FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-1004
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1998
OR
[] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to ________
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
1-5324 NORTHEAST UTILITIES 04-2147929
(a Massachusetts voluntary association)
174 Brush Hill Avenue
West Springfield, Massachusetts 01090-2010
Telephone: (413) 785-5871
0-11419 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850
(a Connecticut corporation)
107 Selden Street
Berlin, Connecticut 06037-1616
Telephone: (860) 665-5000
1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050
(a New Hampshire corporation)
1000 Elm Street
Manchester, New Hampshire 03105-0330
Telephone: (603) 669-4000
0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130
(a Massachusetts corporation)
174 Brush Hill Avenue
West Springfield, Massachusetts 01090-2010
Telephone: (413) 785-5871
33-43508 NORTH ATLANTIC ENERGY CORPORATION 06-1339460
(a New Hampshire corporation)
1000 Elm Street
Manchester, New Hampshire 03105-0330
Telephone: (603) 669-4000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
Northeast Utilities Common Shares, New York Stock Exchange, Inc.
$5.00 par value
The Connecticut Light 9.3% Cumulative Monthly New York Stock Exchange, Inc.
and Power Company Income Preferred
Securities Series A (1)
(1) Issued by CL&P Capital, L.P., a wholly owned subsidiary of The Connecticut
Light and Power Company ("CL&P"), and guaranteed by CL&P.
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Each Class
The Connecticut Light Preferred Stock, par value $50.00 per share,
and Power Company issuable in series, of which the following series
are outstanding:
$1.90 Series of 1947 4.96% Series of 1958
$2.00 Series of 1947 4.50% Series of 1963
$2.04 Series of 1949 5.28% Series of 1967
$2.20 Series of 1949 6.56% Series of 1968
3.90% Series of 1949 $3.24 Series G of 1968
$2.06 Series E of 1954 7.23% Series of 1992
$2.09 Series F of 1955 5.30% Series of 1993
4.50% Series of 1956
Public Service Company Preferred Stock, par value $25.00 per share, issuable
of New Hampshire in series, of which the following series is outstanding:
10.60% Series A of 1991
Western Massachusetts Preferred Stock, par value $100.00 per share, issuable
Electric Company in series, of which the following series is outstanding:
7.72% Series B of 1971
Class A Preferred Stock, par value $25.00 per share,
issuable in series, of which the following series is
outstanding:
7.60% Series of 1987
Indicate by check mark whether the registrants (1) have 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
registrants were required to file such reports), and (2) have been subject
to such filing requirements for the past 90 days.
Yes X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of Northeast Utilities' Common Share, $5.00 Par
Value, held by nonaffiliates, was $2,056,807,290 based on a closing sales
price of $15.00 per share for the 137,120,486 common shares outstanding on
February 26, 1999. Northeast Utilities holds all of the 12,222,930 shares,
1,000 shares, 1,072,471 shares and 1,000 shares of the outstanding common
stock of The Connecticut Light and Power Company, Public Service Company of
New Hampshire, Western Massachusetts Electric Company, and North Atlantic
Energy Corporation, respectively.
Documents Incorporated by Reference:
Part of Form 10-K
into Which Document
Description is Incorporated
Portions of Annual Reports to Shareholders of
the following companies for the year ended
December 31, 1998:
Northeast Utilities Part II
The Connecticut Light and Power Company Part II
Public Service Company of New Hampshire Part II
Western Massachusetts Electric Company Part II
North Atlantic Energy Corporation Part II
Portions of the Northeast Utilities Proxy
Statement dated March 31, 1999 Part III
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or
acronyms that are found throughout this report:
COMPANIES
NU............................... Northeast Utilities
CL&P............................. The Connecticut Light and Power Company
Charter Oak or COE............... Charter Oak Energy, Inc.
WMECO............................ Western Massachusetts Electric Company
HWP.............................. Holyoke Water Power Company
NUSCO or the Service Company..... Northeast Utilities Service Company
NNECO............................ Northeast Nuclear Energy Company
NAEC............................. North Atlantic Energy Corporation
NAESCO or North Atlantic......... North Atlantic Energy Service Corporation
PSNH............................. Public Service Company of New Hampshire
RRR.............................. The Rocky River Realty Company
Select Energy.................... Select Energy, Inc.
Mode 1........................... Mode 1 Communications, Inc.
HEC.............................. HEC Inc.
Quinnehtuk....................... The Quinnehtuk Company
the System....................... The Northeast Utilities System
CYAPC............................ Connecticut Yankee Atomic Power Company
MYAPC............................ Maine Yankee Atomic Power Company
VYNPC............................ Vermont Yankee Nuclear Power Corporation
YAEC............................. Yankee Atomic Electric Company
the Yankee Companies............. CYAPC, MYAPC, VYNPC and YAEC
GENERATING UNITS
Millstone 1...................... Millstone Unit No. 1, a 660-MW nuclear
generating unit completed in 1970
Millstone 2...................... Millstone Unit No. 2, an 870-MW nuclear
electric generating unit completed in 1975
Millstone 3...................... Millstone Unit No. 3, a 1,154-MW nuclear
electric generating unit completed in 1986
Seabrook or Seabrook 1........... Seabrook Unit No. 1, a 1,148-MW nuclear
electric generating unit completed in 1986.
Seabrook 1 went into service in 1990.
REGULATORS
DOE.............................. U.S. Department of Energy
DTE.............................. Massachusetts Department of
Telecommunications and Energy
DPUC............................. Connecticut Department of Public Utility
Control
MDEP............................. Massachusetts Department of Environmental
Protection
GLOSSARY OF TERMS
REGULATORS (Continued)
CDEP............................. Connecticut Department of Environmental
Protection
EPA.............................. U.S. Environmental Protection Agency
FERC............................. Federal Energy Regulatory Commission
NHDES............................ New Hampshire Department of Environmental
Services
NHPUC............................ New Hampshire Public Utilities Commission
NRC.............................. Nuclear Regulatory Commission
SEC.............................. Securities and Exchange Commission
OTHER
1935 Act......................... Public Utility Holding Company Act of 1935
CAAA............................. Clean Air Act Amendments of 1990
DSM.............................. Demand-Side Management
Energy Act....................... Energy Policy Act of 1992
EWG.............................. Exempt wholesale generator
EAC.............................. Energy Adjustment Clause (CL&P)
FAC.............................. Fuel Adjustment Clause (CL&P)
FPPAC............................ Fuel and purchased power adjustment
clause (PSNH)
FUCO............................. Foreign utility company
GUAC............................. Generation Utilization Adjustment Clause
(CL&P)
IRM.............................. Integrated resource management
kWh.............................. Kilowatt-hour
MW............................... Megawatt
NBFT............................. Niantic Bay Fuel Trust, lessor of nuclear
fuel used by CL&P and WMECO
NEPOOL........................... New England Power Pool
NUGs............................. Nonutility generators
NUG&T............................ Northeast Utilities Generation and
Transmission Agreement
QF............................... Qualifying facility
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
NORTH ATLANTIC ENERGY CORPORATION
1998 Form 10-K Annual Report
Table of Contents
PART I
Page
Item 1. Business............................................... 1
The Northeast Utilities System......................... 1
Safe Harbor Statement.................................. 2
Electric Industry Restructuring........................ 3
General........................................... 3
Connecticut Restructuring......................... 4
Massachusetts Restructuring....................... 5
New Hampshire Restructuring....................... 6
Rates.................................................. 7
Connecticut Retail Rates.......................... 7
New Hampshire Retail Rates........................ 8
Massachusetts Retail Rates........................ 10
Competitive System Businesses.......................... 11
Energy-Related Products and Services.............. 11
Energy Management Services........................ 11
Telecommunications................................ 11
Financing Program...................................... 12
1998 Financings................................... 12
1999 Financing Requirements....................... 13
1999 Financing Plans.............................. 14
Financing Limitations............................. 14
Construction Program................................... 18
Electric Operations.................................... 20
Distribution and Sales............................ 20
Regional and System Coordination.................. 21
Transmission Access and FERC Regulatory Changes... 21
Nuclear Generation..................................... 22
General........................................... 22
Nuclear Plant Performance and Regulatory Oversight 24
Nuclear Insurance................................. 25
Nuclear Fuel...................................... 25
Decommissioning................................... 27
Other Regulatory and Environmental Matters............. 31
Environmental Regulation.......................... 31
Electric and Magnetic Fields...................... 34
FERC Hydro Project Licensing...................... 35
Employees.............................................. 36
Year 2000.............................................. 36
Item 2. Properties............................................. 37
Item 3. Legal Proceedings...................................... 42
Item 4. Submission of Matters to a Vote of Security Holders.... 47
PART II
Item 5. Market for Registrants' Common Equity and Related
Shareholder Matters.................................... 47
Item 6. Selected Financial Data................................ 47
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 48
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk............................................ 48
Item 8. Financial Statements and Supplementary Data............ 49
Item 9. Changes in Disagreements with Accountants on
Accounting and Financial Disclosure.................... 49
PART III
Item 10. Directors and Executive Officers of the Registrants.... 50
Item 11. Executive Compensation................................. 54
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 66
Item 13. Certain Relationships and Related Transactions......... 69
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.................................... 7
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
NORTH ATLANTIC ENERGY CORPORATION
PART I
ITEM 1. BUSINESS
THE NORTHEAST UTILITIES SYSTEM
Northeast Utilities (NU) is the parent of a number of companies
comprising the Northeast Utilities system (the System) and is not itself an
operating company. The System has traditionally furnished franchised retail
electric service in Connecticut, New Hampshire and western Massachusetts
through three of NU's wholly owned subsidiaries (The Connecticut Light and
Power Company [CL&P], Public Service Company of New Hampshire [PSNH] and
Western Massachusetts Electric Company [WMECO]) and has additionally
furnished retail electric service to a limited number of customers through
another wholly owned subsidiary, Holyoke Water Power Company [HWP]. In
addition to their retail electric service, CL&P, PSNH, WMECO and HWP
(including its wholly owned subsidiary, Holyoke Power and Electric Company)
together furnish wholesale electric service to various municipalities and
other utilities and participate in limited retail access programs, providing
off-system retail service. The System serves in excess of 30 percent of New
England's electric needs is and one of the 24 largest electric utility
systems in the country as measured by revenues.
As of January 4, 1999, NU added three new corporations to the System:
NU Enterprises, Inc. (NUEI), Northeast Generation Company (NGC) and
Northeast Generation Services Company (NGS). NUEI, a direct subsidiary of
NU, will act as the new holding company for the System's unregulated
businesses. NGC, a subsidiary of NUEI, will acquire and manage generating
facilities. NGS, another subsidiary of NUEI, will provide services to the
electric generation market as well as to large commercial and industrial
customers in the Northeast. Also, as of January 4, 1999, NU transferred
three subsidiaries, Select Energy, Inc. (Select Energy), HEC Inc. (HEC)
and Mode 1 Communications, Inc. (Mode 1) to NUEI. These companies engage,
either directly or indirectly through subsidiaries, in a variety of energy-
related and telecommunications activities, as applicable. For information
regarding the energy-related activities of these subsidiaries, see
"Competitive System Businesses."
North Atlantic Energy Corporation (NAEC) is a special-purpose operating
subsidiary of NU that owns a 35.98 percent interest in the Seabrook nuclear
generating facility (Seabrook) in Seabrook, New Hampshire, and sells its
share of the capacity and output from Seabrook to PSNH under two life-of-
unit, full-cost recovery contracts.
Several wholly owned subsidiaries of NU provide support services for
the System companies and, in some cases, for other New England utilities.
Northeast Utilities Service Company (NUSCO) provides centralized accounting,
administrative, information resources, engineering, financial, legal,
operational, planning, purchasing and other services to the System
companies. North Atlantic Energy Service Corporation (NAESCO) has
operational responsibility for Seabrook. Northeast Nuclear Energy Company
(NNECO) acts as agent for the System companies and other New England
utilities in operating the Millstone nuclear generating facilities
(Millstone) in Waterford, Connecticut. Three other subsidiaries construct,
acquire or lease some of the property and facilities used by the System
companies.
The System is regulated in virtually all aspects of its business by
various federal and state agencies, including the Securities and Exchange
Commission (SEC), the Federal Energy Regulatory Commission (FERC), the
Nuclear Regulatory Commission (NRC) and various state and/or local
regulatory authorities with jurisdiction over the industry and the service
areas in which each company operates, including the Connecticut Department
of Public Utility Control (DPUC), the New Hampshire Public Utilities
Commission (NHPUC) and the Massachusetts Department of Telecommunications
and Energy (DTE). In recent years, there has been significant activity at
both the legislative and regulatory levels, particularly in New England,
to change the nature of regulation of the industry. For more information
regarding these restructuring initiatives, see "Electric Utility
Restructuring," "Rates," and "Electric Operations."
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 (Reform Act), NU and its reporting
subsidiaries are hereby filing cautionary statements identifying important
factors that could cause NU or its subsidiaries' actual results to differ
materially from those projected in forward-looking statements (as such term
is defined in the Reform Act) made by or on behalf of NU or its subsidiaries
in this combined Form 10-K, in any subsequent filings with the SEC, in
presentations, in response to questions or otherwise. Any statements
that express or involve discussions as to expectations, beliefs, plans,
objectives, assumptions or future events or performance (often, but not
always, through the use of words or phrases such as will likely result, are
expected to, will continue, is anticipated, estimated, projection, outlook)
are not statements of historical facts and may be forward-looking. Forward-
looking statements involve estimates, assumptions and uncertainties that
could cause actual results to differ materially from those expressed in the
forward-looking statements. Accordingly, any such statements are qualified
in their entirety by reference to, and are accompanied by, the following
important factors that could cause NU or its subsidiaries' actual results
to differ materially from those contained in forward-looking statements of
NU or its subsidiaries made by or on behalf of NU or its subsidiaries.
Any forward-looking statement speaks only as of the date on which such
statement is made, and NU and its subsidiaries undertake no obligation to
update any forward-looking statement or statements to reflect events or
circumstances after the date on which such statement is made or to reflect
the occurrence of unanticipated events. New factors emerge from time to
time and it is not possible for management to predict all of such factors,
nor can it assess the impact of each such factor on the business or the
extent to which any factor, or combination of factors may cause actual
results to differ materially from those contained in any forward-looking
statements.
Some important factors that could cause actual results or outcomes to
differ materially from those discussed in the forward-looking statements
include prevailing governmental policies and regulatory actions, including
those of the SEC, the NRC, the FERC and state regulatory agencies, with
respect to allowed rates of return, industry and rate structure, operation
of nuclear power facilities, acquisition and disposal of assets and
facilities, operation and construction of plant facilities, recovery of
purchased-power costs, stranded costs, decommissioning costs and present
or prospective wholesale and retail competition (including but not limited
to retail wheeling and transmission costs).
The business and profitability of NU and its subsidiaries are also
influenced by economic and geographic factors including political and
economic risks, changes with environmental and safety laws and policies,
weather conditions (including natural disasters), population growth rates
and demographic patterns, competition for retail and wholesale customers,
pricing and transportation of commodities, market demand for energy from
plants or facilities, changes in tax rates or policies or in rates of
inflation, changes in project costs, unanticipated changes in certain
expenses and capital expenditures, capital market conditions, competition
for new energy development opportunities, and legal and administrative
proceedings (whether, civil or criminal) and settlements.
All such factors are difficult to predict, contain uncertainties which
may materially affect actual results and are beyond the control of NU or its
subsidiaries.
ELECTRIC INDUSTRY RESTRUCTURING
GENERAL
Competition in the energy industry continues to grow as a result of
legislative and regulatory action, technological advances, relatively high
electric rates in certain regions of the country, including New England,
and the increased availability of natural gas. These competitive pressures
are particularly strong in New England, where legislatures and regulatory
agencies in these states have been at the forefront of restructuring of the
electric industry. Changes in this industry are expected to place downward
pressure on prices and to increase customer choice through competition.
Restructuring initiatives in the System companies' service territories
have created uncertainty with respect to future rates and the recovery of
"stranded costs." Stranded costs are expenditures incurred, or commitments
for future expenditures made, on behalf of customers with the expectation
such expenditures would continue to be recoverable in the future through
rates. However, under certain circumstances these costs might not be
recoverable from customers in a fully competitive electric utility industry
(i.e., the costs may result in above-market energy prices). The System is
particularly vulnerable to stranded costs because of (i) the System's
relatively high investment in nuclear generating capacity, which has a
high cost to build and maintain, (ii) significant regulatory assets, which
are those costs that have been deferred by state regulators for future
collection from customers, and (iii) state and federal government mandated
purchased-power contracts priced above market.
As of December 31, 1998, the System operating companies' net investment
in nuclear generating capacity, excluding its investment in certain regional
nuclear companies, was approximately $2.9 billion ($ 1.9 billion for CL&P,
$83 million for PSNH, $591 million for NAEC and $365 million for WMECO) and
its regulatory assets were approximately $2.3 billion ($1.4 billion for
CL&P, $610.2 million for PSNH, and $322.4 million for WMECO). In addition,
based on current market prices, the System companies have above-market
purchase power obligations, the combined net present value of which is in
excess of a billion dollars. The bulk of these purchase power obligations
are held by CL&P and PSNH.
The System's financial strength and resulting ability to compete in a
restructured environment will be negatively affected if the System companies
are unable to recover their past investments and commitments. Even if the
NU System companies are given the opportunity to recover a large portion of
their stranded costs, earnings prospects in a restructured environment will
be affected in ways which cannot be estimated at this time.
As discussed more fully below, Connecticut and Massachusetts have
enacted restructuring legislation that permits CL&P and WMECO to recover
their prudently incurred stranded costs. PSNH's ability to recover its
stranded costs is currently the subject of litigation.
CONNECTICUT RESTRUCTURING
In April 1998, Connecticut enacted comprehensive electric utility
restructuring legislation. The legislation provides a clear path to
competition in the state, while permitting, subject to mitigation
requirements, utilities to recover their stranded costs. CL&P is subject
to this legislation.
In particular, the bill provides, among other things, that:
(i) Retail choice will occur in two phases: beginning in January
2000, up to 35 percent of CL&P's customers will be able to choose their
electric supplier; and in July 2000, 100 percent of CL&P's customers will
have this ability; rates will be capped at December 31, 1996 levels from
July 1, 1998 until December 31, 1999;
(ii) Customers who do not choose an alternate supplier may take
standard offer service from CL&P beginning January 1, 2000 until January
2004, at a rate which must initially be at least 10 percent less than rates
in effect on December 31, 1996;
(iii) Rates will be unbundled into several components, including
charges for transmission, distribution, generation, the recovery of stranded
costs, public policy costs and new conservation and renewable programs;
CL&P will be permitted to recover stranded costs through a competitive
transition assessment (CTA);
(iv) CL&P will be required to divest its non-nuclear generating
assets by January 2000 and its nuclear generating assets by January 2004
in order to recover its stranded costs; affiliates of CL&P will be allowed
to bid at both auctions; if CL&P cannot sell its nuclear plants above the
minimum price set by the DPUC then it must transfer them to an affiliate at
a value determined by the DPUC; in this circumstance, CL&P will be entitled
to recover nuclear stranded costs equal to the difference between the book
value of its nuclear assets and the minimum price set by the DPUC; until
CL&P's nuclear assets can be sold, CL&P plans, subject to DPUC approval,
to maintain them in a separate corporate division; and
(v) "Securitization" is allowed for generation-related regulatory
assets (other than nuclear assets) and the costs associated with renegotiated
above-market purchased-power contracts; securitization is the refinancing of
stranded costs through the sale of debt securities by an independent entity,
collateralized by the System companies' interests in their stranded cost
recoveries; the above-market portion of purchased-power contracts that have
not been renegotiated can be collected through the CTA.
On October 1, 1998, CL&P filed a plan with the DPUC to auction its
non-nuclear generating assets and purchased-power contracts and a plan
to functionally unbundle its operations. On January 8, 1999, the DPUC
authorized CL&P to proceed with the sale of approximately 3500 MW of
fossil-fueled and hydroelectric plants. The DPUC also imposed a March 15,
1999 deadline on any buyout, buydown or renegotiation of all of its above-
market purchased-power contracts, aggregating approximately 435 MW. Those
contracts as to which no agreement is reached will be auctioned off in a
parallel but separate auction this year. The sale of the non-nuclear
generating plants and the purchased-power contracts is expected to close
before January 1, 2000, the date when CL&P's customer bills are unbundled
and a segment of its customers can choose alternative suppliers for generation
services. Any sale proceeds above book value will be applied to offset CL&P's
stranded costs. The first phase of the auction was launched on February 10,
1999. Certain intervening parties have appealed this order with respect to
the auction of CL&P's above-market purchased-power contracts.
Additional restructuring proceedings, including the determination of the
standard offer rate, the CTA and securitization, are ongoing, or expected to
commence, before the DPUC in early 1999.
Following divestiture and unbundling, CL&P will continue to operate and
maintain its transmission and distribution network and deliver electricity
to its customers.
MASSACHUSETTS RESTRUCTURING
Massachusetts enacted comprehensive electric utility industry
restructuring legislation in November 1997. Pursuant to the legislation,
on March 1, 1998, WMECO decreased its rates by 10 percent from August 1997
levels net of a 2.4 percent rate increase that was scheduled to take effect
on March 1, 1998 and allowed its customers to choose an alternative retail
electricity supplier. The statute requires a further five percent rate
reduction, adjusted for inflation, by September 1, 1999. In addition, the
legislation provides, among other things, for: (i) recovery of stranded
costs through a "transition charge" to customers, subject to review by the
DTE; (ii) a possible limitation on WMECO's return on equity should its
stranded cost charge go above a certain level; (iii) securitization of
allowed stranded costs; and (iv) divestiture of non-nuclear generation.
The statute also provides that an electric company must transfer or
separate ownership of generation, transmission and distribution facilities
into independent affiliates or "functionally separate such facilities within
30 business days of federal approval." Additionally, marketing companies
formed by an electric company are to be separate from the electric company
and separate from generation, transmission or distribution affiliates.
On December 31, 1997, WMECO filed a comprehensive restructuring plan with
the DTE. On February 20, 1998 the DTE issued an interim order approving in
all material respects WMECO's restructuring plan with the DTE, including
the 10 percent reduction in permanent rates and customer choice of supplier,
effective March 1, 1998. Effective July 1, 1998, the DTE approved an additional
reduction in rates of approximately 2.4 percent to make permanent a temporary
rate credit that expired in February 1998. The DTE is currently reviewing
WMECO's restructuring plan and a final decision is expected in 1999.
On January 22, 1999, WMECO announced an agreement to sell 290 MW of
fossil-fired and hydroelectric generation to Consolidated Edison Energy,
Inc., a New York Company, for $47 million. Various federal and state
regulatory approvals are needed before the transaction can be finalized;
these are expected by mid-1999. The current sale does not include WMECO's
interests in Millstone 1, 2 and 3, WMECO's 19 percent interest in the 1,120
MW Northfield Mountain pumped storage project and related hydroelectric
facilities or any purchased-power contracts. These assets will be auctioned
in connection with CL&P's non-nuclear and nuclear auctions, discussed above.
WMECO has also requested authorization in its restructuring filing to
securitize approximately $500 million of stranded costs. A portion of the
proceeds from the asset sales discussed above will be used to lower the
total amount of stranded costs that WMECO will need to recover.
Following divestiture and unbundling, WMECO will continue to operate
and maintain its transmission and distribution network and deliver electricity
to its customers.
NEW HAMPSHIRE RESTRUCTURING
The State of New Hampshire's attempts to restructure the electric utility
industry in that state have resulted in extensive litigation in various federal
and state courts. In 1996, New Hampshire enacted legislation requiring a
competitive electric industry beginning in 1997. In February 1997, the NHPUC
issued restructuring orders that would have forced PSNH and NAEC to write
off all of their regulatory assets and possibly seek protection under
Chapter 11 of the bankruptcy laws. Following the issuance of these orders,
PSNH immediately sought declaratory and injunctive relief on various grounds
in federal district court and has received a preliminary injunction that
freezes implementation of the NHPUC's restructuring orders. The trial in
the federal district court is expected to begin in mid- to late-1999, subject
to the court's ruling on summary judgment motions.
On December 23, 1998, the New Hampshire Supreme Court issued a decision
which addresses issues transferred to it by the NHPUC concerning PSNH's
ability to recover all of its stranded costs under the New Hampshire
restructuring legislation. The court ruled that under the restructuring
statute, the NHPUC can implement a stranded cost recovery charge that
collects less than 100 percent of PSNH's stranded costs, but left open for
the federal court the issue of whether PSNH and NU can assert contractual
and constitutional claims against the State of New Hampshire to the extent
that a stranded cost recovery charge provides less than full recovery.
In January 1999, the NHPUC issued an order stating that it intends to
reopen restructuring hearings. PSNH has requested the federal court to
enforce its preliminary injunction barring the NHPUC from proceeding with
restructuring efforts pending the court's decision on the merits after
trial. The NHPUC has agreed to delay this new proceeding until the federal
court has had an opportunity to rule on PSNH's enforcement motion.
PSNH continues to be involved in settlement discussions with
representatives from the State of New Hampshire. PSNH hopes to reach a
settlement that would include, among other things, substantial rate
reductions, customer choice, an auction of PSNH's generating units and
securitization of PSNH's stranded costs.
RATES
CONNECTICUT RETAIL RATES
GENERAL
As of December 31, 1998, approximately 63 percent of System revenues
was derived from CL&P, and 58 percent of the book value of the System's
electric utility assets was owned by CL&P.
CL&P's retail rates are subject to the jurisdiction of the DPUC.
On February 25, 1998, the DPUC issued a decision in CL&P's interim
rate case, which set rates for CL&P from March 1, 1998 through September 27,
1998. CL&P's rates, effective September 28, 1998 through December 31, 1999
were set according to its base rate case discussed below. The interim
rate case decision required a $30.5 million credit to customer bills
(representing a 1.39 percent rate decrease) to reflect the removal of
Millstone 1 from rates. CL&P rates had been set prior to the interim rate
decision pursuant to a rate settlement approved by the DPUC in 1996. The
interim rate case decision also required CL&P to accelerate the amortization
of regulatory assets by approximately $110.5 million. The interim rates were
effective as of March 1, 1998.
On April 29, 1998, the DPUC issued a decision to remove Millstone 2 from
CL&P's rate base, effective May 1, 1998. The decision further concluded
that the DPUC would remove Millstone 3 from CL&P's rate base, effective
July 1, 1998 if the unit had not been operating for 100 continuous hours at
95 percent capacity by that date. On July 18, 1998, Millstone 3 returned to
rate base after meeting the operating requirements set forth in the DPUC
order.
The removal of Millstone 2 from rate base between May 1, 1998 and
September 27, 1998 resulted in a reduction of CL&P's annual revenues of
about $3.1 million a month. This reduction reflects the removal from rates
of the O&M, depreciation, and investment return related to the unit, net of
costs incurred for power purchased to replace Millstone 2 power, which CL&P
has been allowed to recover. The net reduction of revenue requirements
associated with the removal of Millstone 3 from rates was approximately
$7.4 million for the period July 1, 1998 through July 18, 1998. The DPUC
allowed these reductions to be offset against the potential ratepayer
liability for deferred replacement power costs associated with the shutdown
of the Connecticut Yankee nuclear plant (CY). As a result, there was no
incremental change in rates. CL&P has accounted for these reductions as
a reserve against revenues until the regulatory asset balances are reduced.
Management currently estimates that Millstone 2 will return to service in the
spring of 1999. For more information regarding the outages at Millstone, see
"Electric Operations--Nuclear Generation."
On February 5, 1999, the DPUC issued its final decision in CL&P's rate
case. The DPUC concluded that CL&P's annual revenue requirements should
be reduced by approximately $232 million or 9.68 percent. The revenue
requirement reduction will be achieved through a combination of a $96
million or 4 percent reduction to CL&P's base rates; and accelerated
amortization of approximately $136 million of its deferred tax regulatory
asset. The decision is retroactive to September 28, 1998, with the revenue
requirement reductions for the period from September 28, 1998 to February 5,
1999 being applied to accelerate recovery of the deferred tax regulatory
asset. The rate order allowed CL&P to earn a return on equity of 10.3
percent.
The DPUC also determined that CL&P will be allowed to recover $126
million of its investment in Millstone 1 over a three year period commencing
in October 1998. The portion to be collected in the years 2000 - 2001 will
be collected through CL&P's CTA. See "Electric Utility Restructuring-
Connecticut Restructuring," above. The DPUC, however, disallowed recovery
of $116 million of CL&P's investment in Millstone 1 based upon the benefits
that the DPUC determined customers would have received if the unit had
continued to operate for 1999 and 2000, rather than being retired in 1998.
The DPUC also ordered CL&P to continue the non-cash accrual related
to the Millstone 2 out-of-rate-base disallowance at a revised rate of $6.6
million per month, beginning September 28, 1999, with the accrual being
applied to reduce the CY replacement power cost deferral. Millstone 2 will
be considered in-service when the unit has operated at no less than 75
percent for 100 continuous hours.
For information regarding the financial impact of the February 5, 1999
rate decision on CL&P's ability to meet certain financial covenants, see
"Financial Program-Financing Limitations," below. For information regarding
decommissioning matters, including the decommissioning of Millstone 1, see
"Electric Operations-Nuclear Generation-Decommissioning." For information
regarding CL&P's appeal of the DPUC's 1997 rulings related to the deferral
of certain CY replacement power costs, see "Item 3. Legal Proceedings."
ENERGY ADJUSTMENT CLAUSE
CL&P is subject to an Energy Adjustment Clause (EAC), which is designed
to reconcile and adjust every six months the difference between actual fuel
costs and the fuel revenue collected through base rates.
For more information regarding this matter see "Recoverable Energy
Costs," in the notes to NU's and CL&P's financial statements.
NEW HAMPSHIRE RETAIL RATES
GENERAL
As of December 31, 1998, approximately 25 percent of System revenues
was derived from PSNH, and 18 percent of the book value of the System's
electric utility assets was owned by PSNH.
PSNH's rate agreement (Rate Agreement) between NU, PSNH and the State
of New Hampshire, entered into in 1989 in connection with NU's reorganization
plan to resolve PSNH's bankruptcy, provided for seven base rate increases of
5.5 percent per year beginning in 1990 and a comprehensive fuel and purchased-
power adjustment clause (FPPAC). The final base rate increase went into effect
on June 1, 1996. The Rate Agreement contemplates that PSNH's rates are subject
to traditional rate regulation after the fixed rate period, which expired on
May 31, 1997. The FPPAC, however, would continue through May 31, 2001, and the
Rate Agreement continues in place concerning recovery of various regulatory
assets.
A PSNH base rate case has been pending at the NHPUC since May 1997, but
an order has been delayed due to the restructuring proceedings discussed
above. The base rate proceedings were reopened in late October 1998. A final
decision, which will be reconciled to July 1, 1997, is currently expected to
be issued by June 1, 1999. PSNH's ongoing settlement negotiations with the
State of New Hampshire could resolve this matter and the FPPAC proceedings
discussed below.
FPPAC
The FPPAC provides for the recovery or refund by PSNH, for the ten-year
period beginning on May 16, 1991, of the difference between its actual
prudently incurred energy and purchased-power costs and the estimated amounts
of such costs included in base rates established by the Rate Agreement. The
FPPAC amount is calculated for a six-month period based on forecasted data and
is reconciled to actual data in subsequent FPPAC billing periods.
On May 29, 1998, the NHPUC approved an FPPAC rate of $.00725 per kWh
for the period June 1, 1998 through November 30, 1998, which resulted in an
overall rate increase of approximately 1 percent. This rate includes, among
other things, an offset of the reduced PSNH acquisition premium amortization
with the Seabrook deferred returns that were scheduled to come into rates.
On December 1, 1998, the NHPUC approved a settlement agreement that
recommended that PSNH's FPPAC rate discussed above be continued for another
six month FPPAC period - December 1, 1998 through May 31, 1999. The FPPAC
rate currently in effect will produce an estimated $80 million underrecovery
as of May 31, 1999, comprised of $64 million of underrecovery that existed
as of November 30, 1998, $9 million of "light loading" costs which are
subject to an open docket before the NHPUC, and $7 million of Seabrook
refueling outage costs (to spread the cost of the refueling over 12 months
instead of six months). All other FPPAC costs, including certain purchased-
power obligations discussed below, are being recovered on a current basis.
For more information regarding this matter see "Recoverable Energy
Costs" and "Rate Matters" in the notes to NU's and PSNH's financial statements.
For more information regarding deferred-PSNH acquisition costs and Seabrook
costs, see "PSNH Acquisition Costs" and "Deferred Costs-Nuclear Plants" in
the notes to NU's financial statements and "Acquisition Costs" and "Deferred
Costs-Nuclear Plants" in the notes to PSNH's financial statements.
PURCHASED-POWER CONTRACTS
The costs associated with purchases by PSNH from certain NUGs at prices
above the level assumed in base rates were deferred during the fixed rate
period and are recovered through the FPPAC. As of December 31, 1998, NUG
deferrals, including previously approved buy-out costs, totaled approximately
$156 million, compared to approximately $191.7 million as of December 31, 1997.
Under the Rate Agreement, PSNH and the State of New Hampshire have an
obligation to use their best efforts to renegotiate burdensome purchased-
power arrangements with certain specified hydroelectric and wood-burning
NUGs that were selling their output to PSNH under long-term NHPUC rate
orders. The NHPUC reopened a proceeding in late January 1999 to review
whether PSNH has met its obligations to use its "best efforts" to renegotiate
these arrangements. As part of its restructuring-related litigation, PSNH has
requested the federal court to enforce its preliminary injunction barring
the NHPUC from proceeding with efforts to adjudicate provisions of the Rate
Agreement, including "best efforts" pending the court's decision on the merits
after trial.
PSNH had reached agreements with the six remaining wood-fired NUGs.
The NHPUC conditionally approved one of these agreements, but due to the
uncertainties of PSNH's recovery of the costs to be incurred, it was
determined that the agreement could not be financed. The five remaining
agreements were rejected by the NHPUC in 1998. PSNH hopes to resolve this
issue in connection with a restructuring settlement.
The New Hampshire Legislature is also considering a number of proposals
that could impact PSNH's ability to renegotiate and refinance NUGs rate
orders.
MASSACHUSETTS RETAIL RATES
As of December 31, 1998, approximately 10 percent of System revenues
was derived from WMECO, and 12 percent of the book value of the System's
electric utility assets was owned by WMECO.
WMECO's retail rates are subject to the jurisdiction of the DTE. The
DTE has stated that, pursuant to the restructuring legislation, distribution
rates for WMECO and all other Massachusetts utilities will be "performance-
based" rates (PBR). That is, instead of rate recovery based solely on
cost-of-service, recovery will be based, in part, upon achieving certain
performance levels (for example, a certain level of reliability and customer
satisfaction). The DTE has announced no timetable for the implementation
of PBR.
In accordance with DTE approval, on January 1, 1999, WMECO implemented
changes to components of its rates to increase its standard offer energy
charge in accordance with its restructuring plan and to reduce its transition
charge in a manner that did not change overall rates. During 1999, WMECO is
authorized by the restructuring legislation to apply an inflation adjustment
to its overall rates in March and to implement an additional five percent
reduction, adjusted for inflation, by September 1, 1999.
The rates charged under HWP's contracts with its industrial customers,
which produced revenues in 1998 of approximately $6 million, are not subject
to the ratemaking jurisdiction of any state or federal regulatory agency.
COMPETITIVE SYSTEM BUSINESSES
ENERGY-RELATED PRODUCTS AND SERVICES
Select Energy was created to participate in retail pilot programs and
open-access retail electric markets in the Northeast and other appropriate
areas of the country. Select Energy also recently received FERC approval to
sell electricity at wholesale at market-based rates.
In June 1998, Select Energy won the right to supply the retail electric
service to an organization, NEChoice LLC, that represents an aggregation of
certain commercial and industrial businesses in Massachusetts and Rhode
Island. This aggregation is expected to yield approximately $100 million in
contracted revenue over a five-year period. In November 1998, Select Energy
was awarded through a competitive bid process, the right to supply wholesale
power for all Boston Edison Company (BECO) customers who remain on "standard
offer" service, as well as BECO's existing wholesale power customers. Standard
offer service is for those BECO customers who have not chosen an alternative
competitive energy supplier and are allowing BECO to arrange a power supply
for them. These wholesale power arrangements are estimated to be worth more
than $300 million in revenues to Select Energy over an aggregate 13-month
period, which ends December 31, 1999. In November 1998, Select Energy was
awarded a three-year, $17 million power contract by Shaw's Supermarkets for
approximately 60 locations in Massachusetts and Rhode Island.
In addition, Select Energy also markets natural gas and develops and
markets energy-related products and services. These include energy services,
productivity services, business and financial services, and residential
services. Select Energy continues to take steps to establish strategic
alliances with other companies in various energy-related fields including
fuel supply and management, power quality, energy efficiency and load
management services. In 1998, Select Energy contracted with several chambers
of commerce and business organizations in Connecticut and Massachusetts to
provide their members (approximately 10,000) with comprehensive educational,
energy and energy services packages. NU's aggregate equity investment in
Select Energy was approximately $5 million as of December 31, 1998.
ENERGY MANAGEMENT SERVICES
In general, HEC contracts to reduce its customers' energy costs and/or
conserve energy and other resources. HEC's energy management and consulting
services have primarily been directed to the commercial, industrial and
institutional markets and utilities in New England and New York. In 1998,
HEC was awarded energy-saving contracts for certain federal installations
throughout the United States. NU's aggregate equity investment in HEC was
approximately $3 million as of December 31, 1998.
TELECOMMUNICATIONS
Mode 1 was established in 1996 to participate in a wide range of
telecommunications activities both within and outside New England. NU's
total investment in Mode 1 was approximately $13.8 million as of December
31, 1998.
Mode 1 currently owns approximately 27 percent of the outstanding
common shares, fully diluted, of NorthEast Optic Network, Inc.("NEON"), which
is constructing an approximately 900 mile fiber optic communications network
through New England and New York, including over the System's transmission
facilities. An officer of NU and an officer of NUSCO are members of the
Board of Directors of NEON. In addition, NU is a party to an agreement with
Central Maine Power Company (CMP), an owner of approximately 33 percent of
NEON's common shares, fully diluted, wherein NU and CMP each agree that, as
long as NU owns at least 10 percent of the outstanding common stock of NEON,
fully diluted, and the cumulative holdings of NU and CMP are at least 33 1/3
percent, fully diluted, neither NU nor CMP will take any action which will
allow NEON to merge, consolidate, liquidate or sell, lease or transfer
substantially all of its assets or commence or acquiesce any action or
proceeding under any bankruptcy laws.
FINANCING PROGRAM
1998 FINANCINGS
NU entered into a $25 million, 364-day revolving credit facility on
February 10, 1998 (NU Credit Agreement), which was extended to September 9,
1999.
On April 23, 1998, PSNH entered into a $75 million revolving credit
agreement that will expire in April 1999. PSNH's borrowings under this
agreement are secured, per dollar of borrowing, by $75 million of first
mortgage bonds and substantially all of PSNH's accounts receivable.
On April 23, 1998, PSNH amended and extended letters of credit and
reimbursement agreements that provide credit support for $39.5 million
principal amount of taxable Pollution Control Refunding Revenue Bonds
(PCRB), 1991 Series D, due May 1, 2021, and $69.7 million principal amount
of taxable PCRB, 1991 Series E, due 2021. The Series D and E taxable PCRB's
are special limited obligations of the Business Finance Authority of the
State of New Hampshire (BFA) and are payable solely by PSNH under the
applicable loan and trust agreements. PSNH's obligations to make payments
under the loan and trust agreements, letters of credit and reimbursement
agreements are secured by approximately $110 million of first mortgage
bonds and substantially all of PSNH's accounts receivable.
On May 1, 1998, the $75 million principal amount of tax-exempt PCRB,
1992 Series D, due May 1, 2021, and $44.8 million principal amount of tax-
exempt PCRB, 1993 Series E, due May 1, 2021, which were previously issued by
the BFA on PSNH's behalf as variable rate bonds, were converted to fixed
rate bonds bearing interest at 6 percent per annum. These bonds are special
limited obligations of the BFA and are payable solely by PSNH under the
applicable loan and trust agreement.
CL&P and WMECO utilize the Niantic Bay Fuel Trust (NBFT) to finance
their nuclear fuel requirements for the Millstone units. On June 5, 1998,
the NBFT issued $180 million of Series G intermediate term notes (ITNs) to
refinance the $80 million Series F ITNs which matured on June 5, 1998, to
repay outstanding advances and interest under the NBFT Credit Agreement,
which expired in July 1998 and to be used as cash collateral for future
purchases of nuclear fuel. The Series G ITNs are secured by $72.9 million
and $17.3 million of first mortgage bonds of CL&P and WMECO, respectively.
For information regarding proposed amendments related to this transaction,
see "1999 Financing Plans," below.
In the fall of 1998, CL&P and WMECO completed the conversion of $415.7
million of tax-exempt pollution control revenue refunding bonds from floating
to fixed interest rates. CL&P converted $315.5 million of 30-year bonds, which
carry interest rates ranging from 5.85 percent to 5.95 percent. CL&P also
converted $21 million of such bonds, which mature December 1, 2022, at an
interest rate of 5.85 percent, as well as $25.4 million of 5.9 percent bonds,
some of which will mature November 1, 2016 and others on August 1, 2018.
WMECO converted $53.8 million of tax-exempt pollution control bonds that
mature September 1, 2028 to a fixed rate of 5.85 percent. All of the bonds
had been issued previously on behalf of CL&P and WMECO by the Connecticut
Development Authority and the Business Finance Authority of the State of
New Hampshire. The proceeds from the original issuances were used primarily
to finance pollution control equipment at Millstone 3 and Seabrook.
On November 30, 1998, Select Energy obtained a $50 million letter
of credit to satisfy the credit assurance requirements of two power
supply agreements with BECO (BECO Agreements). The letter of credit was
collateralized by a pledge of all the rights, claims and proceeds from
the BECO Agreements. In addition, NU guaranteed Select Energy's repayment
obligations under the letter of credit. NU also guaranteed Select Energy's
performance obligations under the BECO Agreements.
Total System debt, including short-term and capitalized lease obligations,
was $3.87 billion as of December 31, 1998, compared with $4.15 billion as
of December 31, 1997 and $4.15 billion as of December 31, 1996. For more
information regarding System financing, see "Notes to Consolidated Statements
of Capitalization" in NU's financial statements, other footnotes related
to long-term debt, short-term debt and the sale of accounts receivables, as
applicable, in the notes to NU's, CL&P's, PSNH's, WMECO's and NAEC's financial
statements and "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations."
1999 FINANCING REQUIREMENTS
The System's aggregate capital requirements for 1999 are approximately
as follows:
CL&P PSNH WMECO NAEC Other System
(Millions)
Construction $230.9 $67.9 $33.6 $ 8.2 $23.1 $363.7
Nuclear Fuel 25.2 1.4 5.8 1.6 - 34.0
Maturities 214.0 - 40.0 - - 254.0
Cash Sinking Funds 19.8 25.0 1.5 70.0 26.9 143.2
Total $489.9 $94.3 $80.9 $79.8 $50.0 $794.9
For further information on the System's 1999 and five-year financing
requirements, see "Notes to Consolidated Statements of Capitalization" in
NU's financial statements, "Long-Term Debt" in the notes to CL&P's, PSNH's,
WMECO's and NAEC's financial statements and "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations."
1999 FINANCING PLANS
The System companies generally propose to finance their 1999
requirements through internally generated funds and short-term borrowings.
PSNH's revolving credit agreement expires on April 22, 1999 and
the company currently does not intend to renew it, instead funding its
needs through operating cash flows or through other short term credit
arrangements. PSNH is attempting to renew the bank letters of credit that
support nearly $110 million of taxable variable-rate pollution control
bonds. Those letters of credit also expire April 22, 1999. NU, CL&P and
WMECO's $313.75 million revolving credit line, discussed more fully below,
will expire on November 21, 1999. The NU Credit Agreement has been extended
to September 9, 1999. Select Energy and other NU unregulated businesses are
likely to require additional financial support as they expand their business
in 1999. Management also hopes in 1999 to begin the process of securitizing
CL&P and WMECO's stranded costs.
The permanent shutdown of Millstone 1 in July 1998 afforded the NBFT
ITN holders the right to seek repurchase of a pro rata share of their notes
based upon the stipulated loss value of the Millstone 1 fuel compared to
the stipulated loss value of all fuel then under the NBFT, approximately
$80 million. The shutdown also obligates CL&P and WMECO to pay such amount
to the NBFT under the NBFT lease whether or not any ITN holders request
repurchase. The companies are seeking consents from the ITN holders to
amend this lease provision so that they will not be obligated to make this
payment, but instead expect to issue an additional $80 million of collateral
first mortgage bonds in mid-1999.
On July 14, 1998, the NU Board of Trustees authorized the repurchase
of up to 10 million NU common shares through July 1, 2000 in connection
with the implementation of utility restructuring in New England. Share
repurchases may be accomplished through a variety of means, including
open market purchases and possibly the use of certain derivative financial
instruments or agreements. To date, no shares have been repurchased.
FINANCING LIMITATIONS
Many of the System companies' charters and borrowing facilities contain
financial limitations that must be satisfied before borrowings can be made
and for outstanding borrowings to remain outstanding.
CL&P and WMECO are parties to a revolving credit agreement (Revolving
Credit Agreement) which expires in November 1999 and allows borrowings on
a consolidated basis of $313.75 million. NU had been a party to this
agreement from its inception but withdrew from it in March 1999. In
September 1998 and again in March 1999, the agreement was amended to
adjust certain financial covenants. Under the agreement, as amended
through September 1998, NU, CL&P and WMECO were required to maintain
a ratio of common equity to total capitalization of at least 31 percent.
At December 31, 1998, CL&P'S and WMECO's common equity ratios were 29.86
percent and 32.20 percent, respectively, while NU's common equity ratio
was 33.27 percent.
The Revolving Credit Agreement, as amended through September 1998,
also required, beginning in the fourth quarter of 1998, each of CL&P and
WMECO to maintain a quarterly ratio of operating income to interest expense
(interest coverage ratio) of at least 1.35 to 1 through December 31, 1998;
1.75 to 1 for the quarter ended March 31, 1999 and 2.00 to 1 at the end of
each quarter thereafter. NU was required to maintain a quarterly interest
coverage ratio of 2.0 to 1. For the quarter ended December 31, 1998,
CL&P's and WMECO's interest coverage ratios were 2.21 to 1 and 1.40 to
1, respectively while NU's consolidated interest coverage ratio was 2.58
to 1 percent.
As a result of CL&P's February 5, 1999 rate case decision, CL&P was
required to obtain waivers of or amendments to certain of their common
equity and interest coverage tests. WMECO sought a change to the common
equity test as well. In March 1999, both companies' common equity ratio
tests were reduced to 28 percent for the remaining term of the Revolving
Credit Agreement, and CL&P's interest coverage test for the period beginning
April 1, 1999 was reduced to 1.75 to 1.
Under the NU Credit Agreement, NU was required to maintain a common
equity ratio of at least 32 percent. In addition, NU was required to
maintain a quarterly interest coverage ratio of 2.50 to 1 for the quarter
ending December 31, 1998. NU met these requirements in 1998. In March 1999,
the NU Credit Agreement was amended to reduce the common equity ratio test
to 31 percent for the remaining term of the agreement and to impose a 2.0 to
1 interest coverage ratio test for the first quarter of 1999 and a 1.75 to 1
test for the second quarter.
NU's guarantee of Select Energy's payment obligations under its letter
of credit presently requires it to maintain an interest coverage ratio of
2.0 to 1 and a common equity ratio of 31 percent.
In addition to the Select guarantees, NU has provided credit assurance,
including guarantees of letters of credit, performance guarantees and other
assurances for the financial and performance obligations of certain of its
unregulated subsidiaries. NU currently is limited by the SEC to an aggregate
of $75 million of such credit assurance arrangements. NU expects to
increase this limitation in the future.
PSNH and NAEC are parties to a variety of financing agreements which
provide that the credit thereunder can be terminated or accelerated if each
does not maintain specified minimum ratios of common equity to capitalization
(as defined in each agreement). For PSNH, the minimum common equity ratio
required in certain letters of credit and reimbursement agreements and its
$75 million revolving credit agreement is not less than 32.5 percent. At
December 31, 1998, PSNH's common equity ratio was 53.41 percent. For NAEC,
the minimum common equity ratio required under its term loan agreement is
25 percent; at December 31, 1998, NAEC's common equity ratio was 30.06 percent.
In addition, PSNH's revolving credit agreement and letters of credit
and reimbursement agreements require that for PSNH to obtain and maintain
borrowings thereunder, it must demonstrate that its ratio of operating
income to interest expense will be at least 2.35 to 1 at the end of each
fiscal quarter for the remaining term of the agreements. The NAEC term
loan agreement requires a ratio of adjusted net income to interest expense
of 1.50 to 1 at the end of each fiscal quarter for the remaining term of
the agreement. For the 12-month period ended December 31, 1998 the
corresponding ratios for PSNH and NAEC were 4.07 to 1 and 2.02 to 1,
respectively.
In addition, PSNH and NAEC are parties to a variety of financing
agreements providing in effect that the credit thereunder can be terminated
or accelerated if there are actions taken, either by PSNH or NAEC or by the
State of New Hampshire, that deprive PSNH and/or NAEC of the benefits of the
Rate Agreement and/or the Seabrook Power Contracts.
The amounts of short-term borrowings that may be incurred by NU, CL&P,
PSNH, WMECO, HWP and NAEC are also subject to periodic approval by the SEC
under the 1935 Act. The following table shows the amount of short-term
borrowings authorized by the SEC for each company as of January 1, 1999 and
the net amounts of outstanding short-term debt and cash investments of those
companies at the end of 1998 and as of March 1, 1999:
Short-Term Debt
Maximum Authorized Outstanding
Short-Term Debt and (Cash Investments)*
12/31/98 3/1/99
(Millions)
NU.................. $200 $(34.4) $ (27.9)
CL&P ............... 375 3.4 138.5
PSNH**.............. 125 (58.7) (110.7)
WMECO............... 150 50.9 102.1
HWP................. 5 (10.1) (11.4)
NAEC................ 60 (30.3) (64.1)
OTHER............... N/A (3.0) (9.3)
Total $(82.2) $ 17.2
* These columns include borrowings of or cash investments by various System
companies from NU and other System companies. Total System short-term
indebtedness to unaffiliated lenders was $30 million at December 31, 1998
and $225 million at March 1, 1999.
** The NHPUC has approved short term borrowings by PSNH under the $75
million secured revolving credit agreement that will expire in April 1999.
When the revolving credit agreement expires, PSNH's maximum authorized short
term debt pursuant to New Hampshire law will be approximately $66 million.
The supplemental indentures under which NU issued $175 million in
principal amount of 8.58 percent amortizing notes in December 1991 and $75
million in principal amount of 8.38 percent amortizing notes in March 1992
contain restrictions on dispositions of certain System companies' stock,
limitations of liens on NU assets and restrictions on distributions on and
acquisitions of NU stock. Under these provisions, NU, CL&P, PSNH and WMECO
may not dispose of voting stock of CL&P, PSNH or WMECO other than to NU or
another System company, except that CL&P may sell voting stock for cash to
third persons if so ordered by a regulatory agency so long as the amount
sold is not more than 19 percent of CL&P's voting stock after the sale.
The restrictions also generally prohibit NU from pledging voting stock of
CL&P, PSNH or WMECO or granting liens on its other assets in amounts greater
than five percent of the total common equity of NU. The Revolving Credit
Agreement, the NU Credit Agreement and NU's guarantee of Select Energy's
obligations under its letter of credit have similar restrictions. As of
December 31, 1998, no NU debt was secured by liens on NU assets. Finally,
NU may not declare or make distributions on its capital stock, acquire its
capital stock (or rights thereto), or permit a System company to do the
same, at times when there is an event of default under the supplemental
indentures under which the amortizing notes were issued.
The charters of CL&P and WMECO contain preferred stock provisions
restricting the amount of unsecured debt those companies may incur. As
of December 31, 1998, CL&P's and WMECO's charters permit CL&P and WMECO
to incur an additional $466 million and $96 million, respectively, of
unsecured debt.
The indentures securing the outstanding first mortgage bonds of CL&P,
PSNH, WMECO and NAEC provide that additional bonds may not be issued,
except for certain refunding purposes, unless earnings (as defined in
each indenture and before income taxes, and, in the case of PSNH, without
deducting the amortization of PSNH's regulatory asset), are at least twice
the pro forma annual interest charges on outstanding bonds and certain prior
lien obligations and the bonds to be issued. CL&P and WMECO's 1998 earnings
do not permit them to meet those earnings coverage tests, but as of December
31, 1998, CL&P and WMECO would be able to issue up to $91.6 million and $6.4
million of additional first mortgage bonds, respectively, on the basis of
previously issued but refunded bonds, without having to meet the earnings
coverage test.
The preferred stock provisions of CL&P's and WMECO's charters also
prohibit the issuance of additional preferred stock (except for refinancing
purposes) unless income before interest charges (as defined and after income
taxes and depreciation) is at least 1.5 times the pro forma annual interest
charges on indebtedness and the annual dividend requirements on preferred
stock that will be outstanding after the additional stock is issued. CL&P
and WMECO are currently unable to issue additional preferred stock under
these provisions.
SEC rules under the 1935 Act require that dividends on NU's shares be
based on the amount of dividends received from subsidiaries, not on the
undistributed retained earnings of subsidiaries. NU suspended the payment
of dividends beginning with the quarter ended June 30, 1997.
The supplemental indentures under which CL&P's and WMECO's first
mortgage bonds have been issued limit the amount of cash dividends and
other distributions these subsidiaries can make to NU out of their retained
earnings. As of December 31, 1998, WMECO had $46.0 million of unrestricted
retained earnings. As of the same date, CL&P had an accumulated deficit of
approximately $330.0 million that must be made up before it is able to pay
dividends to NU. The indenture under which NAEC's Series A Bonds have been
issued also limits the amount of cash dividends or distributions NAEC can
make to NU to retained earnings plus $10 million. At December 31, 1998,
approximately $53.2 million was available to be paid under this provision.
PSNH's revolving credit agreement and letters of credit and
reimbursement agreements prohibit it from declaring or paying any cash
dividends or distributions on any of its capital stock, except for dividends
on the preferred stock, unless minimum interest coverage and common equity
ratio tests discussed above are satisfied. These agreements also require
creditor approval to pay more than $25 million in dividends to NU. PSNH's
preferred stock provisions also limit the amount of cash dividends and other
distributions PSNH can make to NU if, after taking the dividend or other
distribution into account, PSNH's common stock equity is less than 25 percent
of total capitalization. At December 31, 1998, approximately $293.2 million
was available to be paid under these provisions. If NAEC could not meet the
common equity covenant referred to above, it would also be unable to pay
common dividends. At December 31, 1998, $45.1 million was available to be
paid by NAEC under this provision.
On March 20, 1998, in connection with the approval of PSNH's revolving
credit agreement, the NHPUC issued an order requiring PSNH to obtain NHPUC
approval before paying any dividends on its common stock and before investing
any PSNH funds in the NU System Money Pool during the expected 364-day term
of the facilities.
Certain System financing agreements also have covenants or trigger events
tied to credit ratings of certain System companies.
The downgrade by Moody's of WMECO's first mortgage bonds to Ba2 in
December 1997 brought those ratings to a level at which the sponsor of WMECO's
$40 million accounts receivable program can take various actions, in its
discretion, which would have the practical effect of limiting WMECO's ability
to utilize the facility. The WMECO accounts receivable program could be
terminated if WMECO's first mortgage bond credit ratings experience one more
level of downgrade. CL&P's $200 million accounts receivable program could be
terminated if its senior secured debt is downgraded two more steps from its
current ratings.
CL&P is party to an operating lease with General Electric Capital
Corporation related to the use of four turbine generators having an
installed cost of approximately $70 million and a stipulated loss value of
$59 million. CL&P must meet certain financial covenants that are similar to
the Revolving Credit Agreement. As a result of CL&P's February 5, 1999 rate
decision, CL&P was required to obtain a waiver of these covenants for the
fourth quarter of 1998 and is in the process of renegotiating the
requirements.
For information regarding the effect of downgrades on certain fossil-
fuel hedging agreements of CL&P, see "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations."
CONSTRUCTION PROGRAM
The System's construction program expenditures, including allowance for
funds used during construction (AFUDC), in the period 1999 through 2003 are
estimated to be as follows:
1999 2000 2001 2002 2003
(Millions of Dollars)
PRODUCTION
CL&P................. $38.8 $ 67.4 $39.5 $26.8 $31.6
PSNH................. 20.0 4.9 6.6 2.4 7.7
WMECO................ 8.7 18.6 11.8 8.9 7.7
NAEC................. 8.2 8.4 4.5 4.3 1.9
Other................ 0.8 3.2 4.3 2.0 0.4
----- ----- ----- ----- -----
System Total....... $76.6 $102.5 $66.7 $44.4 $49.3
SUBSTATIONS AND TRANSMISSION LINES
CL&P................. $ 8.0 $ 3.3 $ 7.0 $ 8.2 $33.1
PSNH................. 5.8 2.1 2.1 2.2 2.3
WMECO................ 6.0 3.0 0.3 0.1 0.1
NAEC................. - - - - -
Other................ 0.1 - - - -
----- ----- ----- ----- -----
System Total....... $19.9 $ 8.4 $ 9.4 $10.5 $35.5
DISTRIBUTION OPERATIONS
CL&P................. $171.4 $236.5 $261.2 $255.0 $248.6
PSNH................. 32.4 57.5 55.7 57.7 58.9
WMECO................ 16.9 20.3 21.1 20.6 19.3
NAEC................. - - - - -
Other................ 0.3 0.2 0.1 0.2 0.1
------ ------ ------ ------ ------
System Total....... $221.0 $314.5 $338.1 $333.5 $326.9
GENERAL
CL&P................. $ 12.7 $ 4.4 $ 43.3 $ 2.8 $ 3.4
PSNH................. 9.7 0.8 0.9 0.9 0.9
WMECO................ 2.0 1.0 0.5 0.5 0.5
NAEC................. - - - - -
Other................ 21.9 20.3 21.0 - -
------ ------ ------ ------ ------
System Total....... $ 46.3 $ 26.5 $ 25.7 $ 30.1 $ 25.4
TOTAL CONSTRUCTION
CL&P................. $230.9 $311.6 $311.0 $292.8 $316.7
PSNH................. 67.9 65.3 65.3 63.2 69.8
WMECO................ 33.6 42.9 33.7 30.1 27.6
NAEC................. 8.2 8.4 4.5 4.3 1.9
Other................ 23.1 23.7 25.4 28.1 21.1
------ ------ ------ ------ ------
System Total....... $363.7 $451.9 $439.9 $418.5 $437.1
The construction program data shown above includes all anticipated
capital costs necessary for committed projects and for those reasonably
expected to become committed, regardless of whether the need for the
project arises from environmental compliance, nuclear safety, reliability
requirements or other causes. The construction program's main focus is
maintaining and upgrading the existing transmission and distribution
system and nuclear and fossil-generating facilities. The increase in
construction expenditures after 1999 is primarily related to projected
capital improvements for the distribution system. System companies'
construction needs, however, may change substantially in light of their
commitment to sell their non-nuclear generating units in connection with
restructuring in Massachusetts and Connecticut. It is possible that the
System companies will no longer construct any new generating facilities,
but instead contract with third parties for capacity in a competitive
generation market.
ELECTRIC OPERATIONS
DISTRIBUTION AND SALES
The System companies traditionally have owned and operated a fully
integrated electric utility business. Restructuring legislation in New
Hampshire, Massachusetts and Connecticut, however, requires PSNH, WMECO
and CL&P, respectively, to separate the distribution, transmission and
generation functions of their business.
The System companies furnish retail franchise service in 149, 198 and 59
cities and towns in Connecticut, New Hampshire and Massachusetts, respectively.
In December 1998, CL&P furnished retail franchise service to approximately 1.11
million customers in Connecticut, PSNH provided retail service to approximately
422,000 customers in New Hampshire and WMECO served approximately 196,000
retail franchise customers in Massachusetts. HWP serves 32 retail customers
in Holyoke, Massachusetts.
The following table shows the sources of 1998 electric revenues based
on categories of customers:
CL&P PSNH** WMECO NAEC Total System
Residential........ 41% 32% 39% - 41%
Commercial......... 37 27 35 - 34
Industrial......... 13 17 20 - 15
Wholesale*......... 7 23 5 100% 9
Other.............. 2 1 1 - 1
Total.............. 100% 100% 100% 100% 100%
* Includes capacity sales and sales from PSNH to CL&P and WMECO.
** Excludes sales related to the retail pilot program in New Hampshire.
NAEC's 1998 electric revenues were derived entirely from sales to PSNH
under the Seabrook power contracts. See "Rates--New Hampshire Retail Rates--
Seabrook Power Contracts" for a discussion of the contracts.
The actual changes in retail kWh sales for the last two years and the
forecasted sales growth estimates for the ten-year period 1998 through 2008,
in each case exclusive of wholesale sales, non-franchised retail sales and
sales related to the retail pilot program in New Hampshire, for the System,
CL&P, PSNH and WMECO are set forth below:
1998 over 1997 over Forecast 1998-2008
1997 1996 Compound Rate of Growth
System......... 1.9% (.3)% 1.3%
CL&P........... 2.2% 0 % 1.1%
PSNH........... 2.3% (.1)% 1.9%
WMECO.......... 1.3% (1.0)% 0.8%
Consolidated NU retail sales rose by 1.9 percent in 1998 compared with
1997 primarily due to the continuing strengthening of the regional economy.
This growth occurred despite the negative impact of weather constraining
sales by an estimated 1.0 percent. Residential electric sales were up
.5 percent. Commercial sales were up by 3.2 percent for the year and
industrial sales increased by 2.2 percent. Retail sales for all of the
System companies increased in 1998 with CL&P, WMECO and PSNH sales up 2.2
percent, 2.3 percent and 1.3 percent, respectively.
