SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
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
IEC Funding Corp.
North Jersey Energy Associates, A Limited Partnership
Northeast Energy Associates, A Limited Partnership
______________________________________________________
(Exact Name of Registrant as Specified in its Charter)
Delaware 04-3255377
New Jersey 04-2955646
Massachusetts 04-2955642
_____________ __________
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
350 Lincoln Place, Hingham, Massachusetts 02043
_________________________________________ _____
(Address of Principal Executive Offices) (Zip Code)
(617) 749-9800
______________
(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
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 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. ____
IEC FUNDING CORP.
NORTHEAST ENERGY ASSOCIATES, A LIMITIED PARTNERSHIP
NORTH JERSEY ENERGY ASSOCIATES, A LIMITIED PARTNERSHIP
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1996
INDEX
PART I Page Number
Items 1, 2 and 3. Business, Properties and Legal Proceedings............................ 3
Items 4. Submission of Matters to Vote of Security Holders..................... 39
PART II
Item 5. Market for the Registrant's Common Stock
and Related Stockholder Matters....................................... 39
Item 6. Selected Financial Data............................................... 40
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................................... 41
Item 8. Financial Statements and Supplementary Data........................... 48
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................................... 79
PART III
Item 10. Directors and Executive Officers of the General Partner............... 79
Item 11. Executive Compensation................................................ 81
Item 12. Security Ownership of Certain Beneficial
Owners and Management................................................. 82
Item 13. Certain Relationships and Related Transactions........................ 85
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K................................................... 86
Signatures............................................................ 96
Defined Terms......................................................... A-1
This Annual Report on Form 10-K is filed in respect of three Registrants:
Northeast Energy Associates, A Limited Partnership ("NEA"), North Jersey
Energy Associates, A Limited Partnership ("NJEA") and IEC Funding Corp.
("IEC Funding"). 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.
PART I
ITEMS 1, 2 AND 3. BUSINESS, PROPERTIES AND LEGAL PROCEEDINGS
OVERVIEW
THE PARTNERSHIPS
NEA and NJEA are each limited partnerships, organized, respectively, in
Massachusetts and New Jersey. Each Partnership was formed in 1986 to develop,
construct, own, operate and manage an approximately 300 MW natural gas-fired
combined cycle cogeneration facility, located, respectively, in Bellingham,
Massachusetts (the "Bellingham Project") and Sayreville, New Jersey (the
"Sayreville Project," and together with the Bellingham Project, the "Projects").
The sole general partner of each of the Partnerships is Intercontinental Energy
Corporation, a Massachusetts corporation ("IEC" or the "General Partner"). IEC
is dedicated solely to the development, operation and management of the
Projects.
IEC FUNDING
IEC Funding Corp. ("IEC Funding") is a Delaware corporation 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. IEC Funding issued the New Securities in the
Exchange Offer in exchange for previously issued securities, the proceeds of
which were originally used by IEC Funding to acquire certain outstanding bank
debt of the Partnerships and to lend additional funds to the Partnerships. The
New Securities are guaranteed by the Partnerships. The terms of the
Partnerships' obligations to IEC Funding (the "Loans") are identical to the
terms of the New Securities. The Loans and the related collateral rights are
the only assets of IEC Funding.
THE PROJECTS
Each of the Projects is an approximately 300 MW combined-cycle cogeneration
facility. Cogeneration is a power production technology that sequentially
produces two or more useful forms of energy by means of an integrated process
employing a single fuel source. The Projects, which began commercial operations
in the third quarter of 1991, use natural gas to produce electrical energy and
thermal energy in the form of steam.
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 in order to maintain QF status, which exempts the Projects
from certain Federal and State regulations.
The Projects were constructed by Westinghouse Electric Corporation
("Westinghouse Electric") and, pursuant to long-term contracts with Westinghouse
Electric, are operated and maintained by Westinghouse Operating Services Company
("Westinghouse Services" or the "Operator"), a subsidiary of Westinghouse
Electric.
NEA currently sells all of the net electrical energy produced by the
Bellingham Project to three regulated utilities, Boston Edison Company ("Boston
Edison"), Commonwealth Electric Company ("Commonwealth"), and Montaup Electric
Company ("Montaup"). NJEA currently sells all of the net electrical energy
produced by the Sayreville Project to one regulated utility, Jersey Central
Power & Light Company ("JCP&L"). Such sales are made pursuant to long-term
Power Purchase Agreements, all of which provide for substantially the continuous
delivery of base load power.
Steam generated by the Bellingham Project is sold to NECO-Bellingham, Inc.
("NECO") for use by a carbon dioxide plant (the "Carbon Dioxide Plant") which is
owned by NEA and leased to NECO. The steam generated by the Sayreville Project
is sold to Hercules, Incorporated ("Hercules") for use by its Parlin, New Jersey
plant.
Over 80% of the natural gas that fuels the Projects is supplied to the
Projects pursuant to Long-term Gas Supply Agreements (as defined herein) with
ProGas Limited of Alberta, Canada ("ProGas"), and, in the case of the Sayreville
Project, also with Public Service Electric and Gas of Newark, New Jersey
("PSE&G"). Gas is transported to, or stored for later use by, the Projects
pursuant to Long-term Gas Transportation Agreements and Long-term Gas Storage
Agreements (each defined herein). The Long-term Gas Supply Agreements are
referred to herein collectively as the "Long-term Gas Arrangements." The
remainder of the daily fuel requirements are met by open market purchases
delivered on an interruptible basis both into storage and directly to the
Projects.
For more detailed information regarding the Projects, including the various
contracts referred to above and regulatory matters affecting the Projects, see
"BUSINESS," "REGULATION" and "SUMMARY OF PRINCIPAL PROJECT AGREEMENTS."
2
BUSINESS
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 was enacted. 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 it is priced below the
utility's estimated avoided cost. Concurrently, there has been a decline in the
construction of large generating plants by electric utilities for reasons
largely unrelated to the growth of the independent power industry, including
advances in generating plant technology and increasingly stringent environmental
regulation. As a result, a significant market for electric power produced by
independent power producers such as the Partnerships has developed in the United
States since the enactment of PURPA.
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 are for
the 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 produced by the
facilities) and the year of scheduled expiration with respect to each of the
Power Purchase Agreements:
3
PURCHASER'S
NOMINAL FINAL YEAR
ENTITLEMENT OF CONTRACT
Bellingham Project:
Boston Edison I Contract 135 MW 46% 2016
Boston Edison II Contract 84 MW 29% 2011
Commonwealth I Contract 25 MW 9% 2016
Commonwealth II Contract 21 MW 7% 2016
Montaup Contract 25 MW 9% 2021
------ ---
Bellingham Total 290 MW 100%
====== ===
Sayreville Project:
JCP&L 250 MW 100% 2011
====== ===
The Power Purchase Agreements generally provide for an account, or Energy
Bank, to be maintained representing the cumulative difference from time to time
between (i) the amount paid by the applicable Power Purchaser for electric power
delivered under the applicable Power Purchase Agreement and (ii) the amount of
such Power Purchaser's "Avoided Cost" of electric power, adjusted in certain
cases for peak and off-peak deliveries of electric power from the Projects.
Avoided Cost is, depending on the Power Purchase Agreement, 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 Avoided Cost, a
positive balance will build up in the applicable Energy Bank which, depending on
the terms of the particular Power Purchase Agreement, must be either fully or
partially secured by a letter of credit and, in the case of the Power Purchase
Agreements for the Bellingham Project, a second mortgage lien on such Project
(junior to the Bellingham Project Mortgage). A positive balance in an Energy
Bank 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 in later periods that Avoided Cost has risen
above the contract rate, and must be repaid under certain circumstances in cash.
For a more detailed summary of the Power Purchase Agreements, see "SUMMARY OF
PRINCIPAL PROJECT AGREEMENTS - Power Purchase Agreements."
GAS SUPPLY ARRANGEMENTS
Over 80% of the Projects' combined fuel requirements of natural gas are
supplied under Long-term Gas Arrangements on a "firm" basis, that is, without
interruption except for events of
4
force majeure and in other limited circumstances. The remaining natural gas
supplies are purchased on the open market and transported by various means to
the Projects. The Long-term Gas Arrangements consist of two long-term contracts
for supply and delivery of gas into the United States with ProGas, one long-term
contract for supply and delivery of gas with PSE&G, 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" and "- Gas Transportation and Storage Agreements."
The chart below illustrates natural gas supply consumed by the Projects for
1996 expressed in Bcf and as a percentage of the total gas requirement for each
Project.
SOURCES OF
GAS CONSUMED CONTRACT
BY THE PROJECTS BELLINGHAM SAYREVILLE TOTAL EXPIRATION
(BCF) (BCF) (BCF)
ProGas/(1)/ 14.1 68% 9.4 50% 23.5 59% 2013
PSE&G - 0% 8.4 45% 8.4 21% 2011
Market Purchases 5.5 26% - 0% 5.5 14% N/A
From Storage/(2)/ 1.3 6% 1.0 5% 2.3 6% 2012
---- ---- ---- --- ---- ---
TOTAL 20.9 100% 18.8 100% 39.7 100%
==== ==== ==== === ==== ===
- -----------------------------------------------------
(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 Arrangements from ProGas.
5
STEAM SALES ARRANGEMENTS
BELLINGHAM
FERC Regulations require that at least 5% of a QF's total energy output be
useful thermal energy. To meet this requirement the Bellingham Project sells
60,000 to 70,000 lbs. per hour of steam to NECO for use in the operation of the
Carbon Dioxide Plant.
Steam Sales. NEA has leased the Carbon Dioxide Plant to NECO and entered
into the Bellingham Steam Sales Agreement with NECO. The NECO Lease and the
Bellingham Steam Sales Agreement each have an initial term expiring in 2007,
renewable at NECO's option for up to four renewal periods of five years each.
The Bellingham Steam Sales Agreement provides for NEA to sell to NECO at
least 60,000 lbs. per hour of steam during each hour that the Bellingham Project
is being fueled by 100% pipeline quality natural gas. NECO has the obligation
to buy all its steam from the Bellingham Project whenever the Bellingham Project
is operating, and the obligation to return all condensate. In any hour in which
the Bellingham Project is being fueled by 100% pipeline quality natural gas,
NECO has contracted to accept steam quantities equal to 5% of the Bellingham
Project's total energy output in order for the Bellingham Project to meet the
annual 5% test for the maintenance of QF status under the FERC rules. The price
of steam is adjusted annually according to an index which takes into account the
blended base prices of gas supplied to NEA under the Bellingham ProGas Agreement
and to NJEA under the Sayreville ProGas Agreement, subject to a floor price of
$3.50 per 1,000 lbs. The average price of steam under the Bellingham Steam
Sales Agreement during 1996 was $3.52 per 1,000 lbs. For a more detailed
summary of the Bellingham Steam Sales Agreement and the NECO Lease, See "SUMMARY
OF PRINCIPAL PROJECT AGREEMENTS - Steam Sales Agreements - Bellingham."
In addition to steam, the Bellingham 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 gas to run at least one turbine year-round in this manner. If the
Bellingham 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, NEA will be obligated to pay liquidated damages to NECO.
Carbon Dioxide Sales Agreements. As required by the NECO Lease, NECO has
entered into carbon dioxide sales agreements with BOC Gases and Praxair whereby
NECO agrees to dedicate 55% of the Carbon Dioxide Plant's output to Praxair and
45% of the Carbon Dioxide Plant's output to BOC Gases. BOC Gases and Praxair are
two of the largest suppliers and distributors of carbon dioxide in the United
States. Under the sales agreements, 88% of Praxair's allocation and 65%
6
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 by BOC Gases to NECO is subject to adjustment with
the New England carbon dioxide market price and 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 is reduced to
$33.00 per ton and BOC Gases has a one-time option, exercisable within six
months after construction, to lower the floor price to $30.00 per ton. The price
to be paid by Praxair to NECO is subject to quarterly adjustment with the
wholesale carbon dioxide market price. The price 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 would be reduced to $30.00 per ton.
Operation and Maintenance. The Carbon Dioxide Plant is presently being
operated for NECO by Westinghouse Services pursuant to an agreement between NECO
and Westinghouse Services.
SAYREVILLE
NJEA has entered into the Sayreville 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 Sayreville Project and is connected by
a steam pipeline over land owned by Hercules.
Steam Sales. The Sayreville Steam Sales Agreement has an initial term
expiring in 2011. Under the Sayreville 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,
actual requirements for the calendar year 1996 averaged approximately 129,998
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
lbs. per hour, or (ii) there are more than five total forced outages annually or
more than 15 partial outages annually. Hercules is obligated under the contract
to take sufficient process steam to maintain the Sayreville Project's QF status.
The Sayreville Steam Sales Agreement with Hercules is terminable upon Hercules'
closing its Parlin plant, although in such case Hercules has agreed to lease
NJEA sufficient land to construct an alternative steam host. For a more
detailed summary of the Sayreville Steam Sales Agreement, see "SUMMARY OF
PRINCIPAL PROJECT AGREEMENTS - Steam Sales Agreements - Sayreville 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 Contract during winter and summer peak-
7
hour periods are substantially higher than those in spring and fall. Otherwise,
the business of the Partnerships is not materially subject to seasonal factors.
COMPETITION
The ownership and operation of cogeneration projects are a rapidly growing
business. Many organizations, including equipment manufacturers and subsidiaries
of utilities and contractors, as well as other organizations similar to the
Partnerships, have entered the market. Recent regulatory change has also 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.)
In addition, to the extent that competitive pressure reduces utilities'
purchased power costs, Energy Banks measuring the difference between contract
price and the utility's actual Avoided Cost may increase more rapidly.
EMPLOYEES
Neither the Partnerships nor IEC Funding has any employees. IEC has
approximately 50 employees and provides management services for the Projects.
The Operator provides operations and maintenance services for both of the
Projects. See "MANAGEMENT" and "CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- - Management Fee."
LEGAL PROCEEDINGS
Neither Partnership nor IEC Funding is involved in any material legal
proceedings.
8
PROPERTIES
The Partnerships' principal properties are as follows:
APPROXIMATE
BUILDING
LOCATION PRINCIPAL USE SQUARE FOOTAGE
Hingham, MA/(1)/ Office Space 15,500
NEA
Bellingham, MA
Bellingham Project /(2)/ Power Production 70,000
Carbon Dioxide Plant/(3)/ Carbon Dioxide Production 9,000
Certain residential
properties/(4)/ Residences 27,500
NJEA
Sayreville, NJ
Sayreville Project /(5)/ Power Production 60,000
- ------------------------------------------
/(1)/ IEC has entered into a lease expiring March 31, 1997 for the lease of
office space located at 350 Lincoln Place, Hingham, MA 02043. The monthly
rent due under this lease is $19,659. IEC is in the process of finalizing
a five-year extension to this lease at the same monthly rent.
/(2)/ NEA owns the Bellingham Project and the land upon which it is located
with the exception of a parcel which is leased under a 26 year operating
lease.
/(3)/ The Carbon Dioxide Plant has been leased to NECO pursuant to the NECO
Lease. See "SUMMARY OF PRINCIPAL PROJECT AGREEMENTS - Steam Sales
Agreements - Bellingham."
/(4)/ NEA owns 12 single family dwellings located on land immediately adjacent
to the Bellingham Site.
/(5)/ NJEA owns the Sayreville Project and the land upon which it is located.
The Bellingham Site, the Bellingham Project, the Carbon Dioxide Plant and all
other related improvements and fixtures on the Bellingham Site owned by NEA are
subject to the Bellingham Project Mortgage (as defined below). The Bellingham
Site and the Bellingham Project are also subject to the Second Mortgage and the
Declaration of Easements (as defined below). The Sayreville Site, the
Sayreville Project and all other related improvements and fixtures on the
Sayreville Site owned by NJEA are subject to the Sayreville Mortgage (as defined
below). The residential properties referred to in the chart above are subject
to the Bellingham Additional Mortgage (as defined below).
9
REGULATION
ENERGY REGULATION
PURPA. PURPA provides an electric generating project with rate and
regulatory incentives if the project is a Qualifying Facility. 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 by an electric utility, electric utility holding company or
an entity or person owned by either of the above.
Under PURPA, Qualifying Facilities receive two primary benefits. First,
PURPA exempts Qualifying Facilities 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 securities, rate and financial regulation.
