In thousands)
Interest income $ 51,084 $ 49,404 $ 47,303
Interest expense (51,084) (49,404) (47,303)
------------ --------------- --------------
Net income $ -- $ -- $ --
------------ --------------- --------------
The accompanying notes are an integral part of these financial statements.
F-23
<PAGE>
ESI TRACTEBEL FUNDING CORP.
(FORMERLY IEC FUNDING CORP.)
STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
For the year ended
December 31,
----------------------------------------------
1995 1996 1997
---- ---- ----
(In thousands)
<S> <C> <C> <C>
Increase (Decrease) in Cash
Cash flows from operating activities:
Interest received from Partnerships $ 51,084 $ 49,404 $ 47,303
Interest paid (51,084) (49,404) (47,303)
------------ ------------ -----------
Net cash provided by operating activities -- -- --
------------ ------------ -----------
Cash flows from financing activities:
Principal received from Partnerships 20,434 25,204 24,075
Principal payments on debt (20,434) (25,204) (24,075)
------------ ------------ -----------
Net cash provided by financing activities -- -- --
------------ ------------ -----------
Net increase in cash -- -- --
Cash at beginning of year 1 1 1
------------ ------------ -----------
Cash at end of year $ 1 $ 1 $ 1
============ ============ ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-24
<PAGE>
ESI TRACTEBEL FUNDING CORP.
(FORMERLY IEC FUNDING CORP.)
NOTES TO FINANCIAL STATEMENTS
1. Nature of Business
IEC Funding Corp. (the "Company") is a Delaware corporation that was
established as a special purpose funding corporation for the purpose of
issuing the Securities described in Note 3. A majority of the common stock
of the Company is owned by the partners of Northeast Energy Associates, a
Limited Partnership, and North Jersey Energy Associates, a Limited
Partnership (the "Partnerships"). The Company acts as agent of the
Partnerships with respect to the Securities and holds itself out as the
agent of the Partnerships in all dealings with third parties relating to
the Securities.
Subsequent to the acquisition discussed in Note 4, the Company changed its
name to ESI Tractebel Funding Corp.
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
development of power production facilities, such as cogeneration, by
requiring electric utilities to purchase power generated by qualifying
facilities.
The Partnerships were organized in 1986 to develop, finance, construct,
own, manage and operate two 300 megawatt gas-fueled cogeneration
facilities, one in Bellingham, Massachusetts and one in Sayreville, New
Jersey. During 1986, the Partnerships were granted permission by FERC to
operate the proposed cogeneration facilities as qualifying facilities
defined in PURPA and as defined in federal regulations.
2. 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. Placement of Securities
On December 1, 1994, 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:
<TABLE>
<CAPTION>
December 31,
--------------------------------
1996 1997
---- ----
<S> <C> <C>
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
============== ==============
</TABLE>
F-25
<PAGE>
ESI TRACTEBEL FUNDING CORP.
(FORMERLY IEC FUNDING CORP.)
NOTES TO FINANCIAL STATEMENTS--(Continued)
3. Placement of Securities--(Continued)
Effective February 10, 1995, the Company 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.
Interest on the above securities is payable semiannually on each June 30
and December 30, commencing December 30, 1994. Principal repayments are
made semiannually commencing on June 30, 1995 and are in amounts stipulated
in the trust indenture. Future principal payments are as follows:
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.
The proceeds of the Securities were used (a) to purchase the notes
outstanding under the loan and credit agreement of the Partnerships and (b)
to make loans to the Partnerships. In connection with these two
transactions, the notes outstanding under the loan and credit agreement of
the Partnerships were surrendered and new notes of the Partnerships were
issued to the Company in an aggregate principal amount equal to the
aggregate principal amount of the Securities (the "New Notes") and the loan
and credit agreement of the Partnerships was assigned to the Company and
amended and restated (the "Amended and Restated Credit Agreement").
The Securities are unconditionally guaranteed, jointly and severally, by
the Partnerships and 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.
The trust indenture governing the Securities 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.
F-26
<PAGE>
ESI TRACTEBEL FUNDING CORP.
(FORMERLY IEC FUNDING CORP.)
NOTES TO FINANCIAL STATEMENTS--(Continued)
3. Placement of Securities--(Continued)
The fair value of the Securities and the notes receivable from the
Partnerships at December 31, 1997 is estimated to be $526,010,000. The fair
value of the Securities and the notes receivable from the Partnerships at
December 31, 1996 was estimated to be $564,075,000. The fair value of the
Securities and the notes receivable has been estimated based on the fixed
nature of the Securities and the notes receivable, the credit risk
associated with the Securities and the notes receivable, and the current
borrowing environment available to the Company.
4. 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 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 and the cash collateral requirement related
to the energy bank balances was eliminated in exchange for the guarantee of
one of the acquiring entities.
The financial statements of the Partnerships are included on pages F-2
through F-20.
F-27
EXHIBIT 12.1
Ratio of Earnings to Fixed Charges
(in Thousands of Dollars)
<TABLE>
<CAPTION>
Partnerships Combined
____________________________________________________________________________
Year Ended December 31,
_____________________________________________________________________________
1993 1994 1995 1996 1997
<S> <C> <C> <C> <C> <C>
Earnings to Fixed Charges
Pre-tax income from continuing operations (1,261) (2,979) 26,857 9,924 36,673
Plus:
Fixed charges
Interest expense (debt and energy bank) 46,244 49,744 67,587 69,516 65,108
Amorization of debt issuance costs 2,599 2,333 2,305 2,373 2,163
1/3 Lease expense and equipment rental 138 149 108 122 126
_____________________________________________________________________________
Total fixed charges 48,981 52,226 70,000 72,011 67,397
Total earnings 47,720 49,247 96,857 81,935 104,070
Earnings to Fixed Charge Ratio _ (1) _ (1) 1.38 1.14 1.54
=============================================================================
<CAPTION>
ESI Tractebel Funding Corp.
________________________________________________________________________________
December 31, December 31, December 31, December 31,
1994 1995 1996 1997
________________________________________________________________________________
<S> <C> <C> <C> <C>
Earnings to Fixed Charges
Pre-tax income from continuing operations
Plus:
Fixed charges
Interest expense (debt) 4,305 51,084 49,404 47,303
________________________________________________________________________________
Total fixed charges 4,305 51,084 49,404 47,303
Total earnings 4,305 51,084 49,404 47,303
Earnings to Fixed Charge Ratio 1.00 1.00 1.00 1.00
================================================================================
</TABLE>
- ----------
(1) The Partnerships' earnings for 1993 and 1994 were inadequate to cover fixed
charges. The coverage deficiencies during 1993 and 1994 are $1.261 million
and $2.979 million, respectively.