REGIONAL AND SYSTEM COORDINATION
The System companies and most other New England utilities are parties
to an agreement (NEPOOL Agreement), which provides for coordinated planning
and operation of the region's generation and transmission facilities. The
NEPOOL Agreement was restated and revised as of March 1997 to provide for
a pool-wide open access transmission tariff and for the creation of an
Independent System Operator (ISO). Under these new arrangements: (i) the
ISO, a non-profit corporation whose board of directors and staff is not
controlled by or affiliated with market participants, ensures the reliability
of the NEPOOL transmission system, administers the NEPOOL tariff and oversees
the efficient and competitive functioning of the regional power market; (ii)
the NEPOOL tariff provides for non-discriminatory open access to the regional
transmission network at one rate regardless of transmitting distance for all
transactions; and (iii) a broader governance structure for NEPOOL and a more
open, competitive market structure are established.
Pursuant to the NEPOOL Agreement, if a participant is unable to meet
its capacity responsibility obligations, the participant is required
to purchase capacity through the ISO at a market clearing price as set
forth in the NEPOOL Agreement. The System has been meeting its capacity
responsibility while the Millstone units were shut down through purchased-
power contracts with other utilities. The cost of these arrangements
for 1998 was approximately $27 million. Assuming Millstone 2 returns to
service in April 1999, the further costs related to the System's capacity
responsibility obligations are estimated to be approximately $6 million.
There are two agreements that determine the manner in which costs
and savings are allocated among the System companies. Under an agreement
(NUG&T) among CL&P, WMECO and HWP (Initial System Companies), these
companies pool their electric production costs and the costs of their
principal transmission facilities. Pursuant to the merger agreement between
NU and PSNH, the Initial System Companies and PSNH entered into a ten-year
sharing agreement (Sharing Agreement), expiring in June 2002, that provides,
among other things, for the allocation of the capability responsibility
savings and energy expense savings resulting from a single-system dispatch
through NEPOOL. It is expected that these agreements will be terminated
and/or modified in connection with restructuring.
TRANSMISSION ACCESS AND FERC REGULATORY CHANGES
In April 1996, FERC issued its final open access rule (Order 888) to
promote competition in the electric industry. Order 888 requires, among
other things, all public utilities that own, control or operate facilities
used for transmitting electric energy in interstate commerce to file an
open-access, nondiscriminatory transmission tariff and to take transmission
service for their own new wholesale sales and purchases under the open
access tariffs. Order 888 also supports full recovery of legitimate, prudent
and verifiable wholesale stranded costs, but indicates that FERC will not
interfere with state determinations of retail stranded costs.
On May 2, 1997, the System companies, along with other parties, filed
with the U.S. Court of Appeals an appeal of Order 888, challenging FERC's
abdication of its responsibility to ensure uniform recovery of full stranded
costs at the wholesale and retail level, including FERC's refusal to endorse
stranded costs payments (e.g., exit fees) for customers physically bypassing
their former supplier, as well as FERC's imposition of an ordinary negligence
standard of liability on transmission providers. This matter is still pending.
In a companion order to Order 888 (Order 889), FERC also required
electric utilities to develop and maintain a same-time information system
that will give existing and potential transmission users the same access
to transmission information that the electric utility enjoys, and required
electric utilities to separate transmission from generation marketing
functions pursuant to standards of conduct. The System companies are
complying with the requirements of Order 889.
In 1998, the System companies collected approximately $34 million in
incremental transmission revenues from other electric utility generators.
For information regarding certain disputes between PSNH and NHEC,
which have been the subject of various FERC proceedings, see "Item 3.
Legal Proceedings."
NUCLEAR GENERATION
GENERAL
Certain System companies have ownership interests in four nuclear
units, Millstone 1, 2 and 3 and Seabrook 1, and equity interests in four
regional nuclear companies (the Yankee Companies) that separately own CY,
MY, Vermont Yankee (VY) and Yankee Rowe. System companies operate the three
Millstone units and Seabrook 1. Yankee Rowe, CY, MY and Millstone 1 have
been permanently removed from service. For information regarding the
decommissioning of these units, see " Electric Operations -- Nuclear
Plant Performance and Regulatory Oversight - Decommissioning," below.
CL&P and WMECO own 100 percent of Millstone 1 and 2 as tenants in
common. Their respective ownership interests in each unit are 81 percent
and 19 percent.
CL&P, PSNH and WMECO have agreements with other New England utilities
covering their joint ownership as tenants in common of Millstone 3. CL&P's,
PSNH's and WMECO's ownership interests in the unit are 52.93, 2.85 and 12.24
percent, respectively. NAEC and CL&P have 35.98 percent and 4.06 percent
ownership interests, respectively, in Seabrook.
In 1996, one of the joint owners of Millstone 3, Vermont Electric
Generation and Transmission Cooperative, Inc. (VEG&T), filed for bankruptcy.
The subsequent liquidation resulted in the offering of VEG&T's .035 percent
share of Millstone 3 for sale to the joint owners of Millstone 3. None
of the non-NU joint owners accepted the offer. CL&P expects to make the
necessary regulatory filings to acquire ownership of the VEG&T share in
1999.
The Millstone 3 and Seabrook joint ownership agreements provide for
pro-rata sharing by the owners of each unit of the construction and
operating costs, the electrical output and the associated transmission
costs. CL&P and WMECO, through NNECO as agent, operate Millstone 3 at cost,
and without profit, under a sharing agreement that obligates them to utilize
good utility operating practice and requires the joint owners to share the
risk of employee negligence and other risks pro rata in accordance with
their ownership shares. The sharing agreement provides that CL&P and WMECO
would only be liable for damages to the non-NU owners for a deliberate
breach of the agreement pursuant to authorized corporate action.
For information regarding lawsuits filed against NU by the non-NU
owners of Millstone 3 regarding the sharing agreement and certain
arbitration proceedings related to the ongoing Millstone outages, see
"Item 3 - Legal Proceedings."
CL&P, PSNH, WMECO and other New England electric utilities are the
stockholders of the Yankee companies. Each Yankee company owns a single
nuclear generating unit. The stockholder-sponsors of each Yankee company
are responsible for proportional shares of the operating and decommissioning
costs of the respective Yankee company and are entitled to proportional
shares of the electrical output in the case of Vermont Yankee (VY), which
is the only operating unit of the four Yankee companies set forth below.
The relative rights and obligations with respect to the Yankee companies
are approximately proportional to the stockholders' percentage stock holdings,
but vary slightly to reflect arrangements under which nonstockholder electric
utilities have contractual rights to some of the output of particular units.
The Yankee companies and CL&P's, PSNH's and WMECO's stock ownership percentages
in the Yankee companies are set forth below:
CL&P PSNH WMECO System
Connecticut Yankee Atomic
Power Company (CYAPC) ...... 34.5% 5.0% 9.5% 49.0%
Maine Yankee Atomic Power
Company (MYAPC) ............ 12.0% 5.0% 3.0% 20.0%
Vermont Yankee Nuclear
Power Corporation (VYNPC)... 9.5% 4.0% 2.5% 16.0%
Yankee Atomic Electric
Company (YAEC) ............ 24.5% 7.0% 7.0% 38.5%
CL&P, PSNH and WMECO are obligated to provide their percentages of any
additional equity capital necessary for VY, but do not expect to need to
contribute additional equity capital in the future. CL&P, PSNH and WMECO
believe that VY could require additional external financing in the next
several years to finance construction expenditures, nuclear fuel and for
other purposes. Although the way in which VYNPC would attempt to finance
these expenditures, if they are needed, has not been determined, CL&P, PSNH
and WMECO could be asked to provide further direct or indirect financial
support. CYAPC, YAEC and MYAPC could also request their sponsors to provide
future financial support necessary in connection with the decommissioning of
their respective units, the level of which support cannot be estimated at
this time, but could be material.
The operators of Millstone 2 and 3, VY and Seabrook 1 hold full term
operating licenses from the NRC and are subject to the jurisdiction of
the NRC. The NRC has broad jurisdiction over the design, construction
and operation of nuclear generating stations, including matters of public
health and safety, financial qualifications, antitrust considerations and
environmental impact. The NRC issues 40-year initial operating licenses
to nuclear units and NRC regulations permit renewal of licenses for an
additional 20-year period. The NRC also has jurisdiction over the
decommissioning activities at Yankee Rowe, CY, MY, and Millstone 1.
The NRC also regularly conducts generic reviews of technical and other
issues, a number of which may affect the nuclear plants in which System
companies have interests. The cost of complying with any new requirements
that may result from these reviews cannot be estimated at this time, but
such costs could be substantial. For more information regarding recent
actions taken by the NRC with respect to the System's nuclear units, see
"Nuclear Plant Performance and Regulatory Oversight" below.
NUCLEAR PLANT PERFORMANCE AND REGULATORY OVERSIGHT
MILLSTONE 2 AND 3
Millstone 2 and 3 are located in Waterford, Connecticut, and have
license expirations of July 31, 2015 and November 25, 2025, respectively.
Millstone Station has been the subject of intense regulatory scrutiny over
the last several years. Millstone 3, the largest plant, was returned to
service in July 1998, after having been shutdown since March 30, 1996. The
unit operated at a capacity factor of 70.5 percent from the time it returned
from its extended outage in July 1998 through December 31, 1998. The unit
was shutdown from December 11, 1998 to December 31, 1998 to modify certain
valves that had failed during routine surveillance testing. The unit is
scheduled to begin a refueling outage on May 1, 1999. Millstone 3 remains
on the NRC's watch list as a Category 2 facility, which indicates that the
NRC intends to continue to closely monitor the facility.
Millstone 2 has been out of service since February 21, 1996. This unit
is presently on the NRC's watch list as a Category 3 plant. Plants in this
category are required to receive formal NRC commissioners' approval to resume
operations. Key steps before restart include final verification that the unit
is in conformance with its design and licensing basis; that management processes
support safe and conservative operations; and that the employees are effective
at identifying and correcting deficiencies at the unit. Management currently
hopes to restart Millstone 2 in the spring of 1999.
In addition to the various technical and design basis issues at Millstone,
the NRC continues to focus on the System's response to employee concerns at
the units. In October 1996, the NRC issued an order that requires NNECO to
develop and implement a comprehensive plan for handling safety concerns raised
by Millstone employees and for assuring an environment free from retaliation
and discrimination. The NRC also ordered NNECO to contract for an independent
third party to oversee the implementation of the comprehensive plan. At an
NRC Commissioners' briefing on January 19, 1999, the NRC Staff recommended
that the third party oversight contractor was no longer necessary.
For information regarding criminal investigations by the NRC's Office
of Investigations (OI) and the Office of the U. S. Attorney for the District
of Connecticut related to various matters at Millstone and CY, a citizens'
petition related to nuclear operations and potential joint owner litigation
related to the extended outages, see "Item 3. Legal Proceedings."
SEABROOK
Seabrook, a 1148-MW pressurized-water reactor, has a license expiration
date of October 17, 2026. The Seabrook operating license expires 40 years
from the date of issuance of authorization to load fuel, which was about
three and one-half years before Seabrook's full-power operating license was
issued. The System will determine at the appropriate time whether to seek
recapture of some or all of this period from the NRC and thus add up to
an additional three and one-half years to the operating term for Seabrook.
Seabrook had no planned refueling and maintenance outage in 1998. In
1998, Seabrook operated at a capacity factor of 82.7 percent. Seabrook
experienced two unplanned outages in 1998 (December 5, 1997 - January 17,
1998 and June 11, 1998 - July 11, 1998). During the course of repairing a
leak during the first outage, problems occurred in the control building air
conditioning system. Modifications were made to the air conditioning system
at that time, but required additional modifications and the replacement of
two refrigeration compressors. The unit is scheduled to begin a 45-day
refueling outage on March 26, 1999.
VERMONT YANKEE
VY, a 514-MW boiling water reactor, has a license expiration date of
March 21, 2012. In 1998, VY operated at a capacity factor of 75.2 percent.
VY had a planned refueling outage from March 20, 1998 to June 3, 1998.
NUCLEAR INSURANCE
For information regarding nuclear insurance, see "Commitments and
Contingencies--Nuclear Insurance Contingencies" in the notes to NU's, CL&P's,
PSNH's, WMECO's and NAEC's financial statements.
NUCLEAR FUEL
GENERAL
The supply of nuclear fuel for the System's existing units requires the
procurement of uranium concentrates, followed by the conversion, enrichment
and fabrication of the uranium into fuel assemblies suitable for use in the
System's units. Fuel may also be purchased at a point after any of the
above processes are completed. The System expects that uranium concentrates
and related services for the units operated by the System and for the other
units in which the System companies are participating that are not covered
by existing contracts, will be available for the foreseeable future on
reasonable terms and prices.
As a result of the Energy Policy Act, the United States commercial
nuclear power industry is required to pay the United States Department
of Energy (DOE), through a special assessment, for the costs of the
decontamination and decommissioning of uranium enrichment plants owned
by the United States government, no more than $150 million per annum for
15 years beginning in 1993. Each domestic nuclear utility's payment is
based on its pro rata share of all enrichment services received by the
United States commercial nuclear power industry from the United States
government through October 1992. Each year, the DOE adjusts the annual
assessment using the Consumer Price Index. The Energy Policy Act provides
that the assessments are to be treated as reasonable and necessary current
costs of fuel, which costs shall be fully recoverable in rates in all
jurisdictions. The System's remaining share to be recovered, assuming no
escalation, is approximately $60 million as of December 31, 1998. Management
believes that the DOE assessments against CL&P, WMECO, PSNH and NAEC will
be recoverable in future rates. Accordingly, each of these companies has
recognized these costs as a regulatory asset, with a corresponding obligation
on its balance sheet.
On October 22, 1998, an action was initiated by the owners of the
Millstone units in the U.S. Court of Federal Claims against the DOE regarding
the special annual assessment that DOE imposes on purchasers of enriched
uranium to meet the future costs of decontaminating and decommissioning
government owned uranium enrichment facilities. Similar actions for Seabrook
and Connecticut Yankee were filed on October 23, 1998. The lawsuits challenge
the imposition of the D&D assessment on federal constitutional grounds, and
are similar to actions filed by a number of other utilities against DOE. As
of December 31, 1998, the System companies had paid approximately $28 million
into the fund.
Nuclear fuel costs associated with nuclear plant operations include
amounts for disposal of spent nuclear fuel. The System companies include in
their nuclear fuel expense spent fuel disposal costs accepted by the DPUC,
NHPUC and DTE in rate case or fuel adjustment decisions. Spent fuel
disposal costs also are reflected in FERC-approved wholesale charges.
HIGH-LEVEL RADIOACTIVE WASTE
The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal
government is responsible for the permanent disposal of spent nuclear reactor
fuel (SNF) and high-level waste. As required by the NWPA, electric utilities
generating SNF and high-level waste are obligated to pay fees into a fund
which would be used to cover the cost of siting, constructing, developing and
operating a permanent disposal facility for this waste. The System companies
have been paying for such services for fuel burned on or after April 7, 1983
on a quarterly basis since July 1983. The DPUC, NHPUC and DTE permit the fee
to be recovered through rates. For nuclear fuel used to generate electricity
prior to April 7, 1983 (prior-period fuel), payment must be made prior to the
first delivery of spent fuel to the DOE. The DOE's current estimate for an
available site is 2010. For more information regarding payments related to
the prior-period fuel, see "Spent Nuclear Fuel Disposal Costs" in the notes
to NU's, CL&P's, PSNH's, WMECO's and NAEC's financial statements.
In return for payment of the fees prescribed by the NWPA, the federal
government is to take title to and dispose of the utilities' high-level
wastes and SNF. There has been numerous litigation involving the DOE's
statutory and contractual obligation to accept high-level waste and SNF.
While the courts have declined to order DOE to begin accepting spent fuel
for disposal on January 31, 1998, the courts left open the utilities'
ability to bring damage claims against the DOE.
On February 18, 1998, YAEC filed a complaint against DOE in the United
States Court of Federal Claims seeking damages in excess of $70 million
resulting from DOE's failure to accept spent nuclear fuel for disposal.
CYAPC and MYAPC filed similar complaints on March 4, 1998 and June 2, 1998
seeking damages of over $90 million and $128 million, respectively. On
October 29, 1998, the court found liability on the part of DOE to YAEC for
breach of the Standard Contract, based upon DOE's failure to begin disposal
of SNF. In separate orders dated October 30, 1998 and November 3, 1998,
respectively, the court extended its rulings in the YAEC case to the damage
claim cases filed by CYAPC and MYAPC. DOE is expected to appeal the claims
court decision.
Until the federal government begins accepting nuclear waste for disposal,
nuclear generating plants will need to retain high-level waste and spent fuel
onsite or make some other provisions for their storage. With the addition of
new storage racks, storage facilities for Millstone 3 are expected to be
adequate for the projected life of the unit. With the implementation of
currently planned modifications, the storage facilities for Millstone 2
are expected to be adequate (maintaining the capacity to accommodate a
full-core discharge from the reactor) until 2005. Fuel consolidation,
which has been licensed for Millstone 2, could provide adequate storage
capability for its projected life. Seabrook is expected to have spent fuel
storage capacity until at least 2010.
The available capacity of the VY spent fuel pool is expected to be able
to accommodate full-core removal until 2001. Full core discharge ability
through the year 2008 could be achieved with the installation of additional
storage racks in the spent fuel pool, subject to approval of a pending NRC
license amendment. VYNPC is also investigating other options for additional
storage capacity beyond the year 2001.
Adequate storage capacity exists to accommodate all of the SNF at
Millstone 1, CY, MY and Yankee Rowe until that fuel is removed by the DOE.
LOW-LEVEL RADIOACTIVE WASTE
The System currently has contracts to dispose its low-level radioactive
waste (LLRW) at two privately operated facilities in Clive, Utah, and in
Barnwell, South Carolina. The current political situation in South Carolina
makes it difficult to predict whether the Barnwell facility will remain
open. Because access to LLRW disposal may be lost at any time, the System
has plans that will allow for onsite storage of LLRW for at least five
years.
DECOMMISSIONING
Based upon the System's most recent comprehensive site-specific updates
of the decommissioning costs for each of the three Millstone units and for
Seabrook, the recommended decommissioning method continues to be immediate
and complete dismantlement of those units at their retirement. The table
below sets forth the estimated Millstone and Seabrook decommissioning costs
for the System companies. The estimates are based on the latest site
studies, stated in December 31, 1998 dollars.
CL&P PSNH WMECO NAEC System
(Millions)
Millstone 1....... $ 560.5 $ - $131.5 $ - $ 692.0
Millstone 2....... 322.0 - 75.5 - 397.5
Millstone 3....... 296.2 15.9 68.5 - 380.6
Seabrook.......... 19.9 - - 175.9 195.8
Total........... $1,198.6 $15.9 $275.5 $175.9 $1,665.9
As of December 31, 1998, the System recorded balances (at market) in
its external decommissioning trust funds are as follows:
CL&P PSNH WMECO NAEC System
(Millions)
Millstone 1....... $210.5 $ - $ 58.7 $ - $269.2
Millstone 2....... 142.1 - 40.9 - 183.0
Millstone 3....... 96.3 5.6 26.0 - 127.9
Seabrook.......... 3.8 - - 35.2 39.0
Total........... $452.7 $5.6 $125.6 $35.2 $619.1
In 1986, the DPUC approved the establishment of separate external
trusts for the currently tax-deductible portions of decommissioning expense
accruals for Millstone 1 and 2 and for all expense accruals for Millstone 3.
WMECO has established independent trusts to hold all decommissioning
expense collections from customers. The DTE has authorized WMECO to collect
its current decommissioning estimate for the three Millstone units.
New Hampshire enacted a law in 1981 requiring the creation of a state-
managed fund to finance decommissioning of any units in that state. NAEC's
costs for decommissioning are billed by it to PSNH and recovered by PSNH
under the Rate Agreement. Under the Rate Agreement, PSNH is entitled to a
base rate increase to recover increased decommissioning costs. In its recent
restructuring orders, the NHPUC determined that PSNH would be allowed to
recover decommissioning costs through stranded cost charges. See "Rates--
New Hampshire Retail Rates" for further information on the Rate Agreement
and restructuring.
The decommissioning cost estimates for the System nuclear units
are reviewed and updated regularly to reflect inflation and changes in
decommissioning requirements and technology. Changes in requirements or
technology, or adoption of a decommissioning method other than immediate
dismantlement, could change these estimates. CL&P, PSNH and WMECO attempt
to recover sufficient amounts through their allowed rates to cover their
expected decommissioning costs. Only the portion of currently estimated
total decommissioning costs that has been accepted by regulatory agencies is
reflected in rates of the System companies. Based on present estimates, and
assuming its nuclear units operate to the end of their respective license
periods, the System expects that the decommissioning trust funds will be
substantially funded when those expenditures have to be made.
Based on a continued unit operation study filed with the DPUC in 1998,
CL&P and WMECO decided to shutdown Millstone 1 and instead prepare for final
decommissioning. The total estimated decommissioning costs, which have been
updated to reflect the early shutdown of the unit, are approximately $692.0
million as of December 31, 1998 ($560.5 million for CL&P and $131.5 million
for WMECO). CL&P and WMECO use external trusts to fund the estimated
decommissioning costs of Millstone 1. At December 31, 1998, the fair market
value of the balance in the trusts was approximately $269.2 million ($210.5
million for CL&P and $58.7 million for WMECO). In addition, CL&P had
previously established a decommissioning reserve on its books which
represents amounts which have been collected by CL&P, but not funded to
the external decommissioning trust, and will also be used to fund the
total estimated decommissioning obligation of Millstone 1. At December 31,
1998, the balance of this account was approximately $21.9 million.
In the February 5, 1999 rate decision, the DPUC allowed for the
recovery of CL&P's decommissioning and closure obligations for Millstone 1.
A proceeding to determine the decommissioning amounts to be recovered for
Millstone 1 will be commenced in 1999. CL&P expects to seek recovery of
decommissioning related costs for its interests in other nuclear units in
restructuring proceedings to be commenced in 1999.
WMECO is seeking recovery of decommissioning related costs as part of
their restructuring regulatory proceedings. Based upon the restructuring law
in Massachusetts, management believes it is probable that WMECO will be
allowed to recover from customers the estimated remaining costs associated
with Millstone 1 which have been recorded on their balance sheets as a
deferred asset, including decommissioning, unrecovered plant and related
assets, and other expenditures. WMECO has recorded a liability on its
balance sheets for its share of the total estimated obligation to
decommission the plant.
CYAPC, YAEC, VYNPC and MYAPC are all collecting revenues for
decommissioning from their power purchasers. The table below sets forth
the System companies' estimated share of decommissioning costs (and closure
costs where applicable) of the Yankee units. The estimates are based on the
latest site studies. For information on the equity ownership of the System
companies in each of the Yankee units, see "Electric Operations--Nuclear
Generation--General."
CL&P PSNH WMECO System
(Millions)
VY................ $ 54.4 $21.2 $13.3 $ 84.8
Yankee Rowe*...... 20.0 5.7 5.7 31.5
CY*............... 172.0 24.9 47.4 244.3
MY*............... 85.8 35.8 21.5 143.0
Total........... $ 328.2 $87.6 $87.8 $503.6
* As discussed more fully below, the costs shown include all of the
expected future billings associated with the funding of decommissioning,
recovery of remaining assets and other closure costs associated with the
early retirement of Yankee Rowe, CY and MY as of December 31, 1998 which
have been recorded as an obligation on the books of the System companies.
As of December 31, 1998 the System's share of the external decommissioning
trust fund balances (at market), which have been recorded on the books of the
Yankee Companies, is as follows:
CL&P PSNH WMECO System
(Millions)
VY................ $ 21.7 $ 9.1 $ 5.7 $ 36.5
Yankee Rowe....... 36.4 10.4 10.4 57.2
CY................ 89.9 13.0 24.8 127.7
MY................ 25.5 10.6 6.4 42.5
Total........... $173.5 $43.2 $47.2 $264.0
CYAPC accrues decommissioning costs on the basis of immediate
dismantlement at retirement. In late December 1996, CYAPC made a filing
with FERC to amend the wholesale power contracts between the owners of the
facility and revise decommissioning cost estimates and other cost estimates
for the facility. The amendments clarify the owners' entitlement to full
recovery of sunk costs and the ongoing costs of maintaining the plant in
accordance with NRC rules until decommissioning begins and ensures that
decommissioning will continue to be funded through June 2007, the full
license term, despite the unit's earlier shutdown.
On August 31, 1998, the FERC Administrative Law Judge (ALJ) released an
initial decision regarding the December 1996 filing. The decision contained
provisions which would allow for the recovery, through rates, of the balance
of the NU System companies' net unamortized investment in CY, which was
approximately $51.7 million as of December 31, 1998. The decision also
called for the disallowance of the recovery of a portion of the return on
the CY investment. The ALJ's decision also stated that decommissioning
collections should continue to be based on the previously approved estimate
of $309.1 million (in 1992 dollars), with an inflation adjustment of 3.8
percent per year, until a new, more reliable estimate has been prepared
and tested.
During October 1998, both CYAPC and the NU Owners filed briefs on
exceptions to the ALJ decision. If the initial ALJ decision is upheld, CYAPC
could be required to write off a portion of the regulatory asset associated
with the plant closing.
If upheld, CYAPC's management has estimated the effect of the ALJ
decision on CYAPC's earnings to be approximately $37.5 million, of which
the NU Owners' share would be approximately $18.4 million. NU management
cannot predict the outcome of the hearing at this time, however, NU will
continue to support CYAPC's efforts to contest this initial decision.
MYAPC also accrues decommissioning costs on the basis of immediate
dismantlement at retirement. On January 14, 1998, MYAPC made a filing with
FERC to amend its power contracts with the owners/purchasers and revise its
decommissioning and other charges. FERC accepted the proposed application
for filing, and made the amendments and the proposed charges under the
contracts effective on January 15, 1998 subject to refund after hearings.
On January 18, 1999, MYAPC filed an offer of settlement which, if accepted
by the FERC, will resolve all the issues in the FERC decommissioning rate
case proceeding. The settlement provides, among other things, the following:
(1) MYAPC will collect $33.6 million annually to pay for decommissioning and
spent fuel; (2) its return on equity will be set at 6.5 percent; (3) MYAPC
is permitted full recovery of all unamortized investment in MY, including
fuel, and (4) an incentive budget for decommissioning is set at $436.3
million. For information regarding a dispute between the sponsors of MY and
a number of municipalities and cooperatives which had purchase agreements
with MYAPC, see "Item 3. Legal Proceedings."
Effective January 1996, YAEC began billing its sponsors, including
CL&P, WMECO and PSNH, amounts based on a revised estimate approved by FERC
that assumes decommissioning by the year 2000.
For more information regarding nuclear decommissioning, see "Nuclear
Decommissioning and Plant Closure Costs" in the notes to NU's, CL&P's,
PSNH's, WMECO's and NAEC's financial statements.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
ENVIRONMENTAL REGULATION
GENERAL
The System and its subsidiaries are subject to federal, state and local
regulations with respect to water quality, air quality, toxic substances,
hazardous waste and other environmental matters. Additionally, the System's
major generation and transmission facilities may not be constructed or
significantly modified without a review by the applicable state agency of
the environmental impact of the proposed construction or modification.
Compliance with environmental laws and regulations, particularly air and
water pollution control requirements, may limit operations or require
substantial investments in new equipment at existing facilities.
SURFACE WATER QUALITY REQUIREMENTS
The federal Clean Water Act (CWA) requires every "point source" discharger
of pollutants into navigable waters to obtain a National Pollutant Discharge
Elimination System (NPDES) permit from the United States Environmental
Protection Agency (EPA) or state environmental agency specifying the allowable
quantity and characteristics of its effluent. System facilities have all
required NPDES permits in effect, but several of these permits are currently
in the renewal process. Compliance with NPDES and state water discharge permits
has necessitated substantial expenditures, which are difficult to estimate,
and may require further expenditures because of additional requirements that
could be imposed in the future. For information regarding a lawsuit related to
alleged violations of certain facilities' NPDES permits, see "Item 3. Legal
Proceedings."
The Federal Oil Pollution Act of 1990 (OPA 90) sets out the requirements
for facility response plans and periodic inspections of spill response equipment
at facilities that can cause substantial harm to the environment by discharging
oil or hazardous substances into the navigable waters of the United States and
onto adjoining shorelines. The System companies are currently in compliance
with the requirements of OPA 90. OPA 90 includes limits on the liability that
may be imposed on persons deemed responsible for release of oil. The limits
do not apply to oil spills caused by negligence or violation of laws or
regulations. OPA 90 also does not preempt state laws regarding liability for
oil spills. In general, the laws of the states in which the System owns
facilities and through which the System transports oil could be interpreted
to impose strict liability for the cost of remediating releases of oil and
for damages caused by releases. The System currently carries general liability
insurance in the total amount of $100 million annual coverage for oil spills.
AIR QUALITY REQUIREMENTS
The Clean Air Act Amendments of 1990 (CAAA) impose stringent requirements
on emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose
of controlling acid rain and ground level ozone. In addition, the CAAA address
the control of toxic air pollutants. Installation of continuous emissions
monitors and expanded permitting provisions also are included. Compliance
with CAAA requirements has cost the System approximately $48 million as of
December 31, 1998: $11 million for CL&P, $33 million for PSNH, $1 million
for WMECO and $3 million for HWP. Compliance costs for additional federal
and state NOX control requirements to be effective in 1999 are currently
estimated to be approximately $10 million for both CL&P and PSNH. In addition,
PSNH expects to spend approximately $2 million a year for SO2 allowances.
Existing and future federal and state air quality regulations,
including Connecticut and Massachusetts restructuring legislation, which
requires development of generator performance standards, and recently
proposed regulations seeking to impose new source standards on existing
units, could hinder or possibly preclude the construction of new, or the
modification of existing, fossil units in the System's service area and
could raise the capital and operating cost of existing units. The ultimate
cost impact of these requirements on the System cannot be estimated because
of uncertainties about how EPA and the states will implement various
requirements of the CAAA.
Section 126 of the Clean Air Act provides for parties to request that
the EPA take action against emissions sources whose emissions may be
atmospherically transported and contribute to nonattainment of the National
Ambient Air Quality Standards in other states. In accordance with this, a
group of northeastern states filed a petition with EPA in 1997 asking them
to take action against a broadly defined group of emissions sources in
several midwestern states which are believed to be contributing to the
nonattainment of the ozone standard in the Northeast. EPA has deferred
specific action on the Section 126 petitions until its call for state
implementation plans in the affected states is complete, probably about
2003. A final decision by the EPA could have a significant effect on NOX
reduction requirements imposed on System companies after 1999.
HAZARDOUS WASTE REGULATIONS
As many other industrial companies have done in the past, System
companies disposed of residues from operations by depositing or burying such
materials on-site or disposing of them at off-site landfills or facilities.
Typical materials disposed of include coal gasification waste, fuel oils,
gasoline and other hazardous materials that might contain polychlorinated
biphenyls (PCBs). It has since been determined that deposited or buried
wastes, under certain circumstances, could cause groundwater contamination
or create other environmental risks. The System has recorded a liability
for what it believes is, based upon currently available information, its
estimated environmental remediation costs for waste disposal sites for
which the System companies expect to bear legal liability, and continues
to evaluate the environmental impact of its former disposal practices.
Under federal and state law, government agencies and private parties can
attempt to impose liability on System companies for such past disposal.
At December 31, 1998, the liability recorded by the System for its estimated
environmental remediation costs for known sites needing remediation including
those sites described below, exclusive of recoveries from insurance or from
third parties, was approximately $21.5 million, within the range of $21.5
million to $36.4 million. These costs could be significantly higher if
alternative remedies become necessary.
Under the federal Comprehensive Environmental Response, Compensation
and Liability Act of 1980, as amended, commonly known as Superfund, EPA has
the authority to clean up or order clean up of hazardous waste sites and to
impose the clean up costs on parties deemed responsible for the hazardous
waste activities on the sites. Responsible parties include the current
owner of a site, past owners of a site at the time of waste disposal, waste
transporters and waste generators. The System currently is involved in one
Superfund site in New Jersey, one in New Hampshire and one in Kentucky,
which could have a material impact on the System. The System has committed
in the aggregate approximately $1.3 million to its share of the clean up of
these sites.
As discussed below, in addition to the remediation efforts for the
above-mentioned Superfund sites, the System has been named as a potentially
responsible party (PRP) and is monitoring developments in connection with
several state environmental actions. The level of study of each site and the
information about the waste contributed to the site by the System and other
parties differs from site to site. Where reliable information is available
that permits the System to make a reasonable estimate of the expected total
costs of remedial action and/or the System's likely share of remediation
costs for a particular site, those cost estimates are provided below. All
cost estimates were made in accordance with generally accepted accounting
principles where remediation costs were probable and reasonably estimable.
In 1987, the Connecticut Department of Environmental Protection (CDEP)
published a list of 567 hazardous waste disposal sites in Connecticut.
The System owns two sites, in Stamford and Rockville, which are on this
list. Both sites were formerly used by CL&P predecessor companies for the
manufacture of coal gas (also known as town gas sites) from the late 1800s
to the 1950s. Site investigations have been completed at these sites and
discussions with state regulators are in progress to address the need for
and extent of remediation necessary to protect public health and the
environment. The total reserve established for these two sites is $6.5
million.
CL&P owns two sections of an abandoned railroad bed in Portland and
Ridgefield, Connecticut. Past studies of portions of the railroad bed have
indicated elevated levels of arsenic in the upper two to three feet of soil
at both locations. A portion of the Portland site was cleaned up in 1997,
but the System reserved approximately $1.8 million for future remediation
efforts.
PSNH contacted New Hampshire Department of Environmental Services
(NHDES) in December 1993 concerning possible coal tar contamination in
Laconia, New Hampshire, in Lake Opechee and the Winnipesaukee River near
an area where PSNH and a second PRP formerly owned and operated a coal
gasification plant from the late 1800's to the 1950's. A comprehensive site
investigation was completed in December 1996. This study has shown that
byproducts from the operation of the former manufactured gas plant are
present in groundwater, subsurface soil and in the sediments of the adjacent
Winnipesaukee River. A remediation action plan is currently under review
by the NHDES. A reserve of $3.8 million has been established for this site.
PSNH has also recently received requests from NHDES to conduct site
investigations at three additional former manufactured gas plant sites.
These sites are located in Keene, Nashua, and Dover, New Hampshire.
Studies are now being planned to understand site conditions and any
environmental impacts. PSNH is also involved in other site studies to
assess contamination, but PSNH's liability at these sites is not expected
to be material.
Environmental contaminants have been identified at the former
Manchester Steam generating station in Manchester, New Hampshire. The NHDES
has requested additional studies to occur at the site in 1999. A reserve of
$4.1 million has been established for abatement and remediation at the site.
In Massachusetts, System companies have been designated by the
Massachusetts Department of Environmental Protection (MDEP) as a PRP for
twelve sites under MDEP's hazardous waste and spill remediation program. At
two sites, the System may incur remediation costs that may be material to
HWP depending on the remediation requirements. At one site, HWP has been
identified by MDEP as one of three PRPs in a coal tar site in Holyoke,
Massachusetts. HWP owned and operated the Holyoke Gas Works from 1859 to
1902. The site is located on the east side of Holyoke, adjacent to the
Connecticut River and immediately downstream of HWP's Hadley Falls Station.
MDEP has designated both the land and river deposit areas as priority waste
disposal sites. The PRPs have been notified of the need to remove tar
deposits from the river. To date, HWP has spent approximately $1 million
for river studies and construction costs related to the site. The total
estimated costs for removal of tar patches in the river range from $2
million to $3 million. HWP has agreed to complete the removal of tar
patches following negotiations of a consent decree with various state
and federal regulatory agencies.
The second site is a former manufactured gas plant facility in
Easthampton, Massachusetts. WMECO predecessor companies owned and operated
the Easthampton Gas Works from 1864 to 1924. Previous investigations have
identified coal tar deposits on the land portion of the site. An analysis
of the human, health and ecological risks at the site and a remedial action
plan will be submitted to the MDEP in 1999. WMECO has reserved approximately
$1.3 million for remediation costs for the site.
In the past, the System has received other claims from government
agencies and third parties for the cost of remediating sites not currently
owned by the System but affected by past System disposal activities and may
receive more such claims in the future. The System expects that the costs
of resolving claims for remediating sites about which it has been notified
will not be material, but cannot estimate the costs with respect to sites
about which it has not been notified.
ELECTRIC AND MAGNETIC FIELDS
Published reports have discussed the possibility of adverse health
effects from electric and magnetic fields (EMF) associated with electric
transmission and distribution facilities and appliances and wiring in
buildings and homes. Most researchers, as well as numerous scientific
review panels considering all significant EMF epidemiological and laboratory
studies to date, agree that current information remains inconclusive,
inconsistent and insufficient for characterizing EMF as a health risk.
Based on this information, management does not believe that a causal
relationship between EMF exposure and adverse health effects has been
established or that significant capital expenditures are appropriate to
minimize unsubstantiated risks. The System companies have closely monitored
research and government policy developments for many years and will continue
to do so.
If further investigation were to demonstrate that the present
electricity delivery system is contributing to increased risk of cancer
or other health problems, the industry could be faced with the difficult
problem of delivering reliable electric service in a cost-effective manner
while managing EMF exposures. To date, no courts have concluded that
individuals have been harmed by EMF from electric utility facilities, but
if utilities were to be found liable for damages, the potential monetary
exposure for all utilities, including the System companies, could be
enormous. Without definitive scientific evidence of a causal relationship
between EMF and health effects, and without reliable information about the
kinds of changes in utilities' transmission and distribution systems that
might be needed to address the problem, if one is found, no estimates of
the cost impacts of remedial actions and liability awards are available.
See "Item 3. Legal Proceedings" for information about lawsuits brought
against NU by plaintiffs regarding EMF exposure.
FERC HYDRO PROJECT LICENSING
Federal Power Act licenses may be issued for hydroelectric projects for
terms of 30 to 50 years as determined by FERC. Upon the expiration of a
license, any hydroelectric project so licensed is subject to reissuance by
FERC to the existing licensee or to others upon payment to the licensee of
the lesser of fair value or the net investment in the project plus severance
damages less certain amounts earned by the licensee in excess of a
reasonable rate of return.
The System companies currently hold FERC licenses for 19 hydroelectric
projects aggregating approximately 1,375 MW of capacity, located in
Connecticut, Massachusetts and New Hampshire. CL&P, WMECO and PSNH have
proposed to auction their hydroelectric projects in the future.
The license for HWP's Holyoke Project expires in late 1999. On
September 3, 1997, HWP filed its application for a new license for the
Holyoke Project. On August 29, 1997, a competing application for the
project was submitted by the Ashburnham Municipal Light Plant and the
Massachusetts Municipal Wholesale Electric Company. The competing
application proposes to add an additional 15 MW of generating capacity
at the site, as well as additional changes, modifications and improvements
to the facility. The competing license application was amended to add the
City of Holyoke Gas and Electric Department as an additional applicant.
Absent significant differences in the competing license applications
the Federal Power Act gives a preference to an existing licensee for the new
license. If the license is awarded to a competing applicant, HWP is entitled
to compensation equal to the lesser of book value or fair market value and
severance damages pursuant to the Federal Power Act. Completion of all licensing
activities and issuance of a new license is expected by September 1, 1999.
CL&P's FERC licenses for operation of the Falls Village and Housatonic
Hydro Projects expire in 2001. A draft license application, which proposes
to combine both projects under one license is scheduled to be completed in
the first quarter of 1999. A final license application is expected to be
submitted to FERC in the third quarter of 1999.
FERC has issued a notice indicating that it has authority to order
project licensees to decommission projects that are no longer economic to
operate. The potential costs of decommissioning a project, however, could
be substantial. FERC has recently ordered its first project decommissioning
under this authority. It is likely that this FERC decision will be
appealed.
EMPLOYEES
As of December 31, 1998, the System companies had 9,077 full and part-
time employees on their payrolls, of which 2,379 were employed by CL&P,
1,265 by PSNH, 533 by WMECO, 77 by HWP, 1,624 by NNECO, 2,355 by NUSCO and
844 by NAESCO. NU, NAEC, Mode 1, NUEI, NGC, NGS, and Select Energy have no
employees.
Approximately 2,300 employees of CL&P, PSNH, WMECO, NAESCO and HWP are
covered by ten union agreements, which expire between May 31, 1999 and
October 1, 2001.
YEAR 2000
For information regarding the System's efforts to address this issue,
see "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations."
ITEM 2. Properties
The physical properties of the NU System are owned or leased by
subsidiaries of NU. CL&P's principal plants and other properties are
located either on land which is owned in fee or on land, as to which CL&P
owns perpetual occupancy rights adequate to exclude all parties except
possibly state and federal governments, which has been reclaimed and filled
pursuant to permits issued by the United States Army Corps of Engineers.
The principal properties of PSNH are held by it in fee. In addition, PSNH
leases space in an office building under a 30-year lease expiring in 2002.
WMECO's principal plants and a major portion of its other properties are
owned in fee, although one hydroelectric plant is leased. NAEC owns a
35.98 percent interest in Seabrook 1 and approximately 560 acres of
exclusion area land located around the unit. In addition, CL&P, PSNH, and
WMECO have certain substation equipment, data processing equipment, nuclear
fuel, gas turbines, nuclear control room simulators, vehicles, and office
space that are leased. With few exceptions, the NU System companies' lines
are located on or under streets or highways, or on properties either owned
or leased, or in which the company has appropriate rights, easements, or
permits from the owners.
CL&P's properties and PSNH's properties are subject to the lien of
each company's respective first mortgage indenture. WMECO's properties are
subject to the lien of its first mortgage indenture. NAEC's First Mortgage
Bonds are secured by a lien on the Seabrook 1 interest described above, and
all rights of NAEC under the Seabrook Power Contracts. In addition, CL&P's
and WMECO's interests in Millstone 1 are subject to second liens for the
benefit of lenders under agreements related to pollution control revenue
bonds. Various of these properties are also subject to minor encumbrances
which do not substantially impair the usefulness of the properties to the
owning company.
The NU System companies' properties are well maintained and are in
good operating condition.
Transmission and Distribution System
At December 31, 1998, the NU System companies owned 103 transmission
and 400 distribution substations that had an aggregate transformer capacity
of 25,186,669 kilovoltamperes (kVa) and 9,153,470 kVa, respectively; 3,074
circuit miles of overhead transmission lines ranging from 69 kilovolt (kV)
to 345 kV, and 192 cable miles of underground transmission lines ranging
from 69 kV to 138 kV; 32,952 pole miles of overhead and 2,060 conduit bank
miles of underground distribution lines; and 409,210 line transformers in
service with an aggregate capacity of 17,399,000 kVa.
Electric Generating Plants
As of December 31, 1998, the electric generating plants of the NU
System companies and the NU System companies' entitlement in the generating
plant of the Vermont Yankee regional generating company were as follows (See
"Item 1. Business - Electric Operations, Nuclear Generation" for information
on ownership and operating results for the year.):
Claimed
Year Capability*
Owner Plant Name (Location) Type Installed (kilowatts)
CL&P Millstone (Waterford, CT)
Unit 2** Nuclear 1975 708,345
Unit 3 Nuclear 1986 603,436
Seabrook (Seabrook, NH) Nuclear 1990 47,175
VT Yankee (Vernon, VT) Nuclear 1972 45,189
Total Nuclear-Steam Plants ( 4 units) 1,404,145
Total Fossil-Steam Plants (10 units) 1954-73 1,883,000
Total Hydro-Conventional (25 units) 1903-55 98,970
Total Hydro-Pumped Storage ( 7 units) 1928-73 937,100
Total Internal Combustion (20 units) 1966-96 567,540
Total CL&P Generating Plant (66 units) 4,890,755
PSNH Millstone (Waterford, CT)
Unit 3 Nuclear 1986 32,461
VT Yankee (Vernon, VT) Nuclear 1972 18,999
Total Nuclear-Steam Plants ( 2 units) 51,460
Total Fossil-Steam Plants ( 7 units) 1952-78 1,056,918
Total Hydro-Conventional (20 units) 1917-83 67,930
Total Internal Combustion ( 5 units) 1968-70 101,850
Total PSNH Generating Plant (34 units) 1,278,158
WMECO Millstone (Waterford, CT)
Unit 2** Nuclear 1975 166,155
Unit 3 Nuclear 1986 139,519
VT Yankee (Vernon, VT) Nuclear 1972 11,904
Total Nuclear-Steam Plants ( 3 units) 317,578
Total Fossil-Steam Plants ( 3 units) 1949-57 209,460
Total Hydro-Conventional (27 units) 1904-34 110,910***
Total Hydro-Pumped Storage ( 4 units) 1972-73 212,800
Total Internal Combustion ( 3 units) 1968-69 63,500
Total WMECO Generating Plant (40 units) 914,248
Claimed
Year Capability*
Owner Plant Name (Location) Type Installed (kilowatts)
NAEC Seabrook (Seabrook, NH) Nuclear 1990 418,111
HWP Mt. Tom (Holyoke, MA) Fossil-Steam 1960 147,000
Total Hydro-Conventional (15 units) 1905-1983 43,560
Total HWP Generating Plant (16 units) 190,560
NU System Millstone (Waterford, CT)
Unit 2** Nuclear 1975 874,500
Unit 3 Nuclear 1986 775,416
Seabrook (Seabrook, NH) Nuclear 1990 465,286
VT Yankee (Vernon, VT) Nuclear 1972 76,092
Total Nuclear-Steam Plants ( 4 units) 2,191,294
Total Fossil-Steam Plants (21 units) 1952-78 3,296,378
Total Hydro-Conventional (87 units) 1903-83 321,370
Total Hydro-Pumped Storage ( 7 units) 1928-73 1,149,900
Total Internal Combustion (28 units) 1966-96 732,890
Total NU System Generating Plant
Including Vermont Yankee (147 units) 7,691,832
Excluding Vermont Yankee (146 units) 7,615,740
*Claimed capability represents winter ratings as of December 31, 1998.
**The number shown represents claimed capability at December 31, 1996.
Millstone 2 has been out of service since February 21, 1996. The
company has restructured its nuclear organization and is currently
implementing comprehensive plans to restart the unit. The actual date
of the return to service for the unit is dependent, in part, upon the
completion of independent inspections and reviews by the NRC and a vote
by the NRC Commissioners. Millstone 2 is expected to be ready to
restart in the spring of 1999.
***Total Hydro-Conventional capability includes the Cobble Mtn. plant's
33,960 kW which is leased from the City of Springfield, MA.
Franchises
NU's operating subsidiaries hold numerous franchises in the territories
served by them. For more information regarding recent judicial, regulatory
and legislative decisions and initiatives that may affect the terms under
which the System companies provide electric service in their franchised
territories, see Item 1. "Business - Electric Industry Restructuring" and
"Item 3. Legal Proceedings."
CL&P. Subject to the power of alteration, amendment or repeal by the
General Assembly of Connecticut and subject to certain approvals, permits
and consents of public authority and others prescribed by statute, CL&P has,
subject to certain exceptions not deemed material, valid franchises free
from burdensome restrictions to provide electric transmission and distribution
services, and, until January 2000, to sell electricity, in the respective areas
in which it is now supplying such service.
In addition to the right to provide electric transmission and
distribution services as set forth above, the franchises of CL&P include,
among others, limited rights and powers, as set forth in Public Act 98-28,
to manufacture, generate, purchase and sell electricity at retail, including
to provide standard offer, backup and default service, to sell electricity
at wholesale to other utility companies and municipalities and to erect and
maintain certain facilities on public highways and grounds, all subject to
such consents and approvals of public authority and others as may be
required by law. The franchises of CL&P include the power of eminent
domain. For a more detailed discussion of Public Act 98-28, see "Item 1.
Business - Electric Industry Restructuring."
PSNH. Subject to the power of alteration, amendment or repeal by the
General Court (legislature) of the State of New Hampshire and subject to
certain approvals, permits and consents of public authority and others
prescribed by statute, PSNH has, subject to certain exceptions not deemed
material, valid franchises free from burdensome restrictions to sell
electricity in the respective areas in which it is now supplying such
service.
In addition to the right to sell electricity as set forth above, the
franchises of PSNH include, among others, rights and powers to manufacture,
generate, purchase, transmit and distribute electricity, to sell electricity
at wholesale to other utility companies and municipalities and to erect and
maintain certain facilities on certain public highways and grounds, all
subject to such consents and approvals of public authority and others as
may be required by law. The franchises of PSNH include the power of eminent
domain.
NNECO. Subject to the power of alteration, amendment or repeal by the
General Assembly of Connecticut and subject to certain approvals, permits
and consents of public authority and others prescribed by statute, NNECO has
a valid franchise free from burdensome restrictions to sell electricity to
utility companies doing an electric business in Connecticut and other
states.
In addition to the right to sell electricity as set forth above, the
franchise of NNECO includes, among others, rights and powers to manufacture,
generate and transmit electricity, and to erect and maintain facilities
on certain public highways and grounds, all subject to such consents and
approvals of public authority and others as may be required by law.
WMECO. WMECO is authorized by its charter to conduct its electric
business in the territories served by it, and has locations in the public
highways for transmission and distribution lines. Such locations are
granted pursuant to the laws of Massachusetts by the Department of Public
Works of Massachusetts or local municipal authorities and are of unlimited
duration, but the rights thereby granted are not vested. Such locations are
for specific lines only, and, for extensions of lines in public highways,
further similar locations must be obtained from the Department of Public
Works of Massachusetts or the local municipal authorities. In addition,
WMECO has been granted easements for its lines in the Massachusetts Turnpike
by the Massachusetts Turnpike Authority.
Pursuant to the Massachusetts restructuring legislation, the DTE is
required to define service territories for each distribution company,
including WMECO, based on the service territories actually served on
July 1, 1997, and following to the extent possible municipal boundaries.
After established by the DTE, until terminated by effect of law or otherwise,
the distribution company shall have the exclusive obligation to provide
distribution service to all retail customers within its service territory,
and no other person shall provide distribution service within such service
territory without the written consent of such distribution company.
HWP and Holyoke Power and Electric Company (HP&E). HWP, and its wholly
owned subsidiary HP&E, are authorized by their charters to conduct their
businesses in the territories served by them. HWP's electric business is
subject to the restriction that sales be made by written contract in amounts
of not less than 100 horsepower, except for municipal customers in the
counties of Hampden or Hampshire, Massachusetts and except for customers
who occupy property in which HWP has a financial interest, by ownership or
purchase money mortgage. HWP also has certain dam and canal and related
rights, all subject to such consents and approvals of public authorities
and others as may be required by law. The two companies have locations in
the public highways for their transmission and distribution lines. Such
locations are granted pursuant to the laws of Massachusetts by the Department
of Public Works of Massachusetts or local municipal authorities and are of
unlimited duration, but the rights thereby granted are not vested. Such
locations are for specific lines only and, for extensions of lines in public
highways, further similar locations must be obtained from the Department of
Public Works of Massachusetts or the local municipal authorities. The two
companies have no other utility franchises.
NAEC. NAEC is authorized by the NHPUC to own and operate its interest
in Seabrook 1.
ITEM 3 - LEGAL PROCEEDINGS
1. Litigation Relating to Electric and Magnetic Fields
On October 14, 1998, the plaintiffs withdrew the remaining lawsuit
pending in Connecticut Superior Court alleging physical and emotional
damages from exposure to EMF in which NU and CL&P were defendants, thus
ending all material litigation against NU and CL&P relating to EMF.
2. Connecticut DPUC - CL&P's Petition for Declaratory Ruling Regarding
Proposed Retail Sales of Electricity by Texas-Ohio Power, Inc. (TOP).
In February 1998 the Connecticut Supreme Court ruled that TOP was a
foreign electric company and therefore was prohibited from making retail
sales of electricity in Connecticut. The Court also ruled that the DPUC was
correct in finding that because TOP did not use public streets it was not an
electric light company prohibited by Connecticut corporate law from making
retail electric sales. The Court made it clear that it would have ruled
differently on this issue if TOP were using public streets.
On September 3, 1998, the bankruptcy court for the Southern District
of Texas - Houston Division granted a Joint Motion to Dismiss filed by the
parties to a related lawsuit. CL&P had been sued in the fall of 1997 by
Triple C Power, Inc., the successor of the bankrupt TOP. The lawsuit stemmed
from CL&P's petition for declaratory rulings from the DPUC.
3. Connecticut Attorney General - Civil Environmental Lawsuit
On October 5, 1998, the Connecticut Superior Court, after hearing
arguments, approved a settlement which resolved a civil lawsuit by the
Connecticut Department of Environmental Protection (CDEP) against NNECO
and NUSCO for violations of the Millstone Station water permit and
Connecticut water discharge regulations. The settlement required NNECO
to pay a $700,000 civil penalty and expend $500,000 to fund three supplemental
environmental projects. NNECO is also required to perform and have third-
party review of two environmental audits of its water compliance program and
to inform the CDEP of major changes to its environmental management system.
An intervening party has appealed the approval of the settlement to
Connecticut Appellate Court.
4. Connecticut Municipal Electric Energy Cooperative (CMEEC) Dispute
In mid-April 1998, the FERC issued an order accepting CL&P's filing
of a settlement with the Connecticut Municipal Electric Energy Cooperative
(CMEEC) over issues arising under the Millstone Units 1 and 2 life of unit
contract. The filing had requested a March 3, 1998 termination date for
the Millstone Units 1 and 2 contract, and a date of October 31, 1998 for
the termination of several CL&P fossil/hydro contracts with CMEEC. In
accordance with the settlement, CL&P received a lump sum payment of $24
million from CMEEC, which had been held in escrow pending FERC approval of
the settlement and the completion of certain additional steps related to
the court and arbitration proceedings.
5. FERC - Transmission Charges Disputes
On May 18, 1998, the FERC issued an order requiring certain NU system
companies, primarily CL&P and WMECO, to refund disputed transmission charges
to MMWEC, United Illuminating and other customers whose transmission rates
are subject to this order. Refunds amounting to approximately $10 million
have been paid to customers and a refund compliance report has been submitted
to the FERC, which report is pending final approval.
6. Shareholder Securities Class Actions
Consolidated Federal Court Actions: Pursuant to a court order dated
October 1, 1997, the six class actions separately filed against NU in
1996 were consolidated for pre-trial and trial purposes. The actions
are based on various Federal securities law and common law theories alleging
misrepresentations and omissions in public disclosures related to the System's
nuclear situation. These complaints represent classes of plaintiffs who
purchased or otherwise acquired NU common stock during periods ranging from
March 1994 to April 1996. This matter is currently in mediation.
State Court Actions: NU has been served with two separately filed
class actions based on various state securities law and common law theories
alleging misrepresentations and omissions in public disclosures related to
the System's nuclear situation. These complaints represent classes of
plaintiffs who purchased or otherwise acquired NU common stock during
periods ranging from December 1993 to April 1996. Plaintiffs' counsel in
both state actions agreed to stay the actions pending the outcome of the
consolidated federal court actions described above.
NU believes that all of these class actions are without merit and
intends to vigorously defend in all such actions.
7. Millstone 3 - Joint Owner Litigation
CL&P and WMECO, through NNECO as agent, operate Millstone 3, at cost
and without profit, under a Sharing Agreement. On August 7, 1997, the non-NU
owners of Millstone 3 filed demands for arbitration with CL&P and WMECO as
well as three lawsuits in Massachusetts Superior Court against NU and its
current and many of its former trustees. The non-NU owners raise a number
of contract, tort and statutory claims, arising out of the operation of
Millstone 3. The demands and lawsuits seek to recover compensatory damages,
punitive damages, treble damages and attorneys' fees. Owners representing
approximately two-thirds of the non-NU interests in Millstone 3 have claimed
compensatory damages in excess of $200 million. The NU companies believe
there is no legal basis for the claims and intend to defend against them
vigorously. An arbitrator to hear the claims against CL&P and WMECO has
been appointed and hearings are scheduled to commence in the fall of 1999.
The defendants, including NU, in the three lawsuits requested consolidation
of those actions, which request was granted. Additionally, NU filed motions
for summary judgment in December 1998, which motions are still pending.
8. Maine Yankee - Secondary Purchasers Dispute
A number of municipalities and cooperatives (Secondary Purchasers)
notified the sponsors of MY, including CL&P, WMECO and PSNH, that they
consider their purchase and payment obligations under their purchase
agreements to have been terminated as a result of the August 6, 1997
decision by the MYAPC Board of Directors (MY Board) to retire MY.
Accordingly, these Secondary Purchasers informed the sponsors that they
would be making no further payments under the contracts for the period
following the MY Board's decision. Through such contracts, the sponsors
agreed to deliver a portion of the capacity and electrical output from MY
until the year 2003 in exchange for payment by the Secondary Purchasers of
a pro rata share of the plant's costs and expenses.
Following a series of regulatory and legal proceedings related to
this matter at the FERC and in Maine state courts, on February 5, 1999,
the parties filed a settlement with the FERC in this matter. A separate
settlement related to the MY decommissioning rate case was filed with
the FERC on January 18, 1999. Upon an order from the FERC accepting the
settlements, the Secondary Purchasers will make a total settlement payment
of $16.5 million in full satisfaction of their obligations with respect
to all past and future MY-related operations and decommissioning costs.
9. Southeastern Connecticut Regional Resources Recovery Authority (SCRRRA)
Contract Disputes
On March 31, 1998, the Connecticut Supreme Court issued a decision in
connection with one of three disputes involving CL&P and SCRRRA. In its
decision, the Court ruled that CL&P was obligated to pay the contract rate
specified in their electricity purchase agreement for the entire net electric
output of SCRRRA's trash-to-energy plant in Preston rather than for the lower
output level specified in the agreement. As a result of this decision, CL&P
agreed to a payment schedule which obligated it to pay SCRRRA approximately
$3.8 million plus accrued interest of approximately $700,000. Most of the
amount paid will be recovered through CL&P's energy adjustment clause.
On November 25, 1998, the DPUC approved a settlement and an associated
amendment, providing for alternative rates, to the SCRRRA contract. This
resolved the second SCRRRA dispute, which related to Connecticut's so-called
"municipal rate law." The amendment lowered the rate CL&P pays to SCRRRA for
electricity. As a result of this contract amendment and settlement, CL&P
withdrew the litigation it had initiated in the remaining dispute involving
SCRRRA.
10. Connecticut DPUC - Energy Adjustment Clause (EAC)
CL&P has appealed to Connecticut Superior Court a DPUC order that,
pending a final ruling in CY's decommissioning proceeding currently
before the FERC, CL&P exclude from its EAC rate the replacement power
costs resulting from the retirement of CY. The appeal has been briefed
and argued and a decision is pending. Pursuant to the February 5, 1999
CL&P rate decision, DPUC permitted CL&P to collect CY replacement power
costs on a current basis effective September 28, 1998. The deferred amount
prior to September 28, 1998 was approximately $75 million.
11. Amended Partial Requirements Agreement (APRA)
On May 29, 1998, FERC issued an order rejecting PSNH's complaint
against the New Hampshire Electric Cooperative, Inc. (NHEC) concerning
NHEC's solicitation of bids from qualifying facilities (QFs) to supplant
wholesale purchase obligations it has with PSNH under the APRA. FERC ruled
that NHEC's purchase obligations under the APRA expressly allow it to
purchase QF power and that the price for such purchases may be determined
by negotiation between NHEC and the individual QF. Additionally, the
decision ordered PSNH to refund to NHEC any overcollections with interest.
On October 6, 1998, FERC issued a final decision rejecting PSNH's request
for clarification and rehearing of the May 1998 order. Refunds were made
in the amount of approximately $98,000. The financial impact of this decision
in the future will vary depending upon the level of purchases from the QFs
made by NHEC.
On February 24, 1999, FERC issued a decision in a separate proceeding
concerning a dispute between PSNH and NHEC over the requirements of the APRA
after the initiation of competition within NHEC's service territory. The
FERC held that the APRA requires NHEC to pay PSNH for all capacity metered
at the delivery points, but that NHEC is not required to pay PSNH for energy
purchased by its members from competitive sources. The financial impact
of this decision in the future will depend upon the implementation of
restructuring in NHEC's service area.
On March 23, 1998, NHEC requested that FERC initiate another proceeding
relating to the APRA's wholesale Fuel and Purchased Power Adjustment Clause
(FPPAC). NHEC's complaint is based on actions taken by the NHPUC concerning
PSNH's retail FPPAC charge. On November 30, 1998, FERC issued an order
rejecting most of NHEC's arguments. With respect to issues concerning the
prudence of post-retirement expenditures for MY and CY, FERC deferred any
ruling pending its decisions in hearings related to those plants. FERC
determined a hearing is necessary to determine the prudence of pre-
retirement costs related to MY and CY. In December 1998, a tentative
settlement was reached with NHEC on the remaining issues which were set
for hearing before the FERC. Under the settlement, PSNH will provide NHEC
with a credit toward current or future obligations. The amount of the credit
is not expected to be material.
In 1998, PSNH had sales to NHEC, under the APRA, of approximately $60.7
million. During 1998, NHEC paid PSNH an average of 10.8 cents per kWh for
these sales.
12. NRC Office of Investigations and U.S. Attorney Investigations and
Related Matters
The NRC's Office of Investigations (OI) has been examining various
matters at Millstone and CY, including but not limited to procedural and
technical compliance matters and employee concerns. One of these matters
was referred, and others may be referred, to the Office of the U.S. Attorney
for the District of Connecticut (U.S. Attorney) for possible criminal
prosecution. The referred matter concerned full core off-load procedures
and related matters at Millstone. On October 2, 1998, the Company was
informed that the U.S. Attorney had declined prosecution of this matter.
Also, in July 1998, the Company was informed that the U.S. Attorney's Office
had declined prosecution of issues arising from the 1996 nuclear workforce
reduction. The U.S. Attorney is also reviewing possible criminal violations
arising out of certain other activities at Millstone and CY, including its
licensed operator training programs. NU has been informed by the government
that it is a target of the investigation, but that no one in senior
management is either a target or a subject of their investigations.
The U.S. Attorney, together with the U.S. EPA, is also investigating
possible criminal violations of federal environmental laws at certain NU
facilities, including Millstone and Devon. NU has been informed by the
government that it is a target of the investigation, but that no one in
senior management is either a target or a subject of their investigations.