Second, FERC's regulations promulgated under PURPA require that (i) electric
utilities purchase electricity generated by Qualifying Facilities, construction
of which commenced on or after November 9, 1978, at a price based on the
purchasing utility's Avoided Costs, and (ii) the utilities sell supplementary,
back-up, maintenance and interruptible power to Qualifying Facilities 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.
The Partnerships expect the Projects to continue to meet all of the
criteria required for designation as Qualifying Facilities under PURPA. If
either Project were to fail to meet such criteria, the related Partnership and,
by virtue of IEC being the common general partner of both partnerships, 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. The O&M Agreements may be suspended
if the Partnerships operate the Projects in a manner likely to result in the
loss of QF status, and such potential loss is certified by an independent
engineer. See "SUMMARY OF PRINCIPAL PROJECT AGREEMENTS-OPERATION AND MAINTENANCE
AGREEMENTS."
10
PUHCA. PUHCA provides that any corporation, partnership or other entity
or organized group which owns, controls or holds power to vote 10% of the
outstanding voting securities of a "public utility company" or a company which
is a "holding company" of a "public utility company" is subject to registration
with the SEC and regulation under PUHCA, unless eligible for an exemption or an
SEC order declaring it not to be a holding company is granted. 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 which is a subsidiary of a registered holding company under PUHCA is
subject to financial and organizational regulation, including approval by the
SEC of its financing transactions.
The Energy Policy Act of 1992 (the "Policy Act") contains amendments to
PUHCA which may allow the Partnerships to operate their businesses without
becoming subject to PUHCA in the event that either Project loses its status as a
Qualifying Facility. 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. In order 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.
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 Qualifying
Facility 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. Certain of the Power Purchase Agreements contain provisions for a
renegotiation of the rates to be paid for electric energy in such event, and
loss of Qualifying Facility status constitutes an event of default under the
JCP&L Contract.
The FPA's and FERC's authority thereunder 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.
11
State Regulation. The Projects, by virtue of being Qualifying Facilities,
are exempt from New Jersey and Massachusetts rate, financial and organizational
regulations that are applicable to public utilities. However, QFs are not
exempt from the state regulatory commissions' general supervisory powers
relating to environmental and safety matters. In addition, the Bellingham
Project is required to file reports used by the Massachusetts Department of
Public Utilities to forecast long-range electrical power needs.
In the event that the Bellingham Project loses its QF status, in addition
to FPA and PUHCA regulation, NEA and the Bellingham 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 Public Utilities of any issuance of
securities. Similarly, in the event that the Sayreville Project loses its QF
status, in addition to FPA and PUHCA regulation, NJEA and the Sayreville Project
could, depending upon the character and extent of the business activities of
NJEA with respect to sales of electricity from the Sayreville Project, be
subject to a wide range of state statutes and regulations applicable to New
Jersey public utilities, which includes the ability of the New Jersey Board of
Regulatory Commissions ("NJBRC") to fix the rates charged by NJEA for the sale
of the electric energy generated by the Sayreville Project, the approval by the
NJBRC of the issuance of securities by NJEA and the requirements for
periodically furnishing to the NJBRC detailed reports of NJEA's finances and
operations.
Wheeling and Interconnection. Under the FPA, FERC is authorized to
regulate the rates, terms and conditions for the transmission of electric energy
in interstate commerce. This has been interpreted to mean that FERC has
jurisdiction to prescribe the terms of and 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 which 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 and assigned it docket number PL 93-2-002;
however, the terms thereof and rates thereunder remain subject to review by
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 Qualifying Facilities and other wholesale electricity
procedures 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
12
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 expiration of Commonwealth's and
Montaup's access rights to Boston Edison's Medway Substation and interconnecting
the Bellingham Project with Montaup and Commonwealth's respective grids.
However, there is no assurance 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. In the spring of 1996, FERC
promulgated its Order No. 888, an order containing significant policy
initiatives designed at opening the market for generation of electricity to
competition. In its order, FERC promulgated rules requiring utilities owning
transmission facilities to file uniform, nondiscriminatory 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. As of the present, FERC has not approved either of
the proposed tariffs. The Partnerships do not expect Order No. 888 to have a
material impact on their ability to obtain access to transmission lines for
electrical sales to those utilities with whom they have power purchase
agreements.
In the spring of 1996 FERC also issued its Order No. 889. This order
requires utilities owning transmission 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 are required to submit revised
tariffs to FERC during the summer of 1997 to reflect FERC 's orders on
rehearing.
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.
Industry restructuring efforts are also underway in Massachusetts and New
Jersey. Like the federal efforts, the principal announced goal of these
restructuring initiatives is to open the electric generation market to increased
competition. A principal source of controversy in these state initiatives
concerns the ability of investor-owned utilities to recover so-called "stranded
costs." These costs are those that are associated with utility-owned generating
facilities and utility power purchase agreements that may become uneconomic in a
truly competitive market for generation. Certain utilities have stated that
they may have to incur significant losses if they are not able to recover all of
these stranded costs. Both the Massachusetts Department of Public Utilities and
the New Jersey Board of Public Utilities have stated that regulated utilities
should be entitled to recover some or all of these costs, including any above-
market costs related to their power purchase agreements, from their states' rate
payers notwithstanding the emergence of competition in the generation market.
These pronouncements are not binding at the present, and they are subject to
future regulatory proceedings and actions by the legislatures of both states.
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. While the Partnerships do not expect utility industry restructuring to
result in any material adverse change to their Power Purchase Agreements, the
impact of electrical industry restructuring on the companies that purchase power
from the Partnerships is uncertain.
13
PERMIT STATUS
The Partnerships believe that as of the date of this report all material
permits required for the operation of the Projects have been obtained.
The 1990 Amendments 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. These requirements could subject the Projects to additional
limitations upon their emissions of nitrogen oxides ("NOx") and volatile organic
compounds ("VOCs").
With regard to NOx standards, as long as the Projects comply with their air
permits, they will also meet the NOx standards currently established by
Massachusetts and New Jersey. Although the adequacy of these standards has yet
to be confirmed by the EPA, the Partnerships believe that the EPA is unlikely to
disapprove of these standards or to impose emission limits more stringent than
those in the Projects' permits. With regard to the VOC standards, the
Massachusetts standards currently exempt facilities such as the Bellingham
Project, and NEA believes that the EPA is unlikely to disapprove of this
exemption. Although New Jersey has promulgated additional VOC regulations, such
regulations will not apply to the Sayreville Project due to that Project's low
VOC emissions.
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 Sayreville Project and the Bellingham
Project and 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.
14
POWER PURCHASE AGREEMENTS
BELLINGHAM POWER PURCHASE AGREEMENTS
Boston Edison I Contract
The Power Purchase Agreement entered into by NEA and Boston Edison as of
April 1, 1986 (the "Boston Edison I Contract"), provides for the sale to Boston
Edison of 46% of the net power actually generated by the Bellingham Project.
Term. The Boston Edison I Contract 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 Contract for an additional five years upon six months
written notice.
Purchase and Delivery. Pursuant to the Boston Edison I Contract, 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 Bellingham
Project equal to the ratio of 135 MW to the Net Electrical Capability of 290 MW
of the Bellingham Project multiplied by 100% of the available capacity and
hourly generation of the Bellingham Project, or 46% 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
Bellingham Project is operating above or below its Net Electrical Capability of
290 MW, the output sold to Boston Edison and other Bellingham Power Purchasers
will be increased or reduced proportionately. 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 Bellingham Project or from any other electricity
generating facility on the Bellingham Site.
Curtailment. Boston Edison has the right under the Boston Edison I
Contract to refuse power from the Bellingham 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, 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 "SUMMARY OF PRINCIPAL PROJECT AGREEMENTS-Boston
Edison Interconnection Agreement."
15
Pricing. The Boston Edison I Contract 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 Contract, the energy payment for the period of any
such extension will be 100% of the Qualifying Facility Power Purchase Rate. The
Boston Edison I Contract 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 1996 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 Contract provides for an Energy Bank,
and the Energy Bank balances under the contract 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
Contract.
Contract Security. The Boston Edison I Contract 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. NEA has granted Boston Edison a second mortgage (shared with
Commonwealth and Montaup) on the Bellingham Project as further contract
security.
Qualifying Facility Status. The Boston Edison I Contract does not require
that the Bellingham Project's QF status be maintained. However, NEA has
warranted to Boston Edison that NEA will use its best efforts to maintain the
Bellingham 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 Contract and may result in termination of the Boston Edison I Contract
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 Contract,
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
16
(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
Contract. In addition, Boston Edison may terminate the Boston Edison I Contract
in the event of NEA's failure to pay costs and expenses, if any, associated with
transmission services, filing fees, administrative costs and any interest
accrued thereon in accordance with such contract.
Boston Edison II Contract
The Power Purchase Agreement entered into by NEA and Boston Edison as of
January 28, 1988 (the "Boston Edison II Contract"), provides for the sale to
Boston Edison of 29% of the net power actually generated by the Bellingham
Project, subject to certain limitations described below.
Term. The Boston Edison II Contract extends for a term of 20 years
expiring September 15, 2011, subject to earlier termination in accordance with
its terms. The Boston Edison II Contract does not include any right to extend
its term.
Purchase and Delivery. Pursuant to the Boston Edison II Contract, 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 Bellingham
Project equal to the ratio of 84 MW to the Net Electrical Capability of 290 MW
of the Bellingham Project multiplied by 100% of the available capacity and
hourly generation of the Bellingham 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 Contract 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 Bellingham Project is
operating above or below its Net Electric Capability of 290 MW, the output sold
to Boston Edison and other Bellingham Power Purchasers will be increased or
reduced proportionately subject to Boston Edison's maximum purchase obligations
described above.
Curtailment. Boston Edison has the right under the Boston Edison II
Contract 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 "SUMMARY OF PRINCIPAL
PROJECT AGREEMENTS-Boston Edison Interconnection Agreement."
17
Pricing. The Boston Edison II Contract 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 1996, this rate was 6.01 cents per kWh.
Energy Bank. Although the Boston Edison II Contract provides for an
Energy Bank, there is no liability remaining for the Energy Bank under the
Boston Edison II Contract.
Contract Security. NEA has granted Boston Edison a second mortgage (shared
with Commonwealth and Montaup) on the Bellingham Project as contract security.
Qualifying Facility Status. The Boston Edison II Contract does not
require that the Bellingham Project's QF status be maintained. However, NEA has
warranted to Boston Edison that NEA will use its best efforts to maintain the
Bellingham 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 Contract and may result in termination of the Boston Edison II
Contract 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 Contract,
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
Bellingham Project is expected to be generating electricity at or near its 290
MW Net Electrical Capability within 90 days, and (y) the Bellingham Project
begins generating at such level within 90 days; and (v) either party contests
the enforceability of the Boston Edison I Contract.
Commonwealth I Contract
The Power Purchase Agreement entered into by NEA and Commonwealth as of
November 26, 1986 (the "Commonwealth I Contract"), provides for the sale to
Commonwealth of 9% of the net power actually generated by the Bellingham
Project.
Term. The Commonwealth I Contract extends for a term of 25 years expiring
September 15, 2016. The Commonwealth I Contract does not have any provision for
extension of its term.
Purchase and Delivery. Pursuant to the Commonwealth I Contract, NEA is
obligated to sell and deliver to Commonwealth, and Commonwealth is obligated to
accept, a portion of the
18
available capacity and hourly generation of the Bellingham Project equal to the
ratio of 25 MW to the Net Electrical Capability of 290 MW of the Bellingham
Project multiplied by 100% of the available capacity and hourly generation of
the Bellingham Project, or 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 Bellingham Project is
operating above or below its Net Electrical Capability of 290 MW, the output
sold to Commonwealth and other Bellingham Power Purchasers will be increased or
reduced proportionately. NEA has the right to withdraw the Bellingham Project
from service and to cease to supply electricity to Commonwealth as necessary to
perform any maintenance or repair of the Bellingham Project.
Curtailment. Commonwealth has the right under the Commonwealth I Contract
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 Contract 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
1996, the average price per kWh under this contract was 6.78 cents.
Contract Security. NEA has granted Commonwealth a second mortgage (shared
with Boston Edison and Montaup) on the Bellingham Project as contract security.
Qualifying Facility Status. Commonwealth's obligations under the
Commonwealth I Contract were conditioned upon the Bellingham 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 Bellingham 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 Contract (including those relating to price).
Commonwealth II Contract
The Power Purchase Agreement entered into by NEA and Commonwealth as of
19
August 15, 1988 (the "Commonwealth II Contract") provides for the sale to
Commonwealth of 7% of the net power actually generated by the Bellingham
Project.
Term. The Commonwealth II Contract extends for a term of 25 years
expiring September 15, 2016. The Commonwealth II Contract does not have any
provision for extension of its term.
Purchase and Delivery. Pursuant to the Commonwealth II Contract, NEA is
obligated to sell and deliver and Commonwealth is obligated to accept a portion
of the available capacity and hourly generation of the Bellingham Project equal
to the ratio of 21 MW to the Net Electrical Capability of 290 MW of the
Bellingham Project multiplied by 100% of the available capacity and hourly
generation of the Bellingham Project, or 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 Bellingham Project is
operating above or below its Net Electrical Capability of 290 MW, the output
sold to Commonwealth and other Bellingham Power Purchasers will be increased or
reduced proportionately. NEA has the right to withdraw the Bellingham Project
from service and to cease to supply electricity to Commonwealth as necessary to
perform any maintenance or repair to the Bellingham Project.
Curtailment. Commonwealth has the right under the Commonwealth II
Contract 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 Contract 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 1996 was 5.90 cents.
Contract Security. NEA's performance of the Commonwealth II Contract is
secured by a $1 million letter of credit to be maintained through September 15,
1998. NEA has granted a second mortgage (shared with Boston Edison and Montaup)
on the Bellingham Project as further contract security.
Qualifying Facility Status. Commonwealth's obligations under the
Commonwealth II Contract were initially conditioned upon the Bellingham
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 Bellingham 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 Contract (including those relating to price).
20
Montaup Contract
The Power Purchase Agreement entered into by NEA and Montaup as of October
17, 1986 (the "Montaup Contract") provides for the sale to Montaup of 9% of the
net power actually generated by the Bellingham Project.
Term. The Montaup Contract extends for an initial term of 30 years
expiring September 15, 2021, subject to earlier termination in accordance with
its terms. The Montaup Contract 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 Contract, NEA is obligated
to deliver to Montaup, and Montaup is obligated to accept, a portion of the
available capacity and hourly generation of the Bellingham Project equal to the
ratio of 25 MW to the Net Electrical Capability of 290 MW of the Bellingham
Project multiplied by 100% of the available capacity and hourly generation of
the Bellingham Project, or 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 Bellingham Project is
operating above or below its Net Electrical Capacity of 290 MW, the output sold
to Montaup and other Bellingham Power Purchasers will be increased or reduced
proportionately.
Curtailment. Montaup has the right under the Montaup Contract to refuse
power for up to 200 hours per year, at its reasonable discretion, in addition to
its other curtailment rights described below. Montaup has the right to
interrupt, reduce or refuse to purchase electric energy, and NEA has the right
to interrupt, reduce or refuse to deliver electric energy, in order to install
equipment, make inspections or perform maintenance and repairs. In addition,
Montaup has the right to curtail or interrupt the taking of electric energy for
as long as reasonably necessary in the event of an emergency.
Pricing. The Montaup Contract 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 Contract 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 Contract. 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 1996, the payment per kWh under
the Montaup Contract was 6.5 cents.
21
Energy Bank. The Montaup Contract provides for an Energy Bank, and the
Energy Bank balance under the Montaup Contract 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.
Contract Security. The Montaup Contract requires NEA to deliver a letter
of credit to Montaup securing the payment of positive Energy Bank balances.
However, under present circumstances the face amount of the letter of credit is
not required to exceed $12.6 million or (if less) the remaining Energy Bank
balance. In addition, NEA has granted Montaup a second mortgage (shared with
Commonwealth and Boston Edison) on the Bellingham Project as further contract
security.
Qualifying Facility Status. NEA has warranted to Montaup that as of the
date the Bellingham Project commenced operations, it would be a QF, and that
should the Bellingham 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 Contract in the event that the Bellingham
Project's QF status is revoked.
Breach of Contract and Remedies; Termination. The Montaup Contract may be
terminated by the non-defaulting party upon the dissolution or liquidation of
either NEA or Montaup, or upon the occurrence of certain events of bankruptcy or
insolvency. In addition, Montaup is entitled to terminate the Montaup Contract
upon NEA's failure to pay within 30 days of notice of such failure transmission
fees, filing fees, administrative costs and any interest accrued thereon in
accordance with such contract.