Management does not believe that any System company or officer has
engaged in conduct that would warrant a federal criminal prosecution. NU
intends to continue to fully cooperate with the OI and the U.S. Attorney in
their ongoing investigations.
13. NRC - Spent Fuel Pool Off-Load Practices 2.206 Petition
In August 1995, a petition was filed with the NRC under Section 2.206
of the NRC's regulations by the organization We the People and a NUSCO
employee. The petitioners maintained that NU's historic practice of off-
loading the full reactor core at Millstone 1 resulted in spent fuel pool
heat loads in excess of the pool's NRC-approved cooling capability, and
asserted that the practice was a knowing and willful violation of NRC
requirements. The petitioners also filed a supplemental petition concerning
refueling practices at Millstone 2 and 3 and Seabrook Station.
On December 26, 1996, the Acting Director of the Office of Nuclear
Reactor Regulation issued a partial decision granting, in part, the
petition. The decision concluded that the design of the spent fuel pool
and related system at Millstone 1 was adequate, and that the full core
offload practices at that unit, Millstone 3 and Seabrook were safe. The
petitioners' assertions regarding Millstone 2 were not substantiated. On
October 15, 1998, NNECO waived the five year statute of limitations with
respect to the NRC's ability to initiate a civil penalty action for a
reporting issue related to the Millstone 1 full-core offload issue. The
NRC is presently reviewing the matter and is expected to take action on
this issue in the near future.
14. Other Legal Proceedings
The following sections of Item 1. "Business" discuss additional
legal proceedings: See "Electric Industry Restructuring" and "Rates"
for information about CL&P's rate and energy adjustment clause proceedings,
various state restructuring proceedings and civil lawsuits related thereto
and NHPUC proceedings involving PSNH's franchise rights; "Electric Operations--
Transmission Access and FERC Regulatory Changes" for information about
proceedings relating to power and transmission issues; "Electric Operations--
Nuclear Generation" and "Electric Operations--Nuclear Plant Performance and
Regulatory Oversight" for information related to nuclear plant performance,
nuclear fuel enrichment pricing, high-level and low-level radioactive waste
disposal, decommissioning matters and NRC regulation; "Other Regulatory and
Environmental Matters" for information about proceedings involving surface
water and air quality, toxic substances and hazardous waste, electric and
magnetic fields, licensing of hydroelectric projects, and other matters.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No Event that would be described in response to this item occurred
with respect to NU, CL&P, PSNH, WMECO or NAEC.
PART II
Item 5. Market for the Registrants' Common Equity and Related
Shareholder Matters
NU. The common shares of NU are listed on the New York Stock Exchange.
The ticket symbol is "NU," although it is frequently presented as "Noeast
Util" and/or "NE Util" in various financial publications. The high and low
sales prices for the past two years, by quarters, are shown below.
Year Quarter High Low
1998 First $14 5/16 $11 11/16
Second 17 13 5/8
Third 17 1/16 14 3/8
Fourth 17 1/4 15 7/16
1997 First $14 1/4 $ 7 5/8
Second 9 7/8 7 3/4
Third 10 9/16 9
Fourth 13 15/16 9 1/2
As of January 29, 1999, there were 89,130 common shareholders of record
of NU. As of the same date, there were a total of 137,031,264 common shares
issued, including 6,029,984 million unallocated ESOP shares held in the ESOP
trust.
No dividends were declared on NU common shares during 1998. NU
declared and paid a quarterly dividend of $0.25 per share during the first
quarter of 1997. On March 25, 1997, the NU Board of Trustees adopted a
resolution suspending the quarterly dividends on NU's common shares,
indefinitely. The declaration of future dividends may vary depending on
capital requirements and income, as well as financial and other conditions
existing at the time.
Information with respect to dividend restrictions for NU and its
subsidiaries is contained in Item 1. Business under the caption "Financing
Program - Financing Limitations" and in Note (b) to the "Consolidated
Statements of Shareholders' Equity" on page 25 of NU's 1998 Annual Report
to Shareholders, which information is incorporated herein by reference.
CL&P, PSNH, WMECO, and NAEC. The information required by this item is
not applicable because the common stock of CL&P, PSNH, WMECO, and NAEC is
held solely by NU.
Item 6. Selected Financial Data
NU. Reference is made to information under the heading "Selected
Consolidated Financial Data" contained on page 48 of NU's 1998 Annual Report
to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the heading "Selected
Financial Data" contained on page 53 of CL&P's 1998 Annual Report, which
information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Selected
Financial Data" contained on pages 50 and 51 of PSNH's 1998 Annual Report,
which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Selected
Financial Data" contained on page 45 of WMECO's 1998 Annual Report, which
information is incorporated herein by reference.
NAEC. Reference is made to information under the heading "Selected
Financial Data" contained on page 30 of NAEC's 1998 Annual Report, which
information is incorporated herein by reference.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations; and
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
NU. Reference is made to information under the heading "Management's
Discussion and Analysis" contained on pages 12 through 19 in NU's 1998
Annual Report to Shareholders, which information is incorporated herein by
reference.
CL&P. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 41 through 52 in CL&P's 1998 Annual Report, which
information is incorporated herein by reference.
PSNH. Reference is made to information under the heading
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" contained on pages 41 through 49 in PSNH's 1998
Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" contained on pages 37 through 44 in WMECO's 1998 Annual Report,
which information is incorporated herein by reference.
NAEC. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 24 through 29 in NAEC's 1998 Annual Report, which
information is incorporated herein by reference.
Item 8. Financial Statements and Supplementary Data
NU. Reference is made to information under the headings "Company
Report," "Report of Independent Public Accountants," "Consolidated
Statements of Income," "Consolidated Statements of Comprehensive Income,"
"Consolidated Statements of Cash Flows," "Consolidated Statements of
Income Taxes," "Consolidated Balance Sheets," "Consolidated Statements of
Capitalization," "Consolidated Statements of Shareholders' Equity," "Notes
to Consolidated Financial Statements," and "Consolidated Statements of
Quarterly Financial Data" contained on pages 20 through 47 in NU's 1998
Annual Report to Shareholders, which information is incorporated herein by
reference.
CL&P. Reference is made to information under the headings
"Consolidated Balance Sheets," "Consolidated Statements of Income,"
"Consolidated Statements of Comprehensive Income," "Consolidated Statements
of Cash Flows," "Consolidated Statements of Common Stockholder's Equity,"
"Notes to Consolidated Financial Statements," "Report of Independent Public
Accountants," and "Statements of Quarterly Financial Data" contained on
pages 2 through 40 and page 53 in CL&P's 1998 Annual Report, which
information is incorporated herein by reference.
PSNH. Reference is made to information under the headings "Balance
Sheets," "Statements of Income," "Statements of Comprehensive Income,"
"Statements of Cash Flows," "Statements of Common Equity," "Notes to
Financial Statements," "Report of Independent Public Accountants," and
"Statements of Quarterly Financial Data" contained on pages 2 through 40 and
page 52 in PSNH's 1998 Annual Report, which information is incorporated
herein by reference.
WMECO. Reference is made to information under the headings
"Consolidated Balance Sheets," "Consolidated Statements of Income,"
"Consoldidated Statements of Comprehensive Income," "Consolidated Statements
of Cash Flows," "Consolidated Statements of Common Stockholder's Equity,"
"Notes to Consolidated Financial Statements," "Report of Independent Public
Accountants," and "Statements of Quarterly Financial Data" contained on
pages 2 through 36 and page 45 in WMECO's 1998 Annual Report, which
information is incorporated herein by reference.
NAEC. Reference is made to information under the headings "Balance
Sheets," "Statements of Income," "Statements of Cash Flows," "Statements of
Common Stockholder's Equity," "Notes to Financial Statements," "Report of
Independent Public Accountants," and "Statements of Quarterly Financial
Data" contained on pages 2 through 23 and page 30 in NAEC's 1998 Annual
Report which information is incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
No event that would be described in response to this item has occurred
with respect to NU, CL&P, PSNH, WMECO, or NAEC.
PART III
Item 10. Directors and Executive Officers of the Registrants
NU.
In addition to the information provided below concerning the executive
officers of NU, incorporated herein by reference is the information contained
in the sections "Proxy Statement", "Committee Composition and Responsibility",
"Common Stock Ownership of Certain Beneficial Owners", "Common Stock Ownership
of Management", "Compensation of Trustees", "Executive Compensation", "Pension
Benefits", and "Report on Executive Compensation" of the definitive proxy
statement for solicitation of proxies by NU's Board of Trustees, dated March 31,
1999, which will be filed with the Commission pursuant to Rule 14a-6 under the
Securities Exchange Act of 1934 (the Act).
First First
Positions Elected Elected
Name Held an Officer a Trustee
John H. Forsgren EVP, CFO 02/01/96 n/a
William T. Frain, Jr. OTH 02/01/94 n/a
Cheryl W. Grise' SVP, SEC, GC 06/01/91 n/a
Bruce D. Kenyon P 09/03/96 n/a
Hugh C. MacKenzie P 07/01/88 n/a
Michael G. Morris CHB, P, CEO, T 08/19/97 08/19/97
Gary D. Simon OTH 04/15/98 n/a
Lisa J. Thibdaue OTH 01/01/98 n/a
CL&P.
First First
Positions Elected Elected
Name Held an Officer a Director
John H. Forsgren EVP, CFO, D 02/01/96 06/10/96
Cheryl W. Grise' SVP, SEC, GC 06/01/91 n/a
Bruce D. Kenyon P, D 09/03/96 09/03/96
Hugh C. MacKenzie P, D 07/01/88 06/06/90
Michael G. Morris CH, D 08/19/97 08/19/97
Lisa J. Thibdaue VP 01/01/98 n/a
PSNH.
First First
Positions Elected Elected
Name Held an Officer a Director
John C. Collins D n/a 10/19/92
John H. Forsgren EVP, CFO, D 02/01/96 08/05/96
William T. Frain, Jr. P, COO, D 03/18/71 02/01/94
Cheryl W. Grise' SVP, SEC, GC 07/31/98 n/a
Bruce D. Kenyon P, D 09/03/96 11/24/97
Gerald Letendre D n/a 10/19/92
Hugh C. MacKenzie D n/a 02/01/94
Michael G. Morris CH, CEO, D 08/19/97 08/19/97
Jane E. Newman D n/a 10/19/92
Lisa J. Thibdaue VP 01/01/98 n/a
WMECO.
First First
Positions Elected Elected
Name Held an Officer a Director
John H. Forsgren EVP, CFO, D 02/01/96 06/10/96
Cheryl W. Grise' SVP, SEC, AC, GC 06/01/91 n/a
Bruce D. Kenyon P, D 09/03/96 09/03/96
Hugh C. MacKenzie P, D 07/01/88 06/06/90
Michael G. Morris CH, D 08/19/97 08/19/97
Lisa J. Thibdaue VP 01/01/98 n/a
NAEC.
First First
Positions Elected Elected
Name Held an Officer a Director
Ted C. Feigenbaum EVP, CNO 10/21/91 n/a
John H. Forsgren EVP, CFO, D 02/01/96 11/01/97
Cheryl W. Grise' SVP, SEC, GC 10/21/91 n/a
Bruce D. Kenyon P, CEO, D 09/03/96 09/03/96
Michael G. Morris CH, D 08/19/97 08/19/97
Key:
AC - Assistant Clerk EVP - Executive Vice President
CAO - Chief Administrative Officer GC - General Counsel
CEO - Chief Executive Officer OTH - Executive Officer of NU system
CFO - Chief Financial Officer P - President
CH - Chairman SEC - Secretary
CHB - Chairman of the Board SVP - Senior Vice President
COO - Chief Operating Officer T - Trustee
D - Director VP - Vice President
Name Age Business Experience During Past 5 Years
John C. Collins (1) 53 Chief Executive Officer, The Hitchcock
Clinic, Dartmouth - Hitchcock Medical
Center since 1977.
Ted C. Feigenbaum (2) 48 Executive Vice President and Chief Nuclear
Officer of NAEC since February, 1996;
previously Senior Vice President of NAEC
since 1991; Senior Vice President and Chief
Nuclear Officer of PSNH June, 1992 to August,
1992; President and Chief Executive Officer -
New Hampshire Yankee Division of PSNH
October, 1990 to June, 1992 and Chief Nuclear
Production Officer of PSNH January, 1990 to
June, 1992.
John H. Forsgren (3) 52 Executive Vice President and Chief
Financial Officer of NU, CL&P, PSNH, WMECO
and NAEC since February, 1996; previously
Managing Director of Chase Manhattan Bank
from 1995 to 1996 and Senior Vice President
of The Walt Disney Company from 1990 to 1994.
William T. Frain, Jr.(4) 57 President and Chief Operating Officer of PSNH
since February, 1994; previously Senior Vice
President of PSNH from 1992 to 1994.
Cheryl W. Grise' 46 Senior Vice President, Secretary and
General Counsel of NU, CL&P, PSNH and NAEC and
Senior Vice President, Secretary, Assistant
Clerk and General Counsel of WMECO since July,
1998; previously Senior Vice President and
Chief Administrative Officer of CL&P, PSNH
and NAEC, and Senior Vice President of WMECO
from December, 1995 to July 1998; previously
Senior Vice President-Human Resources and
Administrative Services of CL&P, WMECO and
NAEC from 1994 to 1995 and Vice President-
Human Resources of CL&P, WMECO and NAEC from
1992 to 1994.
Bruce D. Kenyon (5) 56 President and Chief Executive Officer of NAEC
since September, 1996 and President-Generation
Group of NU, CL&P, PSNH and WMECO since March,
1999; previously President-Nuclear Group of NU,
CL&P, PSNH and WMECO from September, 1996 to
March, 1999; previously President and Chief
Operating Officer of South Carolina Electric
and Gas Company from 1990 to 1996.
Gerald Letendre 57 President, Diamond Casting & Machine Co., Inc.
since 1972.
Hugh C. MacKenzie (6) 56 President-Retail Business Group of NU since
February, 1996 and President of CL&P and WMECO
since January, 1994; previously Senior Vice
President-Customer Service Operations of CL&P
and WMECO from 1990 to 1994.
Michael G. Morris (7) 52 Chairman of the Board, President and Chief
Executive Officer of NU, Chairman and Chief
Executive Officer of PSNH, and Chairman of
CL&P, NAEC and WMECO since August, 1997;
previously President and Chief Executive
Officer of Consumers Power Company from 1994
to 1997 and Executive Vice President and Chief
Operating Officer of Consumers Power Company
from 1992 to 1994.
Jane E. Newman (8) 53 Managing Director, The Commerce Group since
January 10, 1999; formerly Dean, Whittemore
School of Business and Economics of the
University of New Hampshire from January, 1998
to January 5, 1999; previously Executive Vice
President and Director, Exeter Trust Company
from 1995 to 1997 and President, Coastal
Broadcasting Corporation from 1992 to 1995.
Gary D. Simon (9) 50 Senior Vice President-Strategy and Development
of Northeast Utilities Service Company since
April, 1998.
Lisa J. Thibdaue 45 Vice President-Rates, Regulatory Affairs and
Compliance of CL&P, PSNH and WMECO since
January, 1998; previously Executive Director,
Rates and Regulatory Affairs, Consumers Power
Company from 1996 to 1998 and Director of
Regulatory Affairs, Consumers Power Company
from 1991 to 1996.
(1) Director of Blue Cross and Blue Shield of Vermont, Fleet Bank - New
Hampshire, Hamden Assurance Company Limited and the Business and
Industry Association of New Hampshire.
(2) Director of Connecticut Yankee Atomic Power Company, Maine Yankee
Atomic Power Company, Vermont Yankee Nuclear Power Corporation, and
Yankee Atomic Electric Company.
(3) Director of Connecticut Yankee Atomic Power Company and NorthEast Optic
Network, Inc.
(4) Director of the Business and Industry Association of New Hampshire and
the Greater Manchester Chamber of Commerce; Trustee of Saint Anselm
College.
(5) Trustee of Columbia College and Director of Connecticut Yankee Atomic
Power Company.
(6) Director of Connecticut Yankee Atomic Power Company.
(7) Director of Connecticut Yankee Atomic Power Company.
(8) Director of Exeter Trust Company, Perini Corporation and Consumers
Water Company.
(9) Director of NorthEast Optic Network, Inc.
There are no family relationships between any director or executive
officer and any other director or executive officer of NU, CL&P, PSNH, WMECO
or NAEC.
Item 11. Executive Compensation
NU.
Incorporated herein by reference is the information contained in the
sections "Executive Compensation", "Summary Compensation Table", "Option/SAR
Grants in Last Fiscal Year", "Fiscal Year-End Option/SAR Values", "Pension
Benefits", and "Report on Executive Compensation" of the definitive proxy
statement for solicitation of proxies by NU, dated March 31, 1999, which
will be filed with the Commission pursuant to Rule 14a-6 under the Act.
CL&P, PSNH, WMECO and NAEC SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
The following tables present the cash and non-cash compensation received by the Chief Executive Officer and the next
four highest paid executive officers of CL&P, PSNH, WMECO and NAEC, in accordance with rules of the Securities and
Exchange Commission (SEC):
Annual Compensation Long Term Compensation
Awards Payouts
Securities Long
Other Restrict- Underlying Term All
Annual ed Stock Options/ Incentive Other
Compensa- Award(s) Stock Program Compen-
Name and Salary tion($) ($) Appreciation Payouts sation($)
Principal Position Year ($) Bonus($) (Note 1) (Note 2) Rights (#) ($) (Note 3)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Michael G. Morris 1998 757,692 891,000 134,376 255,261 64,574 - 4,800
Chairman of the
Board, President 1997 258,333 1,350,000 - - 500,000 - -
and Chief Executive
Officer 1996 - - - - - - -
Bruce D. Kenyon 1998 500,000 300,000 - - 21,236 - 4,800
President -
Nuclear Group 1997 500,000 300,000 - 306,522 139,745 - -
1996 144,231 400,000 - 499,762 - - -
John H. Forsgren 1998 373,077 - - - 73,183 - 104,800
Executive Vice
President and 1997 350,000 - - 378,787 184,382 - 50,000
Chief Financial
Officer 1996 305,577 - 62,390 80,380 - - -
Hugh C. MacKenzie 1998 270,000 - - - 15,496 37,652 7,500
President - Retail
Business Group 1997 270,000 - - 189,778 142,549 26,998 4,800
1996 264,904 - - - - 19,834 7,500
Cheryl W. Grise' 1998 209,231 - - - 12,916 20,720 6,123
Senior Vice
President, 1997 200,000 - - 119,109 89,468 15,188 4,800
Secretary and
General Counsel 1996 200,000 - - - - 10,937 6,000
(in CL&P, PSNH and
WMECO tables only)
Ted C. Feigenbaum 1998 260,000 48,750 - 40,961 10,044 20,723 7,800
Executive Vice
President and 1997 260,000 30,119 - - - 21,498 4,800
Chief Nuclear Officer
of NAEC 1996 248,858 - - - - 14,770 7,222
(in NAEC table only)
</TABLE>
<TABLE>
<CAPTION>
OPTION/SAR GRANTS IN LAST FISCAL YEAR
Individual Grants Grant Date Value
Number of
Securities % of Total
Underlying Options/SARs Grant Date
Options/SARs Granted to Exercise or Present
Granted (#) Employees Base Price Expiration Value ($)
Name (Note 4) in Fiscal Year ($/sh) Date (Note 4)
<S> <C> <C> <C> <C> <C>
Michael G. Morris 64,574 8.18% 16.3125 5/12/2008 255,417
Bruce D. Kenyon 21,236 2.69% 16.3125 5/12/2008 84,098
John H. Forsgren 73,183 9.28% 16.3125 5/12/2008 289,599
Hugh C. MacKenzie 15,496 1.96% 16.3125 5/12/2008 61,367
Cheryl W. Grise' 12,916 1.64% 16.3125 5/12/2008 51,150
Ted C. Feigenbaum 10,044 1.28% 16.3125 5/12/2008 39,776
</TABLE>
<TABLE>
<CAPTION>
FY-END OPTION/SAR VALUES
Number of Securities Value of Unexercised
Underlying Unexercised In-the-Money
Options/SARS Options/SARs
at Fiscal Year-End (#) at Fiscal Year-End ($)
Exercisable Unexercisable Exercisable Unexercisable
<S> <C> <C> <C> <C>
Michael G. Morris 21,524 543,050 0 3,187,500
Bruce D. Kenyon 7,079 150,919 0 442,445
John H. Forsgren 24,394 229,234 0 583,766
Hugh C. MacKenzie 5,166 149,836 0 451,323
Cheryl W. Grise' 4,306 96,167 0 283,260
Ted C. Feigenbaum 3,348 6,696 0 0
</TABLE>
Notes to Summary Compensation and Option/SAR Grants Tables:
1. Other annual compensation for Mr. Morris consists of 1998 relocation
expense reimbursements, and for Mr. Forsgren consists of 1996 tax
payments on a restricted stock award.
2. The aggregate restricted stock holdings by the five individuals named
in the table were, at December 31, 1998, 137,719 shares with a value of
$2,203,504 (CL&P, PSNH and WMECO) and 130,699 shares with a value of
$2,091,184 (NAEC). Awards shown for 1997 (except for additional awards
made for Messrs. Kenyon and Forsgren - see below) were restricted stock
unit grants under the Stock Price Recovery Incentive Program made on
January 1, 1997 and vested on January 4, 1999. Mr. Kenyon also
received 12,200 Restricted Stock Units on July 8, 1997, with a value
at date of grant of $120,475, which will vest, as will the restricted
shares granted to him in 1996, when Millstone Station is removed from
the Nuclear Regulatory Commission's "watch list," provided that this
occurs within three years of Mr. Kenyon's commencement of employment
(September 3, 1996) and the Systematic Assessment of Licensee
Performance and Institute of Nuclear Power Operations ratings of
Seabrook Station have not materially changed from their 1996 levels,
or, if earlier, when he is transferred to a new position at the Company
or an affiliate, as defined. Mr. Forsgren also received 13,500
Restricted Stock Units on July 8, 1997, with a value at grant of
$133,313, which vested, as did the restricted stock granted to him
in 1996, on January 1, 1999. Any dividends paid on restricted stock
and units are reinvested into additional restricted stock and units,
respectively, subject to the same vesting schedule.
3. "All Other Compensation" consists of employer matching contributions
under the Northeast Utilities Service Company 401k Plan, generally
available to all eligible employees, special matching contributions
under the Northeast Utilities Deferred Compensation Plan for Executives
(Mr. Morris: $17,931, Mr. Kenyon: $10,000, Mr. MacKenzie: $2,700, Mrs.
Grise': $1,323, Mr. Feigenbaum: $3,000), and in the case of Mr.
Forsgren, retention payments ($100,000 in 1998, $50,000 in 1997).
4. These options were granted on May 12, 1998 under the Incentive Plan
(except for Mr. Morris's options, and 45,919 of Mr. Forsgren's options,
which were granted May 19, 1998). All options granted vest one-third on
grant date, one-third on May 12, 1999 and one-third on May 12, 2000.
Valued using the Black-Scholes option pricing model, with the following
assumptions: Volatility: 34.97 percent (36 months of monthly data);
Risk-free rate: 5.88 percent; Dividend yield: 5.54 percent (36 months
of monthly data); Exercise date: May 12, 2008.
COMPENSATION COMMITTEE
REPORT ON EXECUTIVE COMPENSATION
Overview and Strategy
The Compensation Committee of the Board of Trustees (the Committee) is the
administrator of executive compensation for the executives of the Northeast
Utilities system (the Company) with authority to establish and interpret the
terms of the Company's executive salary and incentive programs. The goal of
the Committee's executive compensation program for 1998 was to provide a
competitive compensation package to enable the Company to attract and retain
key executives both during this critical turnaround period for the Company
and with an eye towards the future in a more competitive environment. The
Committee further sought to align executive interests with those of Northeast
Utilities' shareholders and with Company performance by increased use of share-
based incentives.
To help achieve these goals, the Committee drew upon information from a
variety of sources, including compensation consultants, utility and general
industry surveys, and other publicly available information, including proxy
statements. In 1998, the Company's comparison groups for purposes of executive
compensation consisted of a consultant's database of roughly 700 companies from
a broad variety of industries, a consultant's database of over 90 electric and
combination electric and gas utilities, and a smaller group of ten electric
utilities whose operating characteristics were substantially similar to those
of the Company in terms of generation mix and customer size. Nine of the ten
companies are included in the Standard & Poor's (S&P) Electric Companies Index,
which is the index used in the share performance chart shown in the NU Proxy
Statement.
Base Salary
The Committee sets base salary ranges for all executive officers and sets
the annual base salary for each executive officer except for the Chief Executive
Officer (CEO), whose base salary is set by the Board of Trustees following a
recommendation by the Committee. In 1998, the Committee reviewed the base
salary levels of the Company's entire officer group against those of the 90
utility market comparison group with a goal of targeting aggregate officer base
salary to the median. The Committee periodically adjusts officers' base
salaries to reflect considerations such as changes in responsibility, market
sensitivity, individual performance and internal equity. The CEO's base salary
was increased by 3.33 percent in 1998 based on the market review and the
Committee's judgment as to his past and expected future performance.
Stock Price Recovery Incentive Program
During 1996, the Committee established a special Stock Price Recovery
Incentive Program for eight senior officers, including the four executive
officers listed in the Summary Compensation Table other than the CEO, in lieu
of other executive incentive programs for 1996-1998. The purpose of the program
was to focus these senior officers on achieving fundamental business goals
relative to the challenges of nuclear operations and industry restructuring,
with a net effect of advancing shareholder interests through share price
recovery. Awards under the program vested on January 1, 1999, in the form
of common shares and stock appreciation rights.
Annual Incentive Awards
The Committee established an Annual Incentive Bonus Program during 1998 for
officers not participating in the Stock Price Recovery Incentive Program. The
bonus payout target was 80 percent of base salary for the CEO, and varied from
20 to 25 percent of base salary for those officers that did not participate in
the Stock Price Recovery Incentive Program. The Annual Incentive Bonus Program
was designed to calculate actual aggregate payouts based on the Company's
performance against an earnings per share goal. Individual awards were made
from this bonus pool in cash in February, 1999 and for participants other
than the CEO were based upon individual performance as measured against
pre-established individual goals. The CEO received a cash award under this
program at his target level. Based on Company performance during 1998, the
Board also approved an award of common shares for the CEO having a value equal
to 35 percent of his base salary.
Long-Term Incentive Grants
Long-term incentive grants were made in May 1998 to each executive officer
and other officers and key employees of the Company. The Committee targeted
these awards such that the total of base pay, target annual incentive awards,
and long-term incentive awards for the officer group would be at the 75th
percentile of the 90 utility market comparison group. Except for participants
in the Stock Price Recovery Incentive Program, one-half of the grants'
intended value was made in restricted stock and one-half was made in stock
options. Grants under this program to participants in the Stock Price Recovery
Incentive Program were reduced to reflect their participation in that program
and were made entirely in stock options. The CEO's grant was targeted at 60
percent of base salary, as required by his employment agreement.
Long Term Incentive Payouts
During 1998, the Committee made awards under the 1995-1997 long-term
incentive program. Awards, in common shares, were based on the Company's
relative ranking against a group of electric utilities with respect to
shareholder return and cost of service. Achievement of goals was less than
target and resulted in awards that were 49.5 percent of target.
Internal Revenue Service Limitation on Deductibility of Executive
Compensation
The Committee believes that its compensation program will adequately
respond to issues raised by the deductibility cap placed on executive salaries
by Section 162(m) of the Internal Revenue Code because of the use of stock
options and qualified performance-based compensation in Company incentive
programs.
Dated: February 23, 1999
Respectfully submitted,
Robert E. Patricelli, Chairman
William J. Pape II, Vice Chairman
Cotton Mather Cleveland
E. Gail de Planque
Elizabeth T. Kennan
John F. Swope
PENSION BENEFITS
The following table shows the estimated annual retirement
benefits payable to an executive officer of Northeast Utilities upon
retirement, assuming that retirement occurs at age 65 and that the
officer is at that time not only eligible for a pension benefit under
the Northeast Utilities Service Company Retirement Plan (the
Retirement Plan) but also eligible for the make-whole benefit and the
target benefit under the Supplemental Executive Retirement Plan for
Officers of Northeast Utilities System Companies (the Supplemental
Plan). The Supplemental Plan is a non-qualified pension plan
providing supplemental retirement income to system officers. The
make-whole benefit under the Supplemental Plan, available to all
officers, makes up for benefits lost through application of certain
tax code limitations on the benefits that may be provided under the
Retirement Plan, and includes as "compensation" awards under the
executive incentive plans and deferred compensation (as earned). The
target benefit further supplements these benefits and is available to
officers at the Senior Vice President level and higher who are
selected by the Board of Trustees to participate in the target
benefit and who remain in the employ of Northeast Utilities companies
until at least age 60 (unless the Board of Trustees sets an earlier
age).
The benefits presented below are based on a straight life
annuity beginning at age 65 and do not take into account any
reduction for joint and survivorship annuity payments. Final average
compensation for purposes of calculating the target benefit is the
highest average annual compensation of the participant during any 36
consecutive months compensation was earned. Compensation taken into
account under the target benefit described above includes salary,
bonus, restricted stock awards, and long-term incentive payouts shown
in the Summary Compensation Table, but does not include employer
matching contributions under the 401k Plan. In the event that an
officer's employment terminates because of disability, the retirement
benefits shown above would be offset by the amount of any disability
benefits payable to the recipient that are attributable to
contributions made by Northeast Utilities and its subsidiaries under
long term disability plans and policies.
ANNUAL BENEFIT
Final Average Years of Credited Service
Compensation
15 20 25 30 35
$200,000 $72,000 $96,000 $120,000 $120,000 $120,000
250,000 90,000 120,000 150,000 150,000 150,000
300,000 108,000 144,000 180,000 180,000 180,000
350,000 126,000 168,000 210,000 210,000 210,000
400,000 144,000 192,000 240,000 240,000 240,000
450,000 162,000 216,000 270,000 270,000 270,000
500,000 180,000 240,000 300,000 300,000 300,000
600,000 216,000 288,000 360,000 360,000 360,000
700,000 252,000 336,000 420,000 420,000 420,000
800,000 288,000 384,000 480,000 480,000 480,000
900,000 324,000 432,000 540,000 540,000 540,000
1,000,000 360,000 480,000 600,000 600,000 600,000
1,100,000 396,000 528,000 660,000 660,000 660,000
1,200,000 432,000 576,000 720,000 720,000 720,000
Each of the executive officers of Northeast Utilities named in
the Summary Compensation Table is currently eligible for a target
benefit, except Messrs. Morris and Kenyon, whose Employment
Agreements provide specially calculated retirement benefits, based on
their previous arrangements with CMS Energy/Consumers Energy Company
(CMS) and South Carolina Electric and Gas, respectively. Mr.
Morris's agreement provides that upon retirement after reaching the
fifth anniversary of his employment date with the Company (or upon
disability or termination without cause or following a change in
control, as defined, of the Company) he will be entitled to receive a
special retirement benefit calculated by applying the benefit formula
of the CMS Supplemental Executive Retirement Plan to all compensation
earned from the Company and to all service rendered to the Company
and CMS. If Mr. Kenyon retires with at least three years but less
than five years of service with the Company, he will be deemed to
have five years of service for purpose of his special retirement
benefit, and if he retires with at least three years of service with
the Company, he will receive a lump sum payment of $500,000.
As of December 31, 1998, the five current executive officers
named in the Summary Compensation Table had the following years of
credited service for purposes of calculating target benefits under
the Supplemental Plan (or in the case of Messrs. Morris and Kenyon,
for purposes of calculating the special retirement benefits under
their respective Employment Agreements): Mr. Morris - 10, Mr. Kenyon
- - 2, Mr. Forsgren - 2, Mr. MacKenzie - 33, and for CL&P, WMECO and
PSNH, Mrs. Grise' - 18, and for NAEC, Mr. Feigenbaum - 12. Assuming
that retirement were to occur at age 65 for these officers,
retirement would occur with 23, 11, 15, 41, 37, and 29 years of
credited service, respectively.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS
Northeast Utilities Service Company (NUSCO) has entered into
employment agreements (the Officer Agreements) with each of the named
executive officers. The Officer Agreements are also binding on
Northeast Utilities and on each majority-owned subsidiary of
Northeast Utilities.
Each Officer Agreement obligates the officer to perform such
duties as may be directed by the NUSCO Board of Directors or the
Northeast Utilities Board of Trustees, protect the Company's
confidential information, and refrain, while employed by the Company
and for a period of time thereafter, from competing with the Company
in a specified geographic area. Each Officer Agreement provides that
the officer's base salary will not be reduced below certain levels
without the consent of the officer, and that the officer will
participate in specified benefits under the Supplemental Executive
Retirement Plan or other supplemental retirement programs (see
Pension Benefits, above) and/or in certain executive incentive
programs at specified incentive opportunity levels.
Each Officer Agreement provides for a specified employment term
and for automatic one-year extensions of the employment term unless
at least six months' notice of non-renewal is given by either party.
The employment term may also be ended by the Company for "cause", as
defined, at any time (in which case no supplemental retirement
benefit, if any, shall be due), or by the officer on thirty days'
prior written notice for any reason. Absent "cause", the Company may
remove the officer from his or her position on sixty days' prior
written notice, but in the event the officer is so removed and signs
a release of all claims against the Company, the officer will receive
one or two years' base salary and annual incentive payments,
specified employee welfare and pension benefits, and vesting of stock
appreciation rights, options and restricted stock.
Under the terms of an Officer Agreement, upon any termination of
employment following a change of control, as defined, between (a) the
earlier of the date shareholders approve a change of control
transaction or a change of control transaction occurs and (b) the
earlier of the date, if any, on which the Board of Trustees abandons
the transaction or the date two years following the change of
control, if the officer signs a release of all claims against the
Company the officer will be entitled to certain payments including a
multiple (not to exceed four) of annual base salary, annual incentive
payments, specified employee welfare and pension benefits, and
vesting of stock appreciation rights, options and restricted stock.
Certain of the change in control provisions may be modified by the
Board of Trustees prior to a change in control, on at least two
years' notice to the affected officer(s).
Besides the terms described above, the Officer Agreements of
Messrs. Morris, Kenyon, Forsgren and Feigenbaum provide for a
specified salary, cash, restricted stock and/or stock options upon
employment, special incentive programs and/or special retirement
benefits. See Summary Compensation Table and Pension Benefits,
above, for further description of these provisions. Mr. Kenyon's
Officer Agreement also provides for a special short term incentive
compensation program in lieu of a portion of the Stock Price Recovery
Incentive Program. Under this special program Mr. Kenyon is eligible
to receive a payment up to 100 percent of base salary depending on
his fulfillment of certain incentive goals for each of the years
ending August 31, 1997 and August 31, 1998, and for the 16 month
period ending December 31, 1999.
The descriptions of the various agreements set forth above are
for purpose of disclosure in accordance with the proxy and other
disclosure rules of the SEC and shall not be controlling on any
party; the actual terms of the agreements themselves determine the
rights and obligations of the parties.
Item 12. Security Ownership of Certain Beneficial Owners and Management
NU.
Incorporated herein by reference is the information contained in
the sections "Common Stock Ownership of Certain Beneficial Owners",
"Common Stock Ownership of Management", "Compensation of Trustees",
"Executive Compensation", "Pension Benefits", and "Report on
Executive Compensation" of the definitive proxy statement for
solicitation of proxies by NU, dated March 31, 1999 which will be
filed with the Commission pursuant to Rule 14a-6 under the Act.
CL&P, PSNH, WMECO and NAEC.
NU owns 100% of the outstanding common stock of registrants
CL&P, PSNH, WMECO and NAEC. As of February 25, 1999, the Directors
and Executive Officers of CL&P, PSNH, WMECO and NAEC beneficially
owned the number of shares of each class of equity securities of NU
listed below. No equity securities of CL&P, PSNH, WMECO or NAEC are
owned by the Directors and Executive Officers of CL&P, PSNH, WMECO
and NAEC. Unless otherwise noted, each Director and Executive
Officer of CL&P, PSNH, WMECO and NAEC has sole voting and investment
power with respect to the listed shares.
CL&P, PSNH, WMECO, and NAEC DIRECTORS AND EXECUTIVE OFFICERS
Title of Amount and Nature of Percent of
Class Name Beneficial Ownership Class (1)
NU Common John C. Collins 0
NU Common Ted C. Feigenbaum 12,273 (2)
NU Common John H. Forsgren 43,995 (3)
NU Common William T. Frain, Jr. 11,503 (4)
NU Common Cheryl W. Grise' 22,008 (5)
NU Common Bruce D. Kenyon 60,133 (6)
NU Common Gerald Letendre 0
NU Common Hugh C. MacKenzie 23,782 (7)
NU Common Michael G. Morris 72,566 (8)
NU Common Jane E. Newman 0
Amount beneficially owned by Directors and Executive Officers as a group:
Amount and Nature of
Company Number of Persons Beneficial Ownership
CL&P 6 248,904 (9)
PSNH 10 260,407 (10)
WMECO 6 248,904 (9)
NAEC 7 261,177 (11)
(1) As of February 25, 1999 there were 137,120,486 common shares of
NU outstanding. The percentage of such shares beneficially
owned by any Director or Executive Officer, and by all
Directors and Executive Officers of CL&P, PSNH, WMECO and NAEC
as a group, does not exceed one percent.
(2) These shares include 3,348 shares that could be acquired by Mr.
Feigenbaum pursuant to currently exercisable options. These
shares also include 3,596 restricted shares as to which Mr.
Feigenbaum has voting but no investment power.
(3) These shares include 24,394 shares that could be acquired by
Mr. Forsgren pursuant to currently exercisable options. These
shares also include 8,213 restricted shares as to which Mr.
Forsgren has voting but no investment power.
(4) These shares include 2,395 shares that could be acquired by Mr.
Frain pursuant to currently exercisable options. These shares
also include 3,524 restricted shares as to which Mr. Frain has
voting but no investment power.
(5) Mrs. Grise' shares voting and investment power with respect to
259 of these shares, which are held by her husband as custodian
for their minor children. These shares also include 4,306
shares that could be acquired by Mrs. Grise' pursuant to
currently exercisable options. These shares also include 4,928
restricted shares as to which Mrs. Grise' has voting but no
investment power.
(6) These shares also include 7,079 shares that could be acquired
by Mr. Kenyon pursuant to currently exercisable options. These
shares also include 39,544 restricted shares as to which Mr.
Kenyon has voting but no investment power.
(7) These shares also include 5,166 shares that could be acquired
by Mr. MacKenzie pursuant to currently exercisable options.
These shares also include 4,928 restricted shares as to which
Mr. MacKenzie has voting but no investment power.
(8) Mr. Morris shares voting and investment power with respect to
1,333 of these shares with his wife. These shares also include
21,524 shares that could be acquired by Mr. Morris pursuant to
currently exercisable options. These shares also include
34,100 restricted shares as to which Mr. Morris has voting but
no investment power.
(9) Included in the group total are 2,511 shares that could be
acquired by executive officers other than the named executive
officers pursuant to currently exercisable options. The group
total also includes 3,308 restricted shares as to which
executive officers other than the named executive officers have
voting but no investment power.
(10) Included in the group total are 4,906 shares that could be
acquired by executive officers other than the named executive
officers pursuant to currently exercisable options. The group
total also includes 6,832 restricted shares as to which
executive officers other than the named executive officers have
voting but no investment power.
(11) Included in the group total are 5,859 shares that could be
acquired by executive officers other than the named executive
officers pursuant to currently exercisable options. The group
total also includes 6,898 restricted shares as to which
executive officers other than the named executive officers have
voting but no investment power.
Item 13. Certain Relationships and Related Transactions
NU.
Incorporated herein by reference is the information contained in
the section "Certain Relationships and Related Transactions" of the
definitive proxy statement for solicitation of proxies by NU's Board
of Trustees, dated March 31, 1999, which will be filed with the
Commission pursuant to Rule 14a-6 under the Act.
CL&P, PSNH, WMECO and NAEC.
No relationships or transactions that would be described in
response to this item exist now or existed during 1998 with respect
to CL&P, PSNH, WMECO and NAEC.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a) 1. Financial Statements:
The Report of Independent Public Accountants and financial
statements of NU, CL&P, PSNH, WMECO and NAEC are hereby
incorporated by reference and made a part of this report
(see "Item 8. Financial Statements and Supplementary Data").
Report of Independent Public Accountants
on Schedules S-1
Consent of Independent Public Accountants S-3
2. Schedules:
Financial Statement Schedules for NU (Parent),
NU and Subsidiaries, CL&P and Subsidiaries,
PSNH and WMECO and Subsidiary are listed in
the Index to Financial Statements Schedules S-4
3. Exhibits Index E-1
(b) Reports on Form 8-K:
NU and CL&P filed 8-Ks dated January 28, 1999 with
the SEC on January 29, 1999. This 8-K filing
disclosed the details and the impacts of the DPUC
January 19, 1999 draft rate decision.
NORTHEAST UTILITIES
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
NORTHEAST UTILITIES
(Registrant)
Date: March 9, 1999 By /s/ Michael G. Morris
Michael G. Morris
Chairman of the Board,
President and
Chief Executive 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.
Date Title Signature
March 9, 1999 Chairman of the Board, /s/ Michael G. Morris
President and Michael G. Morris
Chief Executive Officer
and a Trustee
March 9, 1999 Executive Vice /s/ John H. Forsgren
President and Chief John H. Forsgren
Financial Officer
March 9, 1999 Vice President and /s/ John J. Roman
Controller John J. Roman
March 9, 1999 Trustee /s/ Cotton M. Cleveland
Cotton M. Cleveland
Trustee
William F. Conway
March 9, 1999 Trustee /s/ E. Gail de Planque
E. Gail de Planque
March 9, 1999 Trustee /s/ Elizabeth T. Kennan
Elizabeth T. Kennan
March 9, 1999 Trustee /s/ William J. Pape II
William J. Pape II
March 9, 1999 Trustee /s/ Robert E. Patricelli
Robert E. Patricelli
March 9, 1999 Trustee /s/ John F. Swope
John F. Swope
March 9, 1999 Trustee /s/ John F. Turner
John F. Turner
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY
(Registrant)
Date: March 9, 1999 By /s/ Michael G. Morris
Michael G. Morris
Chairman
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.
Date Title Signature
March 9, 1999 Chairman and /s/ Michael G. Morris
a Director Michael G. Morris
March 9, 1999 President and /s/ Hugh C. MacKenzie
a Director Hugh C. MacKenzie
March 9, 1999 Executive Vice /s/ John H. Forsgren
President and John H. Forsgren
Chief Financial
Officer and a
Director
March 9, 1999 Vice President /s/ John J. Roman
and Controller John J. Roman
March 9, 1999 Director /s/ Bruce D. Kenyon
Bruce D. Kenyon
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
(Registrant)
Date: March 9, 1999 By /s/ Michael G. Morris
Michael G. Morris
Chairman and
Chief Executive 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.
Date Title Signature
March 9, 1999 Chairman and Chief /s/ Michael G. Morris
Executive Officer Michael G. Morris
and a Director
March 9, 1999 President and /s/ William T. Frain, Jr.
Chief Operating William T. Frain, Jr.
Officer and
a Director
March 9, 1999 Executive Vice /s/ John H. Forsgren
President and John H. Forsgren
Chief Financial
Officer and a
Director
March 9, 1999 Vice President /s/ John J. Roman
and Controller John J. Roman
March 9, 1999 Director /s/ John C. Collins
John C. Collins
March 9, 1999 Director /s/ Bruce D. Kenyon
Bruce D. Kenyon
March 9, 1999 Director /s/ Gerald Letendre
Gerald Letendre
March 9, 1999 Director /s/ Hugh C. MacKenzie
Hugh C. MacKenzie
March 9, 1999 Director /s/ Jane E. Newman
Jane E. Newman
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
(Registrant)
Date: March 9, 1999 By /s/ Michael G. Morris
Michael G. Morris
Chairman
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.
Date Title Signature
March 9, 1999 Chairman and /s/ Michael G. Morris
a Director Michael G. Morris
March 9, 1999 President and /s/ Hugh C. MacKenzie
a Director Hugh C. MacKenzie
March 9, 1999 Executive Vice /s/ John H. Forsgren
President and John H. Forsgren
Chief Financial
Officer and a
Director
March 9, 1999 Vice President /s/ John J. Roman
and Controller John J. Roman
March 9, 1999 Director /s/ Bruce D. Kenyon
Bruce D. Kenyon
NORTH ATLANTIC ENERGY CORPORATION
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
NORTH ATLANTIC ENERGY CORPORATION
(Registrant)
Date: March 9, 1999 By /s/ Michael G. Morris
Michael G. Morris
Chairman
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.
Date Title Signature
March 9, 1999 Chairman and /s/ Michael G. Morris
a Director Michael G. Morris
March 9, 1999 President and /s/ Bruce D. Kenyon
Chief Executive Bruce D. Kenyon
Officer and
a Director
March 9, 1999 Executive Vice /s/ John H. Forsgren
President and John H. Forsgren
Chief Financial
Officer and a
Director
March 9, 1999 Vice President /s/ John J. Roman
and Controller John J. Roman
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES
We have audited in accordance with generally accepted auditing
standards, the financial statements included in Northeast Utilities'
annual report to shareholders and The Connecticut Light and Power
Company's and Western Massachusetts Electric Company's annual reports,
incorporated by reference in this Form 10-K, and have issued our
reports thereon dated February 23, 1999. Our audit was made for the
purpose of forming an opinion on the basic financial statements taken
as a whole. The schedules listed in the accompanying Index to
Financial Statements Schedules are the responsibility of the
companies' management and are presented for purposes of complying with
the Securities and Exchange Commission's rules and are not a required
part of the basic financial statements. These schedules have been
subjected to the auditing procedures applied in the audit of the basic
financial statements and, in our opinion, fairly state in all material
respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Hartford, Connecticut
February 23, 1999
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES
We have audited in accordance with generally accepted auditing
standards, the financial statements included in North Atlantic Energy
Corporation's and Public Service Company of New Hampshire's annual
reports, incorporated by reference in this Form 10-K and have issued
our reports thereon dated February 23, 1999. Our reports included an
explanatory paragraph regarding the existence of conditions which
raise substantial doubt about the companies' abilities to continue as
going concerns. Our audit was made for the purpose of forming an
opinion on the basic financial statements taken as a whole. The
schedules listed in the accompanying Index to Financial Statements
Schedules are the responsibility of the companies' management and are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not a required part of the basic financial
statements. These schedules have been subjected to the auditing
procedures applied in the audit of the basic financial statements and,
in our opinion, fairly state in all material respects the financial
data required to be set forth therein in relation to the basic
financial statements taken as a whole.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Hartford, Connecticut
February 23, 1999
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports included (or incorporated by reference)
in this Form 10-K, into the Company's previously filed Registration
Statements No. 33-55279 of The Connecticut Light and Power Company,
No. 33-56537 of CL&P Capital, LP and No. 33-34622, No. 33-44814, No.
33-63023, No. 33-40156, No. 333-52413, and No. 338-52415 of Northeast
Utilities.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Hartford, Connecticut
March 16, 199
INDEX TO FINANCIAL STATMENTS SCHEDULES
Schedule
I. Financial Information of Registrant:
Northeast Utilities (Parent) Balance
Sheets 1998 and 1997 S-5
Northeast Utilities (Parent) Statements
of Income 1998, 1997, and 1996 S-6
Northeast Utilities (Parent) Statements
of Cash Flows 1998, 1997, and 1996 S-7
II. Valuation and Qualifying Accounts and Reserves
1998, 1997, and 1996:
Northeast Utilities and Subsidiaries S-8 - S-10
The Connecticut Light and Power Company
and Subsidiaries S-11 - S-13
Public Service Company of New Hampshire S-14 - S-16
Western Massachusetts Electric Company
and Subsidiary S-17 - S-19
All other schedules of the companies' for which provision is made
in the applicable regulations of the Securities and Exchange
Commission are not required under the related instructions or are not
applicable, and therefore have been omitted.
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
AT DECEMBER 31, 1998 AND 1997
(Thousands of Dollars)
<TABLE>
<CAPTION>
1998 1997
---------- ----------
<S> <C> <C>
ASSETS
- ------
Other Property and Investments:
Investments in subsidiary companies, at
equity................................................... $2,161,901 $2,314,746
Investments in transmission companies, at equity.......... 17,692 19,635
Other, at cost............................................ 67 402
----------- -----------
2,179,660 2,334,783
----------- -----------
Current Assets:
Cash...................................................... - 10
Notes receivable from affiliated companies................ 34,400 34,200
Notes and accounts receivable............................ 723 711
Receivables from affiliated companies..................... 1,033 961
Taxes receivable...................................... 7,969 -
Prepayments............................................... 96 265
----------- -----------
44,221 36,147
----------- -----------
Deferred Charges:
Accumulated deferred income taxes......................... 5,236 5,692
Unamortized debt expense.................................. 101 232
Other..................................................... 256 47
----------- -----------
5,593 5,971
----------- -----------
Total Assets......................................... $2,229,474 $2,376,901
=========== ===========
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common Shareholders' Equity:
Common shares, $5 par value--Authorized
225,000,000 shares; 137,031,264 shares issued and
130,954,740 shares outstanding in 1998 and
136,842,170 shares issued and
130,182,736 outstanding in 1997......................... $ 685,156 $ 684,211
Capital surplus, paid in.................................. 940,661 932,494
Deferred contribution plan--employee stock ownership plan. (140,619) (154,141)
Retained earnings......................................... 560,769 707,522
Accumulated other comprehensive income.................... 1,405 (1)
----------- -----------
Total common shareholders' equity....................... 2,047,372 2,170,085
Long-term debt............................................ 158,000 177,000
----------- -----------
Total capitalization.................................... 2,205,372 2,347,085
----------- -----------
Current Liabilities:
Long-term debt--current portion........................... 19,000 17,000
Accounts payable.......................................... 1,882 1,857
Accounts payable to affiliated companies.................. 714 216
Accrued taxes............................................. 15 7,860
Accrued interest.......................................... 2,097 2,343
Dividend reinvestment plan................................ - 90
----------- -----------
23,708 29,366
----------- -----------
Other Deferred Credits...................................... 394 450
----------- -----------
Total Capitalization and Liabilities $2,229,474 $2,376,901
=========== ===========
</TABLE>
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996
(Thousands of Dollars Except Share Information)
<TABLE>
<CAPTION>
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Operating Revenues............... $ - $ - $ -
------------- ------------- -------------
Operating Expenses:
Other.......................... 7,674 8,657 8,920
Federal income taxes........... 1,569 (10,697) (10,390)
------------- ------------- -------------
Total operating expenses...... 9,243 (2,040) (1,470)
------------- ------------- -------------
Operating (Loss)/Income.......... (9,243) 2,040 1,470
------------- ------------- -------------
Other Income/(Loss):
Equity in earnings of
subsidiaries.................. (145,874) (118,195) 55,370
Equity in earnings of
transmission companies........ 2,903 2,968 3,306
Other, net..................... 21,995 2,184 368
------------- ------------- -------------
Other (loss)/income, net..... (120,976) (113,043) 59,044
------------- ------------- -------------
(Loss)/income before interest
charges..................... (130,219) (111,003) 60,514
------------- ------------- -------------
Interest Charges................. 16,534 18,959 21,585
------------- ------------- -------------
(Loss)/Earnings for Common Shares $ (146,753) $ (129,962) $ 38,929
============= ============= =============
(Loss)/Earnings Per Common Share
Basic and Diluted.............. $ (1.12) $ (1.01) $ 0.30
============= ============= =============
Common Shares Outstanding
(average)....................... 130,549,760 129,567,708 127,960,382
============= ============= =============
</TABLE>
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1998, 1997, 1996
(Thousands of Dollars)
<TABLE>
<CAPTION> 1998 1997 1996
------------ -------------- --------------
<S> <C> <C> <C>
Operating Activities:
Net (loss)/income...................................... $ (146,753) $ (135,708) $ 1,831
Adjustments to reconcile to net cash
from operating activities:
Equity in earnings of subsidiary companies........... 145,874 123,941 (18,272)
Cash dividends received from subsidiary companies.... 47,000 132,994 247,101
Deferred income taxes................................ 777 1,558 3,868
Other sources of cash................................ 21,512 11,738 17,961
Other uses of cash................................... (586) (2,101) (3,065)
Changes in working capital:
Receivables........................................ (84) 6,247 (7,312)
Accounts payable................................... 523 (14,031) (3,183)
Other working capital (excludes cash).............. (15,981) 5,490 (13,724)
------------ -------------- --------------
Net cash flows from operating activities................. 52,282 130,128 225,205
------------ -------------- --------------
Financing Activities:
Issuance of common shares.............................. 2,659 6,502 10,622
Net decrease in short-term debt........................ - (38,750) (18,750)
Reacquisitions and retirements of long-term debt....... (17,000) (16,000) (14,000)
Cash dividends on common shares........................ - (32,134) (176,276)
------------ -------------- --------------
Net cash flows used for financing activities............. (14,341) (80,382) (198,404)
------------ -------------- --------------
Investment Activities:
NU System Money Pool................................... (200) (28,725) 4,200
Investment in subsidiaries............................. (40,029) (22,583) (33,217)
Other investment activities, net....................... 2,278 1,562 2,208
------------ -------------- --------------
Net cash flows used for investments...................... (37,951) (49,746) (26,809)
------------ -------------- --------------
Net decrease in cash for the period...................... (10) - (8)
Cash - beginning of period............................... 10 10 18
------------ -------------- --------------
Cash - end of period..................................... $ - $ 10 $ 10
============ ============== ==============
Supplemental Cash Flow Information
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized................... $ 18,960 $ 18,960 $ 21,770
============ ============== ==============
Income taxes........................................... $ (16,000) $ (16,000) $ (7,700)
============ ============== ==============
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1998
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,052 $ 3,042 $ - $ 2,677 (a)$ 2,417
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 34,437 $ 12,427 $ - $ 6,426 (b)$ 40,438
========= ========= ========= ========= =========
</TABLE)
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, and expenses in connection therewith.
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1997
(Thousands of Dollars)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 17,062 $ 14,854 $ - $ 29,864 (a) $ 2,052
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 36,260 $ 9,542 $ - $ 11,365 (b) $ 34,437
========= ========= ========= ========= =========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, employee medical expenses, and expenses in connection therewith.
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1996
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance atCharged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 14,379 $ 21,761 $ - $ 19,078 (a) $ 17,062
========= ========= ========= ========== ==========
Asset valuation reserves $ 10,266 $ $ - $ 10,266 $ -
========= ========= ========= ========== ==========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 38,409 $ 8,397 $ - $ 10,546 (b) $ 36,260
========= ========= ========= ========== ==========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, employee medical expenses, and expenses in connection therewith.
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1998
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 300 $ 183 $ - $ 183 (a)$ 300
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 14,962 $ 5,612 $ - $ 3,918 (b)$ 16,656
========= ========= ========= ========= =========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, and expenses in connection therewith.
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1997
(Thousands of Dollars)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 13,241 $ 10,509 $ - $ 23,450 (a) $ 300
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 18,879 $ 4,458 $ - $ 8,375 (b) $ 14,962
========= ========= ========= ========= =========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, employee medical expenses, and expenses in connection therewith.
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1996
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance atCharged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 10,567 $ 15,704 $ - $ 13,030 (a) $ 13,241
========= ========= ========= ========== ==========
Asset valuation reserves $ 10,266 $ - $ - $ 10,266 $ -
========= ========= ========= ========== ==========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 19,874 $ 5,709 $ - $ 6,704 (b) $ 18,879
========= ========= ========= ========== ==========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, employee medical expenses, and expenses in connection therewith.
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1998
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,702 $ 2,726 $ - $ 2,387 (a)$ 2,041
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 7,788 $ 4,136 $ - $ 2,018 (b)$ 9,906
========= ========= ========= ========= =========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, and expenses in connection therewith.
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1997
(Thousands of Dollars)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,700 $ 3,259 $ - $ 3,257 (a) $ 1,702
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 7,265 $ 1,647 $ - $ 1,124 (b) $ 7,788
========= ========= ========= ========= =========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, employee medical expenses, and expenses in connection therewith.
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1996
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance atCharged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,582 $ 2,906 $ - $ 2,788 (a) $ 1,700
========= ========= ========= ========== ==========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 8,142 1,040 $ - $ 1,917 (b) $ 7,265
========= ========= ========= ========== ==========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, employee medical expenses, and expenses in connection therewith.
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1998
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 50 $ 106 $ - $ 106 (a)$ 50
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 5,503 $ 816 $ - $ 359 (b)$ 5,960
========= ========= ========= ========= =========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, and expenses in connection therewith.
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1997
(Thousands of Dollars)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,121 $ 1,086 $ - $ 3,157 (a) $ 50
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 5,575 $ 1,093 $ - $ 1,165 (b) $ 5,503
========= ========= ========= ========= =========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, employee medical expenses, and expenses in connection therewith.
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1996
(Thousands of Dollars)
<CAPTION>
- -------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance atCharged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,230 $ 3,097 $ - $ 3,206 (a) $ 2,121
========= ========= ========= ========== ==========
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 5,144 $ 1,222 $ - $ 791 (b) $ 5,575
========= ========= ========= ========== ==========
</TABLE>
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, employee medical expenses, and expenses in connection therewith.
EXHIBIT INDEX
Each document described below is incorporated by reference to the files
of the Securities and Exchange Commission, unless the reference to the
document is marked as follows:
* - Filed with the 1998 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1998 NU Form 10-K, File No. 1-5324
into the 1998 Annual Reports on Form 10-K for CL&P, PSNH, WMECO and
NAEC.
# - Filed with the 1998 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1998 NU Form 10-K, File No. 1-5324
into the 1998 Annual Report on Form 10-K for CL&P.
@ - Filed with the 1998 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1998 NU Form 10-K, File No. 1-5324
into the 1998 Annual Report on Form 10-K for PSNH.
** - Filed with the 1998 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1998 NU Form 10-K, File No. 1-5324
into the 1998 Annual Report on Form 10-K for WMECO.
## - Filed with the 1998 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1998 Form 10-K, File No. 1-5324 into
the 1998 Annual Report on Form 10-K for NAEC.
Exhibit
Number Description
3 Articles of Incorporation and By-Laws
3.1 Northeast Utilities
3.1.1 Declaration of Trust of NU, as amended through May 24,
1988. (Exhibit 3.1.1, 1988 NU Form 10-K, File No. 1-5324)
3.2 The Connecticut Light and Power Company
3.2.1 Certificate of Incorporation of CL&P, restated to March
22, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File No. 1-
5324)
3.2.2 Certificate of Amendment to Certificate of Incorporation
of CL&P, dated December 26, 1996. (Exhibit 3.2.2, 1996 NU
Form 10-K, File No. 1-5324)
# 3.2.3 Certificate of Amendment to Certificate of Incorporation
of CL&P, dated April 27, 1998.
3.2.4 By-laws of CL&P, as amended to January 1, 1997. (Exhibit
3.2.3, 1996 NU Form 10-K, File No. 1-5324)
3.3 Public Service Company of New Hampshire
3.3.1 Articles of Incorporation, as amended to May 16, 1991.
(Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324)
3.3.2 By-laws of PSNH, as amended to November 1, 1993.
(Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324)
3.4 Western Massachusetts Electric Company
3.4.1 Articles of Organization of WMECO, restated to February
23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K, File No. 1-
5324)
3.4.2 By-laws of WMECO, as amended to February 11, 1998.
(Exhibit 3.4.2, 1997 NU Form 10-K, File No. 1-5324)
3.5 North Atlantic Energy Corporation
3.5.1 Articles of Incorporation of NAEC dated September 20,
1991. (Exhibit 3.5.1, 1993 NU Form 10-K, File No. 1-5324)
3.5.2 Articles of Amendment dated October 16, 1991 and June 2,
1992 to Articles of Incorporation of NAEC. (Exhibit
3.5.2, 1993 NU Form 10-K, File No. 1-5324)
3.5.3 By-laws of NAEC, as amended to November 8, 1993.
(Exhibit 3.5.3, 1993 NU Form 10-K, File No. 1-5324)
4 Instruments defining the rights of security holders, including
indentures
4.1 Northeast Utilities
4.1.1 Indenture dated as of December 1, 1991 between Northeast
Utilities and IBJ Schroder Bank & Trust Company, with
respect to the issuance of Debt Securities. (Exhibit
4.1.1, 1991 NU Form 10-K, File No. 1-5324)
4.1.2 First Supplemental Indenture dated as of December 1, 1991
between Northeast Utilities and IBJ Schroder Bank & Trust
Company, with respect to the issuance of Series A Notes.
(Exhibit 4.1.2, 1991 NU Form 10-K, File No. 1-5324)
4.1.3 Second Supplemental Indenture dated as of March 1, 1992
between Northeast Utilities and IBJ Schroder Bank & Trust
Company with respect to the issuance of 8.38% Amortizing
Notes. (Exhibit 4.1.3, 1992 NU Form 10-K, File No. 1-
5324)
4.1.4 Credit Agreement among NU, CL&P and WMECO and several
commercial banks, dated as of November 21, 1996.
(Exhibit No. B.1, File No. 70-8875)
4.1.5 First Amendment and Waiver dated as of May 30, 1997 to
Credit Agreement dated as of November 21, 1996 among NU,
CL&P, WMECO, and the Co-Agents and Banks named therein.
(Exhibit B.4(a) (Execution Copy), File No. 70-8875)
4.1.6 Second Amendment and Waiver dated as of September 11,
1998 to Credit Agreement dated as of November 21, 1996
among NU, CL&P, WMECO, and the Co-Agents and Banks named
therein. (Exhibit B.10 (Execution Copy), File No. 70-
8875)
4.1.7 Third Amendment and Waiver dated as of March 3, 1999 to
Credit Agreement dated as of November 21, 1996 among NU,
CL&P, WMECO, and the Co-Agents and Banks named therein.
(Exhibit B.11 (Execution Copy), File No. 70-8875)
4.1.8 Credit Agreement dated as of February 10, 1998 among NU,
the Lenders named therein, and Toronto Dominion (Texas),
Inc., as Administrative Agent, TD Securities (USA) Inc.,
as Arranger. (Exhibit B.9 (Execution Copy), File No. 70-
8875)
4.1.9 First Amendment dated as of February 8, 1999 to Credit
Agreement dated as of February 10, 1998 among NU, the
Lenders named therein, and Toronto Dominion (Texas),
Inc., as Administrative Agent, TD Securities (USA) Inc.,
as Arranger. (Exhibit A (Execution Copy), File No. 70-
8875)
4.1.10 Second Amendment dated as of March 9, 1999 to Credit
Agreement dated as of February 10, 1998 among NU, the
Lenders named therein, and Toronto Dominion (Texas),
Inc., as Administrative Agent, TD Securities (USA) Inc.,
as Arranger. (Exhibit B.12 (Execution Copy), File No.70-
8875)
4.2 The Connecticut Light and Power Company
4.2.1 Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, Trustee, dated as of May 1, 1921.
(Composite including all twenty-four amendments to May 1,
1967.) (Exhibit 4.1.1, 1989 NU Form 10-K, File No. 1-
5324)
Supplemental Indentures to the Composite May 1, 1921
Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, dated as of:
# 4.2.2 December 1, 1969. (Exhibit 4.20, File No. 2-60806)
4.2.3 June 30, 1982. (Exhibit 4.33, File No. 2-79235)
4.2.4 December 1, 1989. (Exhibit 4.1.26, 1989 NU Form 10-K,
File No. 1-5324)
4.2.5 July 1, 1992. (Exhibit 4.31, File No. 33-59430)
4.2.6 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
4.2.7 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
4.2.8 December 1, 1993. (Exhibit 4.2.14, 1993 NU Form 10-K,
File No. 1-5324)
4.2.9 February 1, 1994. (Exhibit 4.2.16, 1993 NU Form 10-K,
File No. 1-5324)
4.2.10 June 1, 1994. (Exhibit 4.2.15, 1994 NU Form 10-K, File
No. 1-5324)
4.2.11 October 1, 1994. (Exhibit 4.2.16, 1994 NU Form 10-K, File
No. 1-5324)
4.2.12 June 1, 1996. (Exhibit 4.2.16, 1996 NU Form 10-K, File
No. 1-5324)
4.2.13 January 1, 1997. (Exhibit 4.2.17, 1996 NU Form 10-K, File
No. 1-5324)
4.2.14 May 1, 1997. (Exhibit 4.19, File No. 333-30911)
4.2.15 June 1, 1997. (Exhibit 4.20, File No. 333-30911)
4.2.16 June 1, 1997. (Exhibit 4.2.17, 1997 NU Form 10-K, File
No. 1-5324)
# 4.2.17 May 1, 1998.
# 4.2.18 May 1, 1998.
4.2.19 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and CL&P
(Pollution Control Bonds, 1986 Series) dated as of
December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S,
File No. 30-246)
4.2.20 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and CL&P
(Pollution Control Bonds, 1988 Series) dated as of
October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S, File
No. 30-246)
4.2.21 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and CL&P
(Pollution Control Bonds) dated as of December 1, 1989.
(Exhibit C.1.39, 1989 NU Form U5S, File No. 30-246)
4.2.22 Loan and Trust Agreement among Business Finance Authority
of the State of New Hampshire, CL&P and the Trustee
(Pollution Control Bonds, 1992 Series A) dated as of
December 1, 1992.(Exhibit C.2.33, 1992 NU Form U5S, File
No. 30-246)
4.2.23 Loan Agreement between Connecticut Development Authority
and CL&P (Pollution Control Bonds - Series A, Tax Exempt
Refunding) dated as of September 1, 1993. (Exhibit
4.2.21, 1993 NU Form 10-K, File No. 1-5324)
4.2.24 Loan Agreement between Connecticut Development Authority
and CL&P (Pollution Control Bonds - Series B, Tax Exempt
Refunding) dated as of September 1, 1993. (Exhibit
4.2.22, 1993 NU Form 10-K, File No. 1-5324)
4.2.25 Amended and Restated Loan Agreement between Connecticut
Development Authority and CL&P (Pollution Control Revenue
Bond - 1996A Series) dated as of May 1, 1996 and Amended
and Restated as of January 1, 1997. (Exhibit 4.2.24,
1996 NU Form 10-K, File No. 1-5324)
4.2.25.1 Amended and Restated Indenture of Trust between
Connecticut Development Authority and the
Trustee (CL&P Pollution Control Revenue Bond-
1996A Series), dated as of May 1, 1996 and
Amended and Restated as of January 1, 1997.
(Exhibit 4.2.24.1, 1996 NU Form 10-K, File No.
1-5324)
4.2.25.2 Standby Bond Purchase Agreement among CL&P,
Societe Generale, New York Branch and the
Trustee, dated January 23, 1997. (Exhibit
4.2.24.2, 1996 NU Form 10-K, File No. 1-5324)
4.2.25.3 Amendment No. 1, dated January 21, 1998, to the
Standby Bond Purchase Agreement, dated January
23, 1997. (Exhibit 4.2.24.3, 1997 NU Form 10-
K, File No. 1-5324)
# 4.2.25.4 Amendment No. 2, dated December 9, 1998, to the
Standby Bond Purchase Agreement, dated January
23, 1997.
4.2.25.5 AMBAC Municipal Bond Insurance Policy issued by
the Connecticut Development Authority (CL&P
Pollution Control Revenue Bond-1996A Series),
effective January 23, 1997. (Exhibit 4.2.24.3,
1996 NU Form 10-K, File No. 1-5324)
4.2.26 Amended and Restated Limited Partnership Agreement (CL&P
Capital, L.P.) among CL&P, NUSCO, and the persons who
became limited partners of CL&P Capital, L.P. in
accordance with the provisions thereof dated as of
January 23, 1995 (MIPS). (Exhibit A.1 (Execution Copy),
File No. 70-8451)
4.2.27 Indenture between CL&P and Bankers Trust Company, Trustee
(Series A Subordinated Debentures), dated as of
January 1, 1995 (MIPS). (Exhibit B.1 (Execution Copy),
File No. 70-8451)
4.2.28 Payment and Guaranty Agreement of CL&P dated as of
January 23, 1995 (MIPS). (Exhibit B.3 (Execution Copy),
File No. 70-8451)
4.3 Public Service Company of New Hampshire
4.3.1 First Mortgage Indenture dated as of August 15, 1978
between PSNH and First Fidelity Bank, National
Association, New Jersey, Trustee, (Composite including
all amendments to May 16, 1991). (Exhibit 4.4.1, 1992 NU
Form 10-K, File No. 1-5324)
4.3.1.1 Tenth Supplemental Indenture dated as of May 1,
1991 between PSNH and First Fidelity Bank,
National Association. (Exhibit 4.1, PSNH
Current Report on Form 8-K dated February 10,
1992, File No. 1-6392)
@ 4.3.2 Revolving Credit Agreement, dated as of April 23, 1998
(includes an Assignment and Security Agreement related to
Accounts Receivable).
4.3.3 Series A (Tax Exempt New Issue) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.2, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.4 Series B (Tax Exempt Refunding) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.3, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.5 Series C (Tax Exempt Refunding) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.4, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.6 Series D (Taxable New Issue) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.5, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.6.1 First Supplement to Series D (Tax Exempt
Refunding Issue) PCRB Loan and Trust Agreement
dated as of December 1, 1992. (Exhibit
4.4.5.1, 1992 NU Form 10-K, File No. 1-5324)
@ 4.3.6.2 Second Supplement to Series D PCRB Loan and
Trust Agreement dated as of May 1, 1995.
@ 4.3.6.3 Amended and Restated Second Series D (May 1,
1991 Taxable New Issue) PCRB Letter of Credit
and Reimbursement Agreement dated as of
April 23, 1998.
4.3.7 Series E (Taxable New Issue) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.6, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.7.1 First Supplement to Series E (Tax Exempt
Refunding Issue) PCRB Loan and Trust Agreement
dated as of December 1, 1993. (Exhibit 4.3.8.1,
1993 NU Form 10-K, File No. 1-5324)
@ 4.3.7.2 Second Supplement to Series E PCRB Loan and
Trust Agreement dated as of May 1, 1995.
@ 4.3.7.3 Amended and Restated Second Series E (May 1,
1991 Taxable New Issue) PCRB Letter of Credit
and Reimbursement Agreement dated as of
April 23, 1998.
4.4 Western Massachusetts Electric Company
4.4.1 First Mortgage Indenture and Deed of Trust between WMECO
and Old Colony Trust Company, Trustee, dated as of
August 1, 1954. (Exhibit 4.4.1, 1993 NU Form 10-K, File
No. 1-5324)
Supplemental Indentures thereto dated as of:
** 4.4.2 October 1, 1954.
4.4.3 March 1, 1967. (Exhibit 4.4.3, 1997 NU Form 10-K, File
No. 1-5324)
4.4.4 July 1, 1973. (Exhibit 2.10, File No. 2-68808)
4.4.5 December 1, 1992. (Exhibit 4.15, File No. 33-55772)
4.4.6 January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K, File
No. 1-5324)
4.4.7 March 1, 1994. (Exhibit 4.4.12, 1993 NU Form 10-K, File
No. 1-5324)
4.4.8 May 1, 1997. (Exhibit 4.11, File No. 33-51185)
4.4.9 July 1, 1997. (Exhibit 4.4.10, 1997 NU Form 10-K, File
No. 1-5324)
** 4.4.10 May 1, 1998.
** 4.4.11 May 1, 1998.
4.4.12 Loan Agreement between Connecticut Development Authority
and WMECO, (Pollution Control Bonds - Series A, Tax
Exempt Refunding) dated as of September 1, 1993.
(Exhibit 4.4.13, 1993 NU Form 10-K, File No. 1-5324)
4.5 North Atlantic Energy Corporation
4.5.1 First Mortgage Indenture and Deed of Trust between NAEC and
United States Trust Company of New York, Trustee, dated as
of June 1, 1992. (Exhibit 4.6.1, 1992 NU Form 10-K, File
No. 1-5324)
4.5.2 Term Credit Agreement dated as of November 9, 1995. (Exhibit
4.5.2, 1995 NU Form 10-K, File No. 1-5324)
10 Material Contracts
10.1 Stockholder Agreement dated as of July 1, 1964 among the
stockholders of Connecticut Yankee Atomic Power Company (CYAPC).
(Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324)
10.2 Form of Power Contract dated as of July 1, 1964 between CYAPC and
each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.2, 1994 NU Form
10-K, File No. 1-5324)
10.2.1 Form of Additional Power Contract dated as of April 30,
1984, between CYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324)
10.2.2 Form of 1987 Supplementary Power Contract dated as of
April 1, 1987, between CYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.2.6, 1987 NU Form 10-K, File No. 1-
5324)
10.3 Capital Funds Agreement dated as of September 1, 1964 between CYAPC
and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.3, 1994 NU Form 10-K,
File No. 1-5324)
10.4 Stockholder Agreement dated December 10, 1958 between Yankee Atomic
Electric Company (YAEC) and CL&P, HELCO, PSNH and WMECO. (Exhibit
10.4, 1993 NU Form 10-K, File No. 1-5324)
10.5 Form of Amendment No. 3, dated as of April 1, 1985, to Power
Contract between YAEC and each of CL&P, PSNH and WMECO, including
a composite restatement of original Power Contract dated June 30,
1959 and Amendment No. 1 dated April 1, 1975 and Amendment No. 2
dated October 1, 1980. (Exhibit 10.5, 1988 NU Form 10-K, File No.
1-5324.)
10.5.1 Form of Amendment No. 4 to Power Contract, dated May 6,1988,
between YAEC and each of CL&P, PSNH and WMECO. (Exhibit
10.5.1, 1989 NU Form 10-K, File No. 1-5324)
10.5.2 Form of Amendment No. 5 to Power Contract, dated June 26,
1989, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)
10.5.3 Form of Amendment No. 6 to Power Contract, dated July 1,1989,
between YAEC and each of CL&P, PSNH and WMECO. (Exhibit
10.5.3, 1989 NU Form 10-K, File No. 1-5324)
10.5.4 Form of Amendment No. 7 to Power Contract, dated
February 1, 1992, between YAEC and each of CL&P, PSNH and
WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1-
5324)
10.6 Stockholder Agreement dated as of May 20, 1968 among stockholders
of MYAPC. (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324)
10.7 Form of Power Contract dated as of May 20, 1968 between MYAPC and
each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.7, 1997 Form 10-K,
File No. 1-5324)
10.7.1 Form of Amendment No. 1 to Power Contract dated as of March 1,
1983 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit
10.7.1, 1993 NU Form 10-K, File No. 1-5324)
10.7.2 Form of Amendment No. 2 to Power Contract dated as of
January 1, 1984 between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1-5324)
10.7.3 Form of Amendment No. 3 to Power Contract dated as of
October 1, 1984 between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No.
1-5324)
10.7.4 Form of Additional Power Contract dated as of February 1,
1984 between MYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)
10.8 Capital Funds Agreement dated as of May 20, 1968 between MYAPC and
CL&P, PSNH, HELCO and WMECO. (Exhibit 10.8, 1997 NU Form 10-K, File
No. 1-5324)
10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of
August 1, 1985, between MYAPC, CL&P, PSNH and WMECO.
(Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324)
10.9 Sponsor Agreement dated as of August 1, 1968 among the sponsors of
Vermont Yankee Nuclear Power Corporation (VYNPC). (Exhibit 10.9,
1997 NU Form 10-K, File No. 1-5324)
10.10 Form of Power Contract dated as of February 1, 1968 between VYNPC
and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.10, 1997 NU
Form 10-K, File No. 1-5324)
10.10.1 Form of Amendment to Power Contract dated as of June 1,
1972 between VYNPC and each of CL&P, HELCO, PSNH and WMECO.
(Exhibit 5.22, File No. 2-47038)
10.10.2 Form of Second Amendment to Power Contract dated as of
April 15, 1983 between VYNPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.10.2, 1993 NU Form 10-K, File No. 1-5324)
10.10.3 Form of Third Amendment to Power Contract dated as of
April 24, 1985 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit No. 10.10.3, 1994 NU Form 10-K, File No.
1-5324)
10.10.4 Form of Fourth Amendment to Power Contract dated as of
June 1, 1985 between VYNPC and each of CL&P, PSNH and WMECO.
(Exhibit No. 10.10.4, 1996 NU Form 10-K, File No. 1-5324)
10.10.5 Form of Fifth Amendment to Power Contract dated as of May 6,
1988 between VYNPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.10.5, 1990 NU Form 10-K, File No. 1-5324)
10.10.6 Form of Sixth Amendment to Power Contract dated as of May 6,
1988 between VYNPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.10.6, 1990 NU Form 10-K, File No. 1-5324)
10.10.7 Form of Seventh Amendment to Power Contract dated as of
June 15, 1989 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.7, 1990 NU Form 10-K, File No. 1-5324)
10.10.8 Form of Eighth Amendment to Power Contract dated as of
December 1, 1989 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.8, 1990 NU Form 10-K, File No. 1-5324)
10.10.9 Form of Additional Power Contract dated as of February 1,
1984 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit
10.10.9, 1993 NU Form 10-K, File No. 1-5324)
10.11 Capital Funds Agreement dated as of February 1, 1968 between VYNPC
and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.11, 1997 NU Form 10-K,
File No. 1-5324)
10.11.1 Form of First Amendment to Capital Funds Agreement dated
as of March 12, 1968 between VYNPC and CL&P, HELCO, PSNH and
WMECO. (Exhibit 10.11.1, 1997 NU Form 10-K, File No. 1-5324)
10.11.2 Form of Second Amendment to Capital Funds Agreement dated as
of September 1, 1993 between VYNPC and CL&P, HELCO, PSNH and
WMECO. (Exhibit 10.11.2, 1993 NU Form 10-K, File No. 1-5324)
10.12 Amended and Restated Millstone Plant Agreement dated as of December 1,
1984 by and among CL&P, WMECO and Northeast Nuclear Energy Company
(NNECO). (Exhibit 10.12, 1994 NU Form 10-K, File No. 1-5324)
10.13 Sharing Agreement dated as of September 1, 1973 with respect to 1979
Connecticut nuclear generating unit (Millstone 3). (Exhibit 6.43,
File No. 2-50142)
10.13.1 Amendment dated August 1, 1974 to Sharing Agreement - 1979
Connecticut Nuclear Unit. (Exhibit 5.45, File No. 2-52392)
10.13.2 Amendment dated December 15, 1975 to Sharing Agreement -
1979 Connecticut Nuclear Unit. (Exhibit 7.47, File No.
2-60806)
10.13.3 Amendment dated April 1, 1986 to Sharing Agreement - 1979
Connecticut Nuclear Unit. (Exhibit 10.17.3, 1990 NU Form
10-K, File No. 1-5324)
10.14 Agreement dated July 19, 1990, among NAESCO and Seabrook Joint owners
with respect to operation of Seabrook. (Exhibit 10.53, 1990 NU Form
10-K, File No. 1-5324)
10.15 Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH dated as of
June 1, 1992. (Exhibit 10.17, 1992 NU Form 10-K, File No. 1-5324)
10.16 Rate Agreement by and between NUSCO, on behalf of NU, and the
Governor of the State of New Hampshire and the New Hampshire
Attorney General dated as of November 22, 1989. (Exhibit 10.44,1989
NU Form 10-K, File No. 1-5324)
10.16.1 First Amendment to Rate Agreement dated as of December 5,
1989. (Exhibit 10.16.1, 1995 NU Form 10-K, File No. 1-5324)
10.16.2 Second Amendment to Rate Agreement dated as of December 12,
1989. (Exhibit 10.16.2, 1995 NU Form 10-K, File No. 1-5324)
10.16.3 Third Amendment to Rate Agreement dated as of December 3,
1993. (Exhibit 10.16.3, 1995 NU Form 10-K, File No. 1-5324)
10.16.4 Fourth Amendment to Rate Agreement dated as of September 21,
1994. (Exhibit 10.16.4, 1995 NU Form 10-K, File No. 1-5324)
10.16.5 Fifth Amendment to Rate Agreement dated as of September 9,
1994. (Exhibit 10.16.5, 1995 NU Form 10-K, File No. 1-5324)
10.17 Form of Seabrook Power Contract between PSNH and NAEC, as amended
and restated. (Exhibit 10.45, 1992 NU Form 10-K, File No. 1-5324)
10.18 Agreement (composite) for joint ownership, construction and
operation of New Hampshire nuclear unit, as amended through the
November 1, 1990 twenty-third amendment. (Exhibit No. 10.17, 1994
NU Form 10-K, File No. 1-5324)
10.18.1 Memorandum of Understanding dated November 7, 1988 between
PSNH and Massachusetts Municipal Wholesale Electric Company
(Exhibit 10.17, PSNH 1989 Form 10-K, File No. 1-6392)
10.18.2 Agreement of Settlement among Joint Owners dated as of
January 13, 1989. (Exhibit 10.13.21, 1988 NU Form 10-K,
File No. 1-5324)
10.18.2.1 Supplement to Settlement Agreement, dated as of
February 7, 1989, between PSNH and Central
Maine Power Company. (Exhibit 10.18.1, PSNH
1989 Form 10-K, File No. 1-6392)
10.19 Amended and Restated Agreement for Seabrook Project Disbursing Agent
dated as of November 1, 1990. (Exhibit 10.4.7, File No. 33-35312)
10.19.1 Form of First Amendment to Exhibit 10.19. (Exhibit 10.4.8,
File No. 33-35312)
10.19.2 Form (Composite) of Second Amendment to Exhibit 10.19.
(Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1-5324)
10.20 Agreement dated November 1, 1974 for Joint Ownership, Construction
and Operation of William F. Wyman Unit No. 4 among PSNH, Central
Maine Power Company and other utilities. (Exhibit 5.16 , File No.
2-52900)
10.20.1 Amendment to Exhibit 10.20 dated June 30, 1975. (Exhibit
5.48, File No. 2-55458)
10.20.2 Amendment to Exhibit 10.20 dated as of August 16, 1976.
(Exhibit 5.19, File No. 2-58251)
10.20.3 Amendment to Exhibit 10.20 dated as of December 31, 1978.
(Exhibit 5.10.3, File No. 2-64294)
10.21 Form of Service Contract dated as of July 1, 1966 between each of
NU, CL&P and WMECO and the Service Company. (Exhibit 10.20, 1993
NU Form 10-K, File No. 1-5324)
10.21.1 Service Contract dated as of June 5, 1992 between PSNH and
the Service Company. (Exhibit 10.12.4, 1992 NU Form 10-K,
File No. 1-5324)
10.21.2 Service Contract dated as of June 5, 1992 between NAEC and
the Service Company. (Exhibit 10.12.5, 1992 NU Form 10-K,
File No. 1-5324)
10.21.3 Form of Service Agreement dated as of June 29, 1992 between
PSNH and North Atlantic Energy Service Corporation, and the
First Amendment thereto. (Exhibits B.7 and B.7.1, File No.
70-7787)
10.21.4 Form of Annual Renewal of Service Contract. (Exhibit 10.20.3,
1993 NU Form 10-K, File No. 1-5324)
10.22 Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and
WMECO dated as of June 1, 1970 with respect to pooling of
generation and transmission. (Exhibit 13.32, File No. 2-38177)
10.22.1 Amendment to Memorandum of Understanding between CL&P, HELCO,
HP&E, HWP and WMECO dated as of February 2, 1982 with respect
to pooling of generation and transmission. (Exhibit 10.21.1,
1993 NU Form 10-K, File No. 1-5324)
10.22.2 Amendment to Memorandum of Understanding between CL&P, HELCO,
HP&E, HWP and WMECO dated as of January 1, 1984 with respect
to pooling of generation and transmission. (Exhibit 10.21.2,
1994 NU Form 10-K, File No. 1-5324)
10.23 New England Power Pool (NEPOOL) Agreement effective as of
November 1, 1971, as amended to December 1, 1996. (Exhibit 10.15,
1988 NU Form 10-K, File No. 1-5324.)
10.23.1 Form of Interim Independent System Operator (ISO) Agreement
(Attachment to Thirty-Third Amendment to Exhibit 10.23 dated
as of December 31, 1996). (Exhibit 10.23.6, 1996 NU Form
10-K, File No. 1-5324)
* 10.23.2 Restated NEPOOL Power Pool Agreement (restated by the
Thirty-Sixth Agreement dated as of July 20, 1998 and includes
the Restated NEPOOL Open Access Transmission Tariff).
* 10.23.3 Thirty-Seventh Agreement dated as of August 15, 1998 amending
Exhibit 10.23.2.
* 10.23.4 Thirty-Eighth Agreement dated as of October 30, 1998 amending
Exhibit 10.23.2.
* 10.23.5 Thirty-Ninth Agreement dated as of November 13, 1998 amending
Exhibit 10.23.2.
* 10.23.6 Fortieth Agreement dated as of December 15, 1998 amending
Exhibit 10.23.2.
* 10.23.7 ISO New England Inc., FERC Tariff for Transmission Dispatch
and Power Administration Services.
10.24 Agreements among New England Utilities with respect to the Hydro-
Quebec interconnection projects. (See Exhibits 10(u) and 10(v);
10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of
New England Electric System, File No. 1-3446.)
10.25 Trust Agreement dated February 11, 1992, between State Street Bank
and Trust Company of Connecticut, as Trustor, and Bankers Trust
Company, as Trustee, and CL&P and WMECO, with respect to NBFT.
(Exhibit 10.23, 1991 NU Form 10-K, File No. 1-5324)
10.25.1 Nuclear Fuel Lease Agreement dated as of February 11, 1992,
between Bankers Trust Company, Trustee, as Lessor, and CL&P
and WMECO, as Lessees. (Exhibit 10.23.1, 1991 NU Form 10-K,
File No. 1-5324)
10.26 Simulator Financing Lease Agreement, dated as of February 1, 1985,
by and between ComPlan and NNECO. (Exhibit 10.25, 1994 NU Form
10-K, File No. 1-5324)
10.27 Simulator Financing Lease Agreement, dated as of May 2, 1985, by and
between The Prudential Insurance Company of America and NNECO.
(Exhibit No. 10.26, 1994 NU Form 10-K, File No. 1-5324)
10.28 Lease dated as of April 14, 1992 between The Rocky River Realty
Company (RRR) and Northeast Utilities Service Company (NUSCO) with
respect to the Berlin, Connecticut headquarters (office lease).
(Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324)
10.28.1 Lease dated as of April 14, 1992 between RRR and NUSCO with
respect to the Berlin, Connecticut headquarters (project
lease). (Exhibit 10.29.1, 1992 NU Form 10-K, File No. 1-5324)
10.29 Millstone Technical Building Note Agreement dated as of December 21,
1993 by and between The Prudential Insurance Company of America and
NNECO. (Exhibit 10.28, 1993 NU Form 10-K, File No. 1-5324)
10.30 Lease and Agreement, dated as of December 15, 1988, by and between
WMECO and Bank of New England, N.A., with BNE Realty Leasing
Corporation of North Carolina. (Exhibit 10.63, 1988 NU Form 10-K,
File No. 1-5324.)
10.31 Note Agreement dated April 14, 1992, by and between The Rocky River
Realty Company (RRR) and Purchasers named therein (Connecticut
General Life Insurance Company, Life Insurance Company of North
America, INA Life Insurance Company of New York, Life Insurance
Company of Georgia), with respect to RRR's sale of $15 million of
guaranteed senior secured notes due 2007 and $28 million of
guaranteed senior secured notes due 2017. (Exhibit 10.52, 1992 NU
Form 10-K, File No. 1-5324)
10.31.1 Amendment to Note Agreement, dated September 26, 1997.
(Exhibit 10.31.1, 1997 NU Form 10-K, File No. 1-5324)
10.31.2 Note Guaranty dated April 14, 1992 by Northeast Utilities
pursuant to Note Agreement dated April 14, 1992 between
RRR and Note Purchasers, for the benefit of The
Connecticut National Bank as Trustee, the Purchasers and
the owners of the notes. (Exhibit 10.52.1, 1992 NU Form
10-K, File No. 1-5324)
10.31.2.1 Extension of Note Guaranty, dated September 26,
1997. (Exhibit 10.31.2.1, 1997 NU Form 10-K,
File No. 1-5324)
10.31.3 Assignment of Leases, Rents and Profits, Security Agreement
and Negative Pledge, dated as of April 14, 1992 among RRR,
NUSCO and The Connecticut National Bank as Trustee, securing
notes sold by RRR pursuant to April 14, 1992 Note Agreement.
(Exhibit 10.52.2, 1997 NU Form 10-K, File No. 1-5324)
10.31.3.1 Modification of and Confirmation of Assignment
of Leases, Rents and Profits, Security Agreement
and Negative Pledge, dated as of September 26,
1997. (Exhibit 10.31.3.1, 1997 NU Form 10-K, File
No. 1-5324)
10.31.4 Purchase and Sale Agreement, dated July 28, 1997 by and
between RRR and the Sellers and Purchasers named therein.
(Exhibit 10.31.4, 1997 NU Form 10-K, File No. 1-5324)
10.31.5 Purchase and Sale Agreement, dated September 26, 1997 by
and between RRR and the Purchaser named therein. (Exhibit
10.31.5, 1992 NU Form 10-K, File No. 1-5324)
10.32 Master Trust Agreement dated as of September 2, 1986 between CL&P
and WMECO and Colonial Bank as Trustee, with respect to reserve
funds for Millstone 1 decommissioning costs. (Exhibit No. 10.32,
1996 NU Form 10-K, File No. 1-5324)
10.32.1 Notice of Appointment of Mellon Bank, N.A. as Successor
Trustee, dated November 20, 1990, and Acceptance of
Appointment. (Exhibit 10.41.1, 1992 NU Form 10-K, File
No. 1-5324)
10.33 Master Trust Agreement dated as of September 2, 1986 between CL&P
and WMECO and Colonial Bank as Trustee, with respect to reserve
funds for Millstone 2 decommissioning costs. (Exhibit No. 10.33,
1996 NU Form 10-K, File No. 1-5324)
10.33.1 Notice of Appointment of Mellon Bank, N.A. as Successor
Trustee, dated November 20, 1990, and Acceptance of
Appointment. (Exhibit 10.42.1, 1992 NU Form 10-K, File
No. 1-5324)
10.34 Master Trust Agreement dated as of April 23, 1986 between CL&P and
WMECO and Colonial Bank as Trustee, with respect to reserve funds
for Millstone 3 decommissioning costs. (Exhibit No. 10.34, 1996 NU
Form 10-K, File No. 1-5324)
10.34.1 Notice of Appointment of Mellon Bank, N.A. as Successor
Trustee, dated November 20, 1990, and Acceptance of
Appointment. (Exhibit 10.43.1, 1992 NU Form 10-K, File
No. 1-5324)
10.35 NU Executive Incentive Plan, effective as of January 1, 1991.
Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324)
* 10.35.1 NU Incentive Plan, effective as of January 1, 1998.
* 10.35.1.1 Amendment to Exhibit 10.35.1, effective as of
February 23, 1999.
10.36 Supplemental Executive Retirement Plan for Officers of NU System
Companies, Amended and Restated effective as of January 1, 1992.
(Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30, 1992,
File No. 1-5324)
10.36.1 Amendment 1 to Exhibit 10.36, effective as of August 1, 1993.
(Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324)
10.36.2 Amendment 2 to Exhibit 10.36, effective as of January 1,
1994. (Exhibit 10.35.2, 1993 NU Form 10-K, File No. 1-5324)
10.36.3 Amendment 3 to Exhibit 10.36, effective as of January 1, 1996.
(Exhibit 10.36.3, 1995 NU Form 10-K, File No. 1-5324)
* 10.37 Special Severance Program for Officers of NU System Companies, as
adopted on July 15, 1998.
* 10.37.1 Amendment to Exhibit 10.37, effective as of February 23, 1999.
10.38 Loan Agreement dated as of December 2, 1991, by and between NU and
Mellon Bank, N.A., as Trustee, with respect to NU's loan of $175
million to an ESOP Trust. (Exhibit 10.46, 1991 NU Form 10-K, File
No. 1-5324)
10.38.1 First Amendment to Exhibit 10.38 dated February 7, 1992.
(Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324)
10.38.2 Loan Agreement dated as of March 19, 1992 by and between
NU and Mellon Bank, N.A., as Trustee, with respect to
NU's loan of $75 million to the ESOP Trust. (Exhibit
10.49.1, 1992 NU Form 10-K, File No. 1-5324)
10.38.3 Second Amendment to Exhibit 10.38 dated April 9, 1992.
(Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324)
10.39 Employment Agreement with Michael G. Morris. (Exhibit 10.39, 1997
NU Form 10-K, File No. 1-5324)
* 10.39.1 Amendment to Exhibit 10.39, dated as of February 23,
1999.
10.40 Transition and Retirement Agreement with Bernard M. Fox. (Exhibit
10.39, 1996 NU Form 10-K, File No. 1-5324)
10.41 Employment Agreement with Bruce M. Kenyon. (Exhibit 10.40, 1996 NU
Form 10-K, File No. 1-5324)
* 10.41.1 Amendment to Exhibit 10.41, dated as of January 13, 1998.
* 10.41.2 Amendment to Exhibit 10.41, dated as of February 23, 1999.
10.42 Employment Agreement with John H. Forsgren. (Exhibit 10.41, 1996
NU Form 10-K, File No. 1-5324)
* 10.42.1 Amendment to Exhibit 10.42, dated as of January 13, 1998.
* 10.42.2 Amendment to Exhibit 10.42, dated as of February 23, 1999.
10.43 Employment Agreement with Hugh C. MacKenzie. (Exhibit 10.42, 1996
NU Form 10-K, File No. 1-5324)
* 10.43.1 Amendment to Exhibit 10.43, dated as of January 13, 1998.
* 10.43.2 Amendment to Exhibit 10.43, dated as of February 23, 1999.
* 10.44 Employment Agreement with Cheryl W. Grise'.
* 10.44.1 Amendment to Exhibit 10.44, dated as of January 13, 1998.
* 10.44.2 Amendment to Exhibit 10.44, dated as of February 23, 1999.
10.45 Northeast Utilities Deferred Compensation Plan for Trustees,
Amended and Restated December 13, 1994. (Exhibit 10.39, 1995 NU
Form 10-K, File No. 1-5324)
10.46 Deferred Compensation Plan for Officers of Northeast Utilities
System Companies adopted September 23, 1986. (Exhibit 10.40, 1995
NU Form 10-K, File No. 1-5324)
10.47 Northeast Utilities Deferred Compensation Plan for Executives,
adopted January 13, 1998. (Exhibit A.5, File No. 70-09185)
10.48 Reciprocal Support Agreement Among NNECO, NAESCO, CYAPC, YAEC and
NUSCO dated January 1, 1996. (Exhibit 10.41, 1995 NU Form 10K,
File No. 1-5324)
10.49 Receivables Purchase and Sale Agreement (CL&P and CL&P Receivables
Corporation), dated as of September 30, 1997. (Exhibit 10.49, 1997
NU Form 10-K, File No. 1-5324)
# 10.49.1 Amendment to Exhibit 10.49 dated September 29, 1998.
10.49.2 Purchase and Contribution Agreement (CL&P and CL&P
Receivables Corporation), dated as of September 30, 1997.
(Exhibit 10.49.1, 1997 NU Form 10-K, File No. 1-5324)
10.50 Receivables Purchase Agreement (WMECO and WMECO Receivables
Corporation), dated as of May 22, 1997. (Exhibit 10.50, 1997 NU
Form 10-K, File No. 1-5324)
10.50.1 Purchase and Sale Agreement (WMECO and WMECO Receivables
Corporation), dated as of May 22, 1997. (Exhibit 10.50.1,
1997 NU Form 10-K, File No. 1-5324)
10.51 Master Lease Agreement between General Electric Capital Corporation
and CL&P, dated as of June 21, 1996. (Exhibit 10.50, 1996 NU Form
10-K, File No. 1-5324)
10.51.1 Amendment No. 1 to Master Lease Agreement, dated as of
August 29, 1997. (Exhibit 10.51.1, 1997 NU Form 10-K,
File No. 1-5324)
10.52 NU Guaranty, dated as of November 30, 1998, made by NU, in favor of
the Participating Banks, the Issuing Banks and the Administrative
Agent, all named in a $50,000,000 Letter of Credit and
Reimbursement Agreement, dated as of November 30, 1998, among
Select Energy, Inc., the Participating Banks, the Administrative
Agent, the Issuing Bank and Documentation Agent, and the
Syndication Agent named therein. (Exhibit B.1 (Execution Copy),
File No. 70-9343)
10.52.1 Amendment No. 1 dated as of November 30, 1998 to Exhibit
10.52. (Exhibit B.3 (Execution Copy), File No. 70-9343)
13 Annual Report to Security Holders (Each of the Annual Reports is filed
only with the Form 10-K of that respective registrant.)
* 13.1 Portions of the Annual Report to Shareholders of NU (pages 12-49)
that have been incorporated by reference into this Form 10-K.
13.2 Annual Report of CL&P.
13.3 Annual Report of WMECO.
13.4 Annual Report of PSNH.
13.5 Annual Report of NAEC.
*21 Subsidiaries of the Registrant.
27 Financial Data Schedules (Each Financial Data Schedule is filed only
with the Form 10-K of that respective registrant.)
27.1 Financial Data Schedule of NU.
27.2 Financial Data Schedule of CL&P.
27.3 Financial Data Schedule of WMECO.
27.4 Financial Data Schedule of PSNH.
27.5 Financial Data Schedule of NAEC.
Exhibit 3.2.3
CERTIFICATE OF AMENDMENT
STOCK CORPORATION
Office of the Secretary of the State
30 Trinity Street/P.O. Box 150470/Hartford, CT 06115-0470/new 1-97
Space for Office Use Only
1. NAME OF CORPORATION
The Connecticut Light and Power Company
2. THE CERTIFICATE OF INCORPORATION IS (check A., B. or C.):
X A. AMENDED.
B. AMENDED AND RESTATED.
C. RESTATED.
3. TEXT OF EACH AMENDMENT/RESTATEMENT:
SEE ATTACHMENT A
(Please reference an 8 1/2 X 11 attachment if additional space is
needed)
Space for Office Use Only
4. VOTE INFORMATION (check A., B. or C.)
X. A. The resolution was approved by shareholders as follows:
(set forth all voting information required by Conn. Gen. Stat.
section 33-800 as amended in the space provided below)
1. There are three classes of capital stock as follows:
Preferred Stock, $50 par value, 5,424,000 shares outstanding; Class A
Preferred Stock, $25 par value, 0 shares outstanding; and Common Stock, $10
par value, 12,222,930 shares outstanding.
2. No shares are entitled to be voted as a group.
3. The shareholders vote was as follows:
Vote required for adoption: 8,148,620
Vote favoring adoption: 12,222,930
B. The amendment was adopted by the board of directors without
shareholder action. No shareholder vote was required for adoption.
C. The amendment was adopted by the incorporators without shareholder
action. No shareholder vote was required for adoption.
5. EXECUTION
Dated this 27 th day of April, 1998
Print or type name of signatory
O. Kay Comendul
Capacity of signatory
Assistant Secretary
Signature
/s/O. Kay Comendul
ATTACHMENT A
(The Connecticut Light and Power Company)
RESOLVED, that Section IX of Part Two of Article IV of the Amended and
Restated Certificate of Incorporation of the Company, as amended on December
26, 1996, is hereby deleted in its entirety and replaced with a new Section
IX of Part Two of Article IV to read as follows:
SECTION IX
INDEMNIFICATION OF DIRECTORS, OFFICERS
EMPLOYEES AND AGENTS
Effective January 1, 1997, the Company shall indemnify and advance reasonable
expenses to an individual made or threatened to be made a party to a
proceeding because he/she is or was a Director of the Company to the fullest
extent permitted by law under Section 33-771 and Section 33-773 of the
Connecticut General Statutes, as may be amended from time to time
("Connecticut General Statutes"). The Company shall also indemnify and
advance reasonable expenses under Connecticut General Statutes Sections 33-
770 to 33-778, inclusive, as amended, to any officer, employee or agent of
the company who is not a Director to the same extent as a Director and to
such further extent, consistent with public policy, as may be provided by
contract, the Certificate of Incorporation of the Company, the Bylaws of the
Company or a resolution of the Board of Directors. In connection with any
advance for such expenses, the Company may, but need not, require any such
officer, employee or agent to deliver a written affirmation of his/her good
faith belief that he/she has met the relevant standard of conduct or a
written undertaking to repay any funds advanced for expenses if it is
ultimately determined that he/she is not entitled to indemnification. The
Board of Directors, by resolution, the general counsel of the Company, or
such additional officer or officers as the Board of Directors may specify,
shall have the authority to determine that indemnification or advance for
such expenses to any such officer, employee or agent is permissible and to
authorize payment of such indemnification or advance for expenses. The Board
of Directors, by resolution, the general counsel of the Company, or such
additional officer or officers as the Board of Directors may specify, shall
also have the authority to determine the terms on which the Company shall
advance expenses to any such officer, employee or agent, which terms need not
require delivery by such officer, employee or agent of a written affirmation
of his/her good faith belief that he/she has met the relevant standard of
conduct or a written undertaking to repay any funds advanced for such
expenses if it is ultimately determined that he/she is not entitled to
indemnification.
The indemnification and advance for expenses provided for herein shall not be
deemed exclusive of any other rights to which those indemnified or eligible
for advance for expenses may be entitled under Connecticut law as in effect
on the effective date hereof and as thereafter amended or any Bylaw,
agreement, vote of shareholders or disinterested directors or otherwise, both
as to action in such person's official capacity and as to action in another
capacity while holding such office, and shall continue as to a person who has
ceased to be a director, officer, employee or agent and shall inure to the
benefit of the heirs, executors and administrators of such a person.
No lawful repeal or modification of this Section IX or the adoption of any
provision inconsistent herewith by the Board of Directors and shareholders of
the Company or change in statute shall apply to or have any effect on the
obligations of the Company to indemnify or to pay for or reimburse in advance
expenses incurred by a director, officer, employee or agent of the Company in
defending any proceeding arising out of or with respect to any acts or
omissions occurring at or prior to the effective date of such repeal,
modification or adoption of a provision or statutes change inconsistent
herewith.
Exhibit 4.2.2
Supplemental Indenture
Dated as of December 1, 1969
TO
Indenture of Mortgage and Deed of Trust
Dated as of May 1, 1921
THE CONNECTICUT LIGHT AND POWER COMPANY
TO
BANKERS TRUST COMPANY,
Trustee
`
Northfield Mountain Property
THE CONNECTICUT LIGHT AND POWER COMPANY
Supplemental Indenture, Dated as of December 1, 1969
Table of Contents
Parties
Recitals
Granting Clauses
Habendum
Grant in Trust
SEC. 1.01. Benefits of Supplemental Indenture
SEC. 1.02. Effect of Table of Contents and Headings
SEC. 1.03 Counterparts
TESTIMONIUM
SIGNATURES
ACKNOWLEDGMENTS
SCHEDULE A - Property Subject to the Lien of the Mortgage
SUPPLEMENTAL INDENTURE, dated as of the first day of December, 1969,
between THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and
existing under the laws of the State of Connecticut (hereinafter called
"Company"), and BANKERS TRUST COMPANY, a corporation organized and existing
under the laws of the State of New York (hereinafter called "Trustee"),
WHEREAS, the Company heretofore duly executed, acknowledged and
delivered to the Trustee a certain Indenture of Mortgage and Deed of Trust
dated as of May 1, 1921 and twenty-six Supplemental Indentures thereto dated
respectively as of May 1, 1921, February 1, 1924, July 1, 1926, June 20,
1928, June 1, 1932, July 1, 1932, July 1, 1935, September 1, 1936, October
20, 1936, December 1, 1936, December 1, 1938, August 31, 1944, September 1,
1944, May 1, 1945, October 1, 1945, November 1, 1949, December 1, 1952,
December 1, 1955, January 1, 1958, February 1, 1960, April 1, 1961, September
1, 1963, April 1, 1967, May 1, 1967, January 1, 1968 and October 1, 1968
(said Indenture of Mortgage and Deed of Trust (i) as heretofore amended,
being hereinafter generally called the "Mortgage Indenture", and (ii)
together with said Supplemental Indentures thereto, being hereinafter
generally called the "Mortgage"), all of which have been duly recorded as
required by law, for the purpose of securing its First and Refunding Mortgage
Bonds (of which $285,600,000 aggregate principal amount are outstanding at
the date of this Supplemental Indenture) to an unlimited amount, issued and
to be issued for the purposes and in the manner therein provided, of which
Mortgage this Supplemental Indenture is intended to be made a part, as fully
as if therein recited at length; and
WHEREAS, the Company proposes to execute and deliver this Supplemental
Indenture to confirm the lien of the Mortgage on the property referred to
below, as permitted by Section 14.01 of the Mortgage Indenture; and
WHEREAS, the execution and delivery of this Supplemental Indenture and
other necessary actions have been duly authorized by the Board of Directors
of the Company; and
WHEREAS, all acts and things necessary to constitute this Supplemental
Indenture a valid, binding and legal instrument have been authorized and
performed;
NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE OF MORTGAGE AND DEED OF
TRUST WITNESSETH:
That in order to secure the payment of the principal of and interest on
all bonds issued and to be issued under the Mortgage, according to their
tenor and effect, and according to the terms of the Mortgage and this
Supplemental Indenture, and to secure the performance of the covenants and
obligations in said bonds and in the Mortgage and this Supplemental Indenture
respectively contained, and for the better assuring and confirming unto the
Trustee, its successor or successors and its or their assigns, upon the
trusts and for the purposes expressed in the Mortgage and this Supplemental
Indenture, all and singular the hereditaments, premises, estates and property
of the Company thereby conveyed or assigned or intended so to be, or which
the Company may thereafter have become bound to convey or assign to the
Trustee, as security for said bonds (except such hereditaments, premises,
estates and property as shall have been disposed of or released or withdrawn
from the lien of the Mortgage and this Supplemental Indenture, in accordance
with the provisions thereof and subject to alterations, modifications and
changes in said hereditaments, premises, estates and property as permitted
under the provisions thereof), the Company, for and in consideration of the
premises and the sum of One Dollar ($1.00) to it in hand paid by the Trustee,
the receipt whereof is hereby acknowledged, and of other valuable
considerations, has granted, bargained, sold, assigned, mortgaged, pledged,
transferred, set over, aliened, enfeoffed, released, conveyed and confirmed,
and by these presents does grant, bargain, sell, assign, mortgage, pledge,
transfer, set over, alien, enfeoff, release, convey and confirm unto said
Bankers Trust Company, as Trustee, and its successor or successors in the
trusts created by the Mortgage and this Supplemental Indenture, and its and
their assigns, all of said hereditaments, premises, estates and property
(except and subject as aforesaid), as fully as though described at length
herein including, without limitation of the foregoing, the property, rights
and privileges of the Company described or referred to in Schedule A hereto.
Together with all plants, buildings, structures, improvements and
machinery located upon said real estate or any portion thereof, and all
rights, privileges and easements of every kind and nature appurtenant
thereto, and all and singular the tenements, hereditaments and appurtenances
belonging to the real estate or any part thereof described or referred to in
Schedule A or intended so to be, or in anywise appertaining thereto, and the
reversions, remainders, rents, issues and profits thereof, and also all the
estate, right, title, interest, property, possession, claim and demand
whatsoever, as well in law as in equity, of the Company, of, in and to the
same and any and every part thereof, with the appurtenances; except and
subject as aforesaid.
TO HAVE AND TO HOLD all and singular the property, rights and privileges
hereby granted or mentioned or intended so to be, together with all and
singular the reversions, remainders, rents, revenues, income, issues and
profits, privileges and appurtenances, now or hereafter belonging or in any
way appertaining thereto, unto the Trustee and its successor or successors in
the trusts created by the Mortgage and this Supplemental Indenture, and its
and their assigns, forever, and with like effect as if the above described
property, rights and privileges had been specifically described at length in
the Mortgage and this Supplemental Indenture.
Subject, however, to permitted liens, as defined in the Mortgage
Indenture.
IN TRUST, NEVERTHELESS, upon the terms and trusts of the Mortgage and
this Supplemental Indenture for those who shall hold the bonds and coupons
issued and to be issued thereunder, or any of them, without preference,
priority or distinction as to lien of any said bonds and coupons over any
others thereof by reason of priority in the time of the issue or negotiation
thereof, or otherwise howsoever, subject, however, to the provisions in
reference to extended, transferred or pledged coupons and claims for interest
set forth in the Mortgage (and subject to any sinking fund that may be
hereafter created for the benefit of any particular series).
And it is hereby covenanted that the mortgaged premises are to be held
by the Trustee, upon and subject to the trusts, covenants, provisions and
conditions and for the uses and purposes set forth in the Mortgage and this
Supplemental Indenture, and the Company hereby ratifies, approves and
confirms the Mortgage in all respects as fully as if all the terms,
provisions, covenants and conditions thereof were herein again set forth at
length.
SECTION 1.01. Benefits of Supplemental Indenture. Nothing in this
Supplemental Indenture, expressed or implied, is intended or shall be
construed to give to any person or corporation other than the Company, the
Trustee and the holders of the bonds and interest obligations secured by the
Mortgage and this Supplemental Indenture, any legal or equitable right,
remedy or claim under or in respect of this Supplemental Indenture or of any
covenant, condition or provision herein contained. All the covenants,
conditions and provisions hereof are and shall be held to be for the sole and
exclusive benefit of the Company, the Trustee and the holders of the bonds
and interest obligations secured by the Mortgage and this Supplemental
Indenture.
SECTION 1.02. Effect of Table of Contents and Headings. The table of
contents and the descriptive headings of the several Sections of this
Supplemental Indenture are inserted for convenience of reference only and are
not to be taken to be any part of this Supplemental Indenture or to control
or affect the meaning, construction or effect of the same.
SECTION 1.03. Counterparts. For the purpose of facilitating the record
hereof, this Supplemental Indenture may be executed in any number of
counterparts, each of which shall be and shall be taken to be an original and
all collectively but one instrument.
IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused
these presents to be executed by its President or a Vice President and its
corporate seal to be hereunto affixed, duly attested by its Secretary or an
Assistant Secretary, and Bankers Trust Company has caused these presents to
be executed by a Vice President or Assistant Vice President and its corporate
seal to be hereunto affixed, duly attested by one of its Assistant
Secretaries, as of the Day and year first above written.
THE CONNECTICUT LIGHT AND POWER COMPANY,
(CORPORATE SEAL)
A. E. WALLACE
President.
Attest:
F. L. Kinney
Secretary.
Sealed, signed and delivered in the presence of:
D. R. Greim
R. E. Griswold
BANKERS TRUST COMPANY,
(CORPORATE SEAL)
C. D. Blakely
Vice President
Attest:
A. D. Fass
Assistant Secretary.
Sealed, signed and delivered in the presence of:
P.J. Monaghan
Jerry G. Caden
STATE OF CONNECTICUT
ss:
COUNTY OF HARTFORD
On this 22 nd day of December, 1969, before me, DOROTHY R. GREIM, the
undersigned officer, personally appeared A. E. WALLACE and F. L. KINNEY, who
acknowledged themselves to be President, and Secretary of THE CONNECTICUT
LIGHT AND POWER COMPANY, a corporation, and that they, as such President, and
Secretary, being authorized so to do, executed the foregoing instrument for
the purposes therein contained, by signing the name of the corporation by
themselves as President, and Secretary and affixing the seal of the
corporation, and acknowledged the foregoing instrument to be the free act and
deed of the corporation.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
DOROTHY R. GREIM
Notary Public
(NOTARIAL SEAL)
My Commission Expires April 1, 1972
STATE OF NEW YORK
ss:
COUNTY OF NEW YORK
On this the 22nd day of December, 1969, before me, BETTY A. BOLAND, the
undersigned officer, personally appeared C.D. BLAKELY and A.D. FASS, who
acknowledged themselves to be Vice President, and Assistant Secretary of
BANKERS TRUST COMPANY, a corporation; and that they, as such Vice President,
and Assistant Secretary, being authorized so to do, executed the foregoing
instrument for the purposes therein contained, by signing the name of the
corporation by themselves as Vice President, and Assistant Secretary and
affixing the seal of the corporation, and acknowledged the foregoing
instrument to be the free act and deed of the corporation.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
BETTY A. BOLAND
Notary Public
(NOTARIAL SEAL)
My Commission Expires
BETTY A. BOLAND
Notary Public, State of New York
No. 43-0344990
Qualified in Richmond County
Certificate filed in New York County
Commission Expires March 30, 1971
SCHEDULE A
PROPERTY SUBJECT TO THE LIEN OF THE MORTGAGE
An undivided fifty three (53) per cent interest as tenant in common in
and to the following parcels of land together with all buildings and
improvements thereon in the Towns of Erving and Northfield, in the County of
Franklin and Commonwealth of Massachusetts:
PARCEL 1.
A certain parcel of land situated in Erving, bounded and described as
follows:
Beginning at the northeasterly corner of said parcel at a point
approximately 3420.89 feet westerly from Mountain Road in the Town of Erving
and County of Franklin; thence South 16 degrees 33' 10" East 3323.51 feet to
a point; thence South 21 degrees 10' 34" West 3738.71 feet more or less to an
iron pin in stones; thence South 67 degrees 39' 08" West 299.98 feet more or
less to a stone bound in stones; thence South 73 degrees 20' 20" West 1128.95
feet more or less to a stone in stones; thence South 16 degrees 13' 40" East
328.52 feet more or less to a stone bound in stones; thence South 71 degrees
33' 07" West 1519.10 feet more or less to a stone bound in stones; thence
South 14 degrees 33' 07" West 1519.10 feet more or less to a stone bound in
stones; thence South 14 degrees 53' 04" East 669.42 feet to a point "A";
thence continuing along the above course 300 feet to a point; thence North 79
degrees 56' 08" West 250 feet more or less to point, which is South 35
degrees 00' 48" West 300 feet from Point "A"; thence South 35 degrees 00' 48"
West 1086.20 feet more or less to an iron pin in stones; thence South 3
degrees 28' 05" West 545.74 feet more or less to a pile of stones; thence
South 15 degrees 14' 20" East 1326.95 feet more or less to a stone bound;
thence South 74 degrees 08' 40" West 1344.65 feet more or less to a stone
bound; thence North 16 degrees 35' 37" West 2333.88 feet more or less to an
iron pin; thence North 16 degrees 30' 42" West 317.45 feet more or less to an
iron pin; thence North 16 degrees 37' 27" West 660.81 feet more or less to a
stone bound; thence South 72 degrees 52' 14" West 173.80 feet more less to an
iron pin; thence South 73 degrees 06' 33" West 205.62 feet more or less to an
iron pin; thence South 73 degrees 01' 08" West 296.89 feet more or less to an
iron pin; thence South 73 degrees 57' 35" West 272.83 feet more or less to a
stone bound; thence North 22 degrees 47' 24" West 771.68 feet to a point;
thence North 72 degrees 46' 02" East 554.28 feet to a point; thence North 15
degrees 00' 47" West 376.63 feet to a point; thence South 72 degrees 55' 20"
West 634.26 feet more or less to a stake and stones; thence North 14 degrees
59' 03" West 345.18 feet to a point; thence South 73 degrees 03' 14" West
1211.04 feet more or less to a point; thence North 4 degrees 49' 00" West
539.43 feet to a stone bound at a corner in the Erving-Northfield Town Line;
thence North 4 degrees 40' 00" West 4932.76 feet along said Town Line to a
stone bound; thence North 73 degrees 59' 32" East along said Town Line
5371.89 feet to a stone bound; thence North 73 degrees 46' 23" East along
said Town Line 1410.84 feet to a stone bound; thence North 73 degrees 46' 09"
East along said Town Line 1394.60 feet to a point; thence South 14 degrees
49' 50" East 21.65 feet to an iron pin; thence North 73 degrees 26' 15" East
234.77 feet to a point; thence North 73 degrees 20' 05" East 581.97 feet to
an iron pin; thence North 73 degrees 05' 00" East 102.38 feet to the point of
beginning. Containing 1,496 acres more or less.
Subject to the right of way for transmission lines in favor of Western
Massachusetts Electric Company hereinafter described leading northeasterly
across the northwesterly portion of the above parcel, together with the right
to use and travel over any and all extensions on the above parcel of the road
described in the description of Parcel 2.
Parcel 2
A certain parcel of land situated in the southerly part of the Town of
Northfield and lying between Route 63 and the Northfield-Erving Town Line,
bounded and described as follows:
Beginning at the southeasterly corner of the land herein conveyed at a
stone in stones in the Town Line between Erving and Northfield, said stone
and stones being North 4 degrees 49' East 1063.21 feet from a stone bound at
a corner in said Town Line; thence South 85 degrees 17' 10" West 1335.08 feet
to a point; thence North 13 degrees 35' 50" West 475.58 feet to a point;
thence North 8 degrees 00' 00" East 570.41 feet to a point; thence North 82
degrees 00' 00" West 530.00 feet to a point; thence South 87 degrees 11' 00"
West 330.00 feet to a point; thence South 8 degrees 00' 00" West 850.00 feet
to a point; thence South 85 degrees 31' 50" West 916.63 feet to a point in
the easterly line of the Massachusetts State Highway known as Route 63, said
point being 333.04 feet northerly from a stone bound at the southwesterly
corner of land formerly of Roger W. Billings; thence North 4 degrees 39' 27"
East 818.89 feet along said highway to a Massachusetts Highway Bound; thence
North 4 degrees 48' 08" East 150.87 feet more or less to a point in the south
line of land of Inhabitants of Town of Northfield known as the Northfield
Farms Cemetery; thence North 87 degrees 35' 23" East 22.00 feet to a point;
thence North 4 degrees 48' 08" East 22.00 feet to a point; thence North 87
degrees 35' 23" East 504.52 feet to a concrete bound; thence North 3 degrees
51' 53" East 245.88 feet to a concrete bound; thence South 85 degrees 40' 20"
West 250.54 feet to a concrete post; thence South 85 degrees 44' 46" West
74.66 feet more or less to a concrete bound (the last mentioned six courses
being along said Cemetery); thence North 5 degrees 26' 49" East along land
retained by Eugene J. Galvis 450.00 feet to a concrete bound; thence South 85
degrees 44' 46" West along land of said Galvis 200 feet to a concrete bound
in the easterly line of the aforesaid Route 63; thence North 5 degrees 26'
49" East along said Highway 149.41 feet to a Massachusetts Highway Bound;
(the description of the last four courses in a warranty deed from Eugene J.
Galvis dated September 24, 1965, being as follows: "thence South 85 degrees
47' 21" West along the Northfield Farms Cemetery 82.97 feet to a point in the
north line of the Northfield Farms Cemetery; thence North 6 degrees 13' 58"
East along land of Eugene J. Galvis 449.99 feet; thence South 85 degrees 47'
21" West along land of Eugene J. Galvis 200 feet to Route 63; thence North 6
degrees 13' 58" East along Route 63 a distance of 150.59 feet to Route 63;")
thence North 5 degrees 38' 13" East 233.82 feet to a point in the south line
of land formerly of Frank Fuller; thence North 85 degrees 34' 45" East along
said southerly line of land formerly of Fuller 861.88 feet to a point; thence
North 8 degrees 37' 06" East 1214.80 feet to a point in the southerly line of
land now or formerly of Norman F. Fowler; thence north 74 degrees 14' 02"
East 1769.94 feet to a stone bound at a corner in the Town Line between
Erving and Northfield; thence South 4 degrees 49' West 3869.55 feet to the
place of beginning, containing 190 acres more or less.
Subject to the right of way for transmission lines in favor of Western
Massachusetts Electric Company hereinafter described, leading northerly and
easterly across the above parcel and subject to the right of Western
Massachusetts Electric Company to use and travel over the road leading from
Route 63 to the access tunnel and thence to other land of Western
Massachusetts Electric Company.
Said parcel of land is conveyed subject to a thirty foot right of way
for the Inhabitants of the Town of Northfield leading easterly from Route 63,
said right of way being 8 feet in width at the aforesaid Route 63.
The above reserved right of way for transmission lines in favor of
Western Massachusetts Electric Company is described as follows:
A right of way 250 feet in width being on the westerly and northerly
side 170 feet and on the southerly and easterly side 80 feet from the
following described survey line.
Beginning at a point in Parcel 2 which is North 82 degrees 00' 00" West
387 feet from the northerly end of the third course described in said Parcel;
thence North 8 degrees 00' 00" East 2161.63 feet to an angle point; thence
North 72 degrees 00' 00" East 3076.88 feet crossing the line dividing Parcel
2 and Parcel 1 to an angle point; thence North 54 degrees 30' 00" East 894.07
feet to a point in the Town Line between Erving and Northfield, said point
being North 73 degrees 59' 32" East 2636.05 feet from a stone bound at a
corner in said Town Line, said corner being the northwesterly corner of
Parcel No. 1 and the northeasterly corner of Parcel No. 2.
PARCEL 3
A certain parcel of land situated in the Town of Northfield and lying
westerly of Route 63 bounded and described as follows:
Beginning at a concrete bound at the intersection of the westerly line
of the Massachusetts State Highway known as Route 63 and the southerly line
of Ferry Road; thence South 5 degrees 34' 01" West along said Route 63 261.60
feet to a Massachusetts Highway Bound; thence South 4 degrees 39' 27" West
905 feet more or less along said Highway to the center line of a culvert at
the southeasterly corner of the first tract of land conveyed by Frank S.
Fuller et ux. to Western Massachusetts Electric Company; thence South 84
degrees 20' West 584.32 feet more or less to land of the Central Vermont
Railways Inc.; thence continuing the same course and crossing land of said
Railroad 82.5 feet to the Railroad's westerly line; thence continuing South
84 degrees 20' West 412.28 feet to an iron pin; thence South 83 degrees 03'
West 608.23 feet to a pile of stones; thence North 17 degrees 30' East 392.30
feet to a fence post in the southerly line of land conveyed by Sobieski to
Western Massachusetts Electric Company; thence South 83 degrees 47' West
96.28 feet to a point in the southeasterly line of the relocation of River
Road by the Commissioners of Franklin County as evidenced by an instrument of
taking by eminent domain by said Commissioners dated December 16, 1969, and
recorded in the said Registry of Deeds in Book 1250, Page 662 (hereinafter
referred to as "layout"); thence northeasterly along said relocated Road by a
curve to the right, having a radius of 770.00 feet 100.55 feet to Bound 3 of
said layout; thence North 64 degrees 01' 50" East 303.96 feet to Bound 4;
thence by a curve to the left having a radius of 830.00 feet 480 feet more or
less to a point which is North 88 degrees 04' East from center line Station
13 + 78.46 of said layout; thence South 88 degrees 04' West 72 feet more or
less across said Road and passing through Station 13 + 78.46 on the center
line of said layout to a point on the westerly side of said layout; thence
southwesterly by a curve to the right having a radius of 770.00 feet 410 feet
more or less to Bound 4A; thence South 64 degrees 01' 50" West 303.96 feet to
Bound 3A; thence southwesterly by a curve to the left having a radius of
830.00 feet 212.45 feet to the southerly line of land conveyed by Sobieski to
Western Massachusetts Electric Company; thence South 83 degrees 47' 00" West
71.28 feet to a stump in the northeasterly line of River Road a County Road
now abandoned and discontinued; thence continuing the same course 38 feet
more or less across said abandoned County Road to other land of Western
Massachusetts Electric Company; thence northerly along the northwesterly side
of said abandoned County Road about 520 feet more or less to a concrete
bound; thence North 24 degrees 45' 22" East along said other land of Western
Massachusetts Electric Company 557.86 feet to a concrete bound; thence North
16 degrees 05' 43" East 541.29 feet to a concrete bound; thence North 28
degrees 54' 45" East 62.86 feet to a fence corner; thence South 77 degrees
49' 45" East 290 feet more or less to the westerly line of said layout;
thence by a curve to the left having a radius of 830.00 feet 274.14 feet more
or less to Bound 6A; thence South 9 degrees 45' 00" East 130.36 feet to Bound
5A; thence by a curve to the right having a radius of 770.00 feet 156 feet
more or less to a point which is South 88" 04' West of Station 18+06.26 of
the center line of said layout; thence North 88 degrees 04' East across said
County Road and passing through Station 18+06.26 of the center line of said
layout 60 feet more or less to the easterly side of said layout; thence by a
curve to the left having a radius of 830.00 feet 129 feet more or less to
Bound 5 of said layout at the southeasterly line of the relocation of Ferry
Road; thence North 80 degrees 15' East along said road 20.11 feet to Bound 6
of said layout; thence North 89 degrees 25' East 46.52 feet to Bound 7 of
said layout at the end of the relocation of Ferry Road; thence southeasterly
along Ferry Road about 90 feet to land of said Central Vermont Railways Inc.;
thence continuing southeasterly along said Road and across land of said
Railroad 82.5 feet to the easterly line of said Railroad; thence continuing
southeasterly along said Ferry Road and across the Old County Road leading
from Northfield to Millers Falls about 500 feet to a concrete bound at the
westerly end of the 1967 extension of said Ferry Road; thence South 86
degrees 13' 50" East along said road 132.50 feet to a concrete bound; thence
South 84 degrees 25' 59" East along said Road 49.06 feet to the place of
beginning; containing 50 acres more or less, including that portion of the
Old County Highway leading from Northfield to Millers Falls which was
discontinued and abandoned by the County Commissioners November 14, 1967 by
instrument recorded by said Registry of Deeds Book 1218 Page 166, also those
portions of Ferry Road and River Road which were discontinued and abandoned
by the County Commissioners by the instrument of taking dated December 16,
1969 aforesaid.