SAYREVILLE POWER PURCHASE AGREEMENT
The Power Purchase Agreement entered into by JCP&L and NJEA as of October
22, 1987 (the "JCP&L Contract"), provides for the sale of 250 MW of power from
the Sayreville Project.
Term. The JCP&L Contract 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 Contract, 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 Sayreville Project throughout
the term of the JCP&L Contract. JCP&L has certain rights, but not the
obligation, to purchase certain energy produced by the Sayreville Project in
excess of 250 MW per hour at a discounted price.
22
Curtailment. Pursuant to the JCP&L Contract, 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 Sayreville 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 Sayreville 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 Contract all interconnection facilities and protective
apparatus necessary to effect delivery of power to JCP&L's system pursuant to
the JCP&L Contract, subject to JCP&L's approval and in accordance with its
standards.
Pricing. The JCP&L Contract provides for payment to NJEA of: (i) a
variable energy payment referencing JCP&L's 1989 cost of gas, indexed to the
cost of gas purchased by New Jersey utilities; (ii) a capacity payment that is
made for power purchased during peak hours in peak season (approximately 1,800
hours per year); and (iii) a fixed energy payment. For the elapsed portion of
the operating year commencing in August, 1994 (through July 1995), the average
variable energy payment has been 2.296 cents per kWh, the capacity payment has
been 6.41 cents per kWh and the average fixed energy payment has been 2.2 cents
per kWh, for a total average payment of 5.85 cents per kWh. Commencing in July,
1994, and for each year thereafter, if average annual on-peak electricity
generation is less than 85% of the average annual on-peak generation during the
three preceding years, a penalty payment of 3.6 cents for each kWh of shortfall
in average on-peak generation for such year will be due to JCP&L from NJEA.
Energy Bank. Although the JCP&L Contract provides for an Energy Bank,
there is no liability remaining for the Energy Bank under the JCP&L Contract.
STEAM SALES AGREEMENT
BELLINGHAM
The Bellingham 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 Bellingham
Steam Sales Agreement. The principal terms of the Bellingham Steam Sales
Agreement and the NECO Lease are summarized below.
23
BELLINGHAM STEAM SALES AGREEMENT
The Amended and Restated Bellingham Steam Sales Agreement dated as of
December 21, 1990 between NEA and NECO (the "Bellingham Steam Sales Agreement")
provides for the sale by NEA to NECO of a minimum of 60,000 lbs of steam per
hour when the Bellingham Project is being fueled by 100% pipeline quality
natural gas.
Term. The Bellingham 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 Bellingham 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 Bellingham and Sayreville 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 Bellingham Steam Sales Agreement, NEA has
agreed to deliver a minimum output of 60,000 pounds of steam per hour when the
Bellingham 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 Bellingham 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 Bellingham
Project is in commercial operation using 100% pipeline quality natural gas) a
minimum of 5% of the total energy output of the Bellingham Project. NECO is
obligated to buy all of its steam from the Bellingham Project, subject to
limited exceptions, and also is obligated to return all condensate to the
Bellingham Project.
Interconnection Obligations. The Bellingham 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.
Bellingham Lease of Carbon Dioxide Facility
Term. The NECO Lease, for the use of the Carbon Dioxide Plant and certain
utilities, 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
24
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 upon the occurrence of an event of default, as defined in the
NECO Lease.
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.
SAYREVILLE STEAM SALES AGREEMENT
The Sayreville Project sells steam to Hercules pursuant to the Industrial
Steam Sales Contract dated as of June 5, 1990 between NJEA and Hercules (the
"Sayreville Steam Sales Agreement"). The Sayreville 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 Sayreville
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 Sayreville 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 Sayreville 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.
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, which will satisfy the
minimum thermal use requirement for maintaining the Sayreville Project's QF
status under PURPA. However, Hercules has no obligation to continue purchasing
steam in the event that it closes its Parlin plant. NJEA is entitled to a
minimum of 90 days advance notice of any such closure. NJEA has an option under
the Sayreville Steam Sales Agreement to lease the Parlin plant site from
Hercules in the event of any such closure. Pursuant to the Sayreville Steam
Sales Agreement, the terms and conditions of any
25
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 Sayreville Steam Sales Agreement when the parties enter
into such lease.
GAS PURCHASE AGREEMENTS
BELLINGHAM PROGAS AGREEMENT
Quantities. The Gas Purchase Contract dated as of May 12, 1988 between
NEA and ProGas (the "Bellingham ProGas Agreement") provides for the sale by
ProGas to NEA of up to approximately 50,000 MMBtu of natural gas per day (the
"Daily Bellingham Quantity"). If NEA fails to take 75% of the annualized Daily
Bellingham 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
Bellingham Quantity, ProGas has the right to renegotiate the Daily Bellingham
Quantity unless NEA was unable to take the required amount due to the temporary
inability of the Bellingham Project to utilize the gas supplies.
Term. The term of the Bellingham ProGas Agreement expires November 1,
2013.
Delivery Point. Gas delivered by ProGas under the Bellingham 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 Bellingham Project, see "SUMMARY OF PRINCIPAL
PROJECT AGREEMENTS-Gas Transportation and Storage Agreements."
Price. The price payable by NEA for gas delivered under the Bellingham
ProGas Agreement is determined by reference to a "base price" escalated from
U.S. $2.7665 per MMBtu as of January 1, 1990. The base price, as theretofor
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 the Bellingham and Sayreville
Projects. The "base price" for approximately 70% of the contract quantities is
escalated using the weighted average of (i) the fixed escalators applicable to
Bellingham's fixed price power sales, and (ii) the changes in fuel prices that
determine escalation of price under Bellingham's Avoided Cost contracts. The
remaining 30% of the contract quantities 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 actual billings to NEA by ProGas are developed through the use of a
two-part rate structure, consisting of a monthly demand charge and a commodity
charge. The monthly
26
demand charge is the sum of (i) the monthly demand toll per Mcf charged by
ProGas as approved by the Alberta Petroleum Marketing Commission, (ii) the
monthly demand toll per Mcf charged by NOVA to ProGas as approved by the Alberta
Public Utility Board and (iii) the monthly demand toll per Mcf charged by
TransCanada as determined by Canada's National Energy Board. Payments pursuant
to this monthly demand charge are payable regardless of the actual volume of gas
delivered under the Bellingham ProGas Agreement.
The price of gas sold pursuant to the Bellingham ProGas Agreement will be
adjusted in the event that (i) the Sayreville Project has ceased to operate for
a period of six consecutive months and (ii) as a result of such interruption in
use, ProGas is not selling gas under the Sayreville ProGas Agreement on a
monthly basis at least equal to 65% of the Daily Sayreville 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
Sayreville ProGas Agreement. Pursuant to an amendment to the Bellingham ProGas
Agreement dated July 30, 1993, 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. Any arbitration conducted between November 1, 2001
and October 31, 2006 cannot result in an adjustment which reduces NEA's
projected net operating cash flow after debt service by 10% or more of the
average net cash flow after debt service for the prior three years. Any
arbitration conducted between November 1, 2006 and the end of the term cannot
result in an adjustment which increases or reduces NEA's projected net operating
cash flow after debt service by 10% or more of the average net cash flow after
debt service for the prior three years.
SAYREVILLE GAS PURCHASE AGREEMENTS
Sayreville ProGas Agreement
Quantities. The Gas Purchase Contract dated as of May 12, 1988 between
NJEA and ProGas (the "Sayreville ProGas Agreement") provides for the sale by
ProGas to NJEA of up to approximately 23,000 MMBtu of natural gas per day (the
"Daily Sayreville Quantity"). If NJEA fails to take 75% of the annualized Daily
Sayreville 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
Sayreville Quantity, ProGas has the right to renegotiate the Daily Sayreville
Quantity unless NJEA was unable to take the required amount due to the temporary
inability of the Sayreville Project to utilize the gas supplies.
Term. The term of the Sayreville ProGas Agreement expires November 1,
2013.
27
Delivery Point. Gas delivered by ProGas under the Sayreville 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 Sayreville Project see "SUMMARY OF PRINCIPAL
PROJECT AGREEMENTS - Gas Transportation and Storage Agreements."
Price. The price payable by NJEA for gas delivered under the Sayreville
ProGas Agreement is determined by reference to a "base price" escalated from
U.S. $2.7665 per MMBtu as of January 1, 1990. The base price, as theretofor
escalated, was further increased by $.038 per Mcf, effective December 1, 1994.
Escalation of the "base price" is at the same rate as the escalation rates in
the JCP&L contract. 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 actual billings to NJEA by ProGas are developed through the use of a
two-part rate structure consisting of a monthly demand charge and a commodity
charge. The monthly demand charge is the sum of (i) the monthly demand toll per
Mcf charge by ProGas as approved by the Alberta Petroleum Marketing Commission,
(ii) the monthly demand toll per Mcf charged by NOVA to ProGas as approved by
the Alberta Public Utility Board and (iii) the monthly demand toll per Mcf
charged by TransCanada as determined by the National Energy Board of Canada.
Payments pursuant to this monthly demand charge are payable regardless of the
actual volume of gas delivered under the Sayreville ProGas Agreement.
The commodity charge is the difference between the unitized monthly demand
charge and the then applicable "base price." The commodity charge is applied to
volumes of gas actually delivered under the Sayreville ProGas Agreement.
The price of gas sold pursuant to the Sayreville ProGas Agreement will be
adjusted in the event that (i) the Bellingham Project has ceased to operate for
a period of six consecutive months and (ii) as a result of such interruption in
use, ProGas is not selling gas under the Bellingham ProGas Agreement on a
monthly basis at least equal to 65% of the Daily Bellingham Quantity. 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 Bellingham ProGas
Contract. Pursuant to an amendment to the Sayreville ProGas Agreement dated
July 30, 1993, in any contract year commencing on or after November 1, 2001, the
contract pricing is subject to renegotiation or arbitration if the contract
prices do not track comparable long-term service contracts then prevailing. Any
arbitration conducted between November 1, 2001 and October 31, 2006 cannot
result in an adjustment which reduces NJEA's projected net operating cash flow
after debt service by 10% or more of the average net cash flow after debt
service for the prior three years. Any arbitration conducted between November 1,
2006 and the end of the term cannot result in an adjustment which increases or
reduces NJEA's projected net operating cash flow after debt service by 10% or
more or the average net cash flow after debt service for the prior three years.
28
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 a
maximum daily sales quantity of 25,000 dekatherms of gas and also provides for
certain gas transportation services.
Transportation Service. PSE&G transports for NJEA all of the fuel
required to operate the Sayreville Project (from points originating in PSE&G's
service territory to the delivery point at the Sayreville 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
Sayreville Project up to 32,500 dekatherms of gas per day purchased from sources
other than PSE&G, and PSE&G is required to re-deliver an equal quantity to the
Sayreville Project. In the event that NJEA delivers to PSE&G for transport in
any calendar month an amount less than the amount re-delivered by PSE&G to the
Sayreville Project in such calendar month and NJEA fails to correct the
resulting imbalance in the immediately following month, then PSE&G may sell to
NJEA 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 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 1996, the "customer charge" was approximately $97 per month, the
"commodity charge" was approximately $2.71 per MMBtu, and the "service charge"
was approximately $.33 per MMBtu.
29
Quantity. 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 Sayreville Project with the same delivered
quantity as existed prior to such changes.
Service Interruption. PSE&G may interrupt sales and transportation service
to the Sayreville Project when the mean daily temperature forecast for Newark,
New Jersey is 22(degrees)F or below. On such days, PSE&G may retain the gas
supplies tendered to it by NJEA. This occurred on 16 days during 1996. At NJEA's
election, PSE&G will offer Extended Gas Service on such days, unless the
temperature forecast is 14(degrees)F or below. In the latter case PSE&G may
curtail all service to NJEA and the Sayreville Project may not be able to
operate. This occurred on two days during 1996. 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 1996, NJEA purchased 769,372 MMBtu
of Extended Gas Service supplies at an average price of $7.75 per MMBtu.
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 1996, PSE&G paid NJEA over $2.1 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 the PSE&G
"commodity charge" or an amount which is the lesser of the market price of fuel
oil per MMBtu or PSE&G's propane cost per MBtu. During 1996, PSE&G retained
489,582 MMBtu at an average price of $4.55 per MMBtu.
NJEA has a right to elect in advance to purchase additional gas during the
period commencing November 1 and ending March 31 up to a specified amount. NJEA
has never elected to purchase any additional amounts under the provision.
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. Although the pricing provisions contained in the table below
are based on current tariffs filed with FERC, such tariffs are subject to change
upon application by the respective transporters and approval by FERC. 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.
30
NEA--TRANSPORTATION AGREEMENTS
CONTRACT
GAS TRANSPORTER AND MAXIMUM DAILY EXPIRATION
AGREEMENTS QUANTITY DATE PRICING TERMS(1)
- ---------- -------- ---- ----------------
CNG Transmission 48,817 Dth November 1, Demand Charge per Dth:
Corporation 2001 $4.9353
Firm Gas Transportation Commodity Charge:
Agreement $0.0175 + ACA Surcharge
Rate Schedule X-71 Fuel Retention: 0%
CNG Transmission 1,654 Dth Winter March 31, 1999 Demand Charge per Dth:
Corporation 828 Dth Summer $4.9353
Firm Gas Transportation Commodity Charge:
Agreement $0.0175 + ACA Surcharge
Rate Schedule F-T Fuel Retention: 0%
Transcontinental Gas 50,508 Dth October 31, Demand Charge per
Pipe Line Corporation 2006 Mcf: $5.0034
Firm Gas Transportation Commodity Charge:
Agreement $0.0055 + ACA Surcharge
Rate Schedule X-320 Fuel Retention: .75%
Algonquin Gas 62,000 Dth December 1, Demand Charge per Dth:
Transmission Company 2016 $12.0679 + GRI
Firm Gas Transportation Surcharge
Agreement(2) Commodity Charge:
Rate Schedule AFT-1/X-35 $0.00 + ACA & GRI
Surcharges
Fuel Retention:
Nov. - Apr. 0.95%
Apr. - May 0.46%
Jun. - Sep. 0.23%
Sept. - Oct. 0.51%
CNG Transmission 14,000 Dth March 31, 2012 Demand Charge per Dth:
Corporation $2.232
Firm Gas Storage Commodity Charge:
Agreement $0.00
Rate Schedule FT-GSS II Withdrawal Fuel
Retention: 2.5%
Texas Eastern 14,000 Dth March 31, 2012 Demand Charge per Dth:
Transmission Corporation $5.4040
Firm Gas Transportation Commodity Charge:
Agreement $0.00 + ACA Surcharge
Rate Schedule FTS-5 Fuel Retention: 0%
- --------------------------------
(1) ACA means Annual Charge Adjustments billed by FERC. GRI means Gas Research
Institute. Algonquin Gas Transmission Company's rate is subject to
reduction pending the results of the Company's limited NGA Section 4 filing
made March 29, 1996. Transcontinental Gas Pipeline Corporation's rates are
subject to reduction in FERC Docket No. RP95-197.
31
NJEA--TRANSPORTATION AGREEMENTS
CONTRACT
GAS TRANSPORTER AND MAXIMUM DAILY EXPIRATION
AGREEMENTS QUANTITY DATE PRICING TERMS(1)
- ---------- -------- ---- ----------------
CNG Transmission 22,019 Dth November 1, Demand Charge per Dth:
Corporation 2011 $4.9353
Firm Gas Transportation Commodity Charge:
Agreement $0.0175 + ACA
Rate Schedule X-70 Surcharge
Fuel Retention: 0%
CNG Transmission 746 Dth Winter March 31, 1999 Demand Charge per Dth:
Corporation 372 Dth Summer $4.9353
Firm Gas Transportation Commodity Charge:
Agreement $0.0175 + ACA
Rate Schedule F-T Surcharge
Fuel Retention: 0%
Transcontinental Gas 22,790 Mcf October 31, Demand Charge per
Pipe Line Corporation 2006 Mcf: $5.0034 + GRI
Firm Gas Transportation Surcharge
Agreement Commodity Charge:
Rate Schedule X-319 $0.0053 + ACA & GRI
Surcharges
Fuel Retention: .75%
CONTRACT
GAS TRANSPORTER AND MAXIMUM DAILY EXPIRATION
AGREEMENTS QUANTITY DATE PRICING TERMS(1)
- ----------- -------- ----- ---------------
Public Service Electric 32,500 Dth August 12, 2011 Commodity Charge:
& Gas Company $0.32928
Firm Gas Transportation Fuel Retention: 0%
Agreement
CNG Transmission 10,508 Dth March 31, 2012 Demand Charge per Dth:
Corporation $2.232
Firm Gas Storage Commodity Charge:
Agreement $0.00
Rate Schedule FT-GSS II Withdrawal Fuel
Retention: 2.5%
Texas Eastern 10,508 Dth March 31, 2012 Demand Charge per Dth:
Transmission $5.4040 + Transmission
Corporation Commodity Charge:
Firm Gas Transportation $0.00 + ACA Surcharge
Agreement Fuel Retention: 0%
Rate Schedule FTS-5
- ------------------------------------------
/(1)/ ACA means Annual Charge Adjustments billed by FERC. GRI means Gas
Research Institute.