Excepting therefrom land of the Central Vermont Railways Inc. which runs
in a northerly direction across land formerly of Fuller and Sobieski.
There is also hereby assigned certain perpetual easements consisting of
the right to construct, operate, maintain and repair two tailrace tunnels
under said Route 63 granted to Western Massachusetts Electric Company, its
successors and assigns, by the Commonwealth of Massachusetts by instrument
dated December 10, 1969 to be recorded herewith but prior to the recording
hereof.
There is also hereby assigned like perpetual easements under the right
of way in said Town of Northfield of Central Vermont Railway, Inc., a
corporation of Vermont, granted to Western Massachusetts Electric Company,
its successors and assigns, by said railroad corporation by deed dated
January 29, 1969, recorded with said Registry of Deeds, Book 1237 Page 511.
Said land is conveyed subject to an easement 60 feet in width for a
County highway between Stations 13+78.46 and 18+06.26 of the County highway
layout dated December 16, 1969, recorded in said Registry of Deeds Book 1250
Page 662.
PARCEL 4
A certain parcel of land situated in Erving bounded and described as
follows:
Beginning at an iron pin in the westerly side of Mountain Road South 16
degrees 12' 25" East a distance of 138.67 feet from a point marking the
southeast corner of land formerly of Francis A. Coutu and now of Western
Massachusetts Electric Company; thence South 66 degrees 25' 04" West 679.39
feet to a concrete bound; thence South 56 degrees 04' 34" West 2871.50 feet
to a concrete bound; thence South 16 degrees 33' 10" East 209.59 feet to a
concrete bound; thence north 56 degrees 04' 34" East 2638.50 feet to a
concrete bound; thence North 66 degrees 25' 04" East 635.25 feet to a
concrete bound; thence North 16 degrees 12' 25" West 201.67 feet to the point
of beginning, containing 15.667 acres.
Subject to a right of way over said strip for passage by vehicle or on
foot in common with Western Massachusetts Electric Company.
The interest of The Connecticut Light and Power Company in all of the
above described property consists of a tenancy in common with Western
Massachusetts Electric Company and The Hartford Electric Light Company with
rights of partition reciprocally suspended (pursuant to G.L. c. 164, Section
99A) so long as said property is used or useful for electric utility company
purposes.
Exhibit 4.2.17
SUPPLEMENTAL INDENTURE
Dated as of May 1, 1998
To
Indenture of Mortgage and Deed of Trust
Dated as of May 1, 1921
THE CONNECTICUT LIGHT AND POWER COMPANY
TO
BANKERS TRUST COMPANY, Trustee
1998 Series A Bonds, Due June 1, 1999
THE CONNECTICUT LIGHT AND POWER COMPANY
Supplemental Indenture, Dated as of May 1, 1998
TABLE OF CONTENTS
Parties
Recitals
Granting Clause
Habendum
Grant in Trust
ARTICLE 1. FORM AND PROVISIONS OF BONDS OF 1998 SERIES A
SECTION 1.01. Designation; Amount
SECTION 1.02. Form of Bonds of 1998 Series A
SECTION 1.03. Provisions of Bonds of 1998 Series A; Interest Accrual
SECTION 1.04. Transfer and Exchange of Bonds of 1998 Series A;
Collateral Agent as
Registered Holder: Restriction on Transfer of Bonds of 1998 Series A
SECTION 1.05. Conditions under which 1998 Series A Bond Not Entitled to
Benefits of Mortgage
SECTION 1.06. No Redemption
ARTICLE 2. REPAYMENT OF BONDS OF 1998 SERIES A
SECTION 2.01. Repayment upon reduction of aggregate commitment under the
Facility
ARTICLE 3. MISCELLANEOUS
SECTION 3.01. Benefits of Supplemental Indenture and Bonds of 1998
Series A
SECTION 3.02. Effect of Table of Contents and Headings
SECTION 3.03. Counterparts
SECTION 3.04. Payment Due on Holidays
TESTIMONIUM
SIGNATURES
ACKNOWLEDGMENTS
SCHEDULE A - Form of Bond of 1998 Series A; Form of Trustee's Certificate
SUPPLEMENTAL INDENTURE, dated as of the first day of May, 1998, between THE
CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and existing
under the laws of the State of Connecticut (hereinafter called "CL&P"), and
BANKERS TRUST COMPANY, a corporation organized and existing under the laws of
the State of New York (hereinafter called the "Trustee").
WHEREAS, CL&P heretofore duly executed, acknowledged and delivered to the
Trustee a certain Indenture of Mortgage and Deed of Trust dated as of May 1,
1921, and sixty-eight Supplemental Indentures thereto dated respectively as
of May 1, 1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932,
July 1, 1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1,
1936, December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945,
October 1, 1945, November 1, 1949, December 1, 1952, December 1, 1955,
January 1, 1958, February 1, 1960, April 1, 1961, September 1, 1963, April 1,
1967, May 1, 1967, January 1, 1968, October 1, 1968, December 1, 1969,
January 1, 1970, October 1, 1970, December 1, 1971, August 1, 1972, April 1,
1973, March 1, 1974, February 1, 1975, September 1, 1975, May 1, 1977, March
1, 1978, September 1, 1980, October 1, 1981, June 30, 1982, October 1, 1982,
July 1, 1983, January 1, 1984, October 1, 1985, September 1, 1986, April 1,
1987, October 1, 1987, November 1, 1987, April 1, 1988, November 1, 1988,
June 1, 1989, September 1, 1989 , December 1, 1989, April 1, 1992, July 1,
1992, October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February
1, 1994, February 1, 1994, June 1, 1994, October 1, 1994, June 1, 1996,
January 1, 1997, May 1, 1997, June 1, 1997 and June 1, 1997 (said Indenture
of Mortgage and Deed of Trust (i) as heretofore amended, being hereinafter
generally called the "Mortgage Indenture," and (ii) together with said
Supplemental Indentures thereto, being hereinafter generally called the
"Mortgage"), all of which have been duly recorded as required by law, for the
purpose of securing its First and Refunding Mortgage Bonds (of which
$1,726,000,000 aggregate principal amount are outstanding at the date of this
Supplemental Indenture) in an unlimited amount, issued and to be issued for
the purposes and in the manner therein provided, of which Mortgage this
Supplemental Indenture is intended to be made a part, as fully as if therein
recited at length;
WHEREAS, in order to provide a single, comprehensive, efficient framework for
the financing of nuclear fuel for Millstone 1 and Millstone 2, as well as
CL&P's and Western Massachusetts Electric Company's ("WMECO" and, together
with CL&P, the "Companies") approximately 65.172% ownership interest in the
nuclear fuel for Millstone 3, the Companies entered into arrangements with
Bankers Trust Company, not in its individual capacity but solely as trustee
(the "NBFT Trustee") of the Niantic Bay Fuel Trust (the "Trust") which was
specially created for the purpose of such financing pursuant to a Trust
Agreement dated as of January 4, 1982, as amended and restated as of February
11, 1992 (the "Trust Agreement"), among Bankers Trust Company, as trustee,
State Street Bank and Trust Company of Connecticut, National Association
(which is the successor trustor to the New Connecticut Bank and Trust
Company, National Association, as assignee of the Federal Deposit Insurance
Corporation, as receiver of The Connecticut Bank and Trust Company, National
Association), as Trustor (the "Trustor"), and CL&P, WMECO and The Hartford
Electric Light Company (which merged with and into CL&P on June 30, 1982), as
beneficiaries;
WHEREAS, pursuant to a Nuclear Fuel Lease Agreement (the "Lease Agreement")
dated as of January 4, 1982, as amended and restated as of February 11, 1992,
between CL&P and WMECO, The Hartford Electric Light Company, and the NBFT
Trustee, the Companies have assigned to the NBFT Trustee all of their right,
title, and interest in and to all or part of certain nuclear fuel contracts
and nuclear fuel and the NBFT Trustee, in turn, has agreed to either
reimburse the Companies for payments made to contractors under the assigned
nuclear fuel contracts or to make such payments directly to the contractors;
WHEREAS, as part of the nuclear fuel financing arrangements for the Millstone
Units, the NBFT Trustee entered into a revolving credit facility (the
"Facility") with a syndicate of banks which, pursuant to its terms, was
scheduled to expire on February 19, 1998 and, in connection therewith, a
credit agreement dated as of February 11, 1992, as amended pursuant to a
First Amendment dated as of April 30, 1993 and a Second Amendment dated as of
May 12, 1995, with each of the financial institutions party thereto, and The
First National Bank of Chicago (the "Bank Agent"), as agent for such
financial institutions (as so named and as it may have been otherwise
supplemented, amended or modified through the date hereof the "Current Credit
Agreement" and together with any replacement therefor, the "Credit
Agreement");
WHEREAS, in order to induce the banks to extend the Facility through July 31,
1998, the Companies were required to agree to provide additional collateral,
equal to 50 percent of the banks' commitment under the Facility, by May 1,
1998 in the form of first mortgage bonds, as set forth in a Third Amendment
and Waiver to Credit Agreement dated as of February 19, 1998 (the
"Amendment");
WHEREAS, to satisfy the requirement under the Amendment and to meet a
contractual requirement that the holders of the Trust's Intermediate Term
Notes (the "IT Notes") are entitled to equal treatment with the banks, CL&P
agreed, by appropriate and sufficient corporate action in conformity with the
provisions of the Mortgage to create a further series of bonds under the
Mortgage, First and Refunding Mortgage Bonds, 1998 Series A (hereinafter
generally referred to as the "1998 Series A Bonds" or the "bonds of 1998
Series A"), limited in principal amount to $72,900,000 to be issued to secure
CL&P's obligations under the Lease Agreement and to be assigned by the NBFT
Trustee to The First National Bank of Chicago as Collateral Agent and Pledgee
(the "Collateral Agent") under a certain Security Agreement and Assignment of
Contracts dated as of January 4, 1982, as amended and restated February 11,
1992, (the "Security Agreement") between the NBFT Trustee and the Collateral
Agent for the ratable benefit of the Secured Parties referred to therein (the
"Secured Parties"). The 1998 Series A Bonds shall consist of fully
registered bonds containing terms and provisions duly fixed and determined by
the Board of Directors of CL&P and expressed in this Supplemental Indenture,
including terms and provisions with respect to maturity, interest payment,
interest rate and repayment as provided herein. Such fully registered bonds
and the Trustee's certificate of its authentication thereof to be
substantially in the forms thereof respectively set forth in Schedule A
appended hereto and made a part hereof;
WHEREAS, the execution and delivery of this Supplemental Indenture and the
issue of not exceeding Seventy-Two Million Nine Hundred Thousand Dollars
($72,900,000) in aggregate principal amount of bonds of 1998 Series A and
other necessary actions have been duly authorized by the Board of Directors
of CL&P;
WHEREAS, CL&P proposes to execute and deliver this Supplemental Indenture to
provide for the issue of the bonds of 1998 Series A and to confirm the lien
of the Mortgage on the property referred to below, all as permitted by
Section 14.01 of the Mortgage Indenture; and
WHEREAS, all acts and things necessary to constitute this Supplemental
Indenture a valid, binding and legal instrument and to make the bonds of 1998
Series A when executed by CL&P and authenticated by the Trustee valid,
binding and legal obligations of CL&P have been authorized and performed;
NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE OF MORTGAGE AND DEED OF TRUST
WITNESSETH:
That in order to secure the payment of the principal of and interest on all
bonds issued and to be issued under the Mortgage, according to their tenor
and effect, and according to the terms of the Mortgage and this Supplemental
Indenture, and to secure the performance of the covenants and obligations in
said bonds and in the Mortgage and this Supplemental Indenture respectively
contained, and for the better assuring and confirming unto the Trustee, its
successor or successors and its or their assigns, upon the trusts and for the
purposes expressed in the Mortgage and this Supplemental Indenture, all and
singular the hereditaments, premises, estates and property of CL&P thereby
conveyed or assigned or intended so to be, or which CL&P may thereafter have
become bound to convey or assign to the Trustee, as security for said bonds
(except such hereditaments, premises, estates and property as shall have been
disposed of or released or withdrawn from the lien of the Mortgage and this
Supplemental Indenture, in accordance with the provisions thereof and subject
to alterations, modifications and changes in said hereditaments, premises,
estates and property as permitted under the provisions thereof), CL&P, for
and in consideration of the premises and the sum of One Dollar ($1.00) to it
in hand paid by the Trustee, the receipt whereof is hereby acknowledged, and
of other valuable consideration, has granted, bargained, sold, assigned,
mortgaged, pledged, transferred, set over, aliened, enfeoffed, released,
conveyed and confirmed, and by these presents does grant, bargain, sell,
assign, mortgage, pledge, transfer, set over, alien, enfeoff, release, convey
and confirm unto said Bankers Trust Company, as Trustee, and its successor or
successors in the trust created by the Mortgage and this Supplemental
Indenture, and its and their assigns, all of said hereditaments, premises,
estates and property (except and subject as aforesaid), as fully as though
described at length herein. Together with all plants, buildings, structures,
improvements and machinery located upon said real estate or any portion
thereof, and all rights, privileges and easements of every kind and nature
appurtenant thereto, and all and singular the tenements, hereditaments and
appurtenances belonging to the real estate or any part thereof described or
referred to therein or intended so to be, or in any wise appertaining
thereto, and the reversions, remainders, rents, issues and profits thereof,
and also all the estate, right, title, interest, property, possession, claim
and demand whatsoever, as well in law as in equity, of CL&P, of, in and to
the same and any and every part thereof, with the appurtenances; except and
subject as aforesaid.
TO HAVE AND TO HOLD all and singular the property, rights and privileges
hereby granted or mentioned or intended so to be, together with all and
singular the reversions, remainders, rents, revenues, income, issues and
profits, privileges and appurtenances, now or hereafter belonging or in any
way appertaining thereto, unto the Trustee and its successor or successors in
the trust created by the Mortgage and this Supplemental Indenture, and its
and their assigns, forever, and with like effect as if the above described
property, rights and privileges had been specifically described at length in
the Mortgage and this Supplemental Indenture.
Subject, however, to permitted liens, as defined in the Mortgage Indenture.
IN TRUST, NEVERTHELESS, upon the terms and trusts of the Mortgage and this
Supplemental Indenture for those who shall hold the bonds and coupons issued
and to be issued thereunder, or any of them, without preference, priority or
distinction as to lien of any of said bonds and coupons over any others
thereof by reason of priority in the time of the issue or negotiation
thereof, or otherwise howsoever, subject, however, to the provisions in
reference to extended, transferred or pledged coupons and claims for interest
set forth in the Mortgage and this Supplemental Indenture (and subject to any
sinking fund that may heretofore have been or hereafter be created for the
benefit of any particular series).
And it is hereby covenanted that all such bonds of 1998 Series A are to be
issued, authenticated and delivered, and that the mortgaged premises are to
be held by the Trustee, upon and subject to the trusts, covenants, provisions
and conditions and for the uses and purposes set forth in the Mortgage and
this Supplemental Indenture and upon and subject to the further covenants,
provisions and conditions and for the uses and purposes hereinafter set
forth, as follows, to wit:
ARTICLE 1.
FORM AND PROVISIONS OF BONDS OF 1998 SERIES A
SECTION 1.01. Designation; Amount. The bonds of 1998 Series A shall be
designated "First and Refunding Mortgage Bonds, 1998 Series A" and, subject
to Section 2.08 of the Mortgage Indenture, shall not exceed Seventy-Two
Million Nine Hundred Thousand Dollars ($72,900,000) in aggregate principal
amount at any one time outstanding. The initial issue of the bonds of 1998
Series A may be effected upon compliance with the applicable provisions of
the Mortgage Indenture.
SECTION 1.02. Form of Bonds of 1998 Series A. The bonds of 1998 Series A
shall be issued only in fully registered form without coupons in
denominations of One Thousand Dollars ($1,000) and multiples thereof.
The bonds of 1998 Series A and the certificate of the Trustee upon said bonds
shall be substantially in the forms thereof respectively set forth in
Schedule A appended hereto.
SECTION 1.03. Provisions of Bonds of 1998 Series A; Interest Accrual. The
bonds of 1998 Series A shall mature on June 1, 1999 and shall bear interest
at the Lease Rate (as defined below), as applicable from time to time, but
such interest shall accrue only upon and following the occurrence and during
the continuance of an Accelerating Event (as defined below); provided,
however, that in no event shall the interest rate payable on the 1998 Series
A Bonds exceed 11% per annum; and shall be payable both as to principal and
interest at the office or agency of CL&P in the Borough of Manhattan, New
York, New York, in any coin or currency of the United States of America which
at the time of payment is legal tender for the payment of public and private
debts. After a responsible officer of the Trustee shall have received
written notice from the Collateral Agent of the occurrence of an Accelerating
Event, specifying in reasonable detail the events giving rise to the
Accelerating Event and the date of its occurrence, interest on the
outstanding 1998 Series A Bonds shall be due and payable on demand; provided,
however, that upon the occurrence of an Accelerating Event which is an
Insolvency Event, interest shall be immediately due and payable on demand
whether or not the Trustee has received notice of the occurrence of such
Accelerating Event. Interest shall accrue from and including the date of
occurrence of an Accelerating Event and shall continue to accrue during the
continuance of such Accelerating Event. Interest on the outstanding 1998
Series A Bonds shall cease to accrue following the discontinuance of any such
Accelerating Event as evidenced by a written notice from an officer of the
Collateral Agent to a responsible officer of the Trustee, and any interest on
the outstanding 1998 Series A Bonds that has accrued but has not yet become
due and payable at the time such notice is given shall be extinguished and
shall not be required to be paid at any time thereafter.
Except as specified in the preceding paragraph, no interest shall accrue or
be payable on the 1998 Series A Bonds.
An "Accelerating Event" shall be deemed to have occurred on any date on which
an Event of Default (as defined in the Security Agreement) shall have
occurred and be continuing.
An "Insolvency Event" shall be deemed to have occurred on any date an Event
of Default described in Section 7.1.1 or 7.1.2 of the Current Credit
Agreement, or an Event of Default of the same nature described in any Credit
Agreement or any IT Note Agreement, (as defined in the Lease Agreement),
shall have occurred and be continuing.
The term "Lease Rate" shall mean for any day that rate sufficient to generate
interest due on the outstanding 1998 Series A Bonds for such day in an
aggregate amount equal to that portion of the Daily Lease Charge (as defined
in the Lease Agreement) for such day which is the obligation of CL&P under
the Lease Agreement, but in no event shall such rate exceed 11% per annum.
From time to time following the occurrence of an Accelerating Event, CL&P at
the request of the Collateral Agent shall certify to the Collateral Agent,
the Trustee and the NBFT Trustee the applicable Lease Rate for each day of
the period covered by such certificate.
If any amounts due under the Credit Agreement or any IT Note Agreement (as
defined in the Lease Agreement) shall become, or any bank acting as agent on
behalf of the financial institutions party to the Credit Agreement or the
holder or holders of any IT Notes shall so declare amounts due under such
Credit Agreement or IT Note Agreement, as the case may be, to be, forthwith
due and payable pursuant to the terms of such Credit Agreement or IT Note
Agreement, as the case may be, the entire principal of the bonds of 1998
Series A, together with interest accrued but unpaid thereon, shall without
notice or demand of any kind, become immediately due and payable.
Anything in the Mortgage, this Supplemental Indenture or any bond of 1998
Series A to the contrary notwithstanding, the bonds of 1998 Series A shall be
deemed paid, and all obligations of CL&P to pay at the times provided herein
the principal of, premium, if any, and interest on the bonds of 1998 Series A
shall be satisfied and discharged, if and to the extent, that (A) the Current
Credit Agreement is terminated in its entirety and all obligations thereunder
shall have been paid in full and CL&P shall not have given notice to the
Trustee that such 1998 Series A Bonds shall remain outstanding, (B) each of
the financial institutions party to the Credit Agreement has agreed in
writing that the 1998 Series A Bonds shall be deemed paid, or (C) on June 1,
1999, no Event of Default (as defined in the Security Agreement) shall have
occurred and be continuing; it being understood that the actual indebtedness
evidenced by the 1998 Series A Bonds as of any time shall be limited to 81%
of the Secured Obligations (as defined in the Security Agreement) as
determined at such time, that at no time shall any claim be made for
principal and interest on the 1998 Series A Bonds in excess of 81% of the
Secured Obligations as determined at such time, and that, to the extent that
the outstanding principal amount of the 1998 Series A Bonds exceeds such
amount, neither the Secured Parties nor the Collateral Agent shall have any
right under, or right to exercise any right granted to the holders of such
excess 1998 Series A Bonds under, the Mortgage. The Trustee shall be
entitled to rely on written notice from the Collateral Agent that no Event of
Default has occurred and is continuing under the Security Agreement.
Each bond of 1998 Series A shall be dated as of May 1, 1998 and shall bear
interest on the principal amount thereof as provided herein.
The person in whose name any bond of 1998 Series A is registered at the close
of business on any record date (as hereinafter defined) with respect to any
interest payment date shall be entitled to receive the interest payable on
such interest payment date notwithstanding the cancellation of such bond upon
any registration of transfer or exchange thereof subsequent to the record
date and prior to such interest payment date, except that if and to the
extent CL&P shall default in the payment of the interest due on such interest
payment date, then such defaulted interest shall be paid to the person in
whose name such bond is registered on a subsequent record date for the
payment of defaulted interest if one shall have been established as
hereinafter provided and otherwise on the date of payment of such defaulted
interest. A subsequent record date may be established by CL&P by notice
mailed to the owners of the bonds of 1998 Series A not less than ten (10)
days preceding such record date, which record date shall not be more than
five (5) days prior to the subsequent interest payment date. The term
"record date" as used in this Section with respect to any regular interest
payment date shall mean the day next preceding such interest payment date, or
if such day shall not be a Business Day, the next preceding day which shall
be a Business Day.
SECTION 1.04. Transfer and Exchange of Bonds of 1998 Series A; Agent as
Registered Holder: Restriction on Transfer of Bonds of 1998 Series A. The
bonds of 1998 Series A may be surrendered for registration of transfer as
provided in Section 2.06 of the Mortgage Indenture at the office or agency of
CL&P in the Borough of Manhattan, New York, New York, and may be surrendered
at said office for exchange for a like aggregate principal amount of bonds of
1998 Series A of other authorized denominations. Notwithstanding the
provisions of Section 2.06 of the Mortgage Indenture, no charge, except for
taxes or other governmental charges, shall be made by CL&P for any
registration of transfer of bonds of 1998 Series A or for the exchange of any
bonds of 1998 Series A for such bonds of other authorized denominations.
The bonds of 1998 Series A shall be issued to and registered in the name of
THE FIRST NATIONAL BANK OF CHICAGO, as Pledgee and Collateral Agent under the
Security Agreement for the ratable benefit of the Secured Parties named in
the Security Agreement and, anything in the Mortgage, this Supplemental
Indenture or any bond of 1998 Series A to the contrary notwithstanding, the
bonds of 1998 Series A shall not be sold, assigned, pledged or transferred,
except to effect the transfer to any successor Collateral Agent under the
Security Agreement.
SECTION 1.05. Conditions under which 1998 Series A Bond Not Entitled to
Benefits of Mortgage. Anything in the Mortgage, this Supplemental Indenture
or any bond of 1998 Series A to the contrary notwithstanding, (i) the actual
indebtedness evidenced by the 1998 Series A Bonds as of any time shall be
limited to 81% of the amount of the Secured Obligations (as defined in the
Security Agreement) as determined at such time; (ii) at no time shall any
claim be made for principal and interest on the 1998 Series A Bonds in excess
of 81% of the amount of such Secured Obligations as determined at such time;
and (iii) to the extent that the outstanding principal amount of the 1998
Series A Bonds exceeds such amount, neither the Collateral Agent nor the
Secured Parties (as defined in the Security Agreement) shall have any right
under, or right to exercise any right granted to the holders of such excess
1998 Series A Bonds under, the Mortgage.
SECTION 1.06. No Redemption. The bonds of 1998 Series A shall not be
redeemable.
ARTICLE 2.
REPAYMENT OF BONDS OF 1998 SERIES A.
SECTION 2.01. Repayment upon reduction of Aggregate Commitment under the
Facility. Upon written notice by the Collateral Agent to the Trustee (i)
that the Current Credit Agreement has been amended to reduce or cancel the
Aggregate Commitment (as defined in the Current Credit Agreement) of the
banks thereunder, and (ii) that upon the making of any repayment of
outstanding advances, if any, required pursuant to the terms of the Current
Credit Agreement as a result of such reduction or cancellation, the sum of
the then outstanding principal amount of the IT Notes and the greater of the
Aggregate Commitment under the Current Credit Agreement and the aggregate
principal amount of all loans outstanding under the Current Credit Agreement
equals less than $90,000,000, bonds of the 1998 Series A, in a principal
amount equal to 81% of the amount by which the principal amount of the then
outstanding 1998 Series A Bonds held by the Collateral Agent exceeds the sum
of the then outstanding principal amount of the IT Notes and the greater of
the Aggregate Commitment under the Current Credit Agreement and the aggregate
principal amount of all loans outstanding under the Current Credit Agreement,
shall be deemed paid and all obligations of CL&P hereunder and thereunder
with respect to such principal amount of 1998 Series A Bonds shall be deemed
satisfied and discharged.
ARTICLE 3.
MISCELLANEOUS.
SECTION 3.01. Benefits of Supplemental Indenture and Bonds of 1998 Series A.
Nothing in this Supplemental Indenture, or in the bonds of 1998 Series A,
expressed or implied, is intended or shall be construed to give to any person
or corporation other than CL&P, the Trustee and the holders of the bonds and
interest obligations secured by the Mortgage and this Supplemental Indenture,
any legal or equitable right, remedy or claim under or in respect of this
Supplemental Indenture or of any covenant, condition or provision herein
contained. All the covenants, conditions and provisions hereof are and shall
be for the sole and exclusive benefit of CL&P, the Trustee and the holders of
the bonds and interest obligations secured by the Mortgage and this
Supplemental Indenture.
SECTION 3.02. Effect of Table of Contents and Headings. The table of
contents and the descriptive headings of the several Articles and Sections of
this Supplemental Indenture are inserted for convenience of reference only
and are not to be taken to be any part of this Supplemental Indenture or to
control or affect the meaning, construction or effect of the same.
SECTION 3.03. Counterparts. For the purpose of facilitating the recording
hereof, this Supplemental Indenture may be executed in any number of
counterparts, each of which shall be and shall be taken to be an original and
all collectively but one instrument.
SECTION 3.04. Payment Due on Holidays. If the date for making any payment
or the last date for performance of any act or the exercise of any right, as
provided in this Supplemental Indenture, is not a Business Day, such payment
may be made or act performed or right exercised on the next succeeding
Business Day unless otherwise provided herein, with the same force and effect
as if done on the nominal date provided in this Supplemental Indenture.
IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused these
presents to be executed by a Vice President and its corporate seal to be
hereunto affixed, duly attested by an Assistant Secretary, and Bankers Trust
Company has caused these presents to be executed by an Assistant Vice
President and its corporate seal to be hereunto affixed, duly attested by an
Assistant Treasurer, as of the day and year first above written.
THE CONNECTICUT LIGHT AND
POWER COMPANY
Attest:
By: /s/ O. Kay Comendul By: /s/ John B. Keane
Name: O. Kay Comendul Name: John B. Keane
Title: Assistant Secretary Title: Vice President and Treasurer
(SEAL)
Signed, sealed and delivered in the presence of:
/s/ Tracy A. DeCredico
Tracy A. DeCredico
/s/ Marion Bloomquist
Marion Bloomquist
STATE OF CONNECTICUT)
) ss: BERLIN
COUNTY OF HARTFORD )
On this 27th day of April, 1998, before me, Carole J. Kobrzycki, the
undersigned officer, personally appeared John B. Keane and O. Kay Comendul,
who acknowledged themselves to be Vice President and Treasurer and Assistant
Secretary, respectively, of THE CONNECTICUT LIGHT AND POWER COMPANY, a
corporation, and that they, as such Vice President and Treasurer and such
Assistant Secretary, being authorized so to do, executed the foregoing
instrument for the purpose therein contained, by signing the name of the
corporation by themselves as Vice President and Treasurer and Assistant
Secretary, and as their free act and deed.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
/s/ Carole J. Kobrzycki
Carole J. Kobrzycki
Notary Public
My Commission Expires: January 31, 2003
BANKERS TRUST COMPANY
Attest:
/s/ Jason C. Theriault By: /s/ Vincent Chorney
Name: Jason C. Theriault Name: Vincent Chorney
Title: Assistant Treasurer Title: Assistant Vice President
(SEAL)
Signed, sealed and delivered in the presence of:
/s/ David Beane
David Beane
/s/ Sonia Egge
Sonia Egge
STATE OF NEW YORK )
) ss: NEW YORK
COUNTY OF NEW YORK )
On this 27th day of April, 1998, before me, Sharon V. Alston, the undersigned
officer, personally appeared Vincent Chorney and Jason C. Theriault, who
acknowledged themselves to be an Assistant Vice President and an Assistant
Treasurer, respectively, of BANKERS TRUST COMPANY, a corporation, and that
they, as such Assistant Vice President and such Assistant Treasurer, being
authorized so to do, executed the foregoing instrument for the purposes
therein contained, by signing the name of the corporation by themselves as
Assistant Vice President and Assistant Treasurer, and as their free act and
deed.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
/s/ Sharon V. Alston
Sharon V. Alston
Notary Public
My Commission Expires: May 7, 1998
SCHEDULE A
(FORM OF BONDS OF 1998 SERIES A)
THIS BOND IS TRANSFERABLE ONLY AS PROVIDED HEREIN
No. $
THE CONNECTICUT LIGHT AND POWER COMPANY
Incorporated under the Laws of the State of Connecticut
FIRST AND REFUNDING MORTGAGE BOND, 1998 Series A
PRINCIPAL DUE JUNE 1, 1999
FOR VALUE RECEIVED, THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation
organized and existing under the laws of the State of Connecticut
(hereinafter called the Company) hereby promises to pay to THE FIRST NATIONAL
BANK OF CHICAGO, or registered assigns, in each case as Pledgee and
Collateral Agent for the benefit of the Secured Parties (as such term is
defined in the Security Agreement referred to on the reverse hereof), the
principal sum of or, if less, 81% of the aggregate Secured
Obligations (as defined in the Security Agreement referred to on the reverse
hereof) outstanding on June 1, 1999 or any date before June 1, 1999 on which
the principal hereof becomes due and payable. The Company further agrees to
pay interest on said sum at the Lease Rate (as such term and all other
capitalized terms used but not otherwise defined herein are defined in the
Mortgage referred to on the reverse hereof) as applicable from time to time,
but such interest shall accrue only upon and following the occurrence and
during the continuance of an Accelerating Event; provided, however, that in
no event shall the interest rate payable on the 1998 Series A Bonds exceed
11% per annum. After a responsible officer of the Trustee shall have
received written notice from the Collateral Agent of the occurrence of an
Accelerating Event, specifying in reasonable detail the events giving rise to
the Accelerating Event and the date of its occurrence, interest hereon shall
be due and payable on demand; provided, however, that upon the occurrence of
an Accelerating Event which is an Insolvency Event, interest shall be
immediately due and payable on demand whether or not the Trustee has received
notice of the occurrence of such Accelerating Event. Interest shall accrue
from and including the date of occurrence of an Accelerating Event and shall
continue to accrue during the continuance of such Accelerating Event.
Interest hereon shall cease to accrue following the discontinuance of the
Accelerating Event as evidenced by written notice from an officer of the
Collateral Agent to a responsible officer of the Trustee, and any interest
hereon that has accrued but has not yet become due and payable at the time
such notice is given shall be extinguished and shall not be required to be
paid at any time thereafter. The bonds of 1998 Series A shall be payable
both as to principal and interest at the office or agency of the Company in
the Borough of Manhattan, New York, New York, in any coin or currency of the
United States of America which at the time of payment is legal tender for the
payment of public and private debts. The interest on the bonds of 1998
Series A, whether in temporary or definitive form, shall be payable without
presentation of such bonds; and only to or upon the written order of the
registered holders thereof of record at the applicable record date. If any
amounts due under the Credit Agreement or any IT Note Agreement (as defined
in the Lease Agreement) shall become, or any bank acting as agent on behalf
of the financial institutions party to the Credit Agreement or the holder or
holders of any IT Note shall so declare amounts due under such Credit
Agreement or IT Note Agreement, as the case may be, to be, forthwith due and
payable pursuant to the terms of such Credit Agreement or IT Note Agreement,
as the case may be, the entire principal of the bonds of 1998 Series A,
together with interest accrued but unpaid thereon, shall without notice or
demand of any kind, become immediately due and payable.
Anything in the Mortgage referred to on the reverse hereof, the supplemental
indenture establishing the terms and conditions of bonds of this Series (the
"Supplemental Indenture") or any bond of 1998 Series A to the contrary
notwithstanding, the bonds of 1998 Series A shall be deemed paid, and all
obligations of the Company to pay at the times provided herein the principal
of, premium, if any, and interest on the bonds of 1998 Series A shall be
satisfied and discharged, if and to the extent, that (A) the Current Credit
Agreement is terminated in its entirety and all obligations thereunder shall
have been paid in full and the Company shall not have given notice to the
Trustee that such 1998 Series A Bonds shall remain outstanding, (B) each of
the financial institutions party to the Credit Agreement has agreed in
writing that the 1998 Series A Bonds shall be deemed paid, or (C) on June 1,
1999, no Event of Default (as defined in the Security Agreement) shall have
occurred and be continuing; it being understood that the actual indebtedness
evidenced by the 1998 Series A Bonds as of any time shall be limited to 81%
of the Secured Obligations (as defined in the Security Agreement) as
determined at such time, that at no time shall any claim be made for
principal and interest on the 1998 Series A Bonds in excess of 81% of such
Secured Obligations as determined at such time, and that, to the extent that
the outstanding principal amount of the 1998 Series A Bonds exceeds such
amount, neither the Secured Parties nor the Collateral Agent shall have any
right under, or right to exercise any right granted to the holders of such
excess 1998 Series A Bonds under, the Mortgage. The Trustee shall be
entitled to rely on written notice from the Collateral Agent, that no Event
of Default has occurred and is continuing under such Security Agreement. By
its acceptance of this Bond, the Collateral Agent agrees upon request of the
Company to provide such notice to the Trustee so long as no Event of Default
has occurred and is continuing.
Each installment of interest hereon shall be payable to the person who shall
be the registered owner of this bond at the close of business on the record
date, which shall be the day next preceding such interest payment date, or if
such day shall not be a Business Day (as defined on the reverse hereof), the
next preceding day which is a Business Day.
Reference is hereby made to the further provisions of this Bond set forth on
the reverse hereof, and the registration of transfer and exchangeability of
this bond, and such further provisions shall for all purposes have the same
effect as though fully set forth in this place.
This bond shall not become or be valid or obligatory until the certificate of
authentication hereon shall have been signed by Bankers Trust Company
(hereinafter with its successors as defined in the Mortgage, generally called
the Trustee), or by such a successor.
IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused this
bond to be executed in its corporate name and on its behalf by its Vice
President by his signature or a facsimile thereof, and its corporate seal to
be affixed or imprinted hereon and attested by the manual or facsimile
signature of its Assistant Secretary.
Dated as of , 1998.
THE CONNECTICUT LIGHT AND POWER COMPANY
By
Name:
Title: Vice President
Attest:
Name:
Title: Assistant Secretary
[FORM OF TRUSTEE'S CERTIFICATE]
Bankers Trust Company hereby certifies that this bond is one of the bonds
described in the within mentioned Mortgage.
BANKERS TRUST COMPANY, TRUSTEE
By
Name:
Title: Authorized Officer
[FORM OF BOND]
[REVERSE]
THE CONNECTICUT LIGHT AND POWER COMPANY
FIRST AND REFUNDING MORTGAGE BOND, 1998 Series A
This bond is one of an issue of bonds of the Company, of an unlimited
authorized amount of coupon bonds or registered bonds without coupons, or
both, known as its First and Refunding Mortgage Bonds, all issued or to be
issued in one or more series, and is one of a series of said bonds limited in
principal amount to Seventy-Two Million Nine Hundred Thousand Dollars
($72,900,000), consisting only of registered bonds without coupons and
designated "First and Refunding Mortgage Bonds, 1998 Series A," all of which
bonds are issued or are to be issued under, and equally and ratably secured
by, a certain Indenture of Mortgage and Deed of Trust dated as of May 1,
1921, and by sixty-nine Supplemental Indentures dated respectively as of May
1, 1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932, July 1,
1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1, 1936,
December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945, October 1,
1945, November 1, 1949, December 1, 1952, December 1, 1955, January 1, 1958,
February 1, 1960, April 1, 1961, September 1, 1963, April 1, 1967, May 1,
1967, January 1, 1968, October 1, 1968, December 1, 1969, January 1, 1970,
October 1, 1970, December 1, 1971, August 1, 1972, April 1, 1973, March 1,
1974, February 1, 1975, September 1, 1975, May 1, 1977, March 1, 1978,
September 1, 1980, October 1, 1981, June 30, 1982, October 1, 1982, July 1,
1983, January 1, 1984, October 1, 1985, September 1, 1986, April 1, 1987,
October 1, 1987, November 1, 1987, April 1, 1988, November 1, 1988, June 1,
1989, September 1, 1989, December 1, 1989, April 1, 1992, July 1, 1992,
October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February 1,
1994, February 1, 1994, June 1, 1994, October 1, 1994, June 1, 1996, January
1, 1997, May 1, 1997, June 1, 1997, June 1, 1997 and May 1, 1998 (said
Indenture of Mortgage and Deed of Trust and Supplemental Indentures being
collectively referred to herein as the "Mortgage"), all executed by the
Company to Bankers Trust Company, as Trustee, all as provided in the Mortgage
to which reference is made for a statement of the property mortgaged and
pledged, the nature and extent of the security, the rights of the holders of
the bonds in respect thereof and the terms and conditions upon which the
bonds may be issued and are secured; but neither the foregoing reference to
the Mortgage nor any provision of this bond or of the Mortgage (other than
the last sentence of the next paragraph and Section 1.03 of the Supplemental
Indenture establishing the terms and conditions of the bonds of this Series)
shall affect or impair the obligation of the Company, which is absolute,
unconditional and unalterable, to pay at the maturity herein provided the
principal of and interest on this bond as herein provided. The principal of
this bond may be declared or may become due on the conditions, in the manner
and at the time set forth in the Mortgage, upon the happening of an event of
default as in the Mortgage provided or if any amounts due under the Credit
Agreement or any IT Note Agreement (as such term is defined in the Security
Agreement referred to below) shall become, or any bank acting as agent on
behalf of the financial institutions party to the Credit Agreement or the
holder or holders of any IT Note shall so declare amounts due under such
Credit Agreement or such IT Note Agreement, as the case may be, to be,
forthwith due and payable pursuant to the terms of such Credit Agreement or
IT Note Agreement, as the case may be.
This bond, together with all other bonds of this series, if any, is issued to
evidence and secure the Company's obligations pursuant to the Lease
Agreement, it being understood that the actual indebtedness evidenced by the
1998 Series A Bonds as of any time shall be limited to 81% of the Secured
Obligations (as defined in the Security Agreement hereinbelow referred to) as
determined at such time, that at no time shall any claim be made for
principal and interest on the 1998 Series A Bonds in excess of 81% of such
Secured Obligations as determined at such time, and that, to the extent that
the outstanding principal amount of the 1998 Series A Bonds exceeds such
amount, neither the Secured Parties nor the Collateral Agent shall have any
right under, or right to exercise any right granted to the holders of such
excess 1998 Series A Bonds under, the Mortgage.
The bonds of 1998 Series A shall be issued to and registered in the name of
THE FIRST NATIONAL BANK OF CHICAGO, as Pledgee and Collateral Agent (the
"Collateral Agent") under a Security Agreement and Assignment of Contracts
dated as of January 4, 1982, as amended and restated February 11, 1992
between Bankers Trust Company, not in its individual capacity but solely as
trustee of the Niantic Bay Fuel Trust which was created pursuant to a Trust
Agreement dated as of January 4, 1982, as amended and restated as of February
11, 1992, among Bankers Trust Company, as trustee, State Street Bank and
Trust Company of Connecticut, National Association (which is the successor
trustor to the New Connecticut Bank and Trust Company, National Association,
as assignee of the Federal Deposit Insurance Corporation, as receiver of The
Connecticut Bank and Trust Company, National Association), as Trustor, and
the Company, Western Massachusetts Electric Company ("WMECO") and The
Hartford Electric Light Company (which merged with and into the Company on
June 30, 1982), as beneficiaries, and the Collateral Agent for the ratable
benefit of the Secured Parties referred to therein (the "Security
Agreement"). Anything in the Mortgage, the Supplemental Indenture or any
bond of 1998 Series A to the contrary notwithstanding, the bonds of 1998
Series A shall not be sold, assigned, pledged or transferred, except to
effect the transfer to any successor Collateral Agent under the Security
Agreement. Prior to due presentment for registration of transfer of this
bond the Company and the Trustee may deem and treat the registered owner
hereof as the absolute owner hereof, whether or not this bond be overdue, for
the purpose of receiving payment and for all other purposes, and neither the
Company nor the Trustee shall be affected by any notice to the contrary.
Upon written notice by the Collateral Agent to the Trustee (i) that the
Current Credit Agreement has been amended to reduce or cancel the Aggregate
Commitment (as defined in the Current Credit Agreement) of the banks
thereunder, and (ii) that upon the making of any repayment of outstanding
advances, if any, required pursuant to the terms of the Current Credit
Agreement as a result of such reduction or cancellation, the sum of the then
outstanding principal amount of the IT Note and the greater of the Aggregate
Commitment under the Current Credit Agreement and the aggregate principal
amount of all loans outstanding under the Current Credit Agreement equals
less than $90,000,000, bonds of the 1998 Series A, in a principal amount
equal to 81% of the amount by which the principal amount of the then
outstanding 1998 Series A Bonds held by the Collateral Agent exceeds the sum
of the then outstanding principal amount of the IT Notes and the greater of
the Aggregate Commitment under the Current Credit Agreement and the aggregate
principal amount of all loans outstanding under the Current Credit Agreement,
shall be deemed paid and all obligations of CL&P hereunder and thereunder
with respect to such principal amount of 1998 Series A Bonds shall be deemed
satisfied and discharged.
This bond is exchangeable at the option of the registered holder hereof upon
surrender hereof, at the office or agency of the Company in the Borough of
Manhattan, New York, New York, for an equal principal amount of bonds of this
series of other authorized denominations, in the manner and on the terms
provided in the Mortgage.
The 1998 Series A Bonds shall not be redeemable.
The Mortgage provides that the Company and the Trustee, with consent of the
holders of not less than 66 2/3% in aggregate principal amount of the bonds
at the time outstanding which would be affected by the action proposed to be
taken, may by supplemental indenture add any provisions to or change or
eliminate any of the provisions of the Mortgage or modify the rights of the
holders of the bonds and coupons issued thereunder; provided, however, that
without the consent of the holder hereof no such supplemental indenture shall
affect the terms of payment of the principal of or interest or premium on
this bond, or reduce the aforesaid percentage of the bonds the holders of
which are required to consent to such a supplemental indenture, or permit the
creation by the Company of any mortgage or pledge or lien in the nature
thereof ranking prior to or equal with the lien of the Mortgage or deprive
the holder hereof of the lien of the Mortgage on any of the property which is
subject to the lien thereof.
If the date for making any payment or the last date for performance of any
act or the exercise of any right, as provided in the Supplemental Indenture
establishing the terms and series of the bonds of this series, is not a
Business Day, such payment may be made or act performed or right exercised on
the next succeeding Business Day unless otherwise provided herein, with the
same force and effect as if done on the nominal date provided in the
Supplemental Indenture establishing the terms and series of the bonds of this
series.
No recourse shall be had for the payment of the principal of or the interest
on this bond, or any part thereof, or for any claim based thereon or
otherwise in respect thereof, to any incorporator or any past, present or
future stockholder, officer or director of the Company, either directly or
indirectly, by virtue of any statute or by enforcement of any assessment or
otherwise, and any and all liability of the said incorporators, stockholders,
officers or directors of the Company in respect to this bond is hereby
expressly waived and released by every holder hereof.
SCHEDULE B
THIS SCHEDULE IS A TABLE OF ALL THE EASEMENTS GRANTED BY THE CONNECTICUT
LIGHT AND POWER COMPANY SINCE THE PREVIOUS SUPPLEMENTAL INDENTURE WAS
EXECUTED - IT IS NOT INCLUDED AS PART OF THIS FILING.
Exhibit 4.2.18
SUPPLEMENTAL INDENTURE
Dated as of May 1, 1998
To
Indenture of Mortgage and Deed of Trust
Dated as of May 1, 1921
THE CONNECTICUT LIGHT AND POWER COMPANY
TO
BANKERS TRUST COMPANY, Trustee
Amending First Supplemental Indenture Dated as of May 1, 1998
THE CONNECTICUT LIGHT AND POWER COMPANY
Supplemental Indenture, Dated as of May 1, 1998
TABLE OF CONTENTS
PARTIES
RECITALS
ARTICLE 1 AMENDMENT OF MORTGAGE
SECTION 1.01. Amendment of Section 2.01 of First May 1, 1998 Supplemental
Indenture
SECTION 1.02. Amendment of Schedule A to First May 1, 1998 Supplemental
Indenture
ARTICLE 2 MISCELLANEOUS
SECTION 2.01. Benefits of Supplemental Indenture.
SECTION 2.02. Effect of Table of Contents and Headings.
SECTION 2.03. Counterparts.
TESTIMONIUM
SIGNATURES
ACKNOWLEDGEMENTS
SCHEDULE A - Form of Bond of 1998 Series A; Form of Trustee's Certificate
SUPPLEMENTAL INDENTURE, dated as of the first day of May, 1998, between THE
CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and existing
under the laws of the State of Connecticut (hereinafter called "CL&P"), and
BANKERS TRUST COMPANY, a corporation organized and existing under the laws of
the State of New York (hereinafter called the "Trustee").
WHEREAS, CL&P heretofore duly executed, acknowledged and delivered to the
Trustee a certain Indenture of Mortgage and Deed of Trust dated as of May 1,
1921, and sixty-nine Supplemental Indentures thereto dated respectively as of
May 1, 1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932,
July 1, 1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1,
1936, December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945,
October 1, 1945, November 1, 1949, December 1, 1952, December 1, 1955,
January 1, 1958, February 1, 1960, April 1, 1961, September 1, 1963, April 1,
1967, May 1, 1967, January 1, 1968, October 1, 1968, December 1, 1969,
January 1, 1970, October 1, 1970, December 1, 1971, August 1, 1972, April 1,
1973, March 1, 1974, February 1, 1975, September 1, 1975, May 1, 1977, March
1, 1978, September 1, 1980, October 1, 1981, June 30, 1982, October 1, 1982,
July 1, 1983, January 1, 1984, October 1, 1985, September 1, 1986, April 1,
1987, October 1, 1987, November 1, 1987, April 1, 1988, November 1, 1988,
June 1, 1989, September 1, 1989 , December 1, 1989, April 1, 1992, July 1,
1992, October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February
1, 1994, February 1, 1994, June 1, 1994, October 1, 1994, June 1, 1996,
January 1, 1997, May 1, 1997, June 1, 1997, June 1, 1997 and May 1, 1998
(said Indenture of Mortgage and Deed of Trust (i) as heretofore amended,
being hereinafter generally called the "Mortgage Indenture," and (ii)
together with said Supplemental Indentures thereto, being hereinafter
generally called the "Mortgage"), all of which have been duly recorded as
required by law, for the purpose of securing its First and Refunding Mortgage
Bonds (of which $1,726,000,000 aggregate principal amount are outstanding at
the date of this Supplemental Indenture) in an unlimited amount, issued and
to be issued for the purposes and in the manner therein provided, of which
Mortgage this Supplemental Indenture is intended to be made a part, as fully
as if therein recited at length;
WHEREAS, CL&P executed and delivered a Supplemental Indenture dated as of May
1, 1998 (the "First May 1, 1998 Supplemental Indenture") to provide for the
issue of the bonds of 1998 Series A;
WHEREAS, CL&P proposes to execute and deliver this Supplemental Indenture to
amend Section 2.01 of, and Schedule A to, the First May 1, 1998 Supplemental
Indenture to correct a typographical error appearing in such Section 2.01 of,
and Schedule A to, the First May 1, 1998 Supplemental Indenture, all as
permitted by Section 14.01(e) of the Mortgage Indenture; and
WHEREAS, all acts and things necessary to constitute this Supplemental
Indenture a valid, binding and legal instrument have been authorized and
performed;
NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE OF MORTGAGE AND DEED OF TRUST
WITNESSETH:
ARTICLE 1.
AMENDMENT OF MORTGAGE
SECTION 1.01. Amendment of Section 2.01 of First May 1, 1998 Supplemental
Indenture. The Mortgage shall be, and hereby is, amended to correct a
typographical error by deleting Section 2.01 of the First May 1, 1998
Supplemental Indenture in its entirety and substituting in lieu thereof the
following:
SECTION 2.01. Repayment upon reduction of Aggregate Commitment under the
Facility. Upon written notice by the Collateral Agent to the Trustee (i)
that the Current Credit Agreement has been amended to reduce or cancel the
Aggregate Commitment (as defined in the Current Credit Agreement) of the
banks thereunder, and (ii) that upon the making of any repayment of
outstanding advances, if any, required pursuant to the terms of the Current
Credit Agreement as a result of such reduction or cancellation, the sum of
the then outstanding principal amount of the IT Notes and the greater of the
Aggregate Commitment under the Current Credit Agreement and the aggregate
principal amount of all loans outstanding under the Current Credit Agreement
equals less than $90,000,000, bonds of the 1998 Series A, in a principal
amount equal to the amount by which the principal amount of the then
outstanding 1998 Series A Bonds held by the Collateral Agent exceeds 81% of
the sum of the then outstanding principal amount of the IT Notes and the
greater of the Aggregate Commitment under the Current Credit Agreement and
the aggregate principal amount of all loans outstanding under the Current
Credit Agreement, shall be deemed paid and all obligations of CL&P hereunder
and thereunder with respect to such principal amount of 1998 Series A Bonds
shall be deemed satisfied and discharged.
SECTION 1.02. Amendment of Schedule A to the First May 1, 1998 Supplemental
Indenture. The Mortgage shall be, and hereby is, amended to correct a
typographical error by deleting Schedule A to the First May 1, 1998
Supplemental Indenture in its entirety and substituting in lieu thereof
Schedule A appended hereto.
ARTICLE 2.
MISCELLANEOUS
SECTION 2.01. Benefits of Supplemental Indenture. Nothing in this
Supplemental Indenture, expressed or implied, is intended or shall be
construed to give to any person or corporation other than CL&P, the Trustee
and the holders of the bonds and interest obligations secured by the
Mortgage, any legal or equitable right, remedy or claim under or in respect
of this Supplemental Indenture or of any covenant, condition or provision
herein contained. All the covenants, conditions and provisions hereof are
and shall be for the sole and exclusive benefit of CL&P, the Trustee and the
holders of the bonds and interest obligations secured by the Mortgage.
SECTION 2.02. Effect of Table of Contents and Headings. The table of
contents and the descriptive headings of the several Articles and Sections of
this Supplemental Indenture are inserted for convenience of reference only
and are not to be taken to be any part of this Supplemental Indenture or to
control or affect the meaning, construction or effect of the same.
SECTION 2.03. Counterparts. For the purpose of facilitating the recording
hereof, this Supplemental Indenture may be executed in any number of
counterparts, each of which shall be and shall be taken to be an original and
all collectively but one instrument.
IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused these
presents to be executed by a Vice President and its corporate seal to be
hereunto affixed, duly attested by an Assistant Secretary, and Bankers Trust
Company has caused these presents to be executed by an Assistant Vice
President and its corporate seal to be hereunto affixed, duly attested by an
Assistant Treasurer, as of the day and year first above written.
THE CONNECTICUT LIGHT AND POWER COMPANY
Attest:
/s/ O. Kay Comendul By: /s/ John B. Keane
Name: O. Kay Comendul Name: John B. Keane
Title: Assistant Secretary Title: Vice President and Treasurer
(SEAL)
Signed, sealed and delivered in the presence of:
/s/ Tracy A. DeCredico
Tracy A. DeCredico
/s/ Marion Bloomquist
Marion Bloomquist
STATE OF CONNECTICUT)
) ss: BERLIN
COUNTY OF HARTFORD )
On this 4th day of May, 1998, before me, Susan L. Cifaldi, the undersigned
officer, personally appeared John B. Keane and O. Kay Comendul, who
acknowledged themselves to be Vice President and Treasurer and Assistant
Secretary, respectively, of THE CONNECTICUT LIGHT AND POWER COMPANY, a
corporation, and that they, as such Vice President and Treasurer and such
Assistant Secretary, being authorized so to do, executed the foregoing
instrument for the purpose therein contained, by signing the name of the
corporation by themselves as Vice President and Treasurer and Assistant
Secretary, and as their free act and deed.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
/s/ Susan L. Cifaldi
Carole J. Kobrzycki, Notary Public
My Commission Expires: May 31, 1999
BANKERS TRUST COMPANY
Attest:
/s/ Jason C. Theriault By: /s/ Vincent Chorney
Name: Jason C. Theriault Name: Vincent Chorney
Title: Assistant Treasurer Title: Assistant Vice President
(SEAL)
Signed, sealed and delivered in the presence of:
/s/ David Beane
David Beane
/s/ Sonia Egge
Sonia Egge
STATE OF NEW YORK )
) ss: NEW YORK
COUNTY OF NEW YORK )
On this 4th day of May, 1998, before me, Sharon V. Alston, the undersigned
officer, personally appeared Vincent Chorney and Jason C. Theriault, who
acknowledged themselves to be an Assistant Vice President and an Assistant
Treasurer, respectively, of BANKERS TRUST COMPANY, a corporation, and that
they, as such Assistant Vice President and such Assistant Treasurer, being
authorized so to do, executed the foregoing instrument for the purposes
therein contained, by signing the name of the corporation by themselves as
Assistant Vice President and Assistant Treasurer, and as their free act and
deed.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
/s/ Sharon V. Alston
Sharon V. Alston
Notary Public
My Commission Expires: May 7, 1998
SCHEDULE A
(FORM OF BONDS OF 1998 SERIES A)
THIS BOND IS TRANSFERABLE ONLY AS PROVIDED HEREIN
No. $
THE CONNECTICUT LIGHT AND POWER COMPANY
Incorporated under the Laws of the State of Connecticut
FIRST AND REFUNDING MORTGAGE BOND, 1998 Series A
PRINCIPAL DUE JUNE 1, 1999
FOR VALUE RECEIVED, THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation
organized and existing under the laws of the State of Connecticut
(hereinafter called the Company) hereby promises to pay to THE FIRST NATIONAL
BANK OF CHICAGO, or registered assigns, in each case as Pledgee and
Collateral Agent for the benefit of the Secured Parties (as such term is
defined in the Security Agreement referred to on the reverse hereof), the
principal sum of or, if less, 81% of the aggregate Secured
Obligations (as defined in the Security Agreement referred to on the reverse
hereof) outstanding on June 1, 1999 or any date before June 1, 1999 on which
the principal hereof becomes due and payable. The Company further agrees to
pay interest on said sum at the Lease Rate (as such term and all other
capitalized terms used but not otherwise defined herein are defined in the
Mortgage referred to on the reverse hereof) as applicable from time to time,
but such interest shall accrue only upon and following the occurrence and
during the continuance of an Accelerating Event; provided, however, that in
no event shall the interest rate payable on the 1998 Series A Bonds exceed
11% per annum. After a responsible officer of the Trustee shall have
received written notice from the Collateral Agent of the occurrence of an
Accelerating Event, specifying in reasonable detail the events giving rise to
the Accelerating Event and the date of its occurrence, interest hereon shall
be due and payable on demand; provided, however, that upon the occurrence of
an Accelerating Event which is an Insolvency Event, interest shall be
immediately due and payable on demand whether or not the Trustee has received
notice of the occurrence of such Accelerating Event. Interest shall accrue
from and including the date of occurrence of an Accelerating Event and shall
continue to accrue during the continuance of such Accelerating Event.
Interest hereon shall cease to accrue following the discontinuance of the
Accelerating Event as evidenced by written notice from an officer of the
Collateral Agent to a responsible officer of the Trustee, and any interest
hereon that has accrued but has not yet become due and payable at the time
such notice is given shall be extinguished and shall not be required to be
paid at any time thereafter. The bonds of 1998 Series A shall be payable
both as to principal and interest at the office or agency of the Company in
the Borough of Manhattan, New York, New York, in any coin or currency of the
United States of America which at the time of payment is legal tender for the
payment of public and private debts. The interest on the bonds of 1998
Series A, whether in temporary or definitive form, shall be payable without
presentation of such bonds; and only to or upon the written order of the
registered holders thereof of record at the applicable record date. If any
amounts due under the Credit Agreement or any IT Note Agreement (as defined
in the Lease Agreement) shall become, or any bank acting as agent on behalf
of the financial institutions party to the Credit Agreement or the holder or
holders of any IT Note shall so declare amounts due under such Credit
Agreement or IT Note Agreement, as the case may be, to be, forthwith due and
payable pursuant to the terms of such Credit Agreement or IT Note Agreement,
as the case may be, the entire principal of the bonds of 1998 Series A,
together with interest accrued but unpaid thereon, shall without notice or
demand of any kind, become immediately due and payable.
Anything in the Mortgage referred to on the reverse hereof, the supplemental
indenture dated as of May 1, 1998 establishing the terms and conditions of
bonds of this Series (the "Supplemental Indenture"), the supplemental
indenture dated as of May 1, 1998 amending the Supplemental Indenture or any
bond of 1998 Series A to the contrary notwithstanding, the bonds of 1998
Series A shall be deemed paid, and all obligations of the Company to pay at
the times provided herein the principal of, premium, if any, and interest on
the bonds of 1998 Series A shall be satisfied and discharged, if and to the
extent, that (A) the Current Credit Agreement is terminated in its entirety
and all obligations thereunder shall have been paid in full and the Company
shall not have given notice to the Trustee that such 1998 Series A Bonds
shall remain outstanding, (B) each of the financial institutions party to the
Credit Agreement has agreed in writing that the 1998 Series A Bonds shall be
deemed paid, or (C) on June 1, 1999, no Event of Default (as defined in the
Security Agreement) shall have occurred and be continuing; it being
understood that the actual indebtedness evidenced by the 1998 Series A Bonds
as of any time shall be limited to 81% of the Secured Obligations (as defined
in the Security Agreement) as determined at such time, that at no time shall
any claim be made for principal and interest on the 1998 Series A Bonds in
excess of 81% of such Secured Obligations as determined at such time, and
that, to the extent that the outstanding principal amount of the 1998 Series
A Bonds exceeds such amount, neither the Secured Parties nor the Collateral
Agent shall have any right under, or right to exercise any right granted to
the holders of such excess 1998 Series A Bonds under, the Mortgage. The
Trustee shall be entitled to rely on written notice from the Collateral
Agent, that no Event of Default has occurred and is continuing under such
Security Agreement. By its acceptance of this Bond, the Collateral Agent
agrees upon request of the Company to provide such notice to the Trustee so
long as no Event of Default has occurred and is continuing.
Each installment of interest hereon shall be payable to the person who shall
be the registered owner of this bond at the close of business on the record
date, which shall be the day next preceding such interest payment date, or if
such day shall not be a Business Day (as defined on the reverse hereof), the
next preceding day which is a Business Day.
Reference is hereby made to the further provisions of this Bond set forth on
the reverse hereof, and the registration of transfer and exchangeability of
this bond, and such further provisions shall for all purposes have the same
effect as though fully set forth in this place.
This bond shall not become or be valid or obligatory until the certificate of
authentication hereon shall have been signed by Bankers Trust Company
(hereinafter with its successors as defined in the Mortgage, generally called
the Trustee), or by such a successor.
IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused this
bond to be executed in its corporate name and on its behalf by its President
by his signature or a facsimile thereof and its corporate seal to be affixed
or imprinted hereon and attested by the manual or facsimile signature of its
Secretary.
Dated as of , 1998.
THE CONNECTICUT LIGHT AND POWER COMPANY
By
Name:
Title: President
Attest:
Name:
Title: Secretary
[FORM OF TRUSTEE'S CERTIFICATE]
Bankers Trust Company hereby certifies that this bond is one of the bonds
described in the within mentioned Mortgage.