32
NEA--STORAGE AGREEMENTS
CONTRACT
GAS TRANSPORTER AND MAXIMUM DAILY EXPIRATION
AGREEMENTS QUANTITY DATE PRICING TERMS(1)
- ---------- ---------- ----- -----------------
CNG Transmission Withdrawal: 14,000 Dth March 31, 2012 Demand Charge per
Corporation Injection: 10,000 Dth Dth: $3.4354
Firm Gas Storage Capacity: 1,400,000 Dth Capacity Charge:
$0.0317
Agreement Withdrawal Charge:
Rate Schedule GSS II $0.0238 + ACA
Surcharge
Injection Charge:
$0.0214
Injection Fuel
Retention: 2.25%
NJEA--STORAGE AGREEMENTS
CONTRACT
GAS TRANSPORTER AND MAXIMUM DAILY EXPIRATION
AGREEMENTS QUANTITY DATE PRICING TERMS(1)
- ---------- -------- ---- -----------------
CNG Transmission Withdrawal: 10,508 Dth March 31, 2012 Demand Charge per
Corporation Injection: 7,506 Dth Dth: $3.4354
Firm Gas Storage Capacity: 1,050,800 Dth Capacity Charge:
$0.0317
Agreement Withdrawal Charge:
Rate Schedule GSS II $0.0238 + ACA
Surcharge
Injection Charge:
$0.0214
Injection Fuel
Retention: 2.25%
- -------------------------------------
/(1)/ ACA means Annual Charge Adjustments billed by FERC. GRI means Gas
Research Institute.
33
OPERATIONS AND MAINTENANCE AGREEMENTS
BELLINGHAM OPERATIONS AND MAINTENANCE AGREEMENT
The Second Amended and Restated Operations and Maintenance Agreement for
the Bellingham Plant dated as of June 28, 1989, as amended, between NEA and
Westinghouse Electric (the "Bellingham O&M Agreement"), provides for the
operation and maintenance by Westinghouse Services of the Bellingham Project.
Term. The term of the Bellingham 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, 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 cost-plus basis. Subject to negotiation of certain
terms by the parties, the Bellingham O&M Agreement also may be extended on a
fixed price basis.
Basic Obligations. The Operator has agreed to provide all operations and
maintenance services, including scheduled major maintenance, together with all
personnel, spare parts and consumables necessary in order to operate and
maintain the Bellingham Project, including all services necessary or advisable
to use, operate and maintain the Bellingham Project in good operating condition
and in compliance with (i) the Bellingham Project Documents, (ii) all insurance
policies relating to the Bellingham Project, (iii) the procedures established in
the operation and maintenance manuals provided pursuant to the construction
contract for the Bellingham 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 Bellingham O&M Agreement, and (viii) any and
all governmental approvals, licenses or permits associated with the Bellingham
Project.
Compensation. For the initial term, NEA has agreed to pay the Operator a
monthly fee (the "Bellingham O&M Fee") of $435,417 (in 1990 dollars), subject to
a biannual escalation each January and July calculated on the basis of certain
national indices for the cost of labor, materials and producer prices. The
Bellingham O&M Fee for the month ended December 31, 1996 was $512,986.
Performance Guarantees. The Bellingham O&M Agreement specifies certain
guaranteed performance levels for the Bellingham Project, including but not
limited to (i) guaranteed electrical output of approximately 300 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
Bellingham Project is being fueled by natural gas, (ii) guaranteed electrical
output of approximately 300 MW of capacity, adjusted for
34
variations from standard operating conditions and excused downtime, at 83%
average availability, when the Bellingham Project is burning a combination of
natural gas and fuel oil, (iii) guaranteed steam output of not less than 5% of
the energy output of the Bellingham Project, (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.
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 Mh 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 Bellingham O&M
Agreement. During any extension period, the maximum liability of the Operator
under the Bellingham 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
Bellingham 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. During any extension period beyond the initial term of the Bellingham
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).
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 actions or omissions, the
Operator is obligated to refund the amount of such drawing to NEA.
Right to Suspend Performance for Loss of Qualifying Facility Status. In
the event that the Bellingham Project is operated in a manner that would result
in the loss of its QF status if such operation were to be continued, 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 Bellingham O&M
Agreement and find a replacement operator. See "REGULATION-Energy Regulation."
35
SAYREVILLE OPERATIONS AND MAINTENANCE AGREEMENT
The Amended and Restated Operations and Maintenance Agreement for the
Sayreville Plant dated as of June 28, 1989, as amended, between NJEA and
Westinghouse Electric (the "Sayreville O&M Agreement") provides for the
operation and maintenance by Westinghouse Services of the Sayreville Project.
Term. The term of the Sayreville 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, 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 cost-plus basis. Subject to negotiation of terms by
the parties, the Sayreville O&M Agreement also may be extended on a fixed price
basis.
Basic Obligations. The Operator has agreed to provide all operations and
maintenance services, including scheduled major maintenance together with all
personnel, spare parts and consumables necessary in order to efficiently operate
and maintain the Sayreville Project, including all services necessary or
advisable to use, operate and maintain the Sayreville Project in good operating
condition and in compliance with (i) the Sayreville Project Documents, (ii) all
insurance policies relating to the Sayreville Project, (iii) the procedures
established in the operation and maintenance manuals provided pursuant to the
construction contract for the Sayreville 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 Sayreville O&M Agreement, and
(viii) any and all governmental approvals, licenses or permits associated with
the Sayreville Project.
Compensation. For the initial term, NJEA has agreed to pay the Operator a
monthly fee (the "Sayreville O&M Fee") of $493,750 (in 1990 dollars), subject to
a biannual escalation each January and July calculated on the basis of certain
national indices for the cost of labor, materials and producer prices. The
Sayreville O&M Fee for the month ended December 31, 1996 was $581,712.
Performance Guarantees. The Sayreville O&M Agreement specifies certain
guaranteed performance levels for the Sayreville Project, including but not
limited to (i) guaranteed electrical output of 90% of 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 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
36
the energy output of the Sayreville Project, (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 remediation as sole liability in the event of failure to maintain such
levels.
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 for the first
three years of the contract and (iii) if on-peak output thereafter is less than
85% of average actual output during the preceding 3 years and NJEA is obligated
to pay liquidated damages in respect of such shortfall under the JCP&L Contract,
3.6 cents per kWh of shortfall below 85% to the extent of NJEA's liquidated
damages obligation to JCP&L. 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
Sayreville O&M Agreement. During any extension period, the maximum liability of
the Operator under the Sayreville O&M Agreement is reduced to $3 million (in
1993 dollars) in any operating year.
Bonus Payments. In the event that the amount of energy generated by the
Sayreville 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 Sayreville 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
guaranteed levels of 0.3 cents per kWh. During any extension period beyond the
initial term of the Sayreville 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).
Right to Suspend Performance for Loss of Qualifying Facility Status. In
the event that the Sayreville project is operated in a manner that would result
in the loss of its QF status if such operation were to be continued, and such
projected loss is confirmed by an independent engineer, NJEA has agreed to take
reasonable steps to ensure that operating practices will maintain such QF
status. Under certain circumstances relating to a potential or actual loss of
QF status, the Operator may suspend its performance under the Sayreville O&M
Agreement and find a replacement operator. See "REGULATION-Energy Regulation."
37
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 Bellingham 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 Bellingham Power Purchase Agreements.
Term. The Boston Edison Interconnection Agreement will remain in effect
until the termination date of the latest to terminate of the Bellingham Power
Purchase Agreements. Boston Edison and NEA have agreed to remain interconnected
pursuant to the terms 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. Boston Edison has the sole right to schedule maintenance of its
transmission lines and other interconnection facilities, 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. Pursuant to the terms of the Boston Edison Interconnection
Agreement (i) NEA has agreed to bear 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) NEA has
agreed to reimburse Boston Edison for all operation and maintenance expenses and
all taxes associated with Boston Edison's interconnection facilities used by the
Bellingham 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 under such agreement.
38
PART II
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
This item is not applicable to IEC Funding or the Partnerships.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
This item is not applicable to IEC Funding or the Partnerships.
39
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,
1996. The selected combined financial data for these years have been derived
from the Partnerships' audited combined 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."
YEARS ENDED DECEMBER 31,
--------------------------------------------------
1992/(6)/ 1993/(6)/ 1994/(6)/ 1995/(6)/ 1996
--------- --------- --------- --------- ----
(IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenues:
Power sales to utilities (1) $222,152 $234,142 $234,933 $276,022 $267,789
Steam sales 3,965 4,684 3,779 4,527 4,473
-------- -------- -------- -------- --------
Total revenues $226,117 $238,826 $238,712 $280,549 $272,262
Costs and expenses:
Cost of power and steam 125,467 132,580 128,402 132,839 138,727
Operation and maintenance 19,677 20,283 20,808 24,699 22,854
Depreciation 23,753 24,919 24,314 24,904 24,978
General and administrative 13,055 14,162 11,012 12,010 14,424
-------- -------- -------- -------- --------
Total operating costs and expenses 181,952 191,944 184,536 194,452 200,983
Operating income 44,165 46,882 54,176 86,097 71,279
Other (income) expense:
Amortization of financing costs 2,873 2,599 2,333 2,305 2,373
Interest expense 41,592 38,992 38,068 50,930 49,841
Interest expense on energy
bank balance/(1)/ 3,465 7,252 11,676 16,657 19,675
Interest income (119) (700) (1,656) (10,652) (10,534)
Expense related to future obligations
under interest rate swap agreements - - 6,734 - -
-------- -------- -------- -------- --------
Total other expense 47,811 48,143 57,155 59,240 61,355
-------- -------- -------- -------- --------
(Loss) income before
extraordinary item (3,646) (1,261) (2,979) 26,857 9,924
Extraordinary item
Loss on extinguishment of debt (4) - - 13,937 - -
-------- -------- -------- -------- --------
Net (loss) income $ (3,646) $ (1,261) $(16,916) $ 26,857 $ 9,924
======== ======== ======== ======== ========
AS OF DECEMBER 31,
--------------------------------------------------
1992 1993 1994 1995 1996
--------- --------- --------- --------- ----
(IN THOUSANDS)
BALANCE SHEET DATA:
Total assets $563,032 $546,484 $650,027 $ 617,034 $566,392
Loans payable - IEC Funding Corp.
(current) (2) - - 20,434 25,204 24,075
Bank debt (current) 27,126 27,126 - - -
Mandatory prepayments (3) 8,003 18,168 - - -
Loans Payable - IEC Funding Corp.
(long term)(2) - - 539,566 514,362 490,287
Bank debt (long term) 479,071 420,164 - - -
Energy bank balances (5) 68,961 111,398 155,496 188,053 220,922
Partners' deficit (36,401) (48,540) (92,928) (130,577) (187,479)
(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) Prior to the December 1, 1994 refinancing as described in Note 5 of Notes
to Combined Financial Statements, mandatory prepayments represent the
current portion of estimated prepayment requirements under the Loan
Agreement.
(4) 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.
(5) Energy bank principal balances plus accrued interest thereon.
(6) Certain reclassifications were made to the prior year balances in order to
conform to current year presentation. These reclassifications had no
effect on prior year operating results.
40
ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the Combined
Financial Statements of the Partnerships and the Notes thereto included
elsewhere in this report.
GENERAL
The Partnerships commenced commercial operations in the latter 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 the Power Purchaser 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 "BUSINESS - 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.
41
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 years
ended December 31, 1994, 1995 and 1996.
YEARS ENDED DECEMBER 31,
1994 1995 1996
---------- --------- --------
(IN THOUSANDS)
Gross operating revenues
and receipts /(1)/ $ 271,133 100% $296,450 100% $285,456 100%
Operating costs 149,210 55% 157,538 53% 161,581 56%
Depreciation 24,314 9% 24,904 8% 24,978 9%
General and administrative 11,012 4% 12,010 4% 14,424 5%
---------- -------- --------
Operating income plus
Energy Bank accruals /(2)/ $ 86,597 32% $101,998 34% 84,473 30%
---------- -------- --------
Amortization of
financing costs 2,333 1% 2,305 1% 2,373 1%
Interest expense 38,068 14% 50,930 17% 49,841 17%
Interest income (1,656) 1% (10,652) 4% (10,534) 4%
Expense related to future obligations
under interest rate
swap agreements 6,734 2% - -
Extraordinary item - Loss on
extinguishment of debt 13,937 5% - -
---------- -------- --------
Net income plus
Energy Bank accruals $ 27,181 $ 59,415 $ 42,793
and interest thereon/(2)/ ========== ======== ========
- ------------------------------------------------------
(1) Gross Operating Revenues and Receipts represents total revenues plus annual
change in energy bank principal balances.
(2) Energy bank accruals represent the net change in energy bank principal
balances.
(3) Percentages do not add due to rounding.
42
CALENDAR YEAR 1995 COMPARED TO CALENDAR YEAR 1994
Gross Operating Revenues and Receipts
Gross operating revenues and receipts for the year ended December 31, 1995
of $296.4 million increased by $25.3 million (9.3%) as compared to the year
ended December 31, 1994. Decreases in the frequency and duration of required
maintenance outages afforded higher availability for both Projects.
Operating Costs
Cost of power and steam sales was $132.8 million, or 44.8% of gross
operating revenues and receipts for the year ended December 31, 1995 as compared
to $128.4 million, or 47.3% of gross operating revenues and receipts last year.
While fuel requirements increased to support higher availability, the additional
costs were offset by price decreases under certain contracts. Decreased demand
charges associated with a fuel transportation contract led to savings in excess
of $1 million. Decreased commodity charges associated with two supply contracts
(indexed to spot market pricing) provided additional savings of approximately $5
million. In general, spot market prices were lower in 1995 as compared to 1994.
Operation and maintenance costs increased $3.9 million (18.7%) as compared
to 1994. Increases include normal and expected escalations on O&M contracts, a
one-time water franchise fee, an increased performance bonus payable to the O&M
contractor (as direct result of increased power generation), and increases in
property taxes.
General and Administrative Expenses
General and administrative expenses increased $1.0 million (9.1%). The
increase is primarily due to increased management fee, insurance premiums and
other professional service fees.
Interest Expenses and Interest Income
Interest expense for the year ended December 31, 1995 increased $12.9
million (33.8%) as compared to the year ended December 31, 1994. The increase
is primarily due to the December 1994 financing. The proceeds of the financing
were used to (i) refinance the existing debt that as accruing interest at
floating short-term interest rates with long-term fixed rate obligations, (ii)
to provide cash collateral to secure letters of credit, (iii) to fund various
reserves and (iv) to pay fees and expenses associated with the transaction.
During 1994, the Partnerships' average amount of debt outstanding was $456.4
million at an average interest rate of 7.93%. During 1995, the Partnerships'
average amount of debt outstanding was $554.9 million at an average rate of
9.23%. Interest income also increased in connection with this financing.
Interest income in 1995 totaled $10.7 million as compared to $1.7 million in
1994, increasing $9.0
43
million. This increased income is due to increased funds available for
investment, including cash collateral for letters of credit, coupled with higher
interest rates.
Inflation had no significant impact on results of operations.
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 is 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 Bellingham facility. During the fourth quarter of 1996 a scheduled
overhaul and inspection took place at the Sayreville facility. 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 are primarily attributable to increases in fuel
costs including higher market prices of spot gas and additional charges
applicable under North Jersey Energy Associates' extended gas service
arrangement with a fuel supplier. Extended gas service occurs when temperatures
are below 22 degrees Fahrenheit. 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 are entered into in an attempt to limit exposure to market price
fluctuations).
Operation and maintenance expenses decreased $1.8 million (7.5%) as
compared to 1995. This decrease is a result of a lower performance bonus
payable to the O&M contractor in 1996 as a result of scheduled maintenance
outages, and a one-time 1995 water franchise fee. Offsetting these cost
decreases were normal and expected escalations on O&M contracts.
General and administrative expenses
General and administrative expenses increased $2.4 million (20.1%). The
increase is 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 $1.1
million (2.1%) as compared to the year ended December 31, 1995. Interest on debt
is decreasing as a result of declining principal balances. Principal payments
are made semi-annually on June 30 and December 30. 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, decreasing $.2
million. This decrease is primarily a result of reduced cash collateral being
held in support of letters of credit.
Inflation had no significant impact on results of operations.
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, 1995, cash and cash equivalents totaled approximately
$58.3 million, as compared to $76.3 million at December 31, 1994. The decrease
in cash and cash equivalents is the net effect of $71.2 million provided by
operations, offset by financing activities, including debt principal payments of
$20.4 million, a $5.6 million restructuring fee paid to the general partner in
connection with the debt financing and $64.5 million in distributions to the
partners.
As of December 31, 1995, there were no outstanding loans under the $15
million working capital facility. Debt service reserve requirements remain
fully funded at December 31, 1995.
As of December 31, 1996, cash and cash equivalents totaled approximately
$49.9 million, as compared to $58.3 million at December 31, 1995. The decrease
in cash and cash equivalents is the net effect of (i) $75.0 million provided by
operations and $8.6 million provided by investing activities primarily resulting
from the release of cash collateral being held in support of letters of credit,
offset by (ii) financing activities, including debt principal payments of $25.2
million and $66.8 million in distributions to partners.
As of December 31, 1996, there were no outstanding loans under the $15
million working capital facility. Debt service reserve requirements remain
fully funded at December 31, 1996.
WORKING CAPITAL FACILITY
The Indenture permits the Partnerships to enter into revolving credit
arrangements from time to time with financial institutions with maximum
available borrowings of up to $20 million in order to provide for the working
capital requirements of the Partnerships. The obligations of the Partnerships
in respect of any Working Capital Facility will be secured by the same
44
Collateral that secures the obligations in respect of the Securities, the New
Notes, the Guarantee and the Swaps, but upon an exercise of remedies in respect
of the Collateral, the Working Capital Banks will be entitled to payment in full
of all amounts payable in respect of the Working Capital Facility prior to the
payment of any amounts in respect of such other Secured Obligations.
The Partnerships have entered into an initial Working Capital Facility,
which provides for maximum available borrowings of up to $15 million subject to
a borrowing base calculated based on outstanding receivables and fuel
inventories. The sole lender under the initial Working Capital Facility is The
Sanwa Bank Limited, New York Branch ("Sanwa Bank"), subject to certain rights of
Sanwa Bank to assign its rights and obligations thereunder.
The initial Working Capital Facility matures on the final maturity date of
the Securities and loans thereunder will bear interest at fluctuating interest
rates based upon either the prime rate or the London interbank offered rate
("LIBOR") for interest periods of one, two or three months' duration, as
selected by the Partnerships, plus a margin that varies from 0% to 1.5%
depending upon the ratings of the Securities (as determined by the lower of the
S&P and Moody's ratings) from time to time, the mode (prime or LIBOR) and the
period of time elapsed since the Closing Date.
Interest on loans bearing interest based on the prime rate will be payable
monthly and interest based on LIBOR loans will be payable at the end of each
applicable interest period. The Partnerships also will pay fees under the
initial Working Capital Facility consisting of a fee of $112,500 that was paid
on the Closing Date, commitment fees accruing at the rate of 0.250% per annum on
unused commitments, payable quarterly, and an annual agency fee of $25,000.
The terms of the initial Working Capital Facility require that the
Partnerships repay all loans outstanding thereunder so that there are no
outstanding loans thereunder for at least one continuous period of 10 days
during each calendar year. The initial Working Capital Facility also includes a
cross-default to the Indenture and a default for failure to pay amounts due
under the Working Capital Facility or the Letter of Credit Facility. Otherwise
the covenants and events of default under the initial Working Capital Facility
are substantially the same as those under the Indenture.
The obligations of the Partnerships under the Working Capital Facility are
secured by the Security Documents.
LETTER OF CREDIT FACILITY
The Partnerships are required by the terms of certain of their respective
Power Purchase Agreements to provide 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 Indenture
the Partnerships have
45
agreed to maintain a Letter of Credit Facility to provide such Letters of
Credit and to secure the obligations under such Letter of Credit Facility,
subject to certain terms and conditions set forth in the Indenture. In addition,
the Partnerships require Letters of Credit for certain other purposes in the
ordinary course of business.
The Partnerships have entered into an initial Letter of Credit Facility
with Sanwa Bank, which provides for the issuance of 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 Letters of Credit that may be issued and outstanding under
the initial Letter of Credit Facility will decline as the aggregate amount of
Energy Bank Obligations required to be supported by Letters of Credit declines.
The Partnerships believe that the aggregate amount of Letters of Credit
available under the initial Letter of Credit Facility will be sufficient to
satisfy their respective obligations under the Power Purchase Agreements to
provide Letters of Credit to the Power Purchasers thereunder.
The initial Letter of Credit Facility provides that each Letter of Credit
issued thereunder will expire within one year after the date of issuance,
subject to renewal from time to time until the final maturity date of the
Securities provided that (i) there is no payment default with respect to fees
and expenses payable under the Letter of Credit Facility, (ii) the Partnerships
continue to be controlled by IEC, (iii) the Cash Collateral Proceeds securing
the Letter of Credit Facility are in the minimum amount required at the time and
(iv) the exercise of remedies has not been commenced by or on behalf of any
holders of indebtedness of the Partnerships in an amount equal to or exceeding
$10 million. The Partnerships will pay fees under the initial Letter of Credit
Facility accruing at the rate of 0.300% per annum on outstanding Letters of
Credit and unused commitments to issue Letters of Credit, payable quarterly.
The initial Letter of Credit Facility is secured by the Cash Collateral
Proceeds, consisting of cash collateral and certain permitted investments
thereof. The initial deposit of such Cash Collateral Proceeds was provided on
the Closing Date and invested in a seven year investment with Sanwa Bank. The
minimum amount of Cash Collateral Proceeds required under the initial Letter of
Credit Facility will be equal to the aggregate amount of Letters of Credit
issued or available to be issued thereunder as long as the Cash Collateral
Proceeds are invested with Sanwa Bank or in 30-day U.S. Treasury bills. If the
Cash Collateral Proceeds are not so invested, then the minimum amount of Cash
Collateral Proceeds required under the Letter of Credit Facility will be subject
to increase, at the discretion of Sanwa Bank, depending upon how such Cash
Collateral Proceeds are invested.
The initial Letter of Credit Facility includes a cross-default to the
Indenture and a default for failure to pay amounts due under the Letter of
Credit Facility or the Working Capital Facility. Otherwise, the covenants and
events of default under the initial Letter of Credit Facility are substantially
the same as those under the Indenture.
46
NATURAL GAS HEDGING INSTRUMENTS
Almost 20% of the fuel supply for the Projects must be provided from
sources other than the Long-Term Gas Supply Arrangements. In order 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. 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 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.
47
ITEM 8. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS PAGE
----
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
Report of Independent Accountants 49
Combined Balance Sheet at December 31, 1995 and 1996 50
Combined Statement of Operations for the years ended
December 31, 1994, 1995 and 1996 51
Combined Statement of Partners' Deficit for the years ended
December 31, 1994, 1995 and 1996 52
Combined Statement of Cash Flows for the years ended
December 31, 1994, 1995 and 1996 53
Notes to Combined Financial Statements 55
IEC FUNDING CORP.
Report of Independent Accountants 71
Balance Sheet at December 31, 1995 and 1996 72
Statement of Operations for the period from inception (November 3, 1994)
through December 31, 1994 and the years ended December 31, 1995 and 1996 73
Statement of Stockholders' Equity for the period from inception (November 3, 1994)
through December 31, 1994 and the years ended December 31, 1995 and 1996 74
Statement of Cash Flows for the period from inception (November 3, 1994)
through December 31, 1994 and the years ended December 31, 1995 and 1996 75
Notes to Financial Statements 76
48
Report of Independent Accounts
To the Partners of Northeast Energy Associates, A Limited Partnership,
and North Jersey Energy Associates, A Limited Partnership
In our opinion, the accompanying combined balance sheet and the related combined
statements of operations, of partners' deficit and of cash flows present fairly,
in all material respects, the financial position of Northeast Energy Associates,
A Limited Partnership, and North Jersey Energy Associates, A Limited
Partnership, at December 31, 1995 and 1996, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1996, in conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Partnerships' managements;
our responsibility is to expresss 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 20, 1997
49
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED BALANCE SHEET
- -------------------------------------------------------
December 31,
1995 1996
(In thousands)
Assets
Current assets
Cash and cash equivalents $ 58,277 $ 49,861
Accounts receivable 51,465 43,671
Fuel inventories 4,516 5,410
Prepaid expenses and other current assets 2,913 2,566
--------- ---------
Total current assets 117,171 101,508
--------- ---------
Cogeneration facilities and carbon dioxide facility (net of accumulated
depreciation of $104,184,000 and $129,068,000 at December 31, 1995 and
1996, respectively) 397,692 373,781
Other fixed assets (net of accumulated depreciation of $344,000 and $438,000
at December 31, 1995 and 1996, respectively) 382 304
Unamortized financing costs 20,210 17,837
Other assets 3,011 3,806
Restricted cash 78,568 69,156
--------- ---------
Total non-current assets 499,863 464,884
--------- ---------
Total assets $ 617,034 $ 566,392
========= =========
Liabilities and Partners' Deficit
Current liabilities
Current portion of loans payable - IEC Funding Corp. $ 25,204 24,075
Accounts payable 14,234 14,528
Other accrued expenses 2,104 2,037
Future obligations under interest rate swap agreements 3,654 2,022
--------- ---------
Total current liabilities 45,196 42,662
--------- ---------
Loans payable - IEC Funding Corp. 514,362 490,287
Amounts due utilities for energy bank balances 188,053 220,922
--------- ---------
Total non-current liabilities 702,415 711,209
--------- ---------
Total liabilities 747,611 753,871
--------- ---------
Partners' deficit
General partner (4,047) (4,616)
Limited partners (126,530) (182,863)
--------- ---------
Total partners' deficit (130,577) (187,479)
Commitments and contingencies (Note 6) - -
--------- ---------
Total liabilities and partners' deficit $ 617,034 $ 566,392
========= =========
The accompanying notes are an integral
part of these financial statements.
50
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENT OF OPERATIONS
- ------------------------------------------------------
For the year ended December 31,
1994 1995 1996
(In thousands)
Revenue
Power sales to utilities 234,933 $276,022 $267,789
Steam sales 3,779 4,527 4,473
-------- -------- --------
Total revenue 238,712 280,549 272,262
-------- -------- --------
Costs and expenses
Cost of power and steam sales 128,402 132,839 138,727
Operation and maintenance 20,808 24,699 22,854
Depreciation 24,314 24,904 24,978
General and administrative expenses 11,012 12,010 14,424
-------- -------- --------
Total costs and expenses 184,536 194,452 200,983
-------- -------- --------
Operating income 54,176 86,097 71,279
-------- -------- --------
Other expense (income)
Amortization of financing costs 2,333 2,305 2,373
Interest expense 38,068 50,930 49,841
Interest expense on energy bank balances 11,676 16,657 19,675
Interest income (1,656) (10,652) (10,534)
Expense related to future obligations
under interest rate swap agreements 6,734 - -
-------- -------- --------
Total other expense 57,155 59,240 61,355
-------- -------- --------
(Loss) income before extraordinary item (2,979) 26,857 9,924
Extraordinary item
Loss on extinguishment of debt 13,937 - -
-------- -------- --------
Net (loss) income $(16,916) $ 26,857 $ 9,924
======== ======== ========
The accompanying notes are an integral
part of these financial statements
51
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENT OF PARTNERS' DEFICIT
- ------------------------------------------------------
Total
General Limited Partners'
Partner Partners Deficit
(In thousands)
Balance at December 31, 1993 $(3,226) $(45,314) $(48,540)
Net loss (169) (16,747) (16,916)
Distributions to partners (275) (27,197) (27,472)
------- --------- ---------
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)
======= ========= =========
The accompanying notes are an integral
part of these financial statements.
52
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENT OF CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
- ------------------------------------------------------
For the year ended December 31,
1994 1995 1996
(In thousands)
Cash flows from operating activities:
Cash received from utilities and other customers $ 266,377 $ 287,638 $ 294,942
Cash paid to suppliers (154,969) (164,875) (170,531)
Interest paid (37,743) (53,869) (51,435)
Bank commitment fees paid (282) (38) (38)
Interest received 1,128 8,854 10,807
Cash payments to general partner for
operating activities (3,878) (2,914) (5,031)
Cash payments to owners/management (2,270) (3,566) (3,688)
--------- --------- ---------
Net cash provided by operating activities 68,363 71,230 75,026
--------- --------- ---------
Cash flows from investing activities:
Net expenditures for facilities (148) (1,885) (808)
Expenditures for other fixed assets (207) (76) (16)
(Increase) decrease in restricted cash (82,000) 3,432 9,412
--------- --------- ---------
Net cash (used for) provided by
investing activities (82,355) 1,471 8,588
--------- --------- ---------
Cash flows from financing activities:
Principal payments on debt (34,290) (20,434) (25,204)
Payment of financing costs (16,943) (5,739) -
Advances from IEC Funding Corp. 128,832 - -
Distribution to partners (27,472) (64,506) (66,826)
--------- --------- ---------
Net cash provided by (used for) financing
activities 50,127 (90,679) (92,030)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents 36,135 (17,978) (8,416)
Cash and cash equivalents at beginning of year 40,120 76,255 58,277
--------- --------- ---------
Cash and cash equivalents at end of year $ 76,255 $ 58,277 $ 49,861
========= ========= =========
Non-cash Financing Activities
On December 1, 1994, in connection with the refinancing transaction described in
Note 5, IEC Funding Corp. purchased $431,168,000 in loans payable by the
Partnerships in exchange for the issuance of notes payable to IEC Funding Corp.
Non-cash Investing Activities
At December 31, 1994, total accrued capitalized facility costs were
approximately $5,980,000. During 1995, the accrued capitalized facility costs
were reduced to an actual amount of $1,195,000. As of December 31, 1995, these
costs were paid in full. At December 31, 1996, total accrued capitalized
costs was approximately $165,000.
The accompanying notes are an integral
part of these financial statements.
53
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
COMBINED STATEMENT OF CASH FLOWS (CONTINUED)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
- ------------------------------------------------------
Reconciliation of Net (Loss) Income to Net Cash Provided by
Operating Activities
For the year ended
December 31,
1994 1995 1996
(In thousands)
Net (loss) income $(16,916) $ 26,857 $ 9,924
Adjustments to reconcile net (loss) income to
net cash provided by operating activities:
Extraordinary loss on extinguishment of debt 13,937 - -
Depreciation 24,314 24,904 24,978
Amortization of financing costs 2,333 2,305 2,373
(Increase) decrease in accounts receivable (4,757) (11,346) 7,794
Decrease (increase) in fuel inventories 2,203 - (894)
(Increase) decrease in prepaid expenses
and other current assets (133) (1,765) 347
(Decrease) increase in accounts payable (471) 633 129
(Decrease) increase in other accrued expenses (2,643) 651 (67)
Increase (decrease) in future obligations
under interest rate swap agreements 6,425 (2,771) (1,632)
Increase in amounts due utilities for energy
bank balances 44,098 32,557 32,869
(Increase) in other assets (27) (795) (795)
-------- -------- -------
Net cash provided by operating activities $ 68,363 $ 71,230 $75,026
======== ======== =======
The accompanying notes are an integral
part of these financial statements
54
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
development of non-utility 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") (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.
The general partner of each of the Partnerships is Intercontinental Energy
Corporation ("IEC"), a Massachusetts corporation. IEC owns a one percent
interest in each partnership and the individual stockholders of the general
partner collectively own the majority of the remaining partnership
interests.
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.
55
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- ------------------------------------------------------
COGENERATION FACILITIES AND CARBON DIOXIDE FACILITY
The cogeneration facilities and the carbon dioxide facility are stated at
cost. Cost includes initial acquisition costs increased by subsequent
development and construction costs, including developer fees and
construction management fees, interest expense and amortization of project
loan acquisition costs incurred during the construction period, and
continuing facility improvements. Capitalized facility costs are being
depreciated using the straight-line method over the estimated useful life
of each facility of 20 years.