BANKERS TRUST COMPANY, TRUSTEE
By
Name:
Title: Authorized Officer
[FORM OF BOND]
[REVERSE]
THE CONNECTICUT LIGHT AND POWER COMPANY
FIRST AND REFUNDING MORTGAGE BOND, 1998 Series A
This bond is one of an issue of bonds of the Company, of an unlimited
authorized amount of coupon bonds or registered bonds without coupons, or
both, known as its First and Refunding Mortgage Bonds, all issued or to be
issued in one or more series, and is one of a series of said bonds limited in
principal amount to Seventy-Two Million Nine Hundred Thousand Dollars
($72,900,000), consisting only of registered bonds without coupons and
designated "First and Refunding Mortgage Bonds, 1998 Series A," all of which
bonds are issued or are to be issued under, and equally and ratably secured
by, a certain Indenture of Mortgage and Deed of Trust dated as of May 1,
1921, and by seventy Supplemental Indentures dated respectively as of May 1,
1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932, July 1,
1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1, 1936,
December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945, October 1,
1945, November 1, 1949, December 1, 1952, December 1, 1955, January 1, 1958,
February 1, 1960, April 1, 1961, September 1, 1963, April 1, 1967, May 1,
1967, January 1, 1968, October 1, 1968, December 1, 1969, January 1, 1970,
October 1, 1970, December 1, 1971, August 1, 1972, April 1, 1973, March 1,
1974, February 1, 1975, September 1, 1975, May 1, 1977, March 1, 1978,
September 1, 1980, October 1, 1981, June 30, 1982, October 1, 1982, July 1,
1983, January 1, 1984, October 1, 1985, September 1, 1986, April 1, 1987,
October 1, 1987, November 1, 1987, April 1, 1988, November 1, 1988, June 1,
1989, September 1, 1989, December 1, 1989, April 1, 1992, July 1, 1992,
October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February 1,
1994, February 1, 1994, June 1, 1994, October 1, 1994, June 1, 1996, January
1, 1997, May 1, 1997, June 1, 1997, June 1, 1997, May 1, 1998 and May 1, 1998
(said Indenture of Mortgage and Deed of Trust and Supplemental Indentures
being collectively referred to herein as the "Mortgage"), all executed by the
Company to Bankers Trust Company, as Trustee, all as provided in the Mortgage
to which reference is made for a statement of the property mortgaged and
pledged, the nature and extent of the security, the rights of the holders of
the bonds in respect thereof and the terms and conditions upon which the
bonds may be issued and are secured; but neither the foregoing reference to
the Mortgage nor any provision of this bond or of the Mortgage (other than
the last sentence of the next paragraph and Section 1.03 of the Supplemental
Indenture establishing the terms and conditions of the bonds of this Series)
shall affect or impair the obligation of the Company, which is absolute,
unconditional and unalterable, to pay at the maturity herein provided the
principal of and interest on this bond as herein provided. The principal of
this bond may be declared or may become due on the conditions, in the manner
and at the time set forth in the Mortgage, upon the happening of an event of
default as in the Mortgage provided or if any amounts due under the Credit
Agreement or any IT Note Agreement (as such term is defined in the Security
Agreement referred to below) shall become, or any bank acting as agent on
behalf of the financial institutions party to the Credit Agreement or the
holder or holders of any IT Note shall so declare amounts due under such
Credit Agreement or such IT Note Agreement, as the case may be, to be,
forthwith due and payable pursuant to the terms of such Credit Agreement or
IT Note Agreement, as the case may be.
This bond, together with all other bonds of this series, if any, is issued to
evidence and secure the Company's obligations pursuant to the Lease
Agreement, it being understood that the actual indebtedness evidenced by the
1998 Series A Bonds as of any time shall be limited to 81% of the Secured
Obligations (as defined in the Security Agreement hereinbelow referred to) as
determined at such time, that at no time shall any claim be made for
principal and interest on the 1998 Series A Bonds in excess of 81% of such
Secured Obligations as determined at such time, and that, to the extent that
the outstanding principal amount of the 1998 Series A Bonds exceeds such
amount, neither the Secured Parties nor the Collateral Agent shall have any
right under, or right to exercise any right granted to the holders of such
excess 1998 Series A Bonds under, the Mortgage.
The bonds of 1998 Series A shall be issued to and registered in the name of
THE FIRST NATIONAL BANK OF CHICAGO, as Pledgee and Collateral Agent (the
"Collateral Agent") under a Security Agreement and Assignment of Contracts
dated as of January 4, 1982, as amended and restated February 11, 1992
between Bankers Trust Company, not in its individual capacity but solely as
trustee of the Niantic Bay Fuel Trust which was created pursuant to a Trust
Agreement dated as of January 4, 1982, as amended and restated as of February
11, 1992, among Bankers Trust Company, as trustee, State Street Bank and
Trust Company of Connecticut, National Association (which is the successor
trustor to the New Connecticut Bank and Trust Company, National Association,
as assignee of the Federal Deposit Insurance Corporation, as receiver of The
Connecticut Bank and Trust Company, National Association), as Trustor, and
the Company, Western Massachusetts Electric Company ("WMECO") and The
Hartford Electric Light Company (which merged with and into the Company on
June 30, 1982), as beneficiaries, and the Collateral Agent for the ratable
benefit of the Secured Parties referred to therein (the "Security
Agreement"). Anything in the Mortgage, the Supplemental Indenture, the
supplemental indenture dated as of May 1, 1998 amending the Supplemental
Indenture or any bond of 1998 Series A to the contrary notwithstanding, the
bonds of 1998 Series A shall not be sold, assigned, pledged or transferred,
except to effect the transfer to any successor Collateral Agent under the
Security Agreement. Prior to due presentment for registration of transfer of
this bond the Company and the Trustee may deem and treat the registered owner
hereof as the absolute owner hereof, whether or not this bond be overdue, for
the purpose of receiving payment and for all other purposes, and neither the
Company nor the Trustee shall be affected by any notice to the contrary.
Upon written notice by the Collateral Agent to the Trustee (i) that the
Current Credit Agreement has been amended to reduce or cancel the Aggregate
Commitment (as defined in the Current Credit Agreement) of the banks
thereunder, and (ii) that upon the making of any repayment of outstanding
advances, if any, required pursuant to the terms of the Current Credit
Agreement as a result of such reduction or cancellation, the sum of the then
outstanding principal amount of the IT Notes and the greater of the Aggregate
Commitment under the Current Credit Agreement and the aggregate principal
amount of all loans outstanding under the Current Credit Agreement equals
less than $90,000,000, bonds of the 1998 Series A, in a principal amount
equal to the amount by which the principal amount of the then outstanding
1998 Series A Bonds held by the Collateral Agent exceeds 81% of the sum of
the then outstanding principal amount of the IT Notes and the greater of the
Aggregate Commitment under the Current Credit Agreement and the aggregate
principal amount of all loans outstanding under the Current Credit Agreement,
shall be deemed paid and all obligations of CL&P hereunder and thereunder
with respect to such principal amount of 1998 Series A Bonds shall be deemed
satisfied and discharged.
This bond is exchangeable at the option of the registered holder hereof upon
surrender hereof, at the office or agency of the Company in the Borough of
Manhattan, New York, New York, for an equal principal amount of bonds of this
series of other authorized denominations, in the manner and on the terms
provided in the Mortgage.
The 1998 Series A Bonds shall not be redeemable.
The Mortgage provides that the Company and the Trustee, with consent of the
holders of not less than 66 2/3% in aggregate principal amount of the bonds
at the time outstanding which would be affected by the action proposed to be
taken, may by supplemental indenture add any provisions to or change or
eliminate any of the provisions of the Mortgage or modify the rights of the
holders of the bonds and coupons issued thereunder; provided, however, that
without the consent of the holder hereof no such supplemental indenture shall
affect the terms of payment of the principal of or interest or premium on
this bond, or reduce the aforesaid percentage of the bonds the holders of
which are required to consent to such a supplemental indenture, or permit the
creation by the Company of any mortgage or pledge or lien in the nature
thereof ranking prior to or equal with the lien of the Mortgage or deprive
the holder hereof of the lien of the Mortgage on any of the property which is
subject to the lien thereof.
If the date for making any payment or the last date for performance of any
act or the exercise of any right, as provided in the Supplemental Indenture
establishing the terms and series of the bonds of this series, as amended by
the supplemental indenture dated as of May 1, 1998 amending the Supplemental
Indenture, is not a Business Day, such payment may be made or act performed
or right exercised on the next succeeding Business Day unless otherwise
provided herein, with the same force and effect as if done on the nominal
date provided in the Supplemental Indenture establishing the terms and series
of the bonds of this series, as amended by the supplemental indenture dated
as of May 1, 1998 amending the Supplemental Indenture.
No recourse shall be had for the payment of the principal of or the interest
on this bond, or any part thereof, or for any claim based thereon or
otherwise in respect thereof, to any incorporator or any past, present or
future stockholder, officer or director of the Company, either directly or
indirectly, by virtue of any statute or by enforcement of any assessment or
otherwise, and any and all liability of the said incorporators, stockholders,
officers or directors of the Company in respect to this bond is hereby
expressly waived and released by every holder hereof.
Exhibit 4.2.25.4
AMENDMENT NO. 2
to the
STANDBY BOND PURCHASE AGREEMENT
AMENDMENT NO. 2, dated December 9, 1998 ("Amendment No. 2"), to the
Standby Bond Purchase Agreement, dated January 23, 1997, as amended by
Amendment No. 1, dated January 21, 1998 (the "Original Agreement"), among THE
CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and qualified to
do business as a public utility in the State of Connecticut (the "Company"),
SOCIETE GENERALE, a banking corporation organized under the laws of France,
acting through its New York Branch (the "Bank"), and STATE STREET BANK AND
TRUST COMPANY, a national banking associated, as successor trustee under the
Indenture referred to below (including any successor trustee, the "Trustee").
W I T N E S S E T H:
WHEREAS, the liquidity facility (the "Liquidity Facility") provided
by the Bank pursuit to the Original Agreement is scheduled to expire on
January 19, 1999;
WHEREAS, the Company has requested that the Bank extend the Stated
Expiration Date for on additional period, to expire 364 days from the date
hereof, on December 7, 1999 (the "Second Extension"), and the Bank has agreed
to do so on the terms and conditions contained herein and, to the extent
applicable and not superseded by this Amendment No. 2, according to the terms
and condition of the Original Agreement;
WHEREAS, certain conditions precedent to the effectiveness of this
Amendment No. 2 have been or will be fulfilled to the satisfaction of the
Bank and its compel as of He date of this Amendment No. 2;
NOW, THEREFORE, in consideration of the premises herein contained,
and other good and valuable consideration, the receipt and sufficiency of
which are hereby acknowledged, the parties hereto agree as follows:
1. Definitions. Unless otherwise defined herein, all capitalized
terms used heresy shall have the same respective meanings as in the Original
Agreement. From and after the date of this Amendment No. 2, the term
"Agreement" shall be deemed to mean The Original Agreement as amended by this
Amendment No. 2. References in the Original Agreement to "this Agreement" and
the words "hereof", "herein", "hereto" and the like shall refer to the
Original Agreement, Amendment No. 2, and the Original Agreement as amended by
the Amendment No. 2; provided, that, except as provided in Section 3 of this
Amendment No. 2, the words "the date of this Agreement" and "the date hereof"
shall continue to refer to the date of the Orison Agreement;
2. Amendments to the Original Agent. Effective upon fulfillment
of the conditions specified in Section 4 hereof, the Original Agreement is
hereby amended as follows:
A. The Stated Expiration Date is hereby extended for an
additional period, to expire 364 days from the date hereof, on December 7,
1999, and the definition of "Stated Expiration Date" contained in Section 1.1
of the Original Agreement is amended to read in its entirety as follows:
"Stated Expiration Date" means did later of (i) December 7, 1999,
or if such day is not a Business Day, the next preceding Business Day, and
(ii) the last day of any extension of such date pursuant to Section 2.6 or,
if such day is not a Business Day, the next preceding Business Day.
B. The definition of "Bank Purchase Period" contained in Section
1.1 of the Original Agreement is amended to read in its entirety as follows:
"Blank Purchase Period" means the period from the date of this
Amendment No. 2 to and including the earliest of (a) the Stated Expiration
Date then in effect, (b) the close of business on the fifth Business Day
follow the Conversion Date on which all of the Bonds shall have been
converted to a Fixed Rate or a Multiannual Rate (provided, however, that if
less than all of the Bonds shall have been converted to a Fixed Rate or
Multiannual Rate, the Bank's Available Commitment shall extend only to those
Bonds not bearing interest at the Fixed Rate or the Multiannual Rate), (c)
the fifth Business Day following the mandatory tender for purchase in
connection with a Substitution Date, or (d) the Purchase Termination Date.
C. At the end of Article 6 of the Standby Bond Purchase
Agreement, there shall be added a new Section 6.9 as follows:
Section 6.9, Year 2000 Compliance. The Company shall ensure that it
will be Year 2000 Compliant on or before December 31, 1999 and at all times
thereafter. As used (i) in the preceding sentence, "Year 2000 Compliant"
means the ability of the software and other information processing
capabilities of the Company to correctly interpret and process all data in
whatever form so as to avoid material errors that may otherwise occur because
of the inability of software or other information processing capabilities to
recognize accurately the year 2000 or subsequent dates and (ii) in this
sentence, "material errors" means errors that could, if not corrected, have a
material adverse effect on the Company's business or final condition.
3. Representatives and Warranties. The Company hereby represents
and warrants that all of the Presentations and warranties, contained in
Article 5 of the Original Agreement are true and correct, including any
statements made regarding the Related Documents as they may have been or will
be amended, supplemented or otherwise modified in connection with this Second
Extension, as of the date hereof (except that (i) the dates contained us
Section 5.5 shall be deemed to refer to the end of the Company's most
recently completed fiscal quarter, respectively, (ii) the references in
Section 5.5 to the Company's Annual Report, Quarterly Report and Current
Reports shall be deemed to refer to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1997, Company's Amendment No. 1 on
Form 10-K/A to Annual Report on Form 10-K for the fiscal year ended December
31, 1997, the Company's Quarterly Report on Form 10-Q for the period ended
September 30, 1998 and the Company's Current Reports on Form 8-K dated March
25, 1998, April 15, 1998 and September 10, 1998, and (iii) "prior to the date
hereof" in Section 5.6 shall be deemed to refer to on or prior to the date of
this Amendment No. 2). The Company further represents and warrants that no
Event of Default or Event of Termination has occurred or is occurring, and
that no event has occurred which, with notice or the lapse of time or both,
would become an Event of Default or Event of Termination, as the case may be.
4. Conditions Precedent to the Effectiveness of this Amendment
No. 2. The Bank's obligation to enter into and perform its obligations under
this Amendment No. 2 is subject to the fulfillment, to the satisfaction of
the Bank and its counsel, of each of the following conditions as of the date
of this Amendment No. 2:
(a) The Act; the Resolution. Neither the Act nor the Resolution
shall have been revoked or rescinded, or modified or amended in any material
respect adverse to the interests of the Bank or the holders of the Bonds.
(b) Receipt of Documents. The Bank shall have received an executed
copy of this Amendment No. 2 as well as any other documents and instruments
as the Bank shall reasonably request.
(c) Certificate. The Bank shall have received a certificate from
the Company, dated the date of this Agreement and duly executed by an
Authorized Officer, stating that on and as of the date thereof, except as
otherwise disclosed to the Bank as of the date of this Amendment No. 2;
(i) the Company has obtained all consents, fits, licenses and
approvals of, has made all registrations arid declarations with, and has
taken all other actions with respect to, governmental authorities required
under law to be obtained, made or taken by the Company, to maintain the Bonds
and to execute, deliver and perform this Amendment No. 2;
(ii) that the Insurance Policy is currently effective and
provides for (i) the payment of interest on the Bank Bonds at the Bank Rate
and (ii) amortization of the Bank Bonds in equal semiannual installments
during the Amortization Period.
(iii) to the best knowledge of the Authorized Officer
executing the certificate, no Event of Default or event which, with the
giving of notice or the passage of time or both would constitute an Event of
Default, has occurred or would occur after giving effect to the issuance of
the Bonds or this Amendment No. 2 or the Original Agreement as amended by
this Amendment No. 2.
(iv) all representations and warranties of the Company set
forth in the Original Agreement and the Related Documents to which the
Company is a party are true and correct in all material respects, except to
the extent that any such representation or warranty relates solely to a prior
date;
(v) the Company is not in default of its obligations under
this Amendment No. 2 or the Original Agreement or any of the Related
Documents to which it is a party;
(vi) except for any pending or threatened action, suit,
investigation or proceeding disclosed in the Reoffering Circular or otherwise
disclosed to the Bank in writing on or prior to the date hereof (as to which
certification is not being made), there is no action, suit, investigation or
proceeding pending or, to the best knowledge of the Authorized Officer
executing the certificate, threatened (A) in connection with the Bonds, the
replacement of the Letter of Credit, the Original Agreement, this Amendment
No. 2 or any of the other transactions contemplated by this Amendment No. 2
or the Related Documents, or (B) against or affecting the Company, the result
of which is reasonably likely to have a materially adverse effect on the
business, financial condition or operations of the Company or the ability of
the Company to perform or observe any of its duties, liabilities or
obligations under this Amendment No. 2 or any of the Related Documents.
(d) Proceedings and Certifications. The Bank shall have received a
copy, certified by an Authorized Officer, of all proceedings taken by the
Company authorizing the transactions hereunder and contemplated hereby,
including, without limitation, the execution and delivery of this Amendment
No. 2 and all other documents and agreements contemplated hereby, together
with such other certifications as to matters of fact as shall reasonably be
requested by the Bank or its counsel.
(e) Incumbency Certificate. The Bank shall have received a
certificate of the Secretary or Assistant Secretary of the Company certifying
the names and true signatures of the officials of the Company authorized to
sign this Amendment No. 2 and the other documents to be delivered by the
Company hereunder, and shall also cover such other matters incident to the
transactions contemplated by this Agreement as the Bank or its counsel may
request.
(f) Opinion of Company CounseI. The Bank shall have received an
opinion addressed to it of Day, Berry & Howard, counsel to the Company, dated
the closing date on which the extension of the Liquidity Facility provided by
this Amendment No. 2 shall have become effective, in form and substance
satisfactory to the Bank and its counsel.
(g) Other Documents, Etc. The Bank shall have received such other
documents, certificates, and opinions as the Bank; or its counsel may
reasonably request, including, without limitation, organizational documents
of the Authority, the Company, and the Bond Insurer, and all matters relating
to this Amendment No. 2 and the Bonds shall be satisfactory to the Bank.
5. Fees and Expenses.
(a) Expenses Relating to Amendment No. 2. The Company hereby
agrees to pay all reasonable costs and expenses of the Bank (including,
without limitation, reasonable attorneys' fees and disbursements, but
excluding, overhead and other internal costs of the Bank) in connection with
the negotiation, preparation, review, execution and delivery of this
Amendment No. 2. The Company hereby also agrees to pay on demand all costs
and expenses paid or incurred by the Bank, if any, in connection with the
enforcement of this Amendment No. 2 and in connection the amendment or
enforcement of any Related Documents, and the protection of the rights of the
Bank hereunder and thereunder (including reasonable counsel fees and
disbursements but excluding overhead and other internal costs of the Bank).
(b) Amendment and Extension Fee. The Company hereby also agrees to
pay a one time amendment and extension fee (the "Amendment and Extension
Fee"), calculated at 7.5 basis points on the total Liquidity Facility amount
of sixty-two million nine hundred eighteen thousand dollars ($62,918,000) for
a total Amendment and Extension Fee of forty-seven thousand one hundred
ninety dollars ($47,190,000).
6. Continued Effectiveness. This Amendment No. 2 is to be
narrowly construed. Except as expressly amended by this Amendment No. 2, all
terms and provisions of the Original Agreement are and shall continue in full
force and effect. Any references to the Original Agreement in any of the
Related Documents shall hereafter be deemed to refer to the Original
Agreement, as amended by this Amendment No. 2.
7. Governing Law. This Amendment No. 2 shall be governed by, and
construed in accordance with, the law of the State of New York.
9. Counterparts. This Amendment No. 2 may be expected by the
parties hereto in any number of counterparts.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment
No. 2 to be duly executed and delivered by their respective officers
thereunto authorized as of the date first written above.
/S/THE CONNECTICUT LIGHT AND POWER
COMPANY
Payment Instructions:
Societe Generale /S/SOCIETE GENERALE
New York New York Branch
ABA No. 026004226
Re: The Connecticut Light and
Power Company
Acct. No. 902 5855
/S/STATE STREET BANK AND TRUST
COMPANY, as Trustee
Exhibit 4.3.2
U.S. $75,000,000
REVOLVING CREDIT AGREEMENT
Dated as of April 23, 1998
Among
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
as Borrower
THE BANKS NAMED HEREIN
as Banks
and
THE CHASE MANHATTAN BANK
as Administrative Agent
REVOLVING CREDIT AGREEMENT
Dated as of April 23, 1998
This REVOLVING CREDIT AGREEMENT (this "Agreement") is made by and among:
(i) PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE, a corporation duly organized
and validly existing under the laws of the State of New Hampshire (the
"Borrower"),
(ii) CHASE SECURITIES, INC. ("CSI"), as Arranger for the Lenders hereunder,
(iii) THE CHASE MANHATTAN BANK ("Chase"), as Administrative Agent and
Documentation Agent for the Lenders hereunder, and
(iv) the financial institutions (the "Banks") listed on the signature pages
hereof and the other Lenders (as hereinafter defined) from time to time party
hereto.
The parties hereto agree as follows:
ARTICLE I
Definitions and Accounting Terms
Section I.1 Certain Defined Terms. As used in this Agreement, the
following terms have the meanings specified below (such meanings to be
applicable to the singular and plural forms of the terms defined):
"Advance" means an advance by a Lender to the Borrower pursuant to Section
3.1 hereof and refers to a Eurodollar Rate Advance or a Base Rate Advance
(each of which shall be a "Type" of Advance). For purposes of this
Agreement, all Advances of a Lender (or portions thereof) of the same Type
and Interest Period made on the same day shall be deemed to be a single
Advance by such Lender until repaid.
"Administrative Agent" means Chase or any successor thereto as provided
herein.
"Affiliate" means, with respect to a specified Person, another Person that
directly or indirectly through one or more intermediaries, controls or is
controlled by or is, directly or indirectly, under common control with such
Person. A Person shall be deemed to control another if such Person
possesses, directly or indirectly, the power to direct or cause the direction
of the management and policies of such entity, whether through the ownership
of voting securities, by contract or otherwise.
"Agreement for Capacity Transfer" means the Agreement for Capacity Transfer,
dated as of December 1, 1989, between The Connecticut Light and Power Company
and the Borrower as amended by the First Amendment to Agreement for Capacity
Transfer, dated as of May 1, 1992, which provides for capacity transfers from
the Borrower to The Connecticut Light and Power Company.
"Alternate Base Rate" means, for any day, a rate per annum (rounded upwards,
if necessary, to the next 1/8 of 1%) equal to the greater of:
(a) the Prime Rate in effect on such day; and
(b) the Federal Funds Rate in effect on such day plus 1/2 of 1% per annum.
For purposes hereof, the term "Prime Rate" shall mean the rate of interest
per annum publicly announced from time to time by Chase as its prime rate in
effect at its principal office in New York City; each change in the Prime
Rate shall be effective on the date such change is publicly announced. If
the Administrative Agent shall have determined (which determination shall be
conclusive absent manifest error) that it is unable to ascertain the Federal
Funds Rate for any reason, including the inability or failure of the
Administrative Agent to obtain sufficient quotations in accordance with the
terms thereof, the Alternate Base Rate shall be determined without regard to
clause (b) of the first sentence of this definition until the circumstances
giving rise to such inability no longer exist. Any change in the Alternate
Base Rate due to a change in the Prime Rate or the Federal Funds Rate shall
be effective from and including the effective date of such change in the
Prime Rate or the Federal Funds Rate, respectively.
"Applicable Lending Office" means, with respect to each Lender:
(i) (A) such Lender's "Eurodollar Lending Office" in the case of a
Eurodollar Rate Advance, or (B) such Lender's "Domestic Lending Office" in
the case of a Base Rate Advance, in each case as specified opposite such
Lender's name on Schedule I hereto or in the Lender Assignment pursuant to
which it became a Lender; or
(ii) in each case, such other office or affiliate of such Lender as such
Lender may from time to time specify in writing to the Borrower and the
Administrative Agent.
"Applicable Margin" means, for any day for any outstanding Advance, (i)
2.25% for each Eurodollar Rate Advance and (ii) 1.25% for each Base Rate
Advance.
"Applicable Rate" means:
(ii) in the case of each Eurodollar Rate Advance comprising part of the same
Borrowing, a rate per annum during each Interest Period equal at all times to
the sum of the Eurodollar Rate for such Interest Period plus the Applicable
Margin in effect from time to time during such Interest Period; and
(iii) in the case of each Base Rate Advance, a rate per annum equal at
all times to the sum of the Alternate Base Rate in effect from time to time
plus the Applicable Margin in effect from time to time;
"Available Commitment" means, for each Lender, the unused portion of such
Lender's Commitment (which shall be equal to the excess, if any, of such
Lender's Commitment over such Lender's Advances outstanding). "Available
Commitments" shall refer to the aggregate of the Lenders' Available
Commitments hereunder.
"Barclays" means Barclays Bank PLC, New York Branch, in its capacity as
issuing bank and agent under the Series D Reimbursement Agreement.
"Base Rate Advance" means an Advance in respect of which the Borrower has
selected in accordance with Article III hereof, or this Agreement provides
for, interest to be computed on the basis of the Alternate Base Rate.
"Bond Conversion" means the conversion of the $119.8 million Pollution
Control Revenue Bonds to an unsupported fixed rate mode with a final maturity
of May 1, 2021.
"Borrowing" means a borrowing consisting of Advances of the same Type and
Interest Period made on the same day by the Lenders, ratably in accordance
with their respective Commitments. A Borrowing may be referred to herein as
being a "Type" of Borrowing, corresponding to the Type of Advances comprising
such Borrowing. For purposes of this Agreement, all Advances of the same
Type and Interest Period made on the same day shall hereunder be deemed a
single Borrowing until repaid.
"Business Day" means a day of the year on which banks are not required or
authorized to close in New York City and which is not a day listed on
Schedule II hereto and, if the applicable Business Day relates to any
Eurodollar Rate Advances, on which dealings are carried on in the London
interbank market.
"Closing" means the fulfillment of each of the conditions precedent
enumerated in Section 5.1 hereof to the satisfaction of the Lenders, the
Administrative Agent and the Borrower. All transactions contemplated by the
Closing shall take place on or prior to April 23, 1998, at the offices of
Skadden, Arps, Slate, Meagher & Flom LLP, 919 Third Avenue, New York, New
York 10022, at 12:01 a.m. (New York time), or such other place and time as
the parties hereto may mutually agree (the "Closing Date").
"Code" means the Internal Revenue Code of 1986, as amended from time to time.
"Collateral" means all of the Collateral FMB and the Security Agreement
Collateral.
"Collateral Agent" means Chase in its capacity as collateral agent, or any
successor thereto, as provided in the Intercreditor Agreement.
"Collateral FMB" means that certain First Mortgage Bond, Series H, issued by
the Borrower on the date hereof pursuant to the Eleventh Supplemental
Indenture to the First Mortgage Indenture to the Collateral Agent for the
benefit of the Lenders, in substantially the form of Exhibit 1.1D attached
hereto, as the same may be amended, supplemented or otherwise modified from
time to time.
"Commitment" means, for each Lender, the aggregate amount set forth opposite
such Lender's name on the signature pages hereof or, if such Lender has
entered into one or more Lender Assignments, set forth for such Lender in the
Register maintained by the Administrative Agent pursuant to Section 10.7(c),
in each such case as such amount may be reduced from time to time pursuant to
Section 2.3 hereof. "Commitments" shall refer to the aggregate of the
Lenders' Commitments hereunder.
"Commitment Fee Rate" means, for any date, 0.50% per annum on each Lender's
Available Commitment.
"Common Equity" means, at any date, an amount equal to the sum of: (i) the
aggregate of the par value of, or stated capital represented by, the
outstanding shares of common stock of the Borrower and (ii) the surplus,
paid-in, earned and other, if any, of the Borrower.
"Confidential Information" has the meaning assigned to that term in Section
10.8.
"Debt" means, for any Person, without duplication, (i) indebtedness of such
Person for borrowed money, (ii) obligations of such Person evidenced by
bonds, debentures, notes or other similar instruments, (iii) obligations of
such Person to pay the deferred purchase price of property or services, (iv)
obligations of such Person as lessee under leases which shall have been or
should be, in accordance with generally accepted accounting principles,
recorded as capital leases (but excluding the Unit Contract), (v) obligations
(contingent or otherwise) of such Person under reimbursement or similar
agreements with respect to the issuance of letters of credit, (vi) net
obligations (contingent or otherwise) of such Person under interest rate
swap, "cap," "collar" or other hedging agreements, (vii) obligations of such
person to pay rent or other amounts under leases entered into in connection
with sale and leaseback transactions involving assets of such Person being
sold in connection therewith, (viii) obligations under direct or indirect
guaranties in respect of, and obligations (contingent or otherwise) to
purchase or otherwise acquire, or otherwise to assure a creditor against loss
in respect of, indebtedness or obligations of others of the kinds referred to
in clauses (i) through (vii), above, and (ix) liabilities in respect of
unfunded vested benefits under ERISA Plans.
"Debt Limit" means the limitation on the incurrence of short-term debt
applicable to the Borrower in effect from time to time either in accordance
with applicable law or a waiver thereof granted by competent governmental
authority, including without limitation, the New Hampshire Public Utilities
Commission.
"Default" means the event or condition that constitutes an Event of Default
or that upon notice, lapse of time or both would, unless cured or waived,
become an Event of Default.
"Disclosure Documents" means the Information Memorandum, the Borrower's 1997
Annual Report, the Borrower's Annual Report on Form 10-K for the year ended
December 31, 1997, and any Current Report on Form 8-K of the Borrower, filed
by the Borrower with the Securities and Exchange Commission after December
31, 1997, and any Current Report on Form 8-K of NU which has been furnished
to the Banks prior to the execution and delivery of this Agreement.
"Documentation Agent" means Chase or any successor thereto.
"ERISA" means the Employee Retirement Income Security Act of 1974, as amended
from time to time.
"ERISA Affiliate" means any trade or business (whether or not incorporated)
that, together with the Borrower, is treated as a single employer under
Section 414(b) or (c) of the Code or, solely for purposes of Section 302 of
ERISA and Section 412 of the Code, is treated as a single employer under
Section 414 of the Code.
"ERISA Multiemployer Plan" means a "multiemployer plan" subject to Title IV
of ERISA.
"ERISA Plan" means an employee benefit plan (other than an ERISA
Multiemployer Plan) maintained for employees of the Borrower or any ERISA
Affiliate and covered by Title IV of ERISA.
"ERISA Event" means: (i) a "reportable event", as defined in Section 4043 of
ERISA or the regulations issued thereunder (other than an event for which the
30-day notice period is waived) with respect to an ERISA Plan or an ERISA
Multi-employer Plan, or (ii) the existence with respect to any ERISA plan of
an "accumulated funding deficiency" (as defined in Section 412(d) of the Code
or Section 302 of ERISA), whether or not waived; (iii) the filing pursuant to
Section 412(d) of the Code or Section 303(d) of ERISA of an application for a
waiver of the minimum funding standard with respect to any ERISA Plan; (iv)
the incurrence by the Borrower or any of its ERISA Affiliates of any
liability under Title IV of ERISA with respect to the termination of any
ERISA Plan; (v) the receipt by the Borrower or any of its ERISA Affiliates
from the PBGC or a plan administrator of any notice relating to an intention
to terminate any ERISA Plan or an ERISA Multiemployer Plan under Section 4041
of ERISA or to appoint a trustee to administer any ERISA Plan or ERISA
Multiemployer Plan; (vi) the receipt by the Borrower or any of its ERISA
Affiliates of any notice, or the receipt by any ERISA Multiemployer Plan from
the Borrower or any of its ERISA Affiliates of any notice, concerning the
imposition of liability due to any withdrawal of the Borrower or any of its
ERISA Affiliates from an ERISA Plan or an ERISA Multiemployer Plan during a
plan year in which it was a "substantial employer" as defined in Section
4001(a)(2) of ERISA, or a determination that an ERISA Multiemployer Plan is,
or is expected to be, insolvent or in reorganization, within the meaning of
Title IV of ERISA or (vii) any other event or condition which might
constitute grounds under Section 4042 of ERISA for the termination of, or the
appointment of a trustee to administer, any ERISA Plan or ERISA Multiemployer
Plan.
"Eurocurrency Liabilities" has the meaning assigned to that term in
Regulation D of the Board of Governors of the Federal Reserve System, as in
effect from time to time.
"Eurodollar Rate" means, for each Interest Period and each Eurodollar Rate
Advance comprising part of the same Borrowing, an interest rate per annum
equal to the average (rounded upward to the nearest whole multiple of 1/100
of 1% per annum, if such average is not such a multiple) of the rates per
annum at which deposits in U.S. dollars are offered by the principal office
of each of the Reference Banks in London, England to prime banks in the
London interbank market at 11:00 a.m. (London time) two Business Days before
the first day of such Interest Period in an amount of $1,000,000 and for a
period equal to such Interest Period. The Eurodollar Rate for the Interest
Period for each Eurodollar Rate Advance comprising part of the same Borrowing
shall be determined by the Administrative Agent on the basis of applicable
rates furnished to and received by the Administrative Agent from the
Reference Banks, two Business Days before the first day of such Interest
Period, subject, however, to the provisions of Sections 3.5(d) and 4.3(g).
"Eurodollar Rate Advance" means an Advance in respect of which the Borrower
has selected in accordance with Article III hereof, and this Agreement
provides for, interest to be computed on the basis of the Eurodollar Rate.
"Eurodollar Reserve Percentage" of any Lender for each Interest Period and
each Eurodollar Rate Advance means the reserve percentage applicable during
such Interest Period (or if more than one such percentage shall be so
applicable, the daily average of such percentages for those days in such
Interest Period during which any such percentage shall be so applicable)
under Regulation D or other regulations issued from time to time by the Board
of Governors of the Federal Reserve System (or any successor) for determining
the maximum reserve requirement (including, without limitation, any
emergency, supplemental or other marginal reserve requirement, without
benefit of or credit for proration, exemptions or offsets) for such Lender
with respect to liabilities or assets consisting of or including Eurocurrency
Liabilities having a term equal to such Interest Period.
"Event of Default" has the meaning specified in Section 8.1.
"Existing Collateral Agency Agreement" means the Amended and Restated
Collateral Agency Agreement, dated as of April 1, 1996, between the Borrower
and Chase, as Collateral Agent and the Administrative Agent.
"Existing Revolving Credit Agreement" means the Amended and Restated
Revolving Credit Agreement, dated as of April 1, 1996, among the Borrower,
Chase, as Administrative Agent, and the lenders from time to time party
thereto, as the same may have been amended or supple-mented.
"Facility" means the facility made available to the Borrower by each of the
Lenders under Sections 2.1(a) and 3.1 to request, prepay and repay Advances
in connection with each Lender's Commitment.
"Federal Funds Rate" means, for any period, a fluctuating interest rate per
annum equal for each day during such period to the weighted average (rounded
upwards, if necessary, to the next 1/100 of 1%) of the rates on overnight
Federal funds transactions with members of the Federal Reserve System
arranged by Federal funds brokers, as published on the next succeeding
Business Day by the Federal Reserve Bank of New York, or, if such rate is not
so published for any day that is a Business Day, the average (rounded
upwards, if necessary, to the next 1/100 of 1%) of the quotations for such
day for such transactions received by the Administrative Agent from three
Federal funds brokers of recognized standing selected by it.
"Fee Letter" means the Fee Letter, dated as of February 25, 1998, among the
Borrower, Chase and CSI.
"Final Plan" means the "Final Plan" implementing Chapter 374-F of the Revised
Statutes Annotated of New Hampshire, adopted by the NHPUC on February 28,
1997, and any successor plan or proposal.
"First Mortgage Indenture" means the General and Refunding Mortgage
Indenture, between the Borrower and New England Merchants National Bank, as
trustee and to which First Union National Bank, is successor trustee, dated
as of August 15, 1978, as amended and supplemented through the date hereof,
as the same may hereafter be amended, supplemented or modified from time to
time including pursuant to the Supplemental Indenture.
"Funding Suspension" has the meaning assigned to that term in the
Intercreditor Agreement.
"Governmental Approval" means any authorization, consent, approval, license,
permit, certificate, exemption of, or filing or registration with, any
governmental authority or other legal or regulatory body, required in
connection with any of (i) the execution, delivery or performance of the Rate
Agreement, any Loan Document or any Significant Contract, (ii) the grant and
perfection of any security interest, lien or mortgage contemplated by the
Security Documents, (iii) the nature of the Borrower's business as conducted
or the nature of the property owned or leased by it or (iv) any NUG
Settlement. For purposes of this Agreement, Chapter 362-C of the Revised
Statutes Annotated of New Hampshire, as in effect on the date hereof, shall
be deemed to be a Governmental Approval.
"Hazardous Substance" means any waste, substance or material identified as
hazardous, dangerous or toxic by any office, agency, department, commission,
board, bureau or instrumentality of the United States of America or of the
State or locality in which the same is located having or exercising
jurisdiction over such waste, substance or material.
"Indemnified Person" has the meaning assigned to that term in Section 10.4(b)
hereof.
"Indenture Assets" means any fixed assets of the Borrower (including related
Governmental Approvals and regulatory assets, but excluding Seabrook) which
from time to time are subject to the first-priority lien under the First
Mortgage Indenture.
"Information Memorandum" means the Confidential Information Memorandum, dated
February 1998, regarding the Borrower, as distributed to the Administrative
Agent and the Lenders, including all schedules, attachments and supplements,
if any, thereto.
"Intercreditor Agreement" means the Collateral Agency and Intercreditor
Agreement, dated as of the date hereof, among Chase, in its capacities as
Administrative Agent and Collateral Agent, and Barclays and Swiss Bank, each
acting in its capacity as agent of the Other Credit Documents.
"Interest Expense" means, for any period, the aggregate amount of any
interest on Debt (including long-term and short-term Debt).
"Interest Period" has the meaning assigned to that term in Section 3.5(a).
"Lender Assignment" means an assignment and agreement entered into by a
Lender and an assignee, and accepted by the Administrative Agent, in
substantially the form of Exhibit 10.7 hereto.
"Lenders" means the financial institutions listed on the signature pages
hereof, and each assignee that shall become a party hereto pursuant to
Section 10.7.
"Lien" has the meaning assigned to that term in Section 7.2(a) hereof.
"Loan Documents" means this Agreement, the Notes and the Security Documents
(as each may be amended, supplemented or otherwise modified from time to
time).
"Major Electric Generating Plants" means the following generating stations of
the Borrower: the Merrimack generating station located in Bow, New Hampshire;
the Newington generating station located in Newington, New Hampshire; the
Schiller generating station located in Portsmouth, New Hampshire; the White
Lake combustion turbine located in Tamworth, New Hampshire; the Millstone
Unit No. 3 generating station located in Waterford, Connecticut, and the
Wyman Unit No. 4 generating station located in Yarmouth, Maine.
"Majority Lenders" means, on any date of determination, Lenders who,
collectively, on such date (i) hold at least 66-2/3% of the then aggregate
unpaid principal amount of Advances owing to the Lenders and (ii) have
Percentages in the aggregate of at least 66-2/3% (whether such Commitments
are used or unused). Determination of those Lenders satisfying the criteria
specified above for action by the Majority Lenders shall be made by the
Administrative Agent and shall be conclusive and binding on all parties
absent manifest error.
"Moody's" means Moody's Investors Service, Inc., a corporation organized and
existing under the laws of the State of Delaware, its successors and assigns.
"NAEC" means North Atlantic Energy Corporation, a wholly owned subsidiary of
NU.
"NHPUC" means the New Hampshire Public Utilities Commission.
"Note" means a promissory note of the Borrower payable to the order of a
Lender, in substantially the form of Exhibit 1.1A hereto, evidencing the
aggregate indebtedness of the Borrower to such Lender resulting from the
Advances made by such Lender.
"Notice of Borrowing" has the meaning assigned to that term in Section 3.1
hereof.
"NU" means Northeast Utilities, an unincorporated voluntary business
association organized under the laws of the Commonwealth of Massachusetts.
"NUG Settlement" means any buy-out, buy-down or other transaction, or any
other arrangement or agreement, entered into or proposed to be entered into
by the Borrower to terminate or reduce, or to resolve a dispute concerning,
an obligation of the Borrower to purchase power and/or capacity from a non-
utility generator.
"NUSCO" means Northeast Utilities Service Company, a Connecticut corporation
and a wholly owned subsidiary of NU.
"Obligations" shall mean all obligations of every nature of the Borrower from
time to time owed to the Administrative Agent and the Lenders, or any of
them, under the Loan Documents.
"Operating Income" means, for any period, the Borrower's operating income for
such period, adjusted as follows:
(ii) increased by the amount of income taxes (including New Hampshire
Business Profits Tax and other comparable taxes) paid by the Borrower during
such period, if and to the extent they are deducted in the computation of the
Borrower's operating income for such period; and
(iii) increased by the amount of any depreciation deducted by the
Borrower during such period; and
(iv) increased by the amount of any amortization of acquisition adjustment
deducted by the Borrower during such period; and
(v) decreased by the amount of any capital expenditures paid by the Borrower
during such period.
"Other Credit Agreements" means each of the Series D Reimbursement Agreement
and the Series E Reimbursement Agreement.
"PBGC" means the Pension Benefit Guaranty Corporation (or any successor
entity) established under ERISA.
"Percentage" means, in respect of any Lender on any date of determination,
the percentage obtained by dividing such Lender's Commitment on such day by
the total aggregate amount of the Commitments on such day, and multiplying
the quotient so obtained by 100%.
"Permitted Investments" means (i) securities issued or directly and fully
guaranteed or insured by the United States or any agency or instrumentality
thereof (provided that the full faith and credit of the United States is
pledged in support thereof) having maturities of not more than six (6) months
from the date of acquisition by such Person; (ii) time deposits and
certificates of deposit, with maturities of not more than six (6) months from
the date of acquisition by such Person, of any international commercial bank
of recognized standing having capital and surplus in excess of $500,000,000
and having a rating on its commercial paper of at least A-1 or the equivalent
thereof by S&P or at least P-1 or the equivalent thereof by Moody's; (iii)
commercial paper issued by any Person, which commercial paper is rated at
least A-1 or the equivalent thereof by S&P or at least P-1 or the equivalent
thereof by Moody's and matures not more than six (6) months after the date of
acquisition by such Person; (iv) investments in money market funds
substantially all the assets of which are comprised of securities of the
types described in clauses (i) and (ii) above and (v) United States
Securities and Exchange Commission registered money market mutual funds
conforming to Rule 2a-7 of the Investment Company Act of 1940 if effect in
the United States, that invest primarily in direct obligations issued by the
United States Treasury and repurchase obligations backed by those
obligations, and rated in the highest category by S&P and Moody's.
"Person" means an individual, partnership, corporation (including a business
trust), limited liability company, joint stock company, trust, unincorporated
association, joint venture or other entity, or a government or any political
subdivision or agency thereof.
"Preferred Stock" means 5,000,000 shares of the Borrower's Series A Preferred
Stock (par value $25 per share).
"PSNH Mortgage" means the Mortgage, Assignment, Security Agreement and
Financing Statement, dated as of May 1, 1991, by the Borrower to The Chase
Manhattan Bank (as successor to Chemical Bank and Bankers Trust Company), as
amended.
"Rate Agreement" means the Agreement dated as of November 22, 1989, as
amended by the First Amendment to Rate Agreement dated as of December 5,
1989, the Second Amendment to Rate Agreement dated as of December 12, 1989,
the Third Amendment to Rate Agreement dated as of December 28, 1993, the
Fourth Amendment to Rate Agreement dated as of September 21, 1994 and the
Fifth Amendment to Rate Agreement dated as of September 9, 1994, among NUSCO,
the Governor and Attorney General of the State of New Hampshire and adopted
by the Borrower as of July 10, 1990 (excluding the Unit Contract appended as
Exhibit A thereto subsequent to the effectiveness of such contract).
"Rate Proceeding" means all regulatory proceedings relating to the Borrower
and resulting from the NHPUC's adoption of the Final Plan, together with the
Federal litigation commenced by the Borrower and certain of its Affiliates in
response thereto.
"Recipient" has the meaning assigned to that term in Section 10.8 hereof.
"Reference Banks" means Chase, Citibank, N.A. and Bank of America National
Trust and Savings Association.
"Register" has the meaning specified in Section 10.7(c).
"S&P" means Standard & Poor's Ratings Services, a division of McGraw-Hill
Companies Inc., its successors and assigns.
"Seabrook" means the nuclear-fueled steam-electric generating plant located
in Seabrook, New Hampshire, and the real property interests and other fixed
assets of such plant.
"Secured Party" has the meaning assigned to that term in the Inter-creditor
Agreement.
"Security Agreement" means the Assignment and Security Agreement, dated as of
the date hereof, between the Borrower and the Collateral Agent.
"Security Agreement Collateral" means the "Collateral" as defined in the
Security Agreement.
"Security Documents" means the Collateral FMB, the Security Agreement, the
First Mortgage Indenture, the Supplemental Indenture and the Intercreditor
Agreement (as the same may be amended, supplemented or otherwise modified
from time to time).
"Series D Reimbursement Agreement" means (a) the Second Series D Letter of
Credit and Reimbursement Agreement, dated as of May 1, 1995, among the
Borrower, Barclays and the banks parties thereto from time to time and named
therein relating to the Business Finance Authority (formerly the Industrial
Development Authority) of the State of New Hampshire Pollution Control
Revenue Bonds (Public Service Company of New Hampshire Project - 1991 Taxable
Series D) and Pollution Control Revenue Refunding Bonds (Public Service
Company of New Hampshire Project - 1992 Tax-Exempt Series D), as amended by
the Series D Reimbursement Agreement Amendment and as the same may from time
to time be further amended, modified or supplemented and (b) any
reimbursement agreement or similar agreement relating to a substitute credit
facility applicable to such bonds.
"Series D Reimbursement Agreement Amendment" means the First Amendment, dated
as of April 23, 1998, to the Series D Reimbursement Agreement.
"Series E Reimbursement Agreement" means (a) the Second Series E Letter of
Credit and Reimbursement Agreement, dated as of May 1, 1995, among the
Borrower, Swiss Bank and the banks parties thereto from time to time and
named therein relating to the Business Finance Authority (formerly the
Industrial Development Authority) of the State of New Hampshire Pollution
Control Revenue Bonds (Public Service Company of New Hampshire Project - 1991
Taxable Series E) and Pollution Control Revenue Refunding Bonds (Public
Service Company of New Hampshire Project - 1993 Tax-Exempt Series E), as
amended by the Series E Reimbursement Agreement Amendment and as the same may
from time to time be further amended, modified or supplemented and (b) any
reimbursement agreement or similar agreement relating to a substitute credit
facility applicable to such bonds.
"Series E Reimbursement Agreement Amendment" means the First Amendment, dated
as of April 23, 1998, to the Series E Reimbursement Agreement.
"Sharing Agreement" means the Sharing Agreement, dated as of June 1, 1992,
among The Connecticut Light and Power Company, Western Massachusetts Electric
Company, Holyoke Water Power Company, Holyoke Power and Electric Company, the
Borrower and NUSCO.
"Significant Contracts" means the following contracts, in each case as the
same may be amended, modified or supplemented from time to time in accordance
with this Agreement:
(ii) the Agreement for Capacity Transfer;
(iii) the Sharing Agreement;
(iv) the Tax Allocation Agreement; and
(v) the Unit Contract.
"Supplemental Indenture" means the Eleventh Supplemental Indenture dated as
of April 23, 1998 to the First Mortgage Indenture.
"Swiss Bank" means Swiss Bank Corporation, New York Branch, in its capacity
as issuing bank and agent under the Series E Reimbursement Agreement.
"Tax Allocation Agreement" means the Tax Allocation Agreement dated as of
January 1, 1990 among NU and the members of the consolidated group of which
NU is the common parent, including, without limitation, the Borrower.
"Termination Date" means the earlier to occur of (i) April 22, 1999, (ii)
April 30, 1998, if the Closing Date shall not have occurred on or prior to
such date, (iii) the date of termination or reduction in whole of the
Commitments pursuant to Section 2.3 or 8.2 or (iv) the date of acceleration
of all amounts payable hereunder and under the Notes pursuant to Section 8.2.
"Total Capitalization" means, as of any day, the aggregate of all amounts
that would, in accordance with generally accepted accounting principals
applied on a basis consistent with the standards referred to in Section 1.3
hereof, appear on the balance sheet of the Borrower as of such day as the sum
of (i) the principal amount of all long-term Debt of the Borrower on such
day, (ii) the par value of, or stated capital represented by, the outstanding
shares of the all classes of common and preferred shares of the Borrower on
such day, (iii) the surplus of the Borrower, paid-in, earned and other, if
any, on such day and (iv) the unpaid principal amount of all short-term Debt
of the Borrower on such day.
"Transaction Documents" means the Loan Documents, the Other Credit Agreements
and the other documents to be delivered to the Administrative Agent by or on
behalf of the Borrower in connection with the Closing.
"Type" has the meaning assigned to such term (i) in the definition of
"Advance" when used in the such context and (ii) in the definition of
"Borrowing" when used in such context.
"Unit Contract" means the Unit Contract, dated as of June 5, 1992, between
the Borrower and NAEC.
Section I.2 Computation of Time Periods. In the computation of periods of
time under this Agreement any period of a specified number of days or months
shall be computed by including the first day or month occurring during such
period and excluding the last such day or month. In the case of a period of
time "from" a specified date "to" or "until" a later specified date, the word
"from" means "from and including" and the words "to" and "until" each means
"to but excluding."
Section I.3 Accounting Terms. All accounting terms not specifically
defined herein shall be construed in accordance with generally accepted
accounting principles applied on a basis consistent with the application
employed in the preparation of the financial projections referred to in
Section 5.1 hereof.
Section I.4 Computations of Outstandings. Whenever reference is made in
this Agreement to the principal amount outstanding on any date under this
Agreement, such reference shall refer to the sum of the aggregate principal
amount of all Advances outstanding on such date in each case after giving
effect to all Advances to be made on such date and the application of the
proceeds thereof.
ARTICLE II
Commitments
Section II.1 The Commitments. (a) Each Lender severally agrees, on the
terms and conditions hereinafter set forth, to make Advances to the Borrower
from time to time on any Business Day during the period from the Closing Date
until the Termination Date in an aggregate outstanding amount not to exceed
on any day such Lender's Available Commitment (after giving effect to all
Advances to be made on such day and the application of the proceeds thereof).
Within the limits of each Lender's Available Commitment, the Borrower may
request Advances hereunder, repay or prepay Advances and utilize the
resulting increase in the Available Commitments for further Advances in
accordance with the terms hereof, including, without limitation, the
conditions set forth in Section 5.2.
(b) In no event shall the Borrower be entitled to request or receive any
Advance under subsection (a) that would cause the total principal amount
advanced pursuant thereto to exceed the Available Commitment. In no event
shall the Borrower be entitled to request or receive any Advance that would
cause the total principal amount outstanding hereunder to exceed the
Commitments.
Section II.2 Fees. (a) The Borrower agrees to pay to the Administrative
Agent for the account of each Lender a commitment fee on the amount of such
Lender's Available Commitment at the Commitment Fee Rate, effective as of the
Closing Date, in the case of each Bank, and from the effective date specified
in the Lender Assignment pursuant to which it became a Lender, in the case of
each other Lender, until the Termination Date, payable quarterly in arrears
on the last day of each March, June, September and December, commencing the
first such date following the Closing Date, with final payment payable on the
Termination Date.
(b) The Borrower agrees to pay to the Administrative Agent and to CSI or
Chase the fees specified in the Fee Letter, together with such other fees as
may be separately agreed to between the Borrower and the Administrative
Agent.
Section II.3 Reduction of the Commitments. (a) The Borrower may, upon at
least five Business Days' notice to the Administrative Agent, terminate in
whole or reduce ratably in part the Available Commitments of the respective
Lenders; provided (i) that any such partial reduction shall be in the
aggregate amount of $10,000,000 or integral multiple of $1,000,000 in excess
thereof, (ii) that in no event shall the aggregate Commitments be reduced
hereunder to an amount less than the principal amount outstanding hereunder
and (iii) that in no event shall the Commitments be reduced to an amount less
than the aggregate principal amount of Advances then outstanding.
(b) If the Closing Date does not occur on or prior to April 30, 1998, the
Commitments of each Lender shall automatically terminate.
ARTICLE III
Advances
Section III.1 Advances. Each Borrowing shall consist of Advances of the
same Type and Interest Period made on the same Business Day by the Lenders
ratably according to their respective Commitments. The Borrower may request
that more than one borrowing be made on the same day. Each Borrowing shall
be made on notice, given not later than 11:00 a.m. (New York City time) (i)
in the case of Eurodollar Rate Advances, on the third Business Day prior to
the date of the proposed Borrowing and (ii) in the case of Base Rate
Advances, one Business Day prior to the date of the proposed Borrowing, by
the Borrower to the Administrative Agent, who shall give to each Lender
prompt notice thereof on the same day such notice is received. Each such
notice of a Borrowing (a "Notice of Borrowing") shall be in substantially the
form of Exhibit 3.1A hereto, specifying therein the requested (i) date of
such Borrowing, (ii) Type of Advances comprising such Borrowing and (iii)
Interest Period for each such Advance. Each proposed Borrowing shall be
subject to the provisions of Sections 3.2, 4.3 and Article V hereof.
Section III.2 Terms Relating to the Making of Advances. (a) Notwithstanding
anything in Section 3.1 above to the contrary:
(i) at no time shall more than ten different Borrowings be outstanding
hereunder;
(ii) each Borrowing hereunder shall be in an aggregate principal amount of
not less than $10,000,000 or an integral multiple of $1,000,000 in excess
thereof, or such lesser amount as shall be equal to the total amount of the
Available Commitments for Advances on such date after giving effect to all
other Borrowings to be made on such date; and
(iii) each Borrowing hereunder which is to be comprised of Eurodollar
Rate Advances shall be in an aggregate principal amount of not less than
$10,000,000.
(b) Each Notice of Borrowing shall be irrevocable and binding on the
Borrower.
Section III.3 Making of Advances. (a) Each Lender shall, before 12:00 noon
(New York City time) on the date of such Borrowing, make available for the
account of its Applicable Lending Office to the Administrative Agent at the
Administrative Agent's address referred to in Section 10.2, in same day
funds, such Lender's portion of such Borrowing. After the Administrative
Agent's receipt of such funds and upon fulfillment of the applicable
conditions set forth in Article V, the Administrative Agent will make such
funds available to the Borrower at the Administrative Agent aforesaid
address.
(b) Unless the Administrative Agent shall have received notice from a Lender
prior to the date of any Borrowing that such Lender will not make available
to the Administrative Agent such Lender's ratable portion of such Borrowing,
the Administrative Agent may assume that the Lender has made such portion
available to the Administrative Agent on the date of such Borrowing in
accordance with subsection (a) of this Section 3.3, and the Administrative
Agent may, in reliance upon such assumption, make available to the Borrower
on such date a corresponding amount. If and to the extent that any such
Lender (a "non-performing Lender") shall not have so made such ratable
portion available to the Administrative Agent, the non-performing Lender and
the Borrower severally agree to repay to the Administrative Agent forthwith
on demand such corresponding amount together with interest thereon, for each
day from the date such amount is made available to the Borrower until the
date such amount is repaid to the Administrative Agent, at (i) in the case of
the Borrower, the interest rate applicable at the time to Advances comprising
such Borrowing and (ii) in the case of such Lender, the Federal Funds Rate.
Nothing herein shall in any way limit, waive or otherwise reduce any claims
that any party hereto may have against any non-performing Lender.
(c) The failure of any Lender to make the Advance to be made by it as part
of any Borrowing shall not relieve any other Lender of its obligation, if
any, hereunder to make its Advance on the date of such Borrowing, but no
Lender shall be responsible for the failure of any other Lender to make the
Advance to be made by such other Lender on the date of any Borrowing.
Section III.4 Repayment of Advances. The Borrower shall repay the principal
amount of each Advance on the last day of the Interest Period for such
Advance, which last day shall be the maturity date for such Advance.
Section III.5 Interest. (a) Interest Periods. The period commencing on the
date of each Advance and ending on the last day of the period selected by the
Borrower with respect to such Advance pursuant to the provisions of this
Section 3.5 is referred to herein as an Interest Period (the "Interest
Period"). The duration of each Interest Period shall be (i) in the case of
any Eurodollar Rate Advance 1, 2 or 3 months, and (ii) in the case of any
Base Rate Advance, 90 days following the date on which such Advance was made;
provided, however, that no Interest Period may be selected by the Borrower if
such Interest Period would end after the Termination Date.
(b) Interest Rates. The Borrower shall pay interest on the unpaid principal
amount of each Advance owing to each Lender from the date of such Advance
until such principal amount shall be paid in full, at the Applicable Rate for
such Advance (except as otherwise provided in this subsection (b)), payable
as follows:
(i) Eurodollar Rate Advances. If such Advance is a Eurodollar Rate Advance,
interest thereon shall be payable on the last day of the Interest Period
therefor; provided that if an Event of Default shall have occurred and is
continuing, any principal amounts outstanding shall bear interest during such
period, payable on demand, at a rate per annum equal at all times to (A) for
the remaining term, if any, of the Interest Period for such Advance, 2% per
annum above the Applicable Rate for such Advance for such Interest Period,
and (B) thereafter, 2% per annum above the Applicable Rate in effect from
time to time for Base Rate Advances.
(ii) Base Rate Advances. If such Advance is a Base Rate Advance, interest
thereon shall be payable quarterly on the last day of each March, June,
September and December and on the date such Base Rate Advance shall be paid
in full; provided that if an Event of Default shall have occurred and is
continuing, any principal amounts outstanding shall bear interest during such
period, payable on demand, at a rate per annum equal at all times to 2% per
annum above the Applicable Rate in effect from time to time for Base Rate
Advances.
(c) Other Amounts. If an Event of Default shall have occurred and is
continuing, any other amounts payable hereunder during such time shall (to
the fullest extent permitted by law) bear interest at a rate per annum equal
at all times to 2% per annum above the Applicable Rate in effect from time to
time for Base Rate Advances, payable on demand.
(d) Interest Rate Determinations. The Administrative Agent shall give
prompt notice to the Borrower and the Lenders of the Applicable Rate
determined from time to time by the Administrative Agent for each Advance.
Each Reference Bank agrees to furnish to the Administra-tive Agent timely
information for the purpose of determining the Eurodollar Rate for any
Interest Period. If any one Reference Bank shall not furnish such timely
information, the Administrative Agent shall determine such interest rate on
the basis of the timely information furnished by the other two Reference
Banks.
ARTICLE IV
Payments
Section IV.1 Payments and Computations. (a) The Borrower shall make each
payment hereunder and under the other Loan Documents not later than 12:00
noon (New York City time) on the day when due in U.S. Dollars to the
Administrative Agent at its address referred to in Section 10.2 in same day
funds. The Administrative Agent will promptly thereafter cause to be
distributed like funds relating to the payment of principal, interest, fees
or other amounts payable to the Lenders, to the respective Lenders to whom
the same are payable, for the account of their respective Applicable Lending
Offices, in each case to be applied in accordance with the terms of this
Agreement. Upon its acceptance of a Lender Assignment and recording of the
information contained therein in the Register pursuant to Section 10.7, from
and after the effective date specified in such Lender Assignment, the
Administrative Agent shall make all payments hereunder and under the Notes in
respect of the interest assigned thereby to the Lender assignee thereunder,
and the parties to such Lender Assignment shall make all appropriate
adjustments in such payments for periods prior to such effective date
directly between themselves.
(b) The Borrower hereby authorizes the Administrative Agent and each Lender,
if and to the extent payment owed to the Administrative Agent or such Lender,
as the case may be, is not made when due hereunder (or, in the case of a
Lender, under the Note held by such Lender), to charge from time to time
against any or all of the Borrower's accounts with the Administrative Agent
or such Lender, as the case may be, any amount so due.
(c) All computations of interest based on the Alternate Base Rate when based
on the Prime Rate and of fees payable pursuant to Section 2.2(a) shall be
made by the Administrative Agent on the basis of a year of 365 or 366 days,
as the case may be. All computations of interest and other amounts pursuant
to Section 4.3 shall be made by the Lender claiming such interest or other
amount, on the basis of a year of 360 days. All other computations of
interest and fees hereunder (including computations of interest based on the
Eurodollar Rate and the Federal Funds Rate (including the Alternate Base Rate
if and so long as such Rate is based on the Federal Funds Rate)) shall be
made by the Administrative Agent on the basis of a year of 360 days. In each
such case, such computation shall be made for the actual number of days
(including the first day but excluding the last day) occurring in the period
for which such interest or fees are payable. Each such determination by the
Administrative Agent or a Lender shall be conclusive and binding for all
purposes, absent manifest error.
(d) Whenever any payment hereunder or under any other Loan Document shall be
stated to be due, or the last day of an Interest Period hereunder shall be
stated to occur, on a day other than a Business Day, such payment shall be
made and the last day of such Interest Period shall occur on the next
succeeding Business Day, and such extension of time shall in such case be
included in the computation of payment of interest and fees hereunder;
provided, however, that if such extension would cause payment of interest on
or principal of Eurodollar Rate Advances to be made, or the last day of an
Interest Period for a Eurodollar Rate Advance to occur, in the next following
calendar month, such payment shall be made on the next preceding Business Day
and such reduction of time shall in such case be included in the computation
of payment of interest hereunder.
(e) Unless the Administrative Agent shall have received notice from the
Borrower prior to the date on which any payment is due to the Lenders
hereunder that the Borrower will not make such payment in full, the
Administrative Agent may assume that the Borrower has made such payment in
full to the Administrative Agent on such date and the Administrative Agent
may, in reliance upon such assumption, cause to be distributed to each Lender
on such due date an amount equal to the amount then due such Lender. If and
to the extent the Borrower shall not have so made such payment in full to the
Administrative Agent, such Lender shall repay to the Administrative Agent
forthwith on demand such amount distributed to such Lender, together with
interest thereon, for each day from the date such amount is distributed to
such Lender until the date such Lender repays such amount to the
Administrative Agent, at the Federal Funds Rate.
Section IV.2 Prepayments and Repayments. (a) The Borrower shall have no
right to prepay any principal amount of any Advances except in accordance
with subsection (b) below.
(b) The Borrower may, upon at least one Business Days' notice to the
Administrative Agent stating the proposed date and aggregate principal amount
of the prepayment, and if such notice is given, the Borrower shall, prepay
the outstanding principal amounts of Advances comprising part of the same
Borrowing, in whole or ratably in part, together with accrued interest to the
date of such prepayment on the principal amount prepaid; provided, however,
that each partial prepayment shall be in an aggregate principal amount not
less than $5,000,000.
(c) The Advances shall be repaid, and the Commitments permanently reduced,
by an amount equal to the amount by which any of the Other Credit Agreements
shall have been repaid or prepaid (provided such amounts are not available to
be reborrowed under any such Other Credit Agreements), in connection with a
resolution of a Funding Suspension under any of such Other Credit Agreements.
Section IV.3 Yield Protection. (a) Change in Circumstances.
Notwithstanding any other provision herein, if after the date hereof, the
adoption of or any change in applicable law or regulation or in the
interpretation or administration thereof by any governmental authority
charged with the interpretation or administration thereof (whether or not
having the force of law) shall (i) change the basis of taxation of payments
to any Lender of the principal of or interest on any Eurodollar Rate Advance
made by such Lender or any fees or other amounts payable hereunder (other
than changes in respect of taxes imposed on the overall net income of such
Lender or its Applicable Lending Office by the jurisdiction in which such
Lender has its principal office or in which such Applicable Lending Office is
located or by any political subdivision or taxing authority therein), or (ii)
shall impose, modify or deem applicable any reserve, special deposit or
similar requirement against commitments or assets of, deposits with or for
the account of, or credit extended by, such Lender, or (iii) shall impose on
such Lender or the London interbank market any other condition affecting this
Agreement or Eurodollar Rate Advances made by such Lender, and the result of
any of the foregoing shall be to increase the cost to such Lender of agreeing
to make, making or maintaining any Advance or to reduce the amount of any sum
received or receivable by such Lender hereunder or under the Notes (whether
of principal, interest or otherwise), then the Borrower will pay to such
Lender upon demand such additional amount or amounts as will compensate such
Lender for such additional costs incurred or reduction suffered.
(b) Capital. If any Lender shall have determined that any change after the
date hereof in any law, rule, regulation or guideline adopted pursuant to or
arising out of the July 1988 report of the Basle Committee on Banking
Regulations and Supervisory Practices entitled "International Convergence of
Capital Measurement and Capital Standards", or the adoption after the date
hereof of any law, rule, regulation or guideline regarding capital adequacy,
or any change in any of the foregoing or in the interpretation or
administration of any of the foregoing by any governmental authority, central
bank or comparable agency charged with the interpretation or administration
thereof, or compliance by any Lender (or any Applicable Lending Office of
such Lender) or any Lender's holding company with any request or directive
regarding capital adequacy (whether or not having the force of law) of any
such authority, central bank or comparable agency, has or would have the
effect (i) of reducing the rate of return on such Lender's capital or on the
capital of such Lender's holding company, if any, as a consequence of this
Agreement, the Commitment of such Lender hereunder or the Advances made by
such Lender pursuant hereto to a level below that which such Lender or such
Lender's holding company could have achieved, but for such applicability,
adoption, change or compliance (taking into consideration such Lender's
policies and the policies of such Lender's holding company with respect to
capital adequacy), or (ii) of increasing or otherwise determining the amount
of capital required or expected to be maintained by such Lender or such
Lender's holding company based upon the existence of this Agreement, the
Commitment of such Lender hereunder, the Advances made by such Lender
pursuant hereto and other similar such commitments, agreements or assets,
then from time to time the Borrower shall pay to such Lender upon demand such
additional amount or amounts as will compensate such Lender or such Lender's
holding company for any such reduction or allocable capital cost suffered.
(c) Eurodollar Reserves. The Borrower shall pay to each Lender upon demand,
so long as such Lender shall be required under regulations of the Board of
Governors of the Federal Reserve System to maintain reserves with respect to
liabilities or assets consisting of or including Eurocurrency Liabilities,
additional interest on the unpaid principal amount of each Eurodollar Rate
Advance of such Lender, from the date of such Advance until such principal
amount is paid in full, at an interest rate per annum equal at all times to
the remainder obtained by subtracting (i) the Eurodollar Rate for the
Interest Period for such Advance from (ii) the rate obtained by dividing such
Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Reserve
Percentage of such Lender for such Interest Period. Such additional interest
shall be determined by such Lender and notified to the Borrower and the
Administrative Agent.
(d) Breakage Indemnity. The Borrower shall indemnify each Lender against
any loss, cost or reasonable expense which such Lender may sustain or incur
as a consequence of (i) any failure by the Borrower to fulfill on the date of
any Borrowing hereunder of Eurodollar Rate Advances the applicable conditions
set forth in Article V, (ii) any failure by the Borrower to borrow any
Eurodollar Rate Advance hereunder after irrevocable Notice of Borrowing has
been given pursuant to Section 3.1, (iii) any payment or prepayment of a
Eurodollar Rate Advance required or permitted by any other provision of this
Agreement or otherwise made or deemed made on a date other than the last day
of the Interest Period applicable thereto, (iv) any default in payment or
prepayment of the principal amount of any Eurodollar Rate Advance or any part
thereof or interest accrued thereon, as and when due and payable (at the due
date thereof, by irrevocable notice of prepayment or otherwise) or (v) the
occurrence of any Event of Default, including, in each such case, any loss or
reasonable expense sustained or incurred or to be sustained or incurred in
liquidating or employing deposits from third parties acquired to effect or
maintain any Advance or any part thereof as a Eurodollar Rate Advance. Such
loss, cost or reasonable expense shall include an amount equal to the excess,
if any, as reasonably determined by such Lender, of (A) its cost of obtaining
the funds for the Eurodollar Rate Advance being paid, prepaid or not borrowed
for the period from the date of such payment, prepayment or failure to borrow
to the last day of the Interest Period for such Advance (or, in the case of a
failure to borrow, the Interest Period for such Advance which would have
commenced on the date of such failure) over (B) the amount of interest (as
reasonably determined by such Lender) that would be realized by such Lender
in reemploying the funds so paid, prepaid or not borrowed for such period or
Interest Period, as the case may be. For purposes of this subsection (d), it
shall be presumed that in the case of any Eurodollar Rate Advance, each
Lender shall have funded each such Advance with a fixed-rate instrument
bearing the rates and maturities designated in the determination of the
Applicable Rate for such Advance.
(e) Notices. A certificate of each Lender setting forth such Lender's claim
for compensation hereunder and the amount necessary to compensate such Lender
or its holding company pursuant to subsections (a) through (d) of this
Section 4.3 shall be submitted to the Borrower and the Administrative Agent
and shall be conclusive and binding for all purposes, absent manifest error.
The Borrower shall pay each Lender directly the amount shown as due on any
such certificate within 10 days after its receipt of the same. The failure
of any Lender to provide such notice or to make demand for payment under this
Section 4.3 shall not constitute a waiver of such Lender's rights hereunder;
provided that such Lender shall not be entitled to demand payment pursuant to
subsections (a) through (d) of this Section 4.3, in respect of any loss,
cost, expense, reduction or reserve, if such demand is made more than six
months following the later of such Lender's incurrence or sufferance thereof
or such Lender's actual knowledge of the event giving rise to such Lender's
rights pursuant to such subsections. Each Lender shall use reasonable
efforts to ensure the accuracy and validity of any claim made by it
hereunder, but the foregoing shall not obligate any Lender to assert any
possible invalidity or inapplicability of the law, rule, regulation,
guideline or other change or condition which shall have occurred or been
imposed.
(f) Change in Legality. Notwithstanding any other provision herein, if the
adoption of or any change in any law or regulation or in the interpretation
or administration thereof by any governmental authority charged with the
administration or interpretation thereof shall make it unlawful for any
Lender to make or maintain any Eurodollar Rate Advance or to give effect to
its obligations as contemplated hereby with respect to any Eurodollar Rate
Advance, then, by written notice to the Borrower and the Administrative
Agent, such Lender may:
(i) declare that Eurodollar Rate Advances will not thereafter be made by
such Lender hereunder, whereupon the right of the Borrower to select
Eurodollar Rate Advances for any Borrowing shall be forthwith suspended until
such Lender shall withdraw such notice as provided hereinbelow or shall cease
to be a Lender hereunder pursuant to Section 10.7(g) hereof; and
(ii) require that all outstanding Eurodollar Rate Advances made by it be
repaid as of the effective date of such notice as provided herein below.
Upon receipt of any such notice, the Administrative Agent shall promptly
notify the other Lenders. Promptly upon becoming aware that the
circumstances that caused such Lender to deliver such notice no longer exist,
such Lender shall deliver notice thereof to the Borrower and the Administra-
tive Agent withdrawing such prior notice (but the failure to do so shall
impose no liability upon such Lender). Promptly upon receipt of such
withdrawing notice from such Lender (or upon such Lender assigning all of its
Commitments, Advances, participation and other rights and obligations
hereunder in accordance with Section 10.7(g)), the Administrative Agent shall
deliver notice thereof to the Borrower and the Lenders and such suspension
shall terminate. Prior to any Lender giving notice to the Borrower under this
subsection (f), such Lender shall use reasonable efforts to change the
jurisdiction of its Applicable Lending Office, if such change would avoid
such unlawfulness and would not, in the sole determination of such Lender, be
otherwise disadvantageous to such Lender. Any notice to the Borrower by any
Lender shall be effective as to each Eurodollar Rate Advance on the last day
of the Interest Period currently applicable to such Eurodollar Rate Advance;
provided that if such notice shall state that the maintenance of such Advance
until such last day would be unlawful, such notice shall be effective on the
date of receipt by the Borrower and the Administrative Agent.
(g) Market Rate Disruptions. If (i) less than two Reference Banks furnish
timely information to the Administrative Agent for determining the Eurodollar
Rate for Eurodollar Rate Advances in connection with any proposed Borrowing
or (ii) if the Majority Lenders shall notify the Administrative Agent that
the Eurodollar Rate will not adequately reflect the cost to such Majority
Lenders of making, funding or maintaining their respective Eurodollar Rate
Advances, the right of the Borrower to select or receive Eurodollar Rate
Advances for any Borrowing shall be forthwith suspended until the
Administrative Agent shall notify the Borrower and the Lenders that the
circumstances causing such suspension no longer exist, and until such
notification from the Administrative Agent, each requested Borrowing of
Eurodollar Rate Advances hereunder shall be deemed to be a request for Base
Rate Advances.
Section IV.4 Sharing of Payments, Etc. If any Lender shall obtain any
payment (whether voluntary, involuntary, through the exercise of any right of
set-off, or otherwise, but excluding any proceeds received by assignments or
sales of participation in accordance with Section 10.7 hereof to a Person
that is not an Affiliate of the Borrower) on account of the Advances owing to
it (other than pursuant to Section 4.3 hereof) in excess of its ratable share
of payments on account of the Advances obtained by all the Lenders, such
Lender shall forthwith purchase from the other Lenders such participation in
the Advances owing to them as shall be necessary to cause such purchasing
Lender to share the excess payment ratably with each of them; provided,
however, that if all or any portion of such excess payment is thereafter
recovered from such purchasing Lender, such purchase from each Lender shall
be rescinded and such Lender shall repay to the purchasing Lender the
purchase price to the extent of such recovery together with an amount equal
to such Lender's ratable share (according to the proportion of (i) the amount
of such Lender's required repayment to (ii) the total amount so recovered
from the purchasing Lender) of any interest or other amount paid or payable
by the purchasing Lender in respect of the total amount so recovered. The
Borrower agrees that any Lender so purchasing a participation from another
Lender pursuant to this Section 4.4 may, to the fullest extent permitted by
law, exercise all its rights of payment (including the right of set-off) with
respect to such participation as fully as if such Lender were the direct
creditor of the Borrower in the amount of such participation.
Notwithstanding the foregoing, if any Lender shall obtain any such excess
payment involuntarily, such Lender may, in lieu of purchasing participation
from the other Lenders in accordance with this Section 4.4, on the date of
receipt of such excess payment, return such excess payment to the
Administrative Agent for distribution in accordance with Section 4.1(a).
Section IV.5 Taxes. (a) All payments by the Borrower hereunder and under
the other Loan Documents shall be made in accordance with Section 4.1 free
and clear of and without deduction for all present or future taxes, levies,
imposts, deductions, charges or withholdings, and all liabilities with
respect thereto, excluding, in the case of each Lender and the Administrative
Agent, taxes imposed on its overall net income, and franchise taxes imposed
on it, by the jurisdiction under the laws of which such Lender or the
Administrative Agent (as the case may be) is organized or any political
subdivision thereof and, in the case of each Lender, taxes imposed on its
overall net income, and franchise taxes imposed on it, by the jurisdiction of
such Lender's Applicable Lending Office or any political subdivision thereof
(all such non-excluded taxes, levies, imposts, deductions, charges,
withholdings and liabilities being hereinafter referred to as "Taxes"). If
the Borrower shall be required by law to deduct any Taxes from or in respect
of any sum payable hereunder or under any other Loan Document to any Lender
or the Administrative Agent, (i) the sum payable shall be increased as may be
necessary so that making all required deductions (including deductions
applicable to additional sums payable under this Section 4.5) such Lender or
the Administrative Agent (as the case may be) receives an amount equal to the
sum it would have received had no such deductions been made, (ii) the
Borrower shall make such deductions and (iii) the Borrower shall pay the full
amount deducted to the relevant taxation authority or other authority in
accordance with applicable law.
(b) In addition, the Borrower agrees to pay any present or future stamp or
documentary taxes or any other excise or property taxes, charges or similar
levies that arise from any payment made hereunder or under any other Loan
Document or from the execution, delivery or registration of, or otherwise
with respect to, this Agreement or any other Loan Document (hereinafter
referred to as "Other Taxes").
(c) The Borrower will indemnify each Lender and the Administrative Agent for
the full amount of Taxes and Other Taxes (including, without limitation, any
Taxes and Other Taxes imposed by any jurisdiction on amounts payable under
this Section 4.5) paid by such Lender or the Administrative Agent (as the
case may be) and any liability (including penalties, interest and expenses)
arising therefrom or with respect thereto, whether or not such Taxes or Other
Taxes were correctly or legally asserted. Any Lender's claim for such
indemnification shall be set forth in a certificate of such Lender setting
forth in reasonable detail the amount necessary to indemnify such Lender
pursuant to this subsection (c) and shall be submitted to the Borrower and
the Administrative Agent and shall be conclusive and binding for all
purposes, absent manifest error. The Borrower shall pay each Lender directly
the amount shown as due on any such certificate within 30 days after the
receipt of same. If any Taxes or Other Taxes for which a Lender or the
Administrative Agent has received payments from the Borrower hereunder shall
be finally determined to have been incorrectly or illegally asserted and are
refunded to such Lender or the Administrative Agent, such Lender or the
Administrative Agent, as the case may be, shall promptly forward to the
Borrower any such refunded amount. The Borrower's, the Administrative
Agent's and each Lender's obligations under this Section 4.5 shall survive
the payment in full of the Advances.
(d) Within 30 days after the date of any payment of Taxes, the Borrower will
furnish to the Administrative Agent, at its address referred to in Section
10.2, the original or a certified copy of a receipt evidencing payment
thereof.
(e) Each Lender shall, on or prior to the date it becomes a Lender
hereunder, deliver to the Borrower and the Administrative Agent such
certificates, documents or other evidence, as required by the Internal
Revenue Code of 1986, as amended from time to time (the "Code"), or treasury
regulations issued pursuant thereto, including Internal Revenue Service Form
4224 and any other certificate or statement of exemption required by Treasury
Regulation Section 1.1441-1(a) or Section 1.1441-6(c) or any subsequent
version thereof, properly completed and duly executed by such Lender
establishing that it is (i) not subject to withholding under the Code or (ii)
totally exempt from United States of America tax under a provision of an
applicable tax treaty. Each Lender shall promptly notify the Borrower and
the Administrative Agent of any change in its Applicable Lending Office and
shall deliver to the Borrower and the Administrative Agent together with such
notice such certificates, documents or other evidence referred to in the
immediately preceding sentence. Each Lender will use good faith efforts to
appraise the Borrower as promptly as practicable of any impending change in
its tax status that would give rise to any obligation by the Borrower to pay
any additional amounts pursuant to this Section 4.5. Unless the Borrower and
the Administrative Agent have received forms or other documents satisfactory
to them indicating that payments hereunder or under the Notes are not subject
to United States of America withholding tax or are subject to such tax at a
rate reduced by an applicable tax treaty, the Borrower or the Administrative
Agent shall withhold taxes from such payments at the applicable statutory
rate in the case of payments to or for any Lender organized under the laws of
a jurisdiction outside the United States of America. Each Lender represents
and warrants that each such form supplied by it to the Administrative Agent
and the Borrower pursuant to this Section 4.5, and not superseded by another
form supplied by it, is or will be, as the case may be, complete and
accurate.
(f) Any Lender claiming any additional amounts payable pursuant to this
Section 4.5 shall use reasonable efforts (consistent with legal and
regulatory restrictions) to file any certificate or document requested by the
Borrower or to change the jurisdiction of its Applicable Lending Office if
the making of such a filing or change would avoid the need for or reduce the
amount of any such additional amounts which may thereafter accrue and would
not, in the sole determination of such Lender, be otherwise disadvantageous
to such Lender.
(g) Notwithstanding anything to the contrary set forth in this Section 4.5,
the failure or inability of any Lender to provide any of the forms referred
to therein shall not relieve the Borrower from its obligations under Sections
4.5(a), 4.5(b) and 4.5(c).
ARTICLE V
Conditions Precedent
Section V.1 Conditions Precedent to Effectiveness. The effectiveness of
this Agreement is subject to fulfillment of the following conditions
precedent:
(a) The Administrative Agent shall have received on or before the Closing
Date the following, each dated the Closing Date, in form and substance
satisfactory to each Lender and in sufficient copies for each Lender except
for the Notes:
(i) This Agreement, duly executed by the Borrower.
(ii) The Notes made to the order of the respective Lenders, duly executed by
the Borrower.
(iii) The Intercreditor Agreement, duly executed by Barclays, Swiss Bank,
the Collateral Agent and the Administrative Agent.
(iv) The Security Agreement, duly executed by the Borrower and by Chase as
the Collateral Agent and Administrative Agent, together with all Uniform
Commercial Code Financing Statements requested by the Administrative Agent or
Collateral Agent, duly executed by the Borrower. In addition, all other
actions, as may be necessary or, in the opinion of the Collateral Agent,
desirable to perfect the Liens created by the Security Agreement shall have
been taken.
(v) The Collateral FMB, duly executed by the Borrower, and authenti-cated by
the Trustee.
(vi) A copy of the results of a record search of the appropriate filing
offices in each jurisdiction in which the Borrower has an office or in which
assets of the Borrower are located shall have revealed no filings or
recordings, including, without limitation, judgment liens or tax liens, with
respect to any of the Collateral (other than Liens permitted under Section
7.2 hereof and filings which are being terminated on the Closing Date).
(vii) A certificate of the Secretary or Assistant Secretary of the
Borrower certifying (A) that attached thereto are true and correct copies of
(1) the Articles of Incorporation of the Borrower, and all amendments
thereto, as in effect on such date, (2) the By-laws of the Borrower, as in
effect on such date, and (3) resolutions of the Executive Committee of the
Board of Directors of the Borrower approving this Agreement, the other Loan
Documents (other than the First Mortgage Indenture and Intercreditor
Agreement) and the other documents to be delivered by the Borrower hereunder
and thereunder, and of all documents evidencing other necessary corporate
action, if any, with respect to the execution, delivery and performance by
the Borrower of this Agreement and the other Loan Documents (other than the
First Mortgage Indenture and Intercreditor Agreement), (B) that such
resolutions have not been modified, revoked or rescinded and are in full
force and effect on such date and (C) the names and true signatures of the
officers of the Borrower authorized to sign this Agreement and the other Loan
Documents (other than the First Mortgage Indenture and Intercreditor
Agreement) and the other documents to be delivered hereunder and thereunder.
(viii) A certificate of a duly authorized officer of the Borrower
certifying that (i) the Borrower has no investments in, or loans to, either
directly or indirectly, any Affiliate of the Borrower other than such
investments or loans outstanding as of April 23, 1998 and (ii) the
assumptions on which the financial projections (contained in the Information
Memorandum) were based continue to be valid.
(ix) Financial projections (contained in the Information Memorandum),
demonstrating projected compliance with Section 7.1(j) hereof.
(x) An audited balance sheet of the Borrower as at December 31, 1997 and the
related statements of the Borrower's results of operations, changes in
retained earnings and cash flows as of and for the year then ended, together
with copies of all Disclosure Documents (other than the Information
Memorandum, the prior receipt of which is hereby acknowledged by the Banks).
(xi) A certificate of a duly authorized officer of the Borrower certifying
that attached thereto are true and correct copies of all Governmental
Approvals referred to in clause (i) of the definition of "Governmental
Approval" required to be obtained or made by the Borrower in connection with
the execution and delivery of this Agreement or any Loan Document (other than
the First Mortgage Indenture and Intercreditor Agreement).
(xii) Copies of all orders, approvals, or items of similar import of the
New Hampshire Public Utilities Commission or other state regulatory
authorities required to be obtained or made by the Borrower in connection
with the execution and delivery of this Agreement or any Loan Document (other
than the First Mortgage Indenture and Intercreditor Agreement), certified by
the applicable state regulatory authority.
(xiii) A certificate of a duly authorized officer of the Borrower setting
forth all material pending or known threatened action or proceeding
(including, without limitation, any action or proceeding relating to any
environmental protections laws or regulations) affecting the Borrower or its
properties before any court, governmental agency or arbitrator to the extent
such action or proceeding has not previously been disclosed in any of the
Disclosure Documents.
(xiv) A certificate signed by the Treasurer or Assistant Treasurer of the
Borrower, certifying as to the absence of any material adverse change in the
financial condition, operations, properties or prospects of the Borrower
since December 31, 1997 except as disclosed in the Disclosure Documents;
provided, however, that the existence of the Rate Proceeding shall not be
deemed in and of itself to be a material adverse change; provided further,
however, that, notwithstanding the foregoing, a material adverse change shall
be deemed to have occurred and be continuing upon the occurrence of a
material adverse development or determination in the Rate Proceeding.
(xv) A certificate signed by the Chief Financial Officer, Treasurer or
Assistant Treasurer of NU, certifying as to the absence of any material
adverse change in the financial condition, operations, properties or
prospects of NU since December 31, 1997 except as disclosed in the Disclosure
Documents.
(xvi) A certificate of a duly authorized officer of the Borrower stating
that (i) the representations and warranties contained in Section 6.1 are
correct, in all material respects, on and as of the Closing Date before and
after giving effect to any Advances to be made on such date and the
application of the proceeds thereof, and (ii) no event has occurred and is
continuing which constitutes a Default or an Event of Default, or would
result from any such initial Advances or the application of the proceeds
thereof.
(xvii) Favorable opinions of each of the following in form and substance
satisfactory to the Administrative Agent:
(A) Catherine E. Shively, Senior Counsel to the Borrower, in substantially
the form of Exhibit 5.1A and as to such other matters as the Majority
Lenders, through the Administrative Agent, may reasonably request;
(B) Sulloway & Hollis, special New Hampshire counsel to the Borrower, in
substantially the form of Exhibit 5.1B and as to such other matters as the
Majority Lenders, through the Administra-tive Agent, may reasonably request;
(C) Drummond Woodsum & MacMahon, special Maine counsel to the Borrower, in
substantially the form of Exhibit 5.1C and as to such other matters as the
Majority Lenders, through the Administrative Agent, may reasonably request;
(D) Zuccaro, Willis & Bent, special Vermont counsel to the Borrower, in
substantially the form of Exhibit 5.1D and as to such other matters as the
Majority Lenders, through the Administrative Agent, may reasonably request;
(E) Day, Berry & Howard, special Connecticut counsel to the Borrower, in
substantially the form of Exhibit 5.1E and as to such other matters as the
Majority Lenders, through the Administrative Agent, may reasonably request;
and
(F) Skadden, Arps, Slate, Meagher & Flom LLP, counsel to the Administrative
Agent, in substantially the form of Exhibit 5.F and as to such other matters
as the Majority Lenders, through the Administrative Agent, may reasonably
request.
(xviii) The Other Credit Agreements shall have been executed and delivered
by the Borrower and the other parties thereto and shall be in full force and
effect.
(b) The Existing Revolving Credit Agreement and Existing Collateral Agency
Agreement shall have been terminated, all outstanding obligations thereunder
shall have been indefeasibly paid in full and all Liens granted in favor of
the agent thereto, including the PSNH Mortgage, shall have been terminated
and released and the Administrative Agent shall have received all instruments
of release, including, without limitation all Form UCC-3 termination
statements and mortgage satisfactions to evidence such termination and
release.
(c) All fees and other amounts payable pursuant to Section 2.2 hereof or
pursuant to the Fee Letter shall have been paid (to the extent then due and
payable).
(d) The Administrative Agent shall have received such other approvals,
opinions and documents as the Majority Lenders, through the Administrative
Agent, may reasonably request as to the legality, validity, binding effect or
enforceability of the Loan Documents or the financial condition, properties,
operations or prospects of the Borrower.
Section V.2 Conditions Precedent to Certain Advances. The obligation of
any Lender to make any Advance to the Borrower (except as set forth in
Section 5.3) including the initial Advance to the Borrower, shall be subject
to the conditions precedent that, on the date of such Advance and after
giving effect thereto:
(a) the following statement shall be true (and each of the giving of the
applicable notice or request with respect to such Advance and the performance
of such Advance without prior correction by the Borrower shall constitute a
representation and warranty by the Borrower that on the date of such Advance
such statements are true):
(i) the representations and warranties contained in Section 6.1 of this
Agreement and in the Security Agreement are correct on and as of the date of
such Advance, before and after giving effect to such Advance and to the
application of the proceeds therefrom, as though made on and as of such date,
(ii) no Default or Event of Default has occurred and is continuing, or would
result from such Advance or from the application of the proceeds thereof, and
(iii) the making of such Advance, when aggregated with all other
outstanding and requested Advances and all other short-term debt of the
Borrower would not cause the Borrower's Debt Limit then in effect to be
exceeded; and
(b) the Borrower shall have furnished to the Administrative Agent such other
approvals, opinions or documents as any Lender, through the Administrative
Agent, may reasonably request as to the legality, validity, binding effect or
enforceability of the Loan Document;
(c) the Borrower shall have delivered to the Administrative Agent a
certificate of a duly authorized officer of the Borrower certifying that the
Borrower has made no investments in, or loans to, either directly or
indirectly, any Affiliate of the Borrower after April 23, 1998;
(d) the Bond Conversion shall have occurred and each Letter of Credit under
and as defined in the Other Credit Agreements shall have been issued; and
(e) no material adverse change in the financial condition, operation,
properties or prospects of the Borrower shall have occurred and be
continuing; provided, however, that the existence of the Rate Proceeding
shall not be deemed in and of itself to be a material adverse change;
provided, further, however, notwithstanding the foregoing, a material adverse
change shall be deemed to have occurred and be continuing upon the occurrence
of a material adverse development or determination in the Rate Proceeding.
Section V.3 Conditions Precedent to Other Advances. The obligation of
each Lender to make any Advance that would not cause the aggregate
outstanding amount of the Advances made by such Lender (outstanding
immediately prior to and after the making of such Advance) to increase shall
be subject to the conditions precedent that, on the date of such Advance and
after giving effect thereto:
(a) the following statement shall be true (and each of the giving of the
applicable notice or request with respect to such Advance and the acceptance
of such Advance without prior correction by the Borrower shall constitute a
representation and warranty by the Borrower that on the date of such Advance
such statements are true):
(i) the representations and warranties contained in Section 6.1 of this
Agreement (other than those set forth in the last sentence of Section 6.1(e)
and in Section 6.1(f)) and the Security Agreement are correct on and as of
the date of such Advance, before and after giving effect to such Advance and
to the application of the proceeds therefrom, as though made on and as of
such date, and
(ii) no Event of Default has occurred and is continuing, or would result from
such Advance or from the application of the proceeds thereof, and
(iii) the making of such Advance, when aggregated with all other
outstanding and requested Advances and all other short-term debt of the
Borrower would not cause the Borrower's Debt Limit then in effect to be
exceeded; and
(b) the Borrower shall have furnished to the Administrative Agent such other
approvals, opinions or documents as any Lender, through the Administrative
Agent, may reasonably request as to the legality, validity, binding effect or
enforceability of the Loan Documents.
Section V.4 Reliance on Certificates. The Lenders and the Administrative
Agent shall be entitled to rely conclusively upon the certificates delivered
from time to time by officers of the Borrower, NU and the other parties to
the Significant Contracts as to the names, incumbency, authority and
signatures of the respective persons named therein until such time as the
Administra-tive Agent may receive a replacement certificate, in form
acceptable to the Administrative Agent, from an officer of such Person
identified to the Administrative Agent as having authority to deliver such
certificate, setting forth the names and true signatures of the officers and
other representatives of such Person thereafter authorized to act on behalf
of such Person, and, in all cases, the Lenders and the Administrative Agent
may rely on the information set forth in any such certificate including,
without limitation, information relating to the Debt Limit.
ARTICLE VI
Representations and Warranties
Section VI.1 Representations and Warranties of the Borrower. The Borrower
represents and warrants as follows:
(a) The Borrower is a corporation duly organized and validly existing under
the laws of the State of New Hampshire. The Borrower is duly qualified to do
business in, and is in good standing in, all other jurisdictions where the
nature of its business or the nature of property owned or used by it makes
such qualifications necessary.
(b) The execution, delivery and performance by the Borrower of the Rate
Agreement, each Loan Document and each Significant Contract to which it is a
party are within the Borrower's corporate powers, have been duly authorized
by all necessary corporate action, and do not and will not contravene (i) the
Borrower's charter or by-laws or (ii) any legal or contractual restriction
binding on or affecting the Borrower; and such execution, delivery and
performance do not and will not result in or require the creation of any Lien
(other than pursuant hereto or pursuant to the Security Documents or the
First Mortgage Indenture) upon or with respect to any of its properties.
(c) All Governmental Approvals referred to in clauses (i) and (ii) of the
definition of "Governmental Approvals" have been duly obtained or made, and
all applicable periods of time for review, rehearing or appeal with respect
thereto have expired. The Borrower has obtained all Governmental Approvals
referred to in clause (iii) of the definition of "Governmental Approvals,"
except those not yet required but which are obtainable in the ordinary course
of business as and when required and those the absence of which would not
materially adversely affect the financial condition, properties, prospects or
operations of the Borrower as a whole.
(d) This Agreement, the Rate Agreement, each other Transaction Document,
each other Loan Document and each Significant Contract are legal, valid and
binding obligations of the Borrower enforceable against the Borrower in
accordance with their respective terms; subject to the qualifications,
however, that the enforcement of the rights and remedies herein and therein
is subject to bankruptcy and other similar laws of general application
affecting rights and remedies of creditors and the application of general
principles of equity (regardless of whether considered in a proceeding in
equity or law), that the remedy of specific performance or injunctive relief
is subject to the discretion of the court before which any proceedings
therefor may be brought, and that indemnifica-tion against violations of
securities and similar laws may be subject to matters of public policy.
(e) The audited balance sheet of the Borrower as at December 31, 1997, and
the related statements of the Borrower setting forth the results of
operations, retained earnings and cash flows of the Borrower for the fiscal
year then ended, copies of which have been furnished to each Bank, fairly
present in all material respects the financial condition, results of
operations, retained earnings and cash flows of the Borrower at and for the
year ended on such date, and have been prepared in accordance with generally
accepted accounting principles consistently applied. Except as reflected in
such financial statements, the Borrower has no material non-contingent
liabilities, and all contingent liabilities have been appropriately reserved.
The financial projections referred to in Section 5.1(a)(ix) have each been
prepared in good faith and on reasonable assumptions. Since December 31,
1997, there has been no material adverse change in the Borrower's financial
condition, operations, properties or prospects other than as disclosed in the
Disclosure Documents; provided, however, that the existence of the Rate
Proceeding shall not be deemed in an of itself to be a material adverse
change; provided, further, however, that notwithstanding the foregoing, a
material adverse change shall be deemed to have occurred and be continuing
upon the occurrence of a material adverse change or development in the Rate
Proceeding.
(f) Except as set forth in the Disclosure Documents, there is no pending or
known threatened action or proceeding (including, without limitation, any
action or proceeding relating to any environmental protection laws or
regulations) affecting the Borrower or its properties before any court,
governmental agency or arbitrator, (i) which affects or purports to affect
the legality, validity or enforceability of the Loan Documents, the Rate
Agreement or any Significant Contract or (ii) which, if adversely determined,
would materially adversely affect the financial condition, properties,
prospects or operations of the Borrower. Notwithstanding the foregoing, any
material adverse development in respect of the Rate Proceeding, the existing
Rate Agreement or the Final Plan that results, or would reasonably be
expected to result, in a material adverse effect on the financial condition,
properties, prospects or operations of the Borrower shall be deemed to be an
event within clause (ii) of the preceding sentence.
(g) All insurance required by Section 7.1(c) hereof will be in full force
and effect.
(h) No ERISA Event has occurred nor is reasonably expected to occur with
respect to any ERISA Plan which would materially adversely affect the
financial condition, properties, prospects or operations of the Borrower,
except as disclosed to and consented by the Majority Lenders in writing.
Since the date of the most recent Schedule B (Actuarial Information) to the
annual report of the Borrower (Form 5500 Series), if any, there has been no
material adverse change in the funding status of the ERISA Plans referred to
therein and no "prohibited transaction" has occurred with respect thereto,
except as described in the Borrower's Annual Report on Form 10-K for the year
ended December 31, 1997 and except as the same may be exempt pursuant to
Section 408 of ERISA and regulations and orders thereunder. Neither the
Borrower nor any of its ERISA Affiliates has incurred nor reasonably expects
to incur any material withdrawal liability under ERISA to any ERISA
Multiemployer Plan, except as disclosed to and consented by the Majority
Lenders in writing.
(i) The Major Electric Generating Plants are on land in which the Borrower
owns a full or an undivided fee interest subject only to Liens permitted by
Section 7.2(a) hereof, which do not materially impair the usefulness to the
Borrower of such properties; the electric transmission and distribution lines
of the Borrower in the main are located in New Hampshire and on land owned in
fee by the Borrower or over which the Borrower has easements, or are in or
over public highways or public waters pursuant to adequate statutory or
regulatory authority, and any defects in the title to such transmission and
distribution lands or easements are in the main curable by the exercise of
the Borrower's right of eminent domain upon a finding that such eminent
domain proceedings are necessary to meet the reasonable requirements of
service to the public; the Borrower enjoys peaceful and undisturbed
possession under all of the leases under which it is operating, none of which
contains any unusual or burdensome provision which will materially affect or
impair the operation of the Borrower; and the Security Documents create valid
Liens in the Collateral, subject only to Liens permitted by Section 7.2(a)
hereof, and all filings and other actions necessary to perfect and protect
such security interests (to the extent such security interests may be
perfected or protected by filing) have been taken.
(j) No material part of the properties, business or operations of the
Borrower are materially adversely affected by any fire, explosion, accident,
strike, lockout, or other labor disputes, drought, storm, hail, earthquake,
embargo, act of God or of the public enemy or other casualty (except for any
such circumstance, if any, which is covered by insurance, which coverage has
been confirmed and not disputed by the relevant insurer or by fully-funded
self-insurance programs).
(k) The Borrower has filed all tax returns (Federal, state and local)
required to be filed and paid taxes shown thereon to be due, including
interest and penalties, or, to the extent the Borrower is contesting in good
faith an assertion of liability based on such returns, has provided adequate
reserves in accordance with generally accepted accounting principles for
payment thereof.
(l) No exhibit, schedule, report or other written information provided by
the Borrower or its agents to the Lenders in connection with the negotiation,
execution and closing of this Agreement and the other Transaction Documents
(including, without limitation, the Information Memorandum) knowingly
contained when made any material misstatement of fact or knowingly omitted to
state any material fact necessary to make the statements contained therein
not misleading in light of the circumstances under which they were made.
(m) No event has occurred and is continuing which constitutes a material
default under the Rate Agreement or any Significant Contract.
(n) All proceeds of the Advances shall be used (i) for general working
capital, (ii) for the partial repayment of $170,000,000 outstanding first
mortgage bonds, (iii) for payments to redeem up to $25,000,000 of Preferred
Stock and (iv) upon the prior written consent of all Lenders, for payments
for approved NUG Settlements which have received all requisite Governmental
Approvals. Except for the acquisition of preferred stock in anticipation of
the payments referred to in subclause (iii) of this clause (n), no proceeds
of any Advance will be used (i) to acquire any equity security of a class
which is registered pursuant to Section 12 of the Securities Exchange Act of
1934 or (ii) to buy or carry any margin stock (within the meaning of
Regulation U issued by the Board of Governors of the Federal Reserve System)
or to extend credit to others for such purpose.
(o) The Borrower (i) is not an "investment company" within the meaning
ascribed to that term in the Investment Company Act of 1940 and (ii) is not
engaged in the business of extending credit for the purpose of buying or
carrying margin stock.
(p) Each of the Liens created pursuant to the Security Documents is a valid
and enforceable, perfected, first priority Lien (subject to Liens permitted
pursuant to Section 7.2(a)) with respect to the Collateral covered by such
Security Document.
ARTICLE VII
Covenants of the Borrower
Section VII.1 Affirmative Covenants. So long as any Note shall remain
unpaid or any Lender shall have any Commitment hereunder, the Borrower shall,
unless the Majority Lenders shall otherwise consent in writing:
(a) Use of Proceeds. Apply all proceeds of each Advance solely as specified
in Section 6.1(n) hereof.
(b) Payment of Taxes, Etc. Pay and discharge before the same shall become
delinquent, all taxes, assessments and governmental charges, royalties or
levies imposed upon it or upon its property except to the extent the Borrower
is contesting the same in good faith by appropriate proceedings and has set
aside adequate reserves for the payment thereof.
(c) Maintenance of Insurance. Maintain, or cause to be maintained,
insurance (including appropriate plans of self-insurance) covering the
Borrower and its properties in effect at all times in such amounts and
covering such risks as may be required by law and in addition as is usually
carried by companies engaged in similar businesses and owning similar
properties.
(d) Preservation of Existence, Etc. Preserve and maintain its corporate
existence, material rights (statutory and otherwise) and franchises except as
otherwise expressly provided for in the Security Documents.
(e) Compliance with Laws, Etc. Comply in all material respects with the
requirements of all applicable laws, rules, regulations and orders of any
governmental authority, including without limitation any such laws, rules,
regulations and orders relating to utilities, zoning, environmental
protection, use and disposal of Hazardous Substances, land use, construction
and building restrictions, and employee safety and health matters relating to
business operations, except to the extent (i) that the Borrower is contesting
the same in good faith by appropriate proceedings or (ii) that any such non-
compliance, and the enforcement or correction thereof, would not materially
adversely affect the financial condition, properties, prospects or operations
of the Borrower as a whole.
(f) Inspection Rights. At any time and from time to time upon reasonable
notice, permit the Administrative Agent and its agents and representatives to
examine and make copies and abstracts from the records and books of account
of, and the properties of, the Borrower and to discuss the affairs, finances
and accounts of the Borrower with the Borrower and any of its officers,
directors and accountants.
(g) Keeping of Books. Keep proper records and books of account, in which
full and correct entries shall be made of all financial transactions of the
Borrower and the assets and business of the Borrower, in accordance with good
accounting practices consistently applied.
(h) Performance of Related Agreements. From and after the effective date of
the Rate Agreement and each Significant Contract, (i) perform and observe all
material terms and provisions of such agreements to be performed and observed
by the Borrower and (ii) take all reasonable steps to enforce such agreements
substantially in accordance with their terms and to preserve the rights of
the Borrower thereunder; provided, that the foregoing provisions of this
Section 7.1(h) shall not preclude the Borrower from any waiver, amendment,
modification, consent or termination permitted under Section 7.2(g) hereof.
(i) Collection of Accounts Receivable. Promptly bill, and diligently pursue
collection of, in accordance with customary utility practices, all accounts
receivable owing to the Borrower and all other amounts that may from time to
time be owing to the Borrower for services rendered or goods sold.
(j) Maintenance of Financial Covenants.
(i) Operating Income to Interest Expense. Maintain a ratio of Operating
Income to Interest Expense of not less than 2.35 to 1.00 for each period of
four consecutive fiscal quarters on each quarter-end ending after December
31, 1997.
(ii) Common Equity to Total Capitalization. Maintain at all times a ratio of
Common Equity to Total Capitalization of not less than 0.325 to 1.00.
(k) Maintenance of Properties, Etc. Except as otherwise expressly permitted
pursuant to Section 7.2(d), (i) as to properties of the type described in
Section 6.1(i) hereof, maintain title of the quality described therein; and
(ii) preserve, maintain, develop, and operate in substantial conformity with
all laws, material contractual obligations and prudent practices prevailing
in the industry, all of its properties which are used or useful in the
conduct of its business in good working order and condition, ordinary wear
and tear excepted, except to the extent such non-conformity would not
materially adversely affect the financial condition, properties, prospects or
operations of the Borrower as a whole.
(l) Governmental Approvals. Duly obtain on or prior to such date as the
same may become legally required, and thereafter maintain in effect at all
times, all Governmental Approvals on its part to be obtained, except those
the absence of which would not materially adversely affect the financial
condition, properties, prospects or operations of the Borrower as a whole.
(m) Further Assurances. Promptly execute and deliver all further
instruments and documents, and take all further action, that may be necessary
or that any Lender through the Administrative Agent may reasonably request in
order to fully give effect to the interests and properties purported to be
covered by the Security Documents.
Section VII.2 Negative Covenants. So long as any Note shall remain unpaid
or any Lender shall have any Commitment hereunder, the Borrower shall not,
without the prior written consent of the Majority Lenders:
(a) Liens, Etc. Create, incur, assume or suffer to exist any lien, security
interest, or other charge or encumbrance (including the lien or retained
security title of a conditional vendor) of any kind, or any other type of
preferential arrangement the intent or effect of which is to assure a
creditor against loss or to prefer one creditor over another upon or with
respect to any of its properties of any character (any of the foregoing being
referred to herein as a "Lien") whether now owned or hereafter acquired, or
sign or file under the Uniform Commercial Code of any jurisdiction a
financing statement which names the Borrower as debtor, sign any security
agreement authorizing any secured party thereunder to file such financing
statement, or assign accounts, excluding, however, from the operations of the
foregoing restrictions the Liens created or perfected under the Loan
Documents and the following, whether now existing or hereafter created or
perfected:
(i) Liens created by the First Mortgage Indenture;
(ii) Permitted Liens (as defined in the First Mortgage Indenture as in effect
on the date hereof) on the Indenture Assets; provided, however, that (A) the
exclusion contained in clause (a) of such definition with respect to Liens
junior to the Lien of the First Mortgage Indenture shall not apply to any
Lien created after the date hereof; (B) the exclusion contained in clauses
(g) and (h) of such definition shall apply only to the extent that all Liens
of the type described therein from time to time existing do not, in the
aggregate, materially and adversely affect the value of the security granted
under the First Mortgage Indenture and no such Lien secures Debt of the
Borrower for borrowed money; and (C) the Borrower shall not, on or after the
date hereof, create, incur or assume any purchase money Debt secured by Liens
of the type described in clause (o) of such definition;
(iii) Liens created or perfected under or in connection with the Pledge
Agreements referred to in the Series D Reimbursement Agreement, the Series E
Reimburse-ment Agreement, the Series D Reimbursement Agreement Amendment and
the Series E Reimbursement Agreement Amendment; and
(iv) Liens created or perfected under or in connection with the Security
Documents;
provided, however, that this Section 7.2(a) shall not be construed to
authorize the Borrower to incur, assume, be liable for or suffer to exist any
Debt not otherwise permitted hereunder.
(b) Debt. (i) Create, incur or assume any Debt other than Debt incurred
pursuant to this Agreement, the Other Credit Agreements and unsecured Debt in
an amount not to exceed $25,000,000 at any one time outstanding and then only
if, at such time and after giving effect thereto, (i) no Event of Default or
Default shall have occurred and be continuing on the date of such creation,
incurrence or assumption and (ii) the Borrower shall have determined that on
the basis of the assumptions and forecasts set forth in the most recent
operating budget/forecast of operations delivered pursuant to Section 7.3(v)
hereof (which the Borrower continues to believe to be reasonable), the
Borrower will continue to be in compliance at all times with the provisions
of Section 7.1(j) hereof. The Borrower will furnish evidence of its
compliance with this subsection (b) for each fiscal quarter pursuant to
Section 7.3(ii) hereof.
(c) Mergers, Etc. Merge with or into or consolidate with or into, or
acquire all or substantially all of the assets of, any Person.
(d) Sales, Etc., of Assets. Sell, lease, transfer or otherwise dispose of
all or any substantial part of its assets whether in a single transaction or
series of transactions during any consecutive 12-month period except for (i)
the sale of the Borrower's generating assets on an arms' length basis in a
transaction (or series of transactions) subject to approval by the NHPUC as
part of a settlement agreement related to the Rate Proceeding and (ii) sales,
leases, transfers or other dispositions in the ordinary course of the
Borrower's business in accordance with ordinary and customary terms and
conditions.
For purposes of this subsection (d) any transaction or series of transactions
during any consecutive 12-month period shall be deemed to involve a
"substantial part" of the Borrower's assets if, in the aggregate, (A) the
book value of such assets equals or exceeds 7.5% of the total assets (net of
regulatory assets) of the Borrower reflected in the financial statements of
the Borrower delivered pursuant to Section 7.3(ii) or 7.3(iii) hereof in
respect of the fiscal quarter or year ending on or immediately prior to the
commencement of such 12-month period or (B) for the four calendar quarters
ending on or immediately prior to commencement of such 12 month period, the
gross revenue derived by the Borrower from such assets shall equal or exceed
7.5% of the total gross revenue of the Borrower.
.
(e) Restricted Payments and NUG Settlements. Declare or pay any dividend,
or make any payment or other distribution of assets, properties, cash,
rights, obligations or securities on account of any share of any class of
capital stock of the Borrower (other than stock splits and dividends payable
solely in equity securities of the Borrower), or purchase, redeem, retire, or
otherwise acquire for value any shares of any class of capital stock of the
Borrower or any warrants, rights, or options to acquire any such Debt or
shares, now or hereafter outstanding, or make any distribution of assets to
any of its shareholders (any such transaction being a "Restricted Payment")
or make any payment of or on account of any NUG Settlement (a "NUG Settlement
Payment"), provided that the Borrower may make one or more Restricted
Payments and NUG Settlement Payments after July 1, 1998 if:
(i) at the time such payment is made and after giving effect thereto, no
Advances will be outstanding;
(ii) the aggregate amount of all such payments shall not exceed $40,000,000;
(iii) without limitation of the foregoing, the aggregate amount of all
Restricted Payments shall not exceed $25,000,000;
(iv) in the case of a NUG Settlement Payment, such NUG Settlement shall have
been approved by the NHPUC and all other Governmental Approvals related
thereto shall have been obtained and be in full force and effect;
(v) no Event of Default or Default shall have occurred and be continuing;
(vi) after giving effect to such payment, the Borrower shall be in full
compliance with Section 7.1(j) hereof (for purposes of determining compliance
with Section 7.1(j) under this clause (vi), computations under Section 7.1(j)
shall be made as of the date of such payment, except that, retained earnings
shall be determined as of the last day of the immediately preceding fiscal
quarter (adjusted for all Restricted Payments made after the last day of such
preceding fiscal quarter)); and
(vii) the Borrower shall have determined that, on the basis of the
assumptions and forecasts set forth in the most recent operating budget
forecast of operations delivered pursuant to Section 7.3(iv) hereof (which
the Borrower continues to believe to be reasonable) and after giving effect
to such payment, the Borrower will continue to be in compliance at all times
with the provisions of Section 7.1(j) hereof.
Notwithstanding the foregoing provisions of this Section 7.2(g), the Borrower
shall be permitted to make Restricted Payments in accordance with Section
6.1(n)(iii) hereof in respect of redemption payments to holders of the
Borrower's Preferred Stock and may declare and pay regularly scheduled
quarterly dividends on the Preferred Stock if, immediately prior to and after
giving effect to any such payment, no Default or Event of Default shall have
occurred and be continuing.
(f) Compliance with ERISA. (i) Terminate, or permit any ERISA Affiliate to
terminate, any ERISA Plan so as to result in any material (in the opinion of
the Majority Lenders) liability of the Borrower to the PBGC, or (ii) permit
to exist any occurrence of any event referred to in clause (i) of the
definition of ERISA Event), or any other event or condition, which presents a
material(in the opinion of the Majority Lenders) risk of such termination by
the PBGC of any ERISA Plan and such a material liability to the Borrower.
(g) Related Agreements.
(i) Amendments. Amend, modify or supplement or give any consent, acceptance
or approval to any amendment, modification or supplement or deviation by any
party from the terms of, the Rate Agreement or any Significant Contract,
except, with respect only to the Significant Contracts, any amendment,
modification or supplement thereto that would not reduce the rights or
entitlements of the Borrower thereunder in any material way.
(ii) Termination. Cancel or terminate (or consent to any cancellation or
termination of) the Rate Agreement or any Significant Contract prior to the
expiration of its stated term, provided that this subsection (ii) shall not
restrict the rights of the Borrower to enforce any remedy against any obligor
under any Significant Contract in the event of a material breach or default
by such obligor thereunder if and so long as the Borrower shall have provided
to the Administrative Agent at least 30 days prior written notice of the
enforcement action proposed to be undertaken by the Borrower.
(h) Change in Nature of Business. Engage in any material business activity
other than those established and engaged in on the date hereof.
(i) Ownership in Nuclear Plants. Acquire, directly or indirectly, any
ownership interest or any additional ownership interest of any kind in any
nuclear-powered electric generating plant.
(j) Subsidiaries. Create or suffer to exist any active subsidiaries other
than Properties, Inc., a New Hampshire corporation; or permit any material
assets or business to be maintained at or conducted by any subsidiary except
for the assets owned by Properties, Inc. not exceeding $20,000,000.
(k) Debt Limit. At any time, cause or permit the Debt Limit to be exceeded,
by voluntary incurrence of short-term debt or by other means.
(l) Affiliate Investments. Make any loans to, or investments in, either
directly or indirectly, any other entities, unless such investment is a
Permitted Investment.
(m) Affiliate Receivables. Permit the aggregate balance of accounts
receivables from Affiliates (other than such receivables constituting
receivables for the wholesale sale of power) to equal or exceed $12,500,000
as at the end of any month.
(n) Prepayment or Alteration of Debt. (i) Prepay, redeem reduce or
voluntarily retire, or make or agree to make any change in the terms of, any
Debt of the Borrower (other than Debt under this Agreement), other than
repayments and prepayments of advances under, and modifications of, the Other
Credit Agreements, in each case to the extent permitted by Section 7.4; (ii)
without limitation of the foregoing, amend, modify or supplement the
Indenture (as defined in the Other Credit Agreements) or the First Mortgage
Indenture or (iii) issue any First Mortgage Bonds as collateral security for
any existing or future debt, or grant any other security to any holder of
existing Debt of the Borrower, except to the extent permitted by Section 7.4.
Section VII.3 Reporting Obligations. So long as any Note shall remain
unpaid or any Lender shall have any Commitment hereunder, the Borrower shall,
unless the Majority shall otherwise consent in writing, furnish to the
Administrative Agent in sufficient copies for each Lender, the following:
(i) as soon as possible and in any event within five (5) days after the
occurrence of each Default or Event of Default continuing on the date of such
statement, a statement of the Chief Financial Officer, Treasurer or Assistant
Treasurer of the Borrower setting forth details of such Default or Event of
Default and the action which the Borrower proposes to take with respect
thereto;
(ii) as soon as available and in any event within fifty (50) days after the
end of each of the first three quarters of each fiscal year of the Borrower,
(A) if and so long as the Borrower is required to submit to the Securities
and Exchange Commission a report on Form 10-Q, a copy of the Borrower's
report on Form 10-Q submitted to the Securities and Exchange Commission with
respect to such quarter and (B) if the Borrower ceases to be required to
submit such report, a balance sheet of the Borrower as of the end of such
quarter and statements of income and retained earnings and of cash flows of
the Borrower for the period commencing at the end of the previous fiscal year
and ending with the end of such quarter, all in reasonable detail and duly
certified (subject to year-end audit adjustments) by the Chief Financial
Officer, Treasurer or Assistant Treasurer of the Borrower as having been
prepared in accordance with generally accepted accounting principles
consistent with those applied in the preparation of the financial statements
referred to in Section 6.1(e) hereof, in each such case, delivered together
with a certificate of said officer (1) stating that no Default or Event of
Default has occurred and is continuing or, if a Default or Event of Default
has occurred and is continuing, a statement as to the nature and the action
which the Borrower proposes to take with respect thereto and (2) (y)
demonstrating compliance with Section 7.1(j) for and as of the end of such
fiscal quarter and compliance with Section 7.2(b), as of the dates on which
any Debt was created, incurred or assumed (using the Borrower's most recent
annual actuarial determinations in the computation of Debt referred to in
clause (ix) in the definition of "Debt"), and (z) demonstrating, after giving
effect to the incurrence of any Debt created, incurred or assumed during such
fiscal quarter (using the Borrower's most recent annual actuarial
determinations in the computation of Debt referred to in clause (ix) in the
definition of "Debt"), compliance with Section 7.1(j) for the remainder of
the fiscal year of the Borrower based on the operating budget/forecast of
operations delivered pursuant to Section 7.3(iv) hereof for such fiscal year,
in each case, such demonstration to be in a schedule (in form satisfactory to
the Majority Lenders) which sets forth the computations used by the Borrower
in determining such compliance;
(iii) as soon as available and in any event within 105 days after the end
of each fiscal year of the Borrower, (A) if and so long as the Borrower is
required to submit to the Securities and Exchange Commission a report on Form
10-K, a copy of the Borrower's report on Form 10-K submitted to the
Securities and Exchange Commission with respect to such year and (B) if the
Borrower ceases to be required to submit such report, a copy of the annual
audit report for such year for the Borrower including therein a balance sheet
of the Borrower as of the end of such fiscal year and statements of income
and retained earnings and of cash flows of the Borrower for such fiscal year,
in each case certified by a nationally-recognized independent public
accountant, in each such case delivered together with a certificate of the
Chief Financial Officer, Treasurer or Assistant Treasurer (A) (1) stating
that the financial statements were prepared in accordance with generally
accepted accounting principles consistent with those applied in the
preparation of financial statements referred to in Section 6.1(e) hereto, and
(2) no Default or Event of Default has occurred and is continuing, or if a
Default or Event of Default has occurred and is continuing, a statement as to
the nature thereof and the action which the Borrower proposes to take with
respect thereto and (B) demonstrating compliance with Section 7.1(j) for and
as of the end of such fiscal year and compliance with Section 7.2(b), as of
the dates on which any Debt was created, incurred or assumed (using the
Borrower's most recent annual actuarial determina-tions in the computation of
Debt referred to in clause (ix) in the definition of "Debt"), such
demonstration to be in a schedule (in form satisfactory to the Majority
Lenders) which sets forth the computations used by the Borrower in
determining such compliance.
(iv) as soon as available and in any event before March 31 of each fiscal
year a copy of an operating budget/forecast of operations of the Borrower as
approved by the Board of Directors of the Borrower in form satisfactory to
the Lenders for the next fiscal year of the Borrower, together with a
certificate of the Chief Financial Officer, Treasurer or Assistant Treasurer
of the Borrower stating that such budget/forecast was prepared in good faith
and on reasonable assumptions;
(v) as soon as available and in any event no later than the New Hampshire
Public Utilities Commission shall have received the Borrower's annual
submission, if any, relating to the "return on equity collar"' referred to in
the Rate Agreement, a copy of such annual submission of the Borrower;
(vi) as soon as possible and in any event (A) within 30 days after the
Borrower knows or has reason to know that any ERISA Event described in clause
(i) of the definition of ERISA Event with respect to any ERISA Plan or ERISA
Multiemployer Plan has occurred and (B) within 10 days after the Borrower
knows or has reason to know that any other ERISA Event with respect to any
ERISA Plan or ERISA Multiemployer Plan has occurred, a statement of the Chief
Financial Officer, Treasurer or Assistant Treasurer of the Borrower
describing such ERISA Event and the action, if any, which the Borrower
proposes to take with respect thereto;
(vii) promptly after receipt thereof by the Borrower or any of its ERISA
Affiliates from the PBGC, copies of each notice received by the Borrower or
any such ERISA Affiliate of the PBGC's intention to terminate any ERISA Plan
or ERISA Multiemployer Plan or to have a trustee appointed to administer any
ERISA Plan or ERISA Multiemployer Plan;
(viii) promptly and in any event within 30 days after the filing thereof
with the Internal Revenue Service, copies of each Schedule B (Actuarial
Information) to the annual report (Form 5500 Series) with respect to each
ERISA Plan (if any) to which the Borrower is a contributing employer;
(ix) promptly after receipt thereof by the Borrower or any of its ERISA
Affiliates from an ERISA Multiemployer Plan sponsor, a copy of each notice
received by the Borrower or any of its ERISA Affiliates concerning the
imposition or amount of withdrawal liability in an aggregate principal amount
of at least $10,000,000 pursuant to Section 4202 of ERISA in respect of which
the Borrower may be liable;
(x) promptly after the Borrower becomes aware of the occurrence thereof,
notice of all actions, suits, proceedings or other events (A) of the type
described in Section 6.1(f), or (B) which purport to affect the legality,
validity or enforceability of any of the Loan Documents, the Rate Agreement,
any Transaction Document or Significant Contracts;
(xi) promptly after the sending or filing thereof, copies of all such proxy
statements, financial statements, and reports which the Borrower sends to its
public security holders (if any) or files with, and copies of all regular,
periodic and special reports and all registration statements and periodic or
special reports, if any, which the Borrower files with, the Securities and
Exchange Commission or any governmental authority which may be substituted
therefor, or with any national securities exchange;
(xii) promptly after receipt thereof, any assertion of the character
described in Section 8.1(h) hereof and the action the Borrower proposes to
take with respect thereto;
(xiii) promptly after knowledge of any material default under the Rate
Agreement or any Significant Contract, notice of such default and the action
the Borrower proposes to take with respect thereto;
(xiv) promptly after knowledge of any amendment, modification, or other
change to the Rate Agreement or any Significant Contract or to any
Governmental Approval affecting the Rate Agreement, notice of such amendment,
modification or other change, it being understood that for purposes of this
clause (xiv) any filing by the Borrower in the ordinary course of the
Borrower's business with, or order issued or action taken by, a governmental
authority or regulatory body to implement the terms of the Rate Agreement
shall not be considered an amendment, modification or change to a
Governmental Approval affecting the Rate Agreement;
(xv) promptly after requested, such other information respecting the
financial condition, operations, properties, prospects or otherwise, of the
Borrower as the Administrative Agent or Majority Lenders may from time to
time reasonably request in writing; and
(xvi) not later than ten days following the end of each fiscal quarter of
the Borrower, a report on the progress of and developments in the Rate
Proceeding, the Final Plan and any negotiations concerning the foregoing.
Section VII.4 Most Favored Lender Covenants. So long as any Note shall
remain unpaid hereunder or any Lender shall have any Commitment;
(a) The Borrower will not amend, modify or supplement, or consent to any
amendment, modification or supplement to, the Other Credit Agreements
(whether the same relates to pricing, tenor, reduction, prepayment,
covenants, other credit terms or otherwise), unless the Borrower shall first
have offered to amend, modify or supplement the Loan Documents in a like
manner, subject however, to the provisions of subsection (b), to the extent
applicable.
(b) If at any time the Borrower shall be unable to borrow under the Other
Credit Agreements (or any successor facility) because the Borrower is unable
to satisfy any "material adverse change" or other condition precedent to
borrowing (a "Funding Suspension"), and (x) the failure to satisfy such
condition does not itself constitute an Event of Default hereunder and (y) no
other Event of Default or Default shall have occurred and be continuing
hereunder, the provisions of subsection (a) shall be subject to the
following:
(i) The Borrower will be free to negotiate with the lenders under the Other
Credit Agreements (or the lenders under such successor facility) (the "Non-
Funding Lenders") and may resolve or not resolve such Funding Suspension in
such manner as it may see fit, without any requirement that the Agent or the
Lenders consent thereto;
(ii) Any improvement in pricing, covenants or other credit terms afforded to
the Non-Funding Lenders to resolve the Funding Suspension shall be offered to
the Agent and the Lenders in the manner prescribed by subsection (a). Any
additional security granted to the Non-Funding Lenders to resolve the Funding
Suspension shall be afforded equally and ratably to the Agent and Lenders;
(iii) If in connection with the resolution of a Funding Suspension, the
Non-Funding Lenders' facility shall be permanently reduced such that any
amounts repaid or prepaid as part of such resolution are not available to be
re-borrowed, the Borrower will pay to the Agent, for the benefit of the
Lenders an amount equal to such repayment or prepayment, dollar-for-dollar,
to be applied to the reduction of the Available Commitment or to be held as
cash collateral for the obligations of the Borrower under the Loan Documents.