UNAMORTIZED FINANCING COSTS
Unamortized financing costs consist primarily of investment banking fees,
legal fees and other costs associated with the placement of securities
(Note 5). In May 1995, the Partnerships paid a $5,600,000 restructuring
fee, out of excess cash flow, to the general partner in connection with the
refinancing (Note 5) equal to 1% of the total refinancing. These costs are
being amortized over the approximate 15-year term of the securities using
the interest method. Unamortized financing costs are net of accumulated
amortization of $2,472,000 and $4,845,000 at December 31, 1995 and 1996,
respectively.
OTHER FIXED ASSETS
Other fixed assets consist primarily of furniture, office equipment and
leasehold improvements and are depreciated using the straight-line method
over estimated useful lives ranging from 3-7 years.
INVENTORIES
Inventories consist of natural gas and fuel oil and are stated at the lower
of cost, determined on a first-in, first-out (FIFO) basis, or market.
INTEREST RATE SWAP AGREEMENTS
Notional principal amounts in contracts and related settlement gains and
losses on interest rate swap agreements are allocated to the Partnerships
based on the relative amounts of outstanding borrowings of each partnership
on the date on which the swap agreements were contracted. Prior to the
refinancing (Note 5), gains and losses, based on the amount the
Partnerships were entitled to receive or required to pay for additional
interest, were determined at each calendar quarter-end based on the
outstanding notional balance and the amount by which the contractual fixed
rate exceeded or was less than the contractual variable rate. Such gains
and losses were recognized as adjustments to interest expense. Subsequent
to the refinancing (Note 5), the net payments required pursuant to all swap
agreements and the change in the fair value of the swap agreements are
recognized as adjustments to interest expense. The fair value of the swap
agreements is recorded as a current liability. See Notes 5 and 9 for
further disclosure regarding interest rate swap agreements.
56
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- ------------------------------------------------------
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
Contracts." Revenue is recognized based on power delivered at rates
stipulated in power sales agreements, except that revenue is deferred to
the extent that stipulated rates are in excess of amounts, either scheduled
or specified, in the agreements. The excess amounts deferred are
accumulated in energy banks, and are reflected as amounts due utilities for
energy bank balances on the combined balance sheet. Revenue from steam
sales is recognized upon delivery of the steam.
INCOME TAXES
The partners are required to report their respective shares of the
Partnerships' taxable income or losses in their income tax returns and are
liable for any related taxes thereon. Accordingly, no provision for income
taxes is made in the combined financial statements of the Partnerships.
The Partnerships' net assets and liabilities for financial reporting
purposes exceeded the net assets and liabilities for tax purposes by
approximately $41.4 million and $31.9 million and $41.6 million at
December 31, 1994, 1995 and 1996, 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.
RECLASSIFICATION
Certain reclassifications were made to the prior years' balances in order
to conform to the current year presentation. These reclassifications had no
effect on prior years' operating results.
57
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- ------------------------------------------------------
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, 1995
and 1996, 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, 1995 and 1996 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.
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).
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
58
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- ------------------------------------------------------
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, 1996. Sales to significant customers are as follows:
During the year ended December 31, 1994, revenue from two different
utilities totaled approximately $114.0 million and $99.0 million, or
approximately 48% and 41% of revenue, respectively.
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.
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 in
later periods that avoided cost rates scheduled or specified in such
agreements rise above contract rates. For those certain agreements
requiring the establishment of energy banks, the Partnerships are required
to provide collateral based on energy bank balances (Note 6).
STEAM SALES AGREEMENTS AND CARBON DIOXIDE FACILITY
In order for the Partnerships' facilities to maintain the status as
qualifying facilities under PURPA, the facilities are required to generate
five percent of total energy output as steam for sale to unrelated third
parties.
In 1989, NEA entered into a 25-year steam sales contract with a processor
and seller of carbon dioxide. Pursuant to this agreement, NEA sells all
the steam generated by the Bellingham facility at a price which fluctuates
based on changes in the price of a specified grade of fuel oil. This
agreement can be extended at the option of the steam user. In conjunction
with this
59
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- ------------------------------------------------------
contract, NEA has constructed a carbon dioxide facility and, in 1989,
entered into a 15-year agreement to lease the facility to the steam user.
Base rent under the terms of the lease is $100,000 per month, adjusted by
the operating results of the carbon dioxide facility for each month as
outlined in the lease agreement. Additionally, NEA pays the steam user
$100,000 annually for administrative services rendered related to the
operation of the carbon dioxide facility. NEA does not operate the carbon
dioxide facility.
In 1989, NJEA entered into a 20-year steam sales contract with a steam user
adjacent to the Sayreville facility. Under the terms of this agreement,
NJEA sells a specified maximum quantity of steam at a floor price which
can increase based on changes in prices of coal. This agreement
automatically renews for two consecutive five year terms unless either
party gives notice not to renew two years before the expiration of each of
the prior terms.
FUEL SUPPLY, TRANSPORTATION AND STORAGE AGREEMENTS
Natural gas is provided to the facilities primarily under long-term
contracts for supply, transportation and storage. The remaining fuel
requirements of the facilities are provided under short-term "spot"
arrangements. The long-term natural gas supply is provided under contracts
with ProGas Limited ("ProGas"), a Canadian gas marketing company, and
Public Service Electric and Gas Company ("PSE&G"), a domestic retail gas
distribution company. Transportation of the natural gas is provided by
various pipeline companies, including CNG Transmission Company ("CNG"),
Transcontinental Gas Pipe Line Corporation ("Transco") and Algonquin Gas
Transmission Company ("Algonquin"). Gas storage agreements provide
contractual arrangements for the storage of limited volumes of natural gas
with third parties for future delivery to the Projects.
The ProGas contracts commenced in 1991. The initial terms of these
contracts of 15 years were extended an additional seven years effective in
1994. Under the ProGas contracts, ProGas is required to arrange for the
aggregation, gathering and transportation of gas from Albert, 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 $44 million, $49 million and $48 million in 1994,
1995 and 1996 respectively, and total payments under such
60
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- ------------------------------------------------------
contracts were approximately $95.9 million, $98.3 million and $100.5
million in 1994, 1995 and 1996, respectively, inclusive of demand charges.
Under 1996 pricing conditions, the demand charge payments would be
approximately $48 million under these contracts for each of the next five
years and approximately $797 million over the remaining life of these
contracts. Total charges under the contract with PSE&G, including
transportation costs, during 1994, 1995 and 1996, were approximately $24.5
million, $24.3 million and $32.4 million, respectively. In the event that
the available capacity under these agreements is not utilized by the
operations of the facilities, the Partnerships have the opportunity under
certain of these contractual agreements to sell unused capacity to third
parties, but have not yet done so.
NEA's facility also has the capability to burn #2 fuel oil. Fuel oil was
obtained and is stored on site for contingency supply for the facility.
5. LOANS PAYABLE
In 1989, as amended in 1990, 1991 and 1992, the Partnerships, together with
the general partner, executed a project loan and credit agreement with a
group of banks for a maximum commitment of $600,000,000 for the
construction and development of the Bellingham and Sayreville facilities
and initial working capital and letters of credit facility.
On December 1, 1994, the Partnerships refinanced their existing borrowings
by means of a placement of securities to qualified institutional investors
as defined in Rule 144A of the Securities Act of 1933 ("Rule 144A").
Borrowings outstanding are as follows:
December 31,
1995 1996
8.43% Senior Secured Notes Due 2000 $120,686,000 $ 95,482,000
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
------------ ------------
$539,566,000 $514,362,000
============ ============
The above securities were issued through a special purpose funding
corporation, IEC Funding Corp., established solely for the purpose of
issuing the securities, and are unconditionally guaranteed, jointly and
severally, by the Partnerships.
61
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- ------------------------------------------------------
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.
Interest on the Securities is payable semiannually on each June 30 and
December 30, commencing December 30, 1994. Principal repayments, which
commenced on June 30, 1995, are made semiannually in amounts stipulated in
the trust indenture. Future principal payments are as follows:
Year ending December 31
1997 $ 24,075,000
1998 21,563,000
1999 23,511,000
2000 26,333,000
2001 20,160,000
Thereafter 398,720,000
------------
$514,362,000
============
The Securities are not subject to optional redemption but are subject to
mandatory redemption in certain limited circumstances involving the
occurrence of an event of loss, as defined in the trust indenture, for
which the Partnerships fail to or are unable to restore a facility.
Additionally, the Partnerships may, at their option, repurchase all or part
of the Securities with proceeds received from the release of cash
collateral maintained as security for letters of credit (Note 6).
The proceeds of the Securities were used (a) to purchase the notes
outstanding under the original loan and credit agreement and (b) to make
loans to the Partnerships. In connection with these two transactions the
notes outstanding under the loan and credit agreement were surrendered and
new notes of the Partnerships were issued to 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 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.
62
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
Under the terms of the trust indenture governing the Securities, the
Partnerships are required to establish certain funds and subfunds, which
must be fully funded before any distributions can be made to partners. The
funding requirements of these funds are defined in the trust indenture. Cash
within these funds can be drawn currently if funds in the partnerships'
other cash accounts are insufficient to meet operational cash requirements.
The order in which these funds may be drawn is described in the trust
indenture. Funds available for distribution to partners as of December 31,
1996 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 the same bank which has issued the outstanding
letters of credit (Note 6). 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, 1995 and 1996, no borrowings
were outstanding under this working capital facility.
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.
During 1995, the Partnerships and the bank who is party to the Swaps entered
into an agreement to consolidate the swaps into one agreement. The
consolidation did not change the net payment schedule or the fair value of
the Swaps.
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
63
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
Partnerships do not anticipate nonperformance by the bank. See Note 9 for
additional information regarding interest rate swap agreements.
As a result of the refinancing described above, the original Swaps no longer
qualify as hedges and, therefore, must be recorded at fair value. At
December 1, 1994, the fair value of the existing Swaps was $6,734,000 which
has been charged to the combined statement of operations. The swaps
described above are 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.
Unamortized financing costs of $13,937,000 at December 1, 1994 associated
with the loan and credit agreement were charged to the combined statement of
operations as loss on extinguishment of debt and has been classified as an
extraordinary item on the Partnerships' combined statement of operations for
the year ended December 31, 1994.
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, 1995
and 1996, the Partnerships' obligation for letters of credit outstanding
under this facility is $75,085,000 and $68,656,000, respectively. The
Partnerships are required to provide cash collateral for the maximum amount
of obligations allowable under the terms of this facility. As of December
31, 1995 and 1996, the Partnerships reserved $78,568,000 and $69,156,000
respectively, in cash as collateral for such obligations (Note 3).
OPERATION AND MAINTENANCE OF THE COGENERATION FACILITIES
In 1989, the Partnerships entered into two separate ten year operation and
maintenance agreements with the same contractor responsible for constructing
and installing the combined-cycle cogeneration plants for both facilities
for an aggregate annual consideration of approximately $11,100,000 subject
to changes in specified indices. The agreements commenced
64
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
during 1991 after the facilities became operational. The Partnerships each
have an option to enter into a successor operation and maintenance agreement
with the contractor for a ten year term following the expiration of the term
of the original agreement, on either a cost plus payment basis or a fixed
fee payment basis to be negotiated at the time of the operation exercise.
Under the terms of these agreements, the Partnerships are required to pay
the operating 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
$2,934,000, $5,375,000 and $3,482,000 related to this bonus in 1994, 1995
and 1996, 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 1994, 1995, and 1996. Amounts expensed under this heat rate bonus
agreement were $1,060,000 in each of 1994, 1995 and 1996.
OPERATING LEASE
Lease payments under the operating lease for the land in Bellingham,
Massachusetts (Note 4) are as follows:
YEAR ENDING DECEMBER 31,
1997 $ 177,000
1998 189,000
1999 201,000
2000 213,000
2001 225,000
Thereafter 2,997,000
------------
$ 4,002,000
============
During 1994, 1995 and 1996, NEA paid and expensed $141,000, $153,000 and
$165,000, respectively, under this agreement.
65
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
GAS TRANSPORTATION CHARGE REFUNDS
In 1994, the Partnerships received refunds of approximately $5.0 million,
representing a portion of charges previously paid to gas transporters. This
amount was recorded as a reduction in cost of power and steam sales. In
conjunction with the settlement agreement related to this refund, the gas
transporter also agreed to charge NEA reduced gas transportation rates for
each of the next five years.
7. EMPLOYEE SAVINGS PLAN
Effective January 1, 1991, the general partner 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 1994, 1995 and 1996, the
Partnerships were charged $90,000, $78,000 and $90,000, respectively, for
their shares of contributions made by the general partner to this plan (Note
8).
8. OTHER RELATED PARTY TRANSACTIONS
Subsequent to the commencement of operations of the Partnerships, the
general partner began to pay certain expenses as a convenience for the
Partnerships. These expenses are reimbursed to the general partner at cost.
The following represents the activity between the Partnerships and the
general partner for the years ended December 31, 1994, 1995 and 1996:
FOR THE YEAR ENDED DECEMBER 31, 1994: NEA NJEA
Expenses paid by the general partner
Payroll and related expenses $1,270,000 $1,083,000
Travel 85,000 85,000
Office space and utilities 202,000 202,000
Professional fees, insurance and other 417,000 424,000
---------- ----------
1,974,000 1,794,000
Payments to the general partner 2,029,000 1,849,000
---------- ----------
Payments in excess of expenses 55,000 55,000
---------- ----------
Due from (to) general partner, Dec. 31, 1993 78,000 (42,000)
---------- ----------
Due from (to) general partner, Dec. 31, 1994 $ 133,000 $ 13,000
========== ==========
66
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
FOR THE YEAR ENDED DECEMBER 31, 1995: NEA NJEA
Expenses paid by the general partner
Payroll and related expenses $1,053,000 $ 878,000
Travel 76,000 76,000
Office space and utilities 126,000 125,000
Professional fees, insurance and other 424,000 413,000
---------- ----------
1,679,000 1,492,000
---------- ----------
Payments to the general partner 1,457,000 1,457,000
---------- ----------
Expenses in excess of payments (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: NEA NJEA
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
========== ==========
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
67
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
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 counter parties. 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.
The following table sets forth the contract or notional amounts of these
financial instruments. While indicating the size of the transaction entered
into, the amounts do not represent the Partnerships' exposure to loss in the
event of nonperformance by the counterparties involved. The Partnerships do
not anticipate nonperformance by the counterparties.
CONTRACT OR CONTRACT OR
NOTIONAL AMOUNT NOTIONAL AMOUNT
AT DECEMBER 31, AT DECEMBER 31,
1995 1996
$ MMBTU $ MMBTU
Interest rate swap
agreements 27,596,000 - 20,335,000 -
Gas purchase swap
agreements - 28,800,000 - 28,600,000
Gas forward purchases - 664,000 - 418,000
68
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
The net effect on interest expense due to the interest rate swap agreements
and the net gain/(loss) included in cost of power and steam sales resulting
from the gas purchase options, swap agreements and forward purchases is as
follows:
FOR THE YEAR ENDED DECEMBER 31,
1994 1995 1996
Net effect on interest expense -
increase (decrease) $ 8,996,000 $ (486,000) $ 137,000
Net (loss)/gain included in cost
of power and steam sales (466,000) (448,000) 5,246,000
The estimated fair value and related carrying amounts of certain financial
instruments are as follows:
DECEMBER 31, 1995 DECEMBER 31, 1996
RELATED RELATED
FAIR CARRYING FAIR CARRYING
VALUE AMOUNT VALUE AMOUNT
ASSET (LIABILITY) $ $ $ $
Loans payable (635,897,000) (539,566,000) (564,075,000) (514,362,000)
Restricted cash 78,568,000 78,568,000 69,156,000 69,156,000
Interest rate
swap agreements (3,654,000) (3,654,000) (2,022,000) (2,022,000)
Gas purchase
swap agreements (2,973,000) - 1,671,000 -
Gas forward purchases - - (143,000) -
The estimated fair values may not be representative of actual values of the
financial instruments that could have been realized as of year end or that
will be realized in the future.
The following methods and assumptions were used to estimate the fair values
of certain instruments:
Loans payable - The fair value of loans payable is 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.
69
NORTHEAST ENERGY ASSOCIATES, A LIMITED PARTNERSHIP AND
NORTH JERSEY ENERGY ASSOCIATES, A LIMITED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
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.
70
Report of Independent Accountants
To the Stockholders of IEC Funding Corp.
In our opinion, the accompanying balance sheet and the related statements of
operations, of stockholders' equity and of cash flows present fairly, in all
material respects, the financial position of IEC Funding Corp. at December 31,
1995 and 1996, and the results of its operations and its cash flows for the
period from inception (November 3, 1994) through December 31, 1994 and for each
of the two years in the period ended December 31, 1996, 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 20, 1997
71
IEC FUNDING CORP.
BALANCE SHEET
- --------------------------------------------------------------------------------
December 31,
1995 1996
(In thousands)
Assets
Current assets
Cash $ 1 $ 1
Current portion of notes receivable from
Northeast Energy Associates and North Jersey
Energy Associates (the "Partnerships") 25,204 24,075
-------- --------
Total current assets 25,205 24,076
Notes receivable from Partnerships 514,362 490,287
-------- --------
Total assets $539,567 $514,363
======== ========
Liabilities and Stockholders' Equity
Current liabilities
Current portion of securities payable $ 25,204 $ 24,075
-------- --------
Total current liabilities 25,204 24,075
Securities payable 514,362 490,287
-------- --------
Total liabilities 539,566 514,362
Stockholders' equity
Common stock, no par value, 10,000 shares
authorized, issued and outstanding 1 1
-------- --------
Total liabilities and stockholders' equity $539,567 $514,363
======== ========
The accompanying notes are an integral
part of these financial statements.
72
IEC FUNDING CORP.
STATEMENT OF OPERATIONS
- --------------------------------------------------------------------------------
For the period
from inception
(November 3, 1994) For the
through year ended
December 31, December 31,
1994 1995 1996
(In thousands)
Interest income $ 4,305 $ 51,084 $ 49,404
Interest expense (4,305) (51,084) (49,404)
------- -------- --------
Net income $ - $ - $ -
======= ======== ========
The accompanying notes are an integral
part of these financial statements
73
IEC FUNDING CORP.
STATEMENT OF STOCKHOLDERS' EQUITY
- --------------------------------------------------------------------------------
Common Stock
------------
Number Total
of stockholders'
shares Amount equity
(In thousands)
Issuance of common stock on November 14, 1994 10 $ 1 $ 1
---- ---- ----
Balance, December 31, 1994, 1995 and 1996 10 $ 1 $ 1
==== ==== ====
The accompanying notes are an integral
part of these financial statements
74
IEC FUNDING CORP.
STATEMENT OF CASH FLOWS
INCREASE (DECREASE) IN CASH
- --------------------------------------------------------------------------------
For the period
from inception
(November 3, 1994) For the
through year ended
December 31, December 31,
1994 1995 1996
(In thousands)
Cash flows from operating activities:
Interest received from Partnerships $ 4,161 $ 51,084 $ 49,404
Interest paid (4,161) (51,084) (49,404)
--------- -------- --------
Net cash provided by operating activities - - -
--------- -------- --------
Cash flows from investing activities:
Repayment of loans payable on
behalf of Partnerships (431,168) - -
Advances to Partnerships (128,832) - -
--------- -------- --------
Net cash used for investing activities (560,000) - -
--------- -------- --------
Cash flows from financing activities:
Cash received from issuance of common stock 1 - -
Cash received from placement of securities 560,000 - -
Principal received from Partnerships - 20,434 25,204
Principal payments on debt - (20,434) (25,204)
--------- -------- --------
Net cash provided by financing activities 560,001 - -
--------- -------- --------
Net increase in cash 1 - -
Cash at beginning of period - 1 1
--------- -------- --------
Cash at end of period $ 1 $ 1 $ 1
========= ======== ========
The accompanying notes are an integral
part of these financial statements
75
IEC FUNDING CORP.
NOTES TO FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
1. Nature of Business
IEC Funding Corp. (the "Company") is a Delaware corporation that has been
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 and
North Jersey Energy Associates (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.
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:
December 31,
1995 1996
8.43% Senior Secured Notes Due 2000 $120,686,000 $ 95,482,000
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
------------ ------------
$539,566,000 $514,362,000
============ ============
76
IEC FUNDING CORP.
NOTES TO FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
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:
Year ending December 31,
1997 $ 24,075,000
1998 21,563,000
1999 23,511,000
2000 26,333,000
2001 20,160,000
Thereafter 398,720,000
-------------
$ 514,362,000
=============
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.
77
IEC FUNDING CORP.
NOTES TO FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
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.
The fair value of the Securities and the notes receivable from the
Partnerships at December 31, 1996 is estimated to be $564,075,000. The fair
value of the Securities and the notes receivable from the Partnerships at
December 31, 1995 was estimated to be $635,897,000. 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.
The financial statements of the Partnerships are included on pages 49
through 70.
78
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVES OFFICERS OF THE GENERAL PARTNER
All management functions of the Partnerships are the responsibility of
the General Partner.
The following table sets forth the names, ages and positions of the
directors and executive officers of the General Partner and their positions with
the General Partner.
NAME AGE POSITION
----- --- --------
Stephen B. Roy 50 President and Director
Peter A. Roy 46 Executive Vice President and Director
Jane L. Roy 41 Executive Vice President, Treasurer, Chief
Financial Officer and Director
Ellen S. Roy 37 Senior Vice President, Clerk and Director
Luciano Lauretti 34 Senior Vice President
Maureen P. Herbert 38 Vice President
George Briden 44 Vice President
Bruce A. Herzfelder 37 Senior Vice President
Leah Taylor Roy 36 Vice President
James Blakey 44 Vice President and General Counsel
Stephen R. Pritchard 39 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 managment 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.
79
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.A. 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 1978 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.
Directors are elected annually and each elected director holds office until
a successor is elected. The Board of Directors currently 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.
80
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
The following table sets forth the names, ages and positions of the
directors and executive officers of IEC Funding and their positions with IEC
Funding. 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 50 President, Assistant Treasurer, Assistant Secretary and Director
Ellen S. Roy 37 Vice President, Secretary, Assistant Treasurer and Director
Jane L. Roy 41 Vice President, Treasurer, Assistant Secretary and Director
Peter A. Roy 46 Vice President, Assistant Secretary and Assistant Treasurer
Maureen P. Herbert 38 Vice President
James Blakey 44 Vice President and
General Counsel
For biographical information on each of the above listed persons, see
"Management Directors and Executive Officers of the General Partner".
ITEM. 11 EXECUTIVE AND BOARD COMPENSATION AND BENEFITS
None of the executive officers or directors of IEC Funding receive any
compensation for their services as such. The directors and executive officers
of IEC are compensated by IEC and are not entitled to any direct compensation
from the Partnerships. However, IEC, all outstanding capital stock of which is
owned by certain Sponsor Members, will be paid a fee by the Partnerships, as
described under "CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS-Fee."
81
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following information is given with respect to the partnership
interests in NEA held by IEC, persons who are direct or indirect beneficial
owners of more than 5% of such partnership interests or persons who are
directors or executive officers of IEC:
NAME OF NATURE OF BENEFICIAL PERCENTAGE
TITLE OF CLASS BENEFICIAL OWNER (1) OWNERSHIP(2) INTEREST
- -------------- -------------------- ------------ --------
General Partnership Interest Intercontinental Energy Corporation General Partner 1.00%
Limited Partnership Interest Stephen B. Roy Limited Partner 30.39%
Limited Partnership Interest Peter A. Roy Limited Partner 20.89%(3)
Limited Partnership Interest Mary Lou Roy Limited Partner 10.70%
Limited Partnership Interest John R. Roy Limited Partner 10.20%
Limited Partnership Interest Jane L. Roy Limited Partner 5.95%
Limited Partnership Interest Ellen S. Roy Limited Partner 2.13%
Limited Partnership Interest Luciano Lauretti Indirect 1.00%
Limited Partnership Interest Bruce A. Herzfelder Indirect 1.00%
______________
(1) Each listed person has an address of Intercontinental Energy Corporation,
350 Lincoln Place, Hingham, Massachusetts 02043.
(2) None of the persons listed has the right to acquire beneficial ownership of
securities as specified in Rule 13d-3(d)(1) under the Securities Exchange
Act of 1934.
(3) Includes interests owned by children of Peter A. Roy.
82
The following information is given with respect to the partnership
interests in NJEA held by IEC, persons who are direct or indirect beneficial
owners of more than 5% of such partnership interests or persons who are
directors or executive officers of IEC:
PERCENTAGE
NAME OF NATURE OF BENEFICIAL OWNERSHIP
TITLE OF CLASS BENEFICIAL OWNER (1) OWNERSHIP(2) INTEREST
- ------------------------------ ----------------------------------- ------------------------ --------------
General Partnership Interest Intercontinental Energy Corporation General Partner 1.00%
Limited Partnership Interest Stephen B. Roy Limited Partner 32.05%
Limited Partnership Interest Peter A. Roy Limited Partner 22.04%(3)
Limited Partnership Interest Mary Lou Roy Limited Partner 11.28%
Limited Partnership Interest John R. Roy Limited Partner 10.75%
Limited Partnership Interest Jane L. Roy Limited Partner 6.27%
Limited Partnership Interest Ellen S. Roy Limited Partner 2.24%
Limited Partnership Interest Luciano Lauretti Indirect 1.00%
Limited Partnership Interest Bruce A. Herzfelder Indirect 1.00%
______________
(1) Each listed person has an address of Intercontinental Energy Corporation,
350 Lincoln Place, Hingham, Massachusetts 02043.
(2) None of the persons listed has the right to acquire beneficial ownership of
securities as specified in Rule 13d-3(d)(1) under the Securities Exchange
Act of 1934.
(3) Includes interests owned by children of Peter A. Roy.
83
Except as specifically provided or required by law, Limited Partners may
not participate in the management or control of the Partnerships. Thus,
although the General Partner has a 1% interest in each Partnership, it has sole
responsibility for the management of each Partnership. All of the outstanding
capital stock of the General Partner is currently owned, collectively, by
certain of the Sponsor Members. See "CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS--Affiliation of Partners of the Partnerships."
The Partnerships are limited partnerships wholly owned by their Partners.
Beneficial interests in the Partnerships are not available to any persons other
than the Partners. See "CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS--
Affiliation of Partners of the Partnerships." Except as specified in the tables
above, none of the executive officers of the General Partner has any beneficial
ownership in the Partnerships.
The following information is given with respect to the beneficial ownership
of the outstanding capital stock of IEC Funding:
NAME OF
NATURE OF BENEFICIAL BENEFICIAL PERCENTAGE
TITLE OF CLASS OWNER OWNERSHIP INTEREST
- -------------- ---------- --------- --------
Common Stock Broad Street 2,500 shares 25.00%
Contract Services, Inc.
Two Wall Street
New York, NY 10005
Common Stock Stephen B. Roy (1)(2) 1,875 shares 18.75%
Common Stock Ellen S. Roy (1)(2) 1,875 shares 18.75%
Common Stock Jane L. Roy (1)(2) 1,875 shares 18.75%
Common Stock Peter A. Roy (2)(3) 1,875 shares 18.75%
Common Stock All directors and
executive officers
as a group 7,500 shares 75.00%
________________
(1) Director and executive officer of IEC Funding.
(2) Each person has an address of Intercontinental Energy Corporation, 350
Lincoln Place, Hingham, MA 02043.
(3) Executive officer of IEC Funding.
84
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
AFFILIATION OF PARTNERS OF THE PARTNERSHIPS
Certain Sponsor Members own, directly or indirectly, 84% of the partnership
interests in NEA and 88% of the partnership interests in NJEA. In addition,
certain Sponsor Members collectively own all of the outstanding capital stock of
IEC and are therefore able, collectively, to control the Partnerships. However,
no agreement exists among the Sponsor Members to act in concert with respect to
issues affecting the management of the General Partner or the Partnerships. It
is a default under the terms of the Indenture for the Sponsor Members to own
less than 25% of the equity interests of each Project and 51% of the voting
stock of IEC.
MANAGEMENT FEE
Fees payable by the Partnerships to IEC are limited to the management fee
permitted under the 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 that are not Sponsor Members and (iv) the
amount determined as provided below. All costs identified in clauses (i), (ii)
and (iii) may be included as part of the fee only to the extent such costs are
certified by the Partnerships as being reasonably allocable to the Projects.
The amount identified in clause (iv) shall be $3.5 million for the calendar year
beginning January 1, 1995, and subject to escalation thereafter as set forth in
the Indenture.
The Partnerships made direct or indirect payments to IEC and the Sponsor
Members (excluding ratable distributions by the Partnerships to their Partners)
aggregating approximately $6,148,000 during the year ended December 31, 1994,
$6,480,000 during the year ended December 31, 1995 and $8,719,000 during the
year ended December 31, 1996. Such payments are not necessarily indicative of
amounts that will be payable by the Partnerships to IEC in the future, which
will be determined as described in the preceding paragraph.
85
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, 1995 and 1996
Combined Statement of Operations for the years ended December 31, 1994,
1995 and 1996
Combined Statement of Partners' Deficit for the years ended December 31,
1994, 1995 and 1996
Combined Statement of Cash Flows for the years ended December 31, 1994,
1995 and 1996
Notes to Combined Financial Statements
IEC FUNDING CORP.
Report of Independent Accountants
Balance Sheet at December 31, 1995 and 1996
Statement of Operations for the period from inception (November 3, 1994)
through December 31, 1994 and the years ended December 31, 1995 and 1996
Statement of Stockholders' Equity for the period from inception (November
3, 1994) through December 31, 1994 and the years ended December 31, 1995
and 1996
Statement of Cash Flows for the period from inception (November 3, 1994)
through December 31, 1994 and the years ended December 31, 1995 and 1996
Notes to Financial Statements
86
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.
(B) REPORTS ON FORM 8-K.
There were no reports on Form 8-K filed during the three months ended
December 31, 1996.
(C) EXHIBITS
Exhibit No. Description of Exhibit
- ----------- ----------------------
3.1* Certificate of Incorporation of IEC Funding
3.2* By-laws of IEC Funding
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 and as
further amended on July 6, 1989
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 and March 4,
1988
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*** Agreement of Limited Partnership of Northeast Energy Associates, A
Limited Partnership, dated as of October 15, 1996
3.8*** Agreement of Limited Partnership of North Jersey Energy Associates, A
Limited Partnership, dated as of October 15, 1996
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")
87
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
4.12* Amended and Restated Assignment and Security Agreement dated as of
December 1, 1994, between NJEA and the Collateral Agent
88
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
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")
89
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
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
90
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")
10.4.6* Northeast Gas Substitution Agreement dated as of July 30, 1993, among
ProGas, NEA and TransCanada
91
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
92
10.6.1* Gas Purchase Contract dated as of May 12, 1988 (the "Bellingham ProGas
Agreement"), between ProGas and NEA
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")
93
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
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")
94
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
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
12* Statements regarding computation of ratios
21* Subsidiaries of NJEA
___________________
* 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.
*** Incorporated herein by reference from the Quarterly Report on Form 10-Q
filed by IEC Funding and the Partnerships on November 14, 1996.
95
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
IEC Funding Corp. has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
IEC FUNDING CORP.
Date: March 28, 1997 By:/s/ Jane L. Roy
--------------------------------------------
Jane L. Roy
Vice President, Chief Financial Officer
and Treasurer (Principal Financial Officer
and Principal Accounting Officer)
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 and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Stephen B. Roy President and Director
- -------------------- (Principal Executive Officer) March 28, 1997
Stephen B. Roy
/s/ Jane L. Roy Vice President, Chief Financial Officer
- -------------------- and Treasurer and Director (Principal Financial Officer
Jane L. Roy and Principal Accounting Officer) March 28, 1997
/s/ Ellen S. Roy Vice President,
- -------------------- Secretary and Director March 28, 1997
Ellen S. Roy
96
SIGNATURES
Pursuant to the requirements 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, thereunto duly authorized.
NORTH JERSEY ENERGY ASSOCIATES,
A LIMITED PARTNERSHIP
By: INTERCONTINENTAL ENERGY CORPORATION,
As General Partner
Date: March 28, 1997 By: /s/ Jane L. Roy
--------------------------------------
Jane L. Roy
Executive Vice President, Chief Financial Officer
and Treasurer (Principal Financial Officer
and Principal Accounting Officer
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 and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Stephen B. Roy President and Director
- ----------------------- (Principal Executive Officer) March 28, 1997
Stephen B. Roy
/s/ Peter A. Roy Executive Vice President,
- ----------------------- and Director March 28, 1997
Peter A. Roy
/s/ Ellen S. Roy Vice President, Clerk
- ----------------------- and Director March 28, 1997
Ellen S. Roy
97
SIGNATURES
Pursuant to the requirements 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, thereunto duly authorized.
NORTHEAST ENERGY ASSOCIATES,
A LIMITED PARTNERSHIP
By: INTERCONTINENTAL ENERGY CORPORATION,
As General Partner
Date: March 28, 1997 By: /s/ Jane L. Roy
-------------------------------------
Jane L. Roy
Executive Vice President, Chief Financial
Officer and Treasurer (Principal Financial
Officer and Principal Accounting Officer)
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 and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Stephen B. Roy President and Director
- ------------------------- (Principal Executive Officer) March 28, 1997
Stephen B. Roy
/s/ Peter R. Roy Executive Vice President,
- -------------------------- and Director March 28, 1997
Peter R. Roy
/s/ Ellen S. Roy Vice President, Clerk
- -------------------------- and Director March 28, 1997
Ellen S. Roy
98
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.
"Avoided Costs" means, in connection with any Power Purchase Agreement, the
applicable Power Purchaser's time-differentiated avoided costs of energy
applicable to deliveries of energy from the applicable Project.
"Algonquin" means Algonquin Gas Transmission Company, a Delaware
corporation.
"Bellingham Additional 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 Bellingham Site.
"Bellingham 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).
"Bellingham O&M Fee" means the monthly fee required to be paid by NEA to
the Operator pursuant to the Bellingham O&M Agreement.
"Bellingham Power Purchase Agreements" means the Boston Edison I Contract,
the Boston Edison II Contract, the Commonwealth I Contract, the Commonwealth II
Contract and the Montaup Contract.
"Bellingham Power Purchasers" means Boston Edison, Commonwealth and
Montaup.
A-1
"Bellingham ProGas Agreement" means the Gas Purchase Contract dated as of
May 12, 1988, between NEA and ProGas.
"Bellingham Project" means the natural gas-fired electrical and steam
generating plant owned by NEA and located on the Bellingham 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.
"Bellingham Project Documents" means, individually and collectively,
certain existing agreements and documents specified in the Indenture (which
include the Bellingham Power Purchase Agreements, the Bellingham Gas Agreements,
the Bellingham 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 to which NEA is a party or which relate to all or
any part of the Bellingham Project or the Carbon Dioxide Plant.
"Bellingham 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 Bellingham Site and all related
improvements and fixtures thereon owned by NEA.
"Bellingham Site" means the approximately 44-acre site on the upper Charles
River in the town of Bellingham, Massachusetts, on which the Bellingham Project
and the Carbon Dioxide Plant are located.
"Bellingham Steam Sales Agreement" means the Amended and Restated Steam
Sales Agreement dated as of December 21, 1990, between NEA and NECO.
"BOC Gases" means the BOC Gases Division of the BOC Group, Inc., a Delaware
corporation.
"Boston Edison" means Boston Edison Company, a Massachusetts corporation.
"Boston Edison I Contract" means the Power Purchase Agreement dated as of
April 1, 1986, between NEA and Boston Edison.
"Boston Edison II Contract" means the Power Purchase Agreement dated as of
January 28, 1988, 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.
"Carbon Dioxide Plant" means the carbon dioxide production facility owned
by NEA and located adjacent to the Bellingham Project on the Bellingham Site and
all equipment and facilities ancillary thereto.
"CNG" means CNG Transmission Corporation, a Delaware corporation.
A-2
"CO" means carbon monoxide.
"Collateral" means, collectively, all of the collateral mortgaged, pledged
or assigned to the Collateral Agent by any of the Company, each Partnership, IEC
and the holders of IEC Funding's capital stock, in each case pursuant to the
granting and assigning clauses of the applicable Security Documents.
"Commonwealth" means Commonwealth Electric Company, a Massachusetts
corporation.
"Commonwealth I Contract" means the Power Sale Agreement dated as of
November 26, 1986, between NEA and Commonwealth.
"Commonwealth II Contract" means the Power Sale Agreement dated as of
August 15, 1988, between NEA and Commonwealth.
"Company" means IEC Funding Corp., a Delaware corporation.
"Daily Bellingham Quantity" means 48,817 MMBtu of natural gas.
"Daily Sayreville Quantity" means 22,019 MMBtu of natural gas.
"Dekatherm" or "Dth" means one MMBtu.
"DOE" means the United States Department of Energy.
"Dollars" and "$" means lawful money of the United States.
"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.
"EPA" means the Environmental Protection Agency of the United States.
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"Exchange Offer" means the offer by IEC Funding, upon the terms and subject
to the conditions set forth in the Prospectus and the accompanying Letter of
Transmittal, to exchange its 8.43% Senior Secured Notes Due 2000, Series A, its
9.16% Senior Secured Notes Due 2002, Series A, its 9.32% Senior Secured Bonds
Due 2007, Series A and its 9.77% Senior Secured Bonds Due 2010, Series A for an
equal principal amount of its issued and outstanding 8.43% Senior Secured Notes
Due 2000, 9.16% Senior Secured Notes Due 2002, 9.32% Senior Secured Bonds Due
2007 and 9.77% Senior Secured Bonds Due 2010.
A-3
"Existing Loan Agreement" means the Project Loan and Credit Agreement dated
as of June 28, 1989, as amended, among the Partnerships as borrowers, IEC, Chase
as Issuing Bank and as Agent for the Banks, The Bank of New York (as successor
to Irving Trust Company) as Co-Agent and the Banks.
"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 22-F or
below.
"FERC" means the United States Federal Energy Regulatory Commission.
"FERC Regulations" means all rules and regulations promulgated by FERC.
"Fluor Daniel" means Fluor Daniel Inc., a California corporation.
"FPA" means the Federal Power Act of 1925, as amended.
"General Partner" means IEC, the general partner of each Partnership.
"Heat Rate" means the number of Btus of heat produced per kilowatt-hour of
electrical energy produced.
"Hercules" means Hercules Incorporated, a Delaware corporation.
"IEC" means Intercontinental Energy Corporation, a Massachusetts
corporation.
"IEC Funding" means IEC Funding Corp., a Delaware corporation and the
issuer of the Securities.
"Import Point" means the point of interconnection between the TransCanada
pipeline and CNG's pipeline at Niagara Falls, Ontario/Niagara Falls, New York.
"Indenture" means the Trust Indenture dated as of November 15, 1994,
entered into by IEC Funding, the Partnerships and the Trustee providing for the
issuance of the Securities.
"JCP&L" means Jersey Central Power & Light Company, a New Jersey
corporation.
"JCP&L Contract" means the Power Purchase Agreement dated as of October 22,
1987 entered into by NJEA and JCP&L.
"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.
A-4
"Limited Partners" means the limited partners of the Partnerships.
"Long-term Gas Arrangements" means the Bellingham Gas Agreements and the
Sayreville Gas Agreements.
"Long-term Gas Storage Agreements" means the Bellingham Gas Storage
Agreement and the Sayreville Gas Storage Agreement.
"Long-term Gas Supply Agreements" means the Bellingham ProGas Agreement,
the Sayreville ProGas Agreement and the PSE&G Contract.
"Long-term Gas Transportation Agreements" means the Bellingham Gas
Transportation Agreements and the Sayreville Gas Transportation Agreements.
"Massachusetts Electric Company" means Massachusetts Electric Company, a
Massachusetts corporation.
"MBtu" means one thousand Btus.
"Mcf" means one thousand cubic feet of gas at 60-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 Contract" means the Power Purchase Agreement dated as of October
17, 1986, between NEA and Montaup.
"NEA" means Northeast Energy Associates, A Limited Partnership, a
Massachusetts limited partnership.
"NECO" means NECO-Bellingham, Inc., a Massachusetts corporation.
"NECO Lease" means the Amended and Restated Lease dated as of December 21,
1990, between NEA and NECO.
A-5
"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 Notes" means (a) the promissory notes of the Partnerships issued to
the Company on the Closing Date pursuant to the Amended and Restated Credit
Agreement, which notes were issued (x) to amend and restate the Existing Notes
and (y) to evidence the Closing Date Company Loan, together with (b) any
promissory notes issued by the Partnerships to the Company subsequent to the
Closing Date in accordance with the terms of the Amended and Restated Credit
Agreement.
"New Securities" means 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.
"1933 Act" means the Securities Act of 1933, as amended.
"1990 Amendments" means the 1990 Amendments to the Federal Clean Air Act of
1955.
"NJBRC" means the New Jersey Board of Regulatory Commissioners.
"NJEA" means North Jersey Energy Associates, A Limited Partnership, a New
Jersey limited partnership.
"NO\\x\\" means Nitrous Oxide.
"O&M Agreements" means the Bellingham O&M Agreement and/or the Sayreville
O&M Agreement, as applicable, together with any replacements therefor (including
any extensions or modifications thereof).
"Old Securities" means the issued and outstanding 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.
"Operator" means Westinghouse Services.
"Partner" means the General Partner and each Limited Partner.
A-6
"Partnerships" means NEA and NJEA.
"Person" means any individual, sole proprietorship, corporation,
partnership, joint venture, limited liability company, trust, unincorporated
association, institution, Government Authority or any other entity.
"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.
"Power Purchase Agreements" means individually and collectively, the Boston
Edison I Contract, the Boston Edison II Contract, the Commonwealth I Contract,
the Commonwealth II Contract, the Montaup Contract and the JCP&L Contract, and
any Additional Project Document (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 sucessor to Liquid Carbonic Carbon
Dioxide Corporation.
"ProGas" means ProGas Limited, an Alberta corporation.
"ProGas Agreements" means the Bellingham ProGas Agreement and the
Sayreville ProGas Agreement.
"Projects" means, collectively, the Bellingham Project and the Sayreville
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" means Public Service Electric and Gas Company, a New Jersey
corporation.
"PSE&G Contract" means the Gas Purchase and Sales Agreement dated as of May
4, 1989, as amended, between NJEA and PSE&G.
A-7
"PUHCA" means the Public Utility Holding Company Act of 1935, as amended.
"PURPA" shall mean 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 that energy rate filed from
time to time by each of the Bellingham Power Purchasers and approved by the
Massachusetts Department of Public Utilities.
"Sayreville Mortgage" means the Amended and Restated Indenture of Mortgage,
Assignment of Rents, Security Agreement and Fixture Filing to be granted by NJEA
to the Collateral Agent with respect to the Sayreville Site and all related
improvements and fixtures thereon owned by NJEA.
"Sayreville 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).
"Sayreville O&M Fee" means the monthly fee required to be paid by NJEA to
the Operator pursuant to the Sayreville O&M Agreement.
"Sayreville ProGas Agreement" means the Gas Purchase Contract dated as of
May 12, 1988, between NJEA and ProGas.
"Sayreville Project" means the natural gas-fired electrical and steam
generating plant owned by NJEA and located on the Sayreville 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.
"Sayreville Project Documents" means, individually and collectively,
certain existing agreements and documents specified in the Indenture (which
include the JCP&L Contract, the Sayreville Gas Agreements and the Sayreville
Steam Sales Agreement), as any of the same may from time to time be amended,
modified or supplemented, together with all Additional Project Documents to
which NJEA is a party or which relate to all or any part of the Sayreville
Project.
"Sayreville Site" means the approximately 49-acre site in the Borough of
Sayreville, New Jersey, on which the Sayreville Project is located.
A-8
"Sayreville Steam Sales Agreement" means the Industrial Steam Sales
Contract dated as of June 5, 1989, as amended, between NJEA and Hercules.
"SEC" means the United States Securities and Exchange Commission.
"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.
"Secured Parties" shall have the meaning ascribed thereto in the Collateral
Agency Agreement entered into by State Street Bank and Trust Company, as
collateral agent (the "Collateral Agent"), the Company, the Partnerships and
others. The Secured Parties include the Holders of the Securities (represented
by the Trustee), the Working Capital Banks, the Swap Banks (as defined in the
Collateral Agency Agreement), if any, the Collateral Agent and the Trustee.
"Securities" means the Old Securities and the New Securities.
"Security Documents" means the mortgages and other security agreements
pursuant to which the Partnerships, the Company, IEC and the holders of the
Company's capital stock grant liens to the Collateral Agent for the benefit of
the Secured Parties.
"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 lineal
descendant of any of the foregoing (excluding Jock 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.
"TransCanada" means Trans Canada Pipelines Limited, an Ontario corporation.
"Transco" means Transcontinental Gas Pipe Line Corporation, a Delaware
corporation.
"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.
A-9
EXHIBIT 10.10.5.1
WESTINGHOUSE ELECTRIC CORPORATION GUARANTY
NECO-Bellingham, Inc.
11104 West Airport Boulevard
Suite 160
Stafford, Texas 77477
Gentlemen:
Reference is made to the Contract between NECO-Bellingham, Inc. ("Lessee") and
Westinghouse Operating Services Company, Inc. ("WOSC") for the Bellingham
Project Carbon Dioxide Recovery Facility ("Contract"). WOSC is a wholly owned
subsidiary of Westinghouse Electric Corporation ("WELCO"). In connection with
said Contract, WELCO agrees as follows:
1. Unless otherwise noted, capitalized terms used in this letter shall
have the meanings assigned to such terms in the Contract.
2. In consideration of one dollar and other good and valuable
consideration, the receipt and sufficiency of which is hereby
acknowledged, WELCO, on behalf of itself, its successors, and
permitted assigns, irrevocably and unconditionally guarantees to
Lessee, its successors, and permitted assigns, the prompt, full and
faithful observance, fulfillment and performance by WOSC of each of
the obligations, responsibilities, and undertakings to be carried out,
performed or observed by WOSC to the extent and under the terms and
conditions set forth in the Contract.
3. If at any time WOSC, its successors, or permitted assigns, fails,
neglects or refuses to timely or fully perform any of its obligations,
responsibilities, or undertakings as expressly provided in the terms
and conditions of the Contract, and if within fifteen (15) days after
written notice of such failure, WOSC has not commenced corrective
action to the extent required by the Contract, then upon receipt of
written notice from Lessee specifying the failure, WELCO shall
perform, or cause to be performed, any such obligation,
responsibility, or undertaking as required pursuant to the terms and
conditions of the Contract, including without limitation all payment
obligations under the Contract.
4. With respect to any claim, action or proceeding against WELCO in
connection with this guaranty, WELCO shall be entitled to assert only
those defenses which WOSC would be able to assert if such claim,
action or proceeding were to be asserted or instituted against WOSC
based upon the Contract.
5. WELCO covenants and agrees with Lessee, its successors, and permitted
assigns, that (i) any amendments, modifications or supplements to the
Contract, or (ii) the
108
giving of any consent by Lessee or WOSC to any permitted assignment of
the Contract, or (iii) the waiver of the performance or observance by
WOSC of any agreement, covenant, term or condition to be performed or
observed by WOSC, or (iv) the lease, sale, transfer or conveyance of
the Equipment or any interest to any party, may all or any of them be
made and done without notice to, or the consent of, WELCO and without
in any way affecting, changing or releasing WELCO from its obligations
hereunder.
6. With respect to this Guaranty, WELCO represents the following:
(i) that it is a corporation duly organized, validly existing and
in good standing under Pennsylvania laws and that the
execution, delivery and performance of this Guaranty has been
duly authorized by all requisite corporate action and will not
violate any provision of any governmental rule, regulation or
ordinance, its charter or by-laws or any indenture, agreement
or instrument to which it is a party; and
(ii) that it is not in violation of any applicable law, statute,
order, rule or regulation promulgated or judgment entered by
any federal, state, local or governmental authority which
violations, individually or in the aggregate, would affect
WELC's guaranty of WOSC's performance of its obligations under
the Contract; and
(iii) that it is not a party to any legal, administrative, arbitral,
investigatory or other proceeding or controversy pending, or,
to the best of WELCO's knowledge, threatened, which would
adversely affect WELCO's ability to guaranty WOSC's
performance of its obligations under the Contract.
7. This Guaranty shall be governed by and interpreted under the
substantive laws of the State of New York, United States of America, excluding
rules governing conflicts of laws. Any dispute arising under or relating to
this guaranty shall be resolved according to the provisions set forth in Article
13, Dispute Resolution, of the Contract.
Very truly yours,
/s/ Paul Loch
---------------------------------
General Manager
EnergyServices Division
Westinghouse Electric Corporation
May 12, 1995
109