For the avoidance of doubt:
(A) a reduction in the unfunded portion of the Non-Funding Lenders' commit-
ments will not, by itself, entitle the Agent and the Lenders to any such
payment or to any reduction in the Available Amount; and
(B) the Agent and the Lenders will not be entitled to any payment or
reduction in the Available Amount solely as a result of repayments and
prepayments of advances under such facility, if such repayment or prepayment
results in the Non-Funding Lenders' commitments becoming again available to
the Borrower in at least the amount of the repayment or prepayment.
ARTICLE VIII
Defaults
Section VIII.1 Events of Default. The following events shall each constitute
an "Event of Default" if the same shall occur and be continuing after the
grace period and notice requirement (if any) applicable thereto:
(a) The Borrower shall fail to pay any principal of any Note or Collateral
FMB when due or shall fail to pay any interest on any Note or Collateral FMB,
fees or other amounts within two days after the same becomes due; or
(b) Any representation or warranty made by the Borrower (or any of its
officers or agents) in this Agreement, any other Loan Document or Transaction
Document, certificate or other writing delivered pursuant hereto or thereto
shall prove to have been incorrect in any material respect when made or
deemed made; or
(c) The Borrower shall fail to perform or observe any term or covenant on
its part to be performed or observed contained in Sections 7.1 (a), (d) or
(j), Section 7.2 or Section 7.3(i) hereof; or
(d) The Borrower shall fail to perform or observe any other term or covenant
on its part to be performed or observed contained in this Agreement or any
Loan Document and any such failure shall remain unremedied, after written
notice thereof shall have been given to the Borrower by the Administrative
Agent or any Lender, for a period of 30 days; or
(e) The Borrower shall fail to pay any of its Debt when due (including any
interest or premium thereon but excluding Debt evidenced by the Notes and
excluding other Debt aggregating in no event more than $10,000,000 in
principal amount at any one time) whether by scheduled maturity, required
prepayment, acceleration, demand or otherwise, and such failure shall
continue after the applicable grace period, if any, specified in any
agreement or instrument relating to such Debt; or any other default under any
agreement or instrument relating to any such Debt, or any other event, shall
occur and shall continue after the applicable grace period, if any, specified
in such agreement or instrument, if the effect of such default or event is to
accelerate, or to permit the acceleration of, the maturity of such Debt; or
any such Debt shall be declared to be due and payable, or required to be
prepaid (other than by a regularly scheduled prepayment or as a result of the
Borrower's exercise of a prepayment option) prior to the stated maturity
thereof; unless in each such case the obligee under or holder of such Debt or
the trustee with respect to such Debt shall have waived in writing such
circumstance without consideration having been paid by the Borrower so that
such circumstance is no longer continuing; or
(f) The Borrower shall generally not pay its debts as such debts become due,
or shall admit in writing its inability to pay its debts generally, or shall
make an assignment for the benefit of creditors; or any proceeding shall be
instituted by or against the Borrower seeking to adjudicate it a bankrupt or
insolvent, or seeking liquidation, winding up, reorganization, arrangement,
adjustment, protection, relief, or composition of its debts under any law
relating to bankruptcy, insolvency, or reorganization or relief of debtors,
or seeking the entry of an order for relief or the appointment of a receiver,
trustee, or other similar official for it or for any substantial part of its
property and, in the case of a proceeding instituted against the Borrower,
either the Borrower shall consent thereto or such proceeding shall remain
undismissed or unstayed for a period of 90 days or any of the actions sought
in such proceeding (including without limitation the entry of an order for
relief against the Borrower or the appointment of a receiver, trustee,
custodian or other similar official for the Borrower or any of its property)
shall occur; or the Borrower shall take any corporate or other action to
authorize any of the actions set forth above in this subsection (f); or
(g) Any judgment or order for the payment of money in excess of $10,000,000
shall be rendered against the Borrower or its properties and either (i)
enforcement proceedings shall have been commenced by any creditor upon such
judgment or order and shall not have been stayed or (ii) there shall be any
period of 15 consecutive days during which a stay of enforcement of such
judgment or order, by reason of a pending appeal or otherwise, shall not be
in effect; or
(h) Any material provision of any Loan Document, the Rate Agreement or any
Significant Contract shall for any reason other than the express terms
thereof or the exercise of any right or option expressly contained therein
cease to be valid and binding on any party thereto except as otherwise
expressly permitted by the exceptions and provisos contained in Section
7.2(g) hereof; or any party thereto other than the Lenders shall so assert in
writing provided that in the case of any party other than the Borrower making
such assertion in respect of the Rate Agreement or any Significant Contract,
such assertion shall not in and of itself constitute an Event of Default
hereunder until (i) such asserting party shall cease to perform under and in
compliance with the Rate Agreement or such Significant Contract, (ii) the
Borrower shall fail to diligently prosecute, by appropriate action or
proceedings, a rescission of such assertion or a binding determination as to
the merits thereof or (iii) such a binding determination shall have been made
in favor of such asserting party's position; or
(i) The Security Documents after delivery under Article V hereof shall for
any reason, except to the extent permitted by the terms thereof, fail or
cease to create valid and perfected Liens (to the extent purported to be
granted by such documents and subject to the exceptions permitted thereunder)
in any of the applicable Collateral, provided, that such failure or cessation
relating to any non-material portion of such applicable Collateral shall not
constitute an Event of Default hereunder unless the same shall not have been
corrected within 30 days after the Borrower becomes aware thereof; or
(j) The Borrower shall not have in full force and effect any or all
insurance required under Section 7.1(c) hereof or there shall be incurred any
uninsured damage, loss or destruction of or to the Borrower's properties in
an amount not covered by insurance (including fully-funded self-insurance
programs) which the Majority Lenders consider to be material; or
(k) Any "Event of Default" (as therein defined) shall occur and be
continuing under the Other Credit Agreements, or a default by the Borrower
shall have occurred under the Rate Agreement and shall not have been
effectively cured within the time period specified therein for such cure; or
a default by any party shall have occurred under any Significant Contract and
such default shall not have been effectively cured within 30 days after
notice from the Administrative Agent to the Borrower stating that, in the
opinion of the Majority Lenders, such default may have a material adverse
effect upon the financial condition, operations, properties or prospects of
the Borrower as a whole; or
(l) Any Governmental Approval (whether federal, state or local) required to
give effect to the Rate Agreement (including, without limitation, Chapter
362-C of the New Hampshire Revised Statutes and the enabling order of The New
Hampshire Public Utilities Commission issued pursuant thereto) shall be
amended, modified or supplemented, or any other regulatory or legislative
action or change (whether federal, state, or local) having the effect,
directly or indirectly, of modifying the benefits or entitlements of the
Borrower under the Rate Agreement shall occur, and in any such case such
amendment, modification, supplement, action or change may have, in the
opinion of the Majority Lenders, a material adverse effect upon the financial
condition, operations, properties or prospects of the Borrower as a whole;
(m) NU shall cease to own all of the outstanding common stock of the
Borrower, free and clear of any Liens; or
(n) The Bond Conversion shall fail to be consummated on May 1, 1998.
Section VIII.2 Remedies Upon Events of Default. Subject to the Intercreditor
Agreement, upon the occurrence and during the continuance of any Event of
Default, then, and in any such event, the Administrative Agent shall at the
request, or may with the consent, of the Majority Lenders, upon notice to the
Borrower (i) declare the Commitments and the obligation of each Lender to
make Advances to be terminated, provided, that any such request or consent
shall be made solely by the Lenders having Percentages in the aggregate of
not less 66-2/3 %, whereupon the same shall forthwith terminate, (ii) declare
the Notes, all interest thereon and other amounts payable under this
Agreement and the applicable Security Documents to be forthwith due and
payable, provided, that any such request or consent shall be made solely by
the Lenders holding at least 66-2/3 % of the then aggregate unpaid principal
amount of the Advances owing to the Lenders, whereupon the Notes, all such
interest and all such amounts shall become and be forthwith due and payable,
without presentment, demand, protest or further notice of any kind, all of
which are hereby expressly waived by the Borrower, and (iii) exercise in
respect of any and all collateral, in addition to the other rights and
remedies provided for herein and in the Security Documents or otherwise
available to the Administrative Agent, the Collateral Agent or the Lenders,
all the rights and remedies of a secured party on default under the Uniform
Commercial Code in effect in the State of New York and in effect in any other
jurisdiction in which Collateral is located at that time; provided, however,
that in the event of an actual or deemed entry of an order for relief with
respect to the Borrower under the Federal Bankruptcy Code, (A) the
Commitments and the obligation of each Lender to make Advances shall
automatically be terminated and (B) the Notes, all such interest and all such
amounts shall automatically become and be due and payable, without
presentment, demand, protest or any notice of any kind, all of which are
hereby expressly waived by the Borrower.
ARTICLE IX
The Administrative Agent
Section IX.1 Authorization and Action. Each Lender hereby appoints and
authorizes the Administrative Agent to take such action as agent on its
behalf and to exercise such powers under this Agreement as are delegated to
the Administrative Agent by the terms hereof, together with such powers as
are reasonably incidental thereto. As to any matters not expressly provided
for by any Loan Documents (including, without limitation, enforcement or
collection thereof), the Administrative Agent shall not be required to
exercise any discretion or take any action, but shall be required to act or
to refrain from acting (and shall be fully protected in so acting or
refraining from acting) upon the instructions of the Majority Lenders, and
such instructions shall be binding upon all Lenders; provided, however, that
the Administrative Agent shall not be required to take any action which
exposes the Administrative Agent to personal liability or which is contrary
to this Agreement or applicable law. The Administrative Agent agrees to
deliver promptly to each Lender notice of each notice given to it by the
Borrower pursuant to the terms of this Agreement.
Section IX.2 Administrative Agent's Reliance, Etc. Neither the
Administrative Agent nor any of its directors, officers, agents or employees
shall be liable for any action taken or omitted to be taken by it or them
under or in connection with any Loan Document, except for its or their own
gross negligence or wilful misconduct. Without limitation of the generality
of the foregoing, the Administrative Agent: (i) may treat the payee of any
Note as the holder thereof until the Administrative Agent receives and
accepts a Lender Assignment entered into by the Lender which is the payee of
such Note, as assignor, and an assignee, as provided in Section 10.7; (ii)
may consult with legal counsel (including counsel for the Borrower),
independent public accountants and other experts selected by it and shall not
be liable for any action taken or omitted to be taken in good faith by it in
accordance with the advice of such counsel, accountants or experts; (iii)
makes no warranty or representation to any Lender and shall not be
responsible to any Lender for the Information Memorandum or any other
statements, warranties or representations made in or in connection with any
Loan Documents; (iv) shall not have any duty to ascertain or to inquire as to
the performance or observance of any of the terms, covenants or conditions of
any Loan Document on the part of the Borrower to be performed or observed, or
to inspect any property (including the books and records) of the Borrower;
(v) shall not be responsible to any Lender for the due execution, legality,
validity, enforceability, genuineness, sufficiency or value of any Loan
Document, Significant Contract or any other instrument or document furnished
pursuant hereto; and (vi) shall incur no liability under or in respect of any
Loan Document by acting upon any notice, consent, certificate or other
instrument or writing (which may be by telegram, cable or telex) believed by
it to be genuine and signed or sent by the proper party or parties.
Section IX.3 Chase and Affiliates. With respect to its Commitment and the
Note issued to it, Chase shall have the same rights and powers under this
Agreement as any other Lender and may exercise the same as though it were not
the Administrative Agent, and the term "Lender" or "Lenders" shall, unless
otherwise expressly indicated, include Chase in its individual capacity.
Chase and its Affiliates may accept deposits from, lend money to, art as
trustee under indentures of, and generally engage in any kind of business
with, the Borrower, any of its subsidiaries and any Person who may do
business with or own securities of the Borrower or any such subsidiary, all
as if Chase was not the Administrative Agent and without any duty to account
therefor to the Lenders.
Section IX.4 Lender Credit Decision. Each Lender acknowledges that it has,
independently and without reliance upon the Administrative Agent or any other
Lender and based on the Information Memorandum and other financial
information referred to in Section 6.1(e) and such other documents and
information as it has deemed appropriate, made its own credit analysis and
decision to enter into this Agreement. Each Lender also acknowledges that it
will, independently and without reliance upon the Administrative Agent or any
other Lender and based on such documents and information as it shall deem
appropriate at the time, continue to make its own credit decisions in taking
or not taking action under this Agreement.
Section IX.5 Indemnification. The Lenders agree to indemnify CSI and the
Administrative Agent (to the extent not reimbursed by the Borrower), ratably
according to the respective principal amounts of the Notes then held by each
of them (or if no Notes are at the time outstanding, ratably according to the
respective Commitments of the Lenders or if any Notes or Commitments are held
by the Borrower or Affiliates thereof, any ratable apportionment hereunder
shall exclude the principal among of the Notes held by the Borrower or its
Commitment hereunder), from and against any and all liabilities, obligations,
losses, damages, penalties, actions, judgments, suits, costs, expenses or
disbursement of any kind or nature whatsoever which may be imposed on,
incurred by, or asserted against CSI or the Administrative Agent in any way
relating to or arising out of this Agreement or any action taken or omitted
by CSI or the Administrative Agent under this Agreement, provided that no
Lender shall be liable for any portion of such liabilities, obligations,
losses, damages, penalties, actions, judgments, suits, costs, expenses or
disbursements resulting from CSI's or the Administrative Agent's gross
negligence or willful misconduct. Without limitation of the foregoing, each
Lender agrees to reimburse CSI and the Administrative Agent promptly upon
demand for its ratable share of any out-of-pocket expenses (including counsel
fees) by CSI or the Administrative Agent in connection with the
preparation, execution, delivery, administration, modification, amendment or
enforcement (whether through negotiations, legal proceedings or otherwise)
of, or legal advice in respect of rights or responsibilities under, this
Agreement to the extent that CSI or the Administrative Agent are entitled to
reimbursement for such expenses pursuant to Section 10.4 but is not
reimbursed for such expenses by the Borrower.
Section IX.6 Successor Administrative Agent. The Administrative Agent may
resign at any time by giving written notice thereof to the Lenders and the
Borrower, with any such resignation to become effective only upon the
appointment of a successor Administrative Agent pursuant to this Section 9.6.
Upon any such resignation, the Majority Lenders shall have the right to
appoint a successor Administrative Agent, which shall be a Lender or another
commercial bank or trust company reasonably acceptable to the Borrower
organized or licensed under the laws of the United States, or of any State
thereof. If no successor Administrative Agent shall have been so appointed
by the Majority Lenders, and shall have accepted such appointment, within 30
days after the retiring Administrative Agent's giving of notice of
resignation, then the retiring Administrative Agent may, on behalf of the
Lenders, appoint a successor Administrative Agent, which shall be Lender or
shall be another commercial bank or trust company organized or licensed under
the laws of the United States or of any State thereof reasonably acceptable
to the Borrower. In addition to the' foregoing right of the Administrative
Agent to resign, the Majority Lenders may remove the Administrative Agent at
any time, with or without cause, concurrently with the appointment by the
Majority Lenders or a successor Administrative Agent. Upon the acceptance of
any appointment as Administrative Agent hereunder by a successor
Administrative Agent and the execution and delivery by the Borrower and the
successor Administrative Agent of an agreement relating to the fees to be
paid to the successor Administrative Agent under Section 2.2(b) hereof in
connection with its acting as Administrative Agent hereunder, such successor
Administrative Agent shall thereupon succeed to and become vested with all
the rights, powers, privileges and duties of the Administrative Agent, and
the retiring Administrative Agent shall be discharged from its duties and
obligations under this Agreement. After any retiring Administrative
Agent's resignation or removal hereunder as Administrative Agent, the
provisions of this Article IX shall inure to its benefit as to any actions
taken or omitted to be taken by it while it was Administrative Agent under
this Agreement.
Section IX.7 Certain Authorizations and Consent. Each Lender by its
acceptance hereof, and each other Lender by its execution and delivery of a
Lender Assignment pursuant to which it became a Lender, consents to,
authorizes, ratifies and confirms in all respects;
(i) the execution, delivery, acceptance and performance by the Agent and by
the Collateral Agent of the Intercreditor Agreement, as the same may be from
time to time amended in accordance with the terms thereof and hereof;
(ii) the execution, delivery and acceptance by the Collateral Agent of, and
the taking by the collateral Agent of all actions under, the Security
Agreement, as the same may be from time to time amended in accordance with
the terms thereof and hereof;
the execution and delivery of this Agreement by the Lenders, or the execution
and delivery of such Lender Assignment by such Lender, as the case may be,
constituting (without further act or deed) the Lender's acceptance and
approval of, and agreement to the terms of, the Intercreditor Agreement and
the Security Agreement with the same effect as if the Lender were itself a
party thereto.
ARTICLE IXA
Security
Section 9.1A Purpose of Article. This Article sets forth the duties and
powers of the Administrative Agent with respect to the Collateral FMB and its
exercise for the benefit of the Lenders of its rights and remedies thereunder
and under the other Loan Documents or otherwise available to the
Administrative Agent.
Section 9.2A Collateral. The Lenders are entitled, pursuant to the terms
hereof and of the other Loan Documents, to the benefits of any Collateral
held or to be held by or for the benefit of the Administrative Agent. The
Borrower hereby agrees to deliver or cause to be delivered to the
Administrative Agent, promptly upon the execution and delivery thereof, an
originally executed and authenticated Collateral FMB. The Administrative
Agent shall keep the Collateral FMB delivered to it at its Principal Office
and shall permit any Lender to inspect the Collateral FMBs upon prior written
request during business hours.
Section 9.3A Default. (a) Unless an Event of Default shall have
occurred and be continuing, the Administrative Agent shall not be obligated
to take any action under this Agreement or any of the Security Documents,
except for the performance of such duties as are specifically set forth
herein or therein.
(b) If any Event of Default shall have occurred and be continuing the
Administrative Agent shall, at the request of, or may with the consent of,
the Required Lenders entitled to make such request, exercise in respect of
the Collateral FMB, in addition to other rights and remedies provided for
herein or otherwise available to it, all the rights and remedies available to
the Administrative Agent under the applicable Security Documents and under
the other Loan Documents or otherwise available to the Administrative Agent.
(c) Subject to paragraph (e) below, the rights and remedies of the
Administrative Agent shall include (without limitation of the other rights
and remedies available to the Administra-tive Agent under the Loan Documents
or otherwise available to it), (i) the right to collect all amounts payable
by the Borrower under the Collateral FMB for the benefit of the Lenders, and
(ii) the right to exercise all rights and remedies of a "holder" of a First
Mortgage Bond under the First Mortgage Indenture.
(d) Notwithstanding any written instructions received by the Administrative
Agent pursuant to paragraph (b) above, and except as expressly provided in
the Credit Agreement, the Administrative Agent shall not release any
Collateral or portion thereof or lien thereon without the consent of the
Lenders.
(e) It is understood that (i) the actual indebtedness evidenced by the
Collateral FMB as of any time shall be limited on a dollar-for-dollar basis
to the outstandings at such time, (ii) at no time shall any claim be made for
principal and interest on that principal amount of the Collateral FMB in
excess of the outstandings at such time, (iii) to the extent that the
outstanding principal amount of the Collateral FMB exceeds such amount,
neither the Lenders nor the Administrative Agent shall have any right under,
or right to exercise any right granted to the holders of such excess amount
of Collateral FMB under, the First Mortgage Indenture, and (iv) to the extent
of any collection on the amounts outstanding under this Agreement or any
collection of the Collateral, other than the Collateral FMB, such collection,
in either case, shall result in a reduction of the principal amount of the
Collateral FMB that may be recovered in respect of the Obligations.
Section 9.4A Distributions. If any Event of Default shall have occurred
and be continuing and if the Administrative Agent shall have declared the
Notes of the Borrower, all interest thereon and all other Obligations to be
immediately due and payable thereunder (or if such amounts have otherwise
automatically become immediately due and payable), all Collateral FMBs held
by the Administrative Agent and all cash proceeds received by the
Administrative Agent in respect of any sale of, collection from, or other
realization upon all or any part of the Collateral FMBs may, in the
discretion of the Administrative Agent, be distributed in whole or in part to
the Administrative Agent for the payment of principal, interest, fees and all
other Obligations to the respective Lenders to whom the same are payable for
the account of their respective Applicable Lending Offices, in each case to
be applied in accordance with the terms of the Credit Agreement, unless
otherwise directed by the Lenders.
In the event that funds to be distributed by the Administrative Agent shall
be insufficient to pay in full the Obligations the Borrower shall remain
liable to the extent of any deficiency between the amount of the proceeds of
the Collateral and the aggregate amount of Obligations owed by such Borrower
to the Lenders.
Section 9.5A Collateral FMB. (a) Except for the safe custody of the
Collateral FMB and for the accounting for moneys actually received by it
hereunder, the Administrative Agent shall have no duty as to any Collateral,
as to ascertaining or taking of any action to be taken by a "holder" of the
Collateral FMB under the First Mortgage Indenture or other matters relative
to the Collateral, whether or not the Administrative Agent or any Lender has
or is deemed to have knowledge of such matters, or as to the taking of any
necessary steps to preserve rights against any parties or any other rights
pertaining to any Collateral. The Administrative Agent shall be deemed to
have exercised reasonable care in the custody and presentation of any
Collateral in its possession if such Collateral is accorded treatment
substantially equal to that which the Administrative Agent accords its own
property.
(b) The Borrower shall promptly forward to the Administrative Agent copies
of all notices, certificates and other documents required to be delivered by
it to the Trustee pursuant to the terms of the First Mortgage Indenture. The
only obligation which the Administrative Agent shall have hereunder with
respect to such notices, certificates and other documents shall be to
promptly forward to the Lenders copies of any such notices, certificates or
documents.
ARTICLE X
Miscellaneous
Section X.1 Amendments, Etc. Subject to the Intercreditor Agreement, no
amendment or waiver of any provision of this Agreement, any Note or any
Security Document, nor consent to any departure by the Borrower therefrom,
shall in any event be effective unless the same shall be in writing and
signed by the Majority Lenders, and then such waiver or consent shall be
effective only in the specific instance and for the specific purpose for
which given; provided, however, that no amendment, waiver or consent shall,
unless in writing and signed by all the Lenders, do any of the following:
(a) waive, modify or eliminate any of the conditions specified in Article V,
(b) increase the Commitment of any Lender hereunder or increase the
Commitments of the Lenders that may be hereunder or subject the Lenders to
any additional obligations, (c) reduce the principal of, or interest on, the
Notes, any Applicable Margin or any fees or other amounts payable hereunder,
(d) postpone any date fixed for any payment of principal of, or interest on,
the Notes or any fees or other amounts payable hereunder (other than fees
payable to the Administrative Agent pursuant to Section 2.2(b) hereof), (e)
change the percentage of the Commitments or of the aggregate unpaid principal
amount of the Notes, or the number of Lenders which shall be required for the
Lenders or any of them to take any action hereunder. (f) amend this
Agreement, any Note or any Security Document in a manner intended to prefer
one or more Lenders over any other Lenders, (g) amend this Section 10.1,
or (h) release any of the Collateral otherwise than in accordance with the
provisions for such release contained in the Security Documents, or change
any provision of any Security Document providing for the release of all or
substantially all of the Collateral; and provided, further, that no
amendment, waiver or consent shall, unless in writing and signed by the
Administrative Agent in addition to the Lenders required above to take such
action, affect the rights or duties of the Administrative Agent under this
Agreement or any Note.
Section X.2 Notices, Etc. Except as otherwise provided in Section 3.3
hereof, all notices and other communications provided for hereunder and under
the other Loan Documents shall be in writing (including telegraphic, telex,
telecopy or cable communication) and mailed, telegraphed, telexed,
telecopied, cabled or delivered, (i) if to the Borrower, at its address at
1000 Elm Street, Manchester, New Hampshire 03105 (telecopy no. (603) 669-
2438), Attention: Treasurer, with a copy to Northeast Utilities Service
Company at its address at 107 Selden Street, Berlin, Connecticut 06037
(telecopy no. (203) 665-5457), Attention: Assistant Treasurer; (ii) if to any
Bank, at its Domestic Lending Office specified opposite its name on Schedule
I hereto; (iii) if to any Lender other than a Bank, at its Domestic Lending
Office specified in the Lender Assignment pursuant to which it became a
Lender; and (iv) if to the Administrative Agent, at its address at 1 Chase
Plaza, New York, New York 10081, Attention: Janet Belden, with a copy to Paul
Farrell at his address at 270 Park Avenue, New York, New York 10017; or, as
to each party, at such other address as shall be designated by such party in
a written notice to the other parties. All such notices and communications
shall, when mailed, telegraphed, telexed, telecopied or cabled, be effective
five days after when deposited in the mails, or when delivered to the
telegraph company, confirmed by telex answerback, telecopied or delivered to
the cable company, respectively, except that notices and communications to
the Administrative Agent pursuant to Article II, III, IV or IX shall not be
effective until received by the Administrative Agent. With respect to any
telephone notice given or received by the Administrative Agent pursuant to
Section 3.3 hereof, the records of the Administra-tive Agent shall be
conclusive for all purposes.
Section X.3 No Waiver Remedies. No failure on the part of any Lender or
the Administrative Agent to exercise, and no delay in exercising, any right
hereunder or under any Note shall operate as a waiver thereof; nor shall any
single or partial exercise of any such right preclude any other or further
exercise thereof or the exercise of any other right. The remedies herein
provided are cumulative and not exclusive of any remedies provided by law.
Section X.4 Costs, Expenses and Indemnification. (a) The Borrower agrees
to pay when due, in accordance with the terms hereof, all costs and expenses,
if any (including, without limitation, reasonable counsel fees and expenses),
of (i) the Administrative Agent and CSI in connection with the preparation,
negotiation, execution and delivery of the Loan Documents and the
administration of the Loan Documents, the care and custody of any and all
collateral, and any proposed modification, amendment, or consent relating
thereto; and (ii) the Administrative Agent, CSI and each Lender in connection
with the enforcement (whether through negotiations, legal proceedings or
otherwise) of this Agreement, the Notes or any other Loan Document.
(b) Borrower hereby agrees to indemnify and hold each Lender, CSI, the
Administrative Agent and their respective officers, directors, employees,
professional advisors and affiliates (each, an "Indemnified Person")
harmless from and against any and all claims, damages, losses, liabilities,
costs or expenses (including reasonable attorney's fees and expenses, whether
or not such Indemnified Person is named as a party to any proceeding or
investigation or is otherwise subjected to judicial or legal process arising
from any such proceeding or investigation) which any of them may incur or
which may be claimed against any of them by any person or entity (except to
the extent such claims, damages, losses, liabilities, costs or expenses arise
from the gross negligence or willful misconduct of the Indemnified Person):
(i) by reason of or in connection with the execution, delivery or
performance of any of the Loan Documents or any transaction contemplated
thereby, or the use by the Borrower of the proceeds of any Advance;
(ii) in connection with or resulting from the utilization, storage, disposal,
treatment, generation, transportation, release or ownership of any Hazardous
Substance (A) at, upon or under any property of the Borrower or any of its
Affiliates or (B) by or on behalf of the Borrower or any of its Affiliates at
any time and in any place; or
(iii) in connection with any documentary taxes, assessments or charges
made by any governmental authority by reason of the execution and delivery of
any of the Loan Documents.
(c) The Borrower's obligations under this Section 10.4 shall survive the
assignment by any Lender pursuant to Section 10.7 and shall survive as well
the repayment of all amounts owing to the Lenders and the Administrative
Agent under the Loan Documents and the termination of the Commitment of any
Lender and the termination of the Commitments. If and to the extent that
the obligations of the Borrower under this Section 10.4 are unenforceable for
any reason, the Borrower agrees to make the maximum contribution to the
payment and satisfaction thereof which is permissible under applicable law.
Section X.5 Right of Set-off. (a) Upon (i) the occurrence and during the
continuance of any Event of Default and (ii) the making of the request or the
granting of the consent specified by Section 8.2 to authorize the
Administrative Agent to declare the Notes due and payable pursuant to the
provisions of Section 8.2, each Lender is hereby authorized at any time and
from time to time, to the fullest extent permitted by law, to set off and
apply any and all deposits (general or special, time or demand, provisional
or final) at any time held and other indebtedness at any time owing by such
Lender to or for the credit or the account of the Borrower against any and
all of the obligations of the Borrower now or hereafter existing under this
Agreement and the Note held by such Lender, including obligations owed to
such Lender as a result of a purchase of participations or otherwise,
irrespective of whether or not such Lender shall have made any demand under
this Agreement or such Note and although such obligations may be unmatured.
Each Lender agrees promptly to notify the Borrower after any such set-off and
application made by such Lender, provided that the failure to give such
notice shall not affect the validity of such set-off and application. The
rights of each Lender under this Section are in addition to other rights and
remedies (including, without limitation, other rights of set-off) which such
Lender may have.
(b) The Borrower agrees that it shall have no right of off-set, deduction or
counterclaim in respect of its obligations hereunder, and that the
obligations of the Lenders hereunder are several and not joint. Nothing
contained herein shall constitute a relinquishment or waiver of the
Borrower's rights to any independent claim that the Borrower may have against
the Administrative Agent or any Lender, but no Lender shall be liable for the
conduct of the Administrative Agent or any other Lender, and the
Administrative Agent shall not be liable for the conduct of any Lender.
Section X.6 Binding Effect. This Agreement shall become effective when it
shall have been executed by the Borrower and the Administrative Agent and
when the Administrative Agent shall have been notified by each Bank that such
Bank has executed it and thereafter shall be binding upon and inure to the
benefit of the Borrower, the Administrative Agent and each Lender and their
respective successors and assigns, except that the Borrower shall not have
the right to assign its rights hereunder or any interest herein without the
prior written consent of the Lenders.
Section X.7 Assignments and Participation. (a) Each Lender may assign to
one or more banks or other entities all or a portion of its rights and
obligations under this Agreement, the Notes and the Security Documents
(including, without limitation, all or a portion of its Commitment, the
Advances owing to it and the Note or Notes held by it) with the prior written
consent of the Borrower and the Administrative Agent to the extent the
assignee thereunder is not then a Lender or an Affiliate of a Lender (each of
which consents shall not be unreasonably withheld); provided, however, that
(i) each such assignment shall be of the same percentage of all of the
assigning Lender's rights and obligations under this Agreement, (ii) to
the extent the assignee thereunder is not then a Lender or an Affiliate
of a Lender, the amount of the Commitment or Note of the assigning Lender
being assigned pursuant to each such assignment (determined as of the date of
the Lender Assignment with respect to such assignment) shall in no event be
less than the lesser of the amount of such Lender's Commitment and
$5,000,000, and (iii) the parties to each such assignment shall execute and
deliver to the Administrative Agent, for its acceptance and recording in the
Register, a Lender Assignment, together with any Note or Notes subject to
such assignment and a processing and recordation fee of $2,500. Upon such
execution, delivery, acceptance and recording, from and after the effective
date specified in each Lender Assignment, which effective date shall be at
least five Business Days after the execution thereof or such earlier date as
the Administrative Agent may agree, (x) the assignee thereunder shall be a
party hereto and, to the extent that rights and obligations hereunder have
been assigned to it pursuant to such Lender Assignment, have the rights and
obligations of a Lender hereunder and (y) the Lender assignor thereunder
shall, to the extent that rights and obligations hereunder have been assigned
by it to an assignee pursuant to such Lender Assignment, relinquish its
rights and be released from its obligations under this Agreement (and, in the
case of a Lender Assignment covering all or the remaining portion of an
assigning Lender's rights and obligations under this Agreement, such Lender
shall cease to be a party hereto); provided, however, if an Event of Default
shall have occurred and be continuing a Lender may assign all or a portion of
its rights and obligations without the prior written consent of the Borrower
but otherwise in accordance with this Section.
(b) By executing and delivering a Lender Assignment, the Lender assignor
thereunder and the assignee thereunder confirm to and agree with each other
and the other parties hereto as follows: (i) other than as provided in such
Lender Assignment, such assigning Lender makes no representation or warranty
and assumes no responsibility with respect to any statements, warranties or
representations made in or in connection with an Loan Document or the
execution, legality, validity, enforce-ability, genuineness, sufficiency or
value of any Loan Document or any other instrument or document furnished
pursuant thereto; (ii) such assigning Lender makes no representation or
warranty and assumes no responsibility with respect to the financial
condition of the Borrower or the performance or observance by the Borrower
of any of its obligations under any Loan Document or any other instrument or
document furnished pursuant thereto; (iii) such assignee confirms that it has
received a copy of each Loan Document, together with copies of the financial
statements referred to in Section 6.1(e) and such other documents and
information as it has deemed appropriate to make its own credit analysis and
decision to enter into such Lender Assignment; (iv) such assignee will,
independently and without reliance upon the Administrative Agent, such
assigning Lender or any other Lender and based on such documents and
information as it shall deem appropriate at the time, continue to make its
own credit decisions in taking or not taking action under this Agreement, the
Notes and the Security Documents; (v) such assignee appoints and authorizes
the Administrative Agent to take such action as agent on its behalf and to
exercise such powers under this Agreement, the Notes and the Security
Documents as are delegated to the Administrative Agent by the terms thereof,
together with such powers as are reasonably incidental thereto; and (vi) such
assignee agrees that it will perform in accordance with their terms all of
the obligations which by the terms of this Agreement, the Notes and the
Security Documents are required to be performed by it as Lender.
(c) The Administrative Agent shall maintain at its address referred to in
Section 10.2 a copy of each Lender Assignment delivered to and accepted by it
and a register for the recordation of the names and addresses of the Lenders
and the Commitment of, and principal amount of the Advances owing to, each
Lender from time to time (the "Register"). The entries in the Register shall
be conclusive and binding for all purposes, absent manifest error, and the
Borrower, the Administrative Agent and the Lenders may treat each Person
whose name is recorded in the Register as a Lender hereunder for all purposes
of this Agreement. The Register shall be available for inspection by the
Borrower or any Lender at any reasonable time and from time to time upon
reasonable prior notice.
(d) Upon its receipt of a Lender Assignment executed by an assigning Lender
and an assignee, together with any Note or Notes subject to such assignment,
the Administrative Agent shall, if such Lender Assignment has been completed
and is in substantially the form of Exhibit 10.07 hereto, accept such Lender
Assignment, (ii) record the information contained therein in the Register and
(iii) give prompt notice thereof to the Borrower. Within five Business Days
after its receipt of such notice, the Borrower, at its own expense, shall
execute and deliver to the Administrative Agent in exchange for the
surrendered Note or Notes a new Note to the order of such assignee in an
amount equal to the Commitment assumed by it pursuant to such Lender
Assignment and, if the assigning Lender has retained a Commitment hereunder,
a new Note to the order of the assigning Lender in an amount equal to the
Commitment retained by it hereunder. Such new Note or Notes shall be in an
aggregate principal amount equal to the aggregate principal amount of such
surrendered Note or Notes, shall be dated the effective date of such Lender
Assignment and shall otherwise be in substantially the form of the Exhibit
1.01A or Exhibit 1.01B hereto, as the case may be.
(e) Each Lender may sell participations to one or more banks or other
entities in or to all or a portion of its rights and obligations under the
Loan Documents (including, without limitation, all or a portion of its
Commitment, the Advances owning to it and the Note or Notes held by it);
provided, however, that (i) such Lender's obligations under this Agreement
(including, without limitation, its Commitment hereunder) shall remain
unchanged, (ii) such Lender shall remain solely responsible to the other
parties hereto for the performance of such obligations, (iii) such Lender
shall remain the holder of any such Note for all purposes of this Agreement,
(iv) the Borrower, the Administrative Agent and the other Lenders shall
continue to deal solely and directly with such Lender in connection with such
Lender's rights and obligations under this Agreement, and (v) the holder of
any such participation, other than an Affiliate of such Lender, shall not be
entitled to require such Lender to take or omit to take any action hereunder,
except action (A) extending the time for payment of interest on, or the final
maturity of any portion of the principal amount, the Notes (B) reducing the
principal amount of or the rate of interest payable on the Notes or (C)
releasing or substantially all of the Collateral otherwise than in accordance
with the provisions for such release contained in the Security Documents.
(f) Any Lender may, in connection with any assignment or participation or
proposed assignment or participation pursuant to this Section 10.7, disclose
to the assignee or participant or proposed assignee or participant, any
information relating to the Borrower furnished to such Lender by or on behalf
of the Borrower; provided that, prior to any such disclosure, the assignee or
participant or proposed assignee or participant shall agree, in accordance
with the terms of Section 10.8, to preserve the confidentiality of any
Confidential Information received by it from such Lender.
(g) If any Lender shall have delivered a notice to the Administrative Agent
described in Section 4.3(a), (b), (c) or (f) hereof, or shall become a non-
performing Lender under Section 3.4(b) hereof, and if and so long as such
Lender shall not have withdrawn such notice or corrected such non-performance
in accordance with Section 3.4(b), the Borrower or the Administrative Agent
may demand that such Lender assign in accordance with Section 10.7 hereof, to
one or more assignees designated by either the Borrower or the Administrative
Agent (and reasonably acceptable to the other), all (but not less than all)
of such Lender's Commitment, Advances, participation and other rights and
obligations hereunder; provided that any such demand by the Borrower during
the continuance of a Default or an Event of Default shall be ineffective
without the consent of the Majority Lenders. If, within 30 days following
any such demand by the Administrative Agent or the Borrower, any such
assignee so designated shall fail to tender such assignment on terms
reasonably satisfactory to the Lender, or the Borrower and the Administrative
Agent shall have failed to designate any such assignee, then such demand by
the Borrower or the Administrative Agent shall become ineffective, it being
understood for purposes of this provision that such assignment shall be
conclusively deemed to be on terms reasonably satisfactory to such Lender,
and such Lender shall be compelled to tender such assignment forthwith, if
such assignee (1) shall agree to such assignment in substantially the form of
the Lender Assignment and (2) shall tender payment to such Lender in an
amount equal to the full outstanding dollar amount accrued in favor of such
Lender hereunder (as computed in accordance with the records of the
Administrative Agent).
(h) Anything in this Section 10.7 to the contrary notwithstanding, any
Lender may assign and pledge all or any portion of its Commitment and the
Advances owing to it to any Federal Reserve Bank (and its transferees) as
collateral security pursuant to Regulation A of the Board of Governors of the
Federal Reserve System and any Operating Circular issued by such Federal
Reserve Bank. No such assignment shall release the assigning Lender from its
obligations hereunder.
Section X.8 Confidentiality. In connection with the negotiation and
administration of this Agreement and the other Loan Documents, the Borrower
has furnished and will from time to time furnish to the Administrative Agent
and the Lenders (each, a "Recipient") written information which is identified
to the Recipient when delivered as confidential (such information, other than
any such information which (i) was publicly available, or otherwise known to
the Recipient, at the time of disclosure, (ii) subsequently becomes publicly
available other than through any act or omission by the Recipient or (iii)
otherwise subsequently becomes known to the Recipient other than through a
Person whom the Recipient knows to be acting in violation of his or its
obligations to the Borrower, being hereinafter referred to as "Confidential
Information"). The Recipient will not knowingly disclose any such
Confidential Information to any third party (other than to those persons who
have a confidential relationship with the Recipient), and will take all
reasonable steps to restrict access to such information in a manner designed
to maintain the confidential nature of such information, in each case until
such time as the same ceases to be Confidential Information or as the
Borrower may otherwise instruct. It is understood, however, that the
foregoing will not restrict the Recipient's ability to freely exchange such
Confidential Information with prospective participants in or assignees of the
Recipient's position herein, but the Recipient's ability to so exchange
Confidential Information shall be conditioned upon any such prospective
participant's entering into an understanding as to confidentiality similar to
this provision. It is further understood that the foregoing will not
prohibit the disclosure of any or all Confidential Information if and to the
extent that such disclosure may be required (i) by a regulatory agency or
otherwise in connection with an examination of the Recipient's records by
appropriate authorities, (ii) pursuant to court order, subpoena or other
legal process or (iii) otherwise, as required by law; in the event of any
required disclosure under clause (ii) or (iii), above, the Recipient agrees
to use reasonable efforts to inform the Borrower as promptly as practicable.
Section X.9 Certain Authorizations and Consent. Each Bank by its
acceptance hereof, and each other Lender by its execution and delivery of the
Lender Assignment pursuant to which it became a Lender, consents to,
authorizes, ratifies and confirms in all respects:
(i) the execution, delivery, acceptance and performance by the
Administrative Agent and by the Collateral Agent of the Collateral Agency
Agreement, as the same may be from time to time amended in accordance with
the terms thereof;
(ii) the execution, delivery and acceptance by the Collateral Agent of, and
the taking by the Collateral Agent of all actions under, the Security
Documents, as the same may be from time to time amended in accordance with
Section 10.1 hereof, and any and all documents that may from time to time
after the date hereof constitute Security Documents; and
(iii) that upon the Closing hereunder, the Collateral Agency Agreement
shall supersede the Existing Collateral Agency Agreement;
the execution and delivery of this Agreement by such Bank, or the execution
and delivery of such Lender Assignment by such Lender, as the case may be,
constituting (without further act or deed) such Bank's or Lender's, as the
case may be, acceptance and approval of, and agreement to the terms of, the
Collateral Agency Agreement and the other Security Documents.
Section X.10 WAIVER OF JURY TRIAL. THE BORROWER, THE ADMINISTRATIVE AGENT,
AND THE LENDERS EACH HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN
ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THIS
AGREEMENT OR ANY OTHER LOAN DOCUMENT, OR ANY OTHER INSTRUMENT OR DOCUMENT
DELIVERED HEREUNDER OR THEREUNDER.
Section X.11 Governing Law. This Agreement and the Notes shall be governed
by, and construed in accordance with, the laws of the State of New York. The
Borrower, the Lenders and the Administrative Agent each (i) irrevocably
submits to the jurisdiction of any New York State Court or Federal court
sitting in New York City in any action arising out of any Loan Document, (ii)
agrees that all claims in such action may be decided in such court, (iii)
waives, to the fullest extent it may effectively do so, the defense of an
inconvenient forum and (iv) consents to the service of process by mail. A
final judgment in any such action shall be conclusive and may be enforced in
other jurisdictions. Nothing herein shall affect the right of any party to
serve legal process in any manner permitted by law or affect its right to
bring any action in any court.
Section X.12 Relation of the Parties; No Beneficiary. No term, provisions
or requirement, whether express or implied, of any Loan Document, or actions
taken or to be taken by any party thereunder, shall be construed to create a
partnership, association, or joint venture between such parties or any of
them. No term or provision of the Loan Documents shall be construed to
confer a benefit upon, or grant a right or privilege to, any Person other
than the parties hereto.
Section X.13 Execution in Counterparts. This Agreement may be executed in
any number of counterparts and by different parties hereto in separate
counterparts, each of which wen so executed shall be deemed to be an original
and all of which taken together shall constitute one and the same agreement.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed by their respective officers thereunto duly authorized, as of the
date first above written.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
By
Name: /s/David R. McHale
Title: Assistant Treasurer
THE CHASE MANHATTAN BANK
as Administrative Agent
By
Name: /s/Paul V. Farrell
Title: Vice President
Commitment Lender
$7,500,000.00 THE CHASE MANHATTAN BANK
By
Name: /s/Paul V. Farrell
Title: Vice President
Commitment Lender
$6,666,666.66 BANK OF AMERICA
By
Name: /s/ R. Vernon Howard, Jr.
Title: Managing Director
Commitment Lender
$6,666,666.66 CITIBANK, N.A.
By
Name: /s/Robert J. Harrity, Jr.
Title: Managing Director
Commitment Lender
$6,666,666.66 CREDIT LYONNAIS,
NEW YORK BRANCH
By
Name: /s/Alan Sidrane
Title: Senior Vice President
Commitment Lender
$6,666,666.66 THE LONG-TERM CREDIT BANK OF
JAPAN, LIMITED, NEW YORK BRANCH
By
Name: /s/Hiroshi Kitada
Title: Deputy General Manager
Commitment Lender
$3,333,333.34 FLEET NATIONAL BANK
By
Name: /s/Daniel Butler
Title: Vice President
Commitment Lender
$3,333,333.34 THE FUJI BANK, LIMITED,
NEW YORK BRANCH
By
Name: /s/Raymond Ventura
Title: Vice President and Manager
Commitment Lender
$3,333,333.34 THE INDUSTRIAL BANK OF JAPAN
TRUST COMPANY
By
Name: /s/John Dippo
Title: Senior Vice President
Commitment Lender
$3,333,333.34 MELLON BANK, N.A.
By
Name: /s/Kurt L. Hewett
Title: Vice President
Commitment Lender
$3,333,333.34 THE NIPPON CREDIT BANK, LTD.
By
Name: /s/Koichi Sunagawa
Title: Representative
Commitment Lender
$6,666,666.66 CIBC INC.
By
Name: /s/Denis P. O'Meara
Title: Executive Director
Commitment Lender
$6,666,666.66 TORONTO DOMINION (TEXAS), INC.
By
Name: /s/Debbie A. Greene
Title: Vice President
Commitment Lender
$2,500,000.00 BARCLAYS BANK PLC
By
Name: /s/Sydney G. Dennis
Title: Director
Commitment Lender
$2,500,000.00 THE FIRST NATIONAL BANK OF
CHICAGO
By
Name: /s/Madeleine N. Pember
Title: Assistant Vice President
Commitment Lender
$3,333,333.34 THE YASUDA TRUST AND BANKING
COMPANY, LIMITED, NEW YORK BRANCH
By
Name: /s/ Rohn Laudenschlager
Title: Senior Vice President
Commitment Lender
$2,500,000.00 THE FIRST NATIONAL BANK OF BOSTON
By
Name: /s/Michael M. Parker
Title: Managing Director
Exhibit 4.3.6.2
SECOND SUPPLEMENT
Dated as of May 1, 1995
among
BUSINESS FINANCE AUTHORITY OF THE
STATE OF NEW HAMPSHIRE
and
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
and
STATE STREET BANK AND TRUST COMPANY, as Trustee
Supplementing and Amending the Series D Loan and Trust Agreement
Dated as of May 1, 1991, as amended by a First Supplement
Dated as of December 1, 1992
TABLE OF CONTENTS
ARTICLE I: INTRODUCTION AND DEFINITIONS
Section 101. Description of the Agreement and the Parties
Section 102. Definitions
ARTICLE II: BOOK-ENTRY ONLY SYSTEM
Section 201. Registration of Bonds in the Book-Entry Only System
ARTICLE III: MISCELLANEOUS
Section 301. Subparagraph 301(e)(iv)(A) Amended
Section 302. Section 315 of First Supplement Amended
Section 303. Section 405 of Original Agreement Amended
Section 304. Original Agreement Affirmed
Section 305. Severability
Section 306. Counterparts
Section 307. Receipt of Documents
Section 308. Captions
Section 309. Governing Law
EXHIBIT A
EXHIBIT B
ARTICLE I: INTRODUCTION AND DEFINITIONS
Section 101. Description of the Agreement and the Parties. This SECOND
SUPPLEMENT (the "Second Supplement") is entered into as of May 1, 1995 by the
Business Finance Authority of the State of New Hampshire (with its
successors, the "Authority"), a body corporate and politic created under New
Hampshire Revised Statutes Annotated 162-A:3 formerly known as The Industrial
Development Authority of the State of New Hampshire; Public Service Company
of New Hampshire (with its successors, the "Company"), a New Hampshire
corporation, and State Street Bank and Trust Company, a Massachusetts trust
company, as Trustee (with its successors, the "Trustee"). This Second
Supplement supplements and amends the Series D Loan and Trust Agreement dated
as of May 1, 1991 (the "Original Agreement") among the Authority, the Company
and the Trustee, as previously amended by a First Supplement dated as of
December 1, 1992 (the "First Supplement" and collectively with the Original
Agreement and this Second Supplement, the "Agreement"), and is entered into
pursuant to Clauses 1101(a)(v) and (viii) of the Original Agreement. The
primary purpose of this Second Supplement is to provide for the establishment
of a book-entry system of registration for the outstanding $39,500,000
principal amount of The Industrial Development Authority of the State of New
Hampshire Pollution Control Revenue Bonds (Public Service Company of New
Hampshire Project-1991 Taxable Series D), and at the election of the Company,
for other Bonds outstanding under the Agreement from time to time.
In consideration of the mutual promises contained in this Second Supplement,
the rights conferred and the obligations assumed hereby, and other good and
valuable consideration, the receipt of which is hereby acknowledged, each of
the Company, the Authority and the Trustee agree, assign, covenant, grant,
pledge, promise, represent and warrant as set forth herein for their own
benefit and for the benefit of the Bondowners and the Bank.
Section 102. Definitions. (a) Words. Unless otherwise defined in this
Second Supplement, or unless the context otherwise requires, the terms
defined in the Original Agreement, as amended by the First Supplement, shall
have the same meaning in this Second Supplement.
ARTICLE II: BOOK-ENTRY ONLY SYSTEM
Section 201. Registration of Bonds in the Book-Entry Only System. (a)
Notwithstanding any provision of the Agreement to the contrary, the
provisions of this Section 201 shall apply with respect to any Bonds (except
the 1992 Series D Bonds) registered to CEDE & CO. or any other nominee of The
Depository Trust Company ("DTC") while the Book-Entry Only System (meaning
the system of registration described in this Section 201) is in effect. The
Book-Entry Only System shall be in effect for any series of Bonds or portion
thereof issued in or converted to any Mode or Rate Period within the
Multiannual Mode if so specified by the Company prior to the issuance in or
conversion to that Mode or Rate Period, subject to the provisions below
concerning termination of the Book-Entry Only System. Until it revokes such
specification in its discretion, the Company hereby specifies that the Book-
Entry Only System shall be in effect while the 1991 Series D Bonds are in
Flexible Mode. Notwithstanding any provision of this Section 201 to the
contrary, the provisions of this Section 201 shall not apply to the 1992
Series D Bonds, which are subject to the Book-Entry Only System described in
Section 303 of the First Supplement.
(b) The Bonds in or to be in the Book-Entry Only System shall be issued in
the form of a separate single authenticated fully registered Bond for each
separate Mode or Rate Period. Any legend required to be on the Bonds by DTC
may be added by the Trustee or Paying Agent. The form of Book-Entry Only
System 1991 Series D Bond in the Flexible Mode is attached hereto as Exhibit
A. On the date of original delivery thereof or date of conversion of the any
[sic] Bonds to a Mode or Rate Period in which the Book-Entry Only System is
in effect, as applicable, such Bonds shall be registered in the registry
books of the Paying Agent in the name of CEDE & CO., as nominee of The
Depository Trust Company as agent for the Authority in maintaining the Book-
Entry Only System. With respect to Bonds registered in the registry books
kept by the Paying Agent in the name of CEDE & CO., as nominee of DTC, the
Authority, the Paying Agent, the Company, the Remarketing Agent and the
Trustee shall have no responsibility or obligation to any Participant (which
means securities brokers and dealers, banks, trust companies, clearing
corporations and various other entities, some of whom or their
representatives own DTC) or to any Beneficial Owner (which means, when used
with reference to the Book-Entry Only System, the person who is considered
the beneficial owner of the Bonds pursuant to the arrangements for book entry
determination of ownership applicable to DTC) with respect to the following:
(A) the accuracy of the records of DTC, CEDE & CO. or any Participant with
respect to any ownership interest in the Bonds, (B) the delivery to or from
any Participant, any Beneficial Owner or any other person, other than DTC, of
any notice with respect to the Bonds, including any notice of redemption or
tender (whether mandatory or optional), or (C) the payment to any
Participant, any Beneficial Owner or any other person, other than DTC, of any
amount with respect to the principal or premium, if any, or interest on the
Bonds. The Paying Agent shall pay all principal of and premium, if any, and
interest on the Bonds only to or upon the order of DTC, and all such payments
shall be valid and effective fully to satisfy and discharge the Authority's
obligations with respect to the principal of and premium, if any, and
interest on Bonds to the extent of the sum or sums so paid. No person other
than DTC shall be entitled to receive an authenticated Bond evidencing the
obligation of the Authority to make payments of principal and premium, if
any, and interest pursuant to this Agreement. Upon delivery by DTC to the
Paying Agent of written notice to the effect that DTC has determined to
substitute a new nominee in place of CEDE & CO., the words "CEDE & CO." in
the Agreement shall refer to such new nominee of DTC.
(c) Upon receipt by the Trustee or the Paying Agent of written notice from
DTC to the effect that DTC is unable or unwilling to discharge its
responsibilities with respect to any Bonds, the Authority shall issue and the
Paying Agent shall transfer and exchange such Bonds as requested by DTC in
appropriate amounts and in authorized denominations, and whenever DTC
requests the Authority, the Paying Agent and the Trustee to do so, the
Trustee, the Paying Agent and the Authority will, at the expense of the
Company, cooperate with DTC in taking appropriate action after reasonable
notice (A) to arrange for a substitute bond depository willing and able upon
reasonable and customary terms to maintain custody of such Bonds or (B) to
make available for transfer and exchange such Bonds registered in whatever
name or names and in whatever authorized denominations as DTC shall
designate.
(d) In the event the Company determines that the Beneficial Owners of any
Bonds in the Book-Entry Only System should be able to obtain Bond
certificates, the Company may so notify DTC, the Paying Agent and the
Trustee, whereupon DTC will notify the Participants of the availability
through DTC of such Bond certificates. In such event, the Authority shall
issue and the Paying Agent shall transfer and exchange Bond certificates as
requested by DTC in appropriate amounts and in authorized denominations.
Whenever DTC requests the Paying Agent to do so, the Paying Agent will
cooperate with DTC in taking appropriate action after reasonable notice to
make available for transfer and exchange Bonds registered in whatever name or
names and in whatever authorized denominations as DTC shall designate.
(e) Notwithstanding any other provision of the Agreement to the contrary, so
long as any 1991 Series D Bond is registered in the name of CEDE & CO., as
nominee of DTC, all payments with respect to the principal of, Purchase
Price, premium, if any, and interest on such 1991 Series D Bond and all
notices with respect to such 1991 Series D Bond shall be made and given,
respectively, to DTC as provided in the Letter of Representation (the
"Representation Letter"), the form of which is included as Exhibit B attached
to this Second Supplement. The form of such Representation Letter may be
modified or replaced in a manner consistent with the provisions of the
Agreement upon conversion or reconversion of the 1991 Series D Bonds to a
Mode or Rate Period in which the Book-Entry Only System is in effect.
(f) Notwithstanding any provision in Subsection 301(h) or Section 310 of the
Original Agreement to the contrary, so long as any of the Bonds outstanding
are held in the Book-Entry Only System, if less than all of such Bonds are to
be converted or redeemed upon any conversion or redemption of Bonds
hereunder, the particular Bonds or portions of Bonds to be converted or
redeemed shall be selected by DTC in such manner as DTC may determine.
(g) So long as the Book-Entry Only System is in effect, a Beneficial Owner
who elects to have its Bonds purchased or tendered pursuant to the Agreement
shall effect delivery by causing a Participant to transfer the Beneficial
Owner's interest in the Bonds pursuant to the Book-Entry Only System. The
requirement for physical delivery of Bonds in connection with a demand for
purchase or a mandatory purchase will be deemed satisfied when the ownership
rights in the Bonds are transferred in accordance with the Book-Entry Only
System.
(h) So long as the Book-Entry Only System is in effect, the Remarketing
Agent shall communicate to DTC information concerning the purchasers of
Tendered Bonds as may be necessary or appropriate, and, notwithstanding any
provision in the Representation Letter to the contrary, the Remarketing Agent
shall continue to remit to the Paying Agent interest rate determination
information pursuant to the terms of the Agreement.
ARTICLE III: MISCELLANEOUS
Section 301. Subparagraph 301(e)(iv)(A) Amended. The last sentence of
Subparagraph 301(e)(iv)(A) of the Original Agreement is amended to read as
follows:
At least forty (40) days prior to the mandatory tender date, the Trustee
shall give notice to the Paying Agent as to whether or not it has received
the notices described in the immediately preceding sentence from Moody's and
S&P, and if the Trustee has not received such notices or if the Credit
Facility is expiring without substitution or replacement, the Paying Agent
shall give notice to the Bondowners of the mandatory tender of the Bonds at
least thirty (30) days prior to the mandatory tender date.
Section 302. Section 315 of First Supplement Amended. Section 315 of the
First Supplement is amended by deleting the words "sixth sentence" and
inserting in lieu thereof the words "fifth sentence."
Section 303. Section 405 of Original Agreement Amended. Section 405 of the
Original Agreement is amended by adding at the end thereof the following
sentence:
At least forty (40) days prior to any redemption pursuant to this Section
405, the Trustee shall notify the Paying Agent of the redemption date and the
principal amount of Tax-Exempt Refunding Bonds to be redeemed.
Section 304. Original Agreement Affirmed. Except as otherwise expressly
supplemented and amended by this Second Supplement, the provisions of the
Original Agreement, the First Supplement and the Assumption Agreement remain
unchanged, binding, and in full force and effect.
Section 305. Severability. In the event that any provision of this Second
Supplement shall be held to be invalid in any circumstance, such invalidity
shall not affect any other provisions or circumstances.
Section 306. Counterparts. This Second Supplement may be executed and
delivered in any number of counterparts, each of which shall be deemed to be
an original, but such counterparts together shall constitute one and the same
instrument.
Section 307. Receipt of Documents. By its execution and delivery of this
Second Supplement the Trustee acknowledges receipt of the opinion of Bond
Counsel required to accompany this Second Supplement pursuant to Subsection
1101(c) of the Original Agreement.
Section 308. Captions. The captions and table of contents of this Second
Supplement are for convenience only and shall not affect the construction
hereof.
Section 309. Governing Law. This instrument shall be governed by the laws
of State of New Hampshire.
IN WITNESS WHEREOF, the Business Finance Authority of the State of New
Hampshire has caused this Second Supplement to be signed and its official
seal to be impressed hereon by its Executive Director; Public Service Company
of New Hampshire has caused this Second Supplement to be signed and its
corporate seal to be impressed hereon by an authorized officer; and State
Street Bank and Trust Company, as Trustee, has caused this Second Supplement
to be signed and its corporate seal to be impressed hereon by an authorized
officer.
BUSINESS FINANCE AUTHORITY OF THE STATE OF NEW HAMPSHIRE
By:
/s/Jack Donovan
Executive Director
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
(Seal)
By:
/s/John B. Keane
Treasurer
STATE STREET BANK AND TRUST COMPANY
as Trustee
By:
/s/Daniel Golden
Assistant Vice President
The undersigned hereby consents
to this Second Supplement.
BARCLAYS BANK PLC, NEW YORK BRANCH
By:
Name:/s/Vijay Rajguru
Title: Associate Director
Exhibit 4.3.6.3
EXECUTION COPY
AMENDED AND RESTATED
SECOND SERIES D LETTER OF CREDIT
AND REIMBURSEMENT AGREEMENT
Dated as of April 23, 1998
Among
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
as Account Party
BARCLAYS BANK PLC, NEW YORK BRANCH
as Issuing Bank and as Agent
and
THE PARTICIPATING BANKS
REFERRED TO HEREIN
Relating to
The Industrial Development Authority of the State of New Hampshire
Pollution Control Revenue Bonds (Public Service Company of
New Hampshire Project - 1991 Taxable Series D)
AMENDED AND RESTATED
SECOND SERIES D LETTER OF CREDIT
AND REIMBURSEMENT AGREEMENT
Dated as of April 23, 1998
This AMENDED AND RESTATED SECOND SERIES D LETTER OF CREDIT AND REIMBURSEMENT
AGREEMENT, dated as of April 23, 1998 (this "Agreement") is made by and
among:
(i) Public Service Company of New Hampshire, a corporation duly organized
and validly existing under the laws of the State of New Hampshire (the
"Account Party");
(ii) Barclays Bank PLC, New York Branch ("Barclays"), as issuer of the Letter
of Credit (the "Issuing Bank");
(iii) The Participating Banks (as hereinafter defined) from time to time
party hereto; and
(iv) Barclays as agent (together with any successor agent hereunder, the
"Agent") for such Participating Banks and the Issuing Bank.
and restates in its entirety the Existing Reimbursement Agreement referred to
herein.
PRELIMINARY STATEMENT
The Business Finance Authority (formerly The Industrial Development
Authority) of the State of New Hampshire (the "Issuer"), pursuant to a Series
D Loan and Trust Agreement, dated as of May 1, 1991 (the "Original
Indenture"), by and among the Issuer, the Account Party and State Street Bank
and Trust Company, as trustee (such entity, or its successor as trustee,
being the "Trustee"), previously issued $114,500,000 aggregate principal
amount of The Industrial Development Authority of the State of New Hampshire
Pollution Control Revenue Bonds (Public Service Company of New Hampshire
Project - 1991 Taxable Series D) (such bonds being herein referred to as the
"Taxable Bonds"). Pursuant to the Original Indenture, a First Supplement
thereto, dated as of December 1, 1992 and a Second Supplement thereto, dated
as of May 1, 1995 (the Original Indenture, as so supplemented by such First
Supplement and such Second Supplement and as the same may be further
supplemented, amended or modified from time to time with the written consent
of the Issuing Bank, being herein referred to as the "Indenture"), the Issuer
refunded $75,000,000 aggregate principal amount of the Taxable Bonds through
the issuance of $75,000,000 aggregate principal amount of Business Finance
Authority of the State of New Hampshire Pollution Control Refunding Revenue
Bonds (Public Service Company of New Hampshire Project - 1992 Tax-Exempt
Series D) (such bonds being herein referred to as the "Existing Tax-Exempt
Refunding Bonds").
The Account Party previously caused Barclays to issue its Irrevocable Letter
of Credit No. 839136, dated May 2, 1995 in a stated amount of $117,858,000
(the "Existing Letter of Credit"), in support of the Taxable Bonds and the
Existing Tax-Exempt Refunding Bonds, and, in connection therewith, the
Account Party entered into a Second Series D Letter of Credit and
Reimbursement Agreement dated as of May 1, 1995 (the "Existing Reimbursement
Agreement") with Barclays as issuing bank and agent thereunder and the
participating banks referred to therein.
The Account Party now wishes to extend and amend the Existing Letter of
Credit and, in furtherance thereof, the Account Party has requested the
Issuing Bank to issue the Letter of Credit Amendment (as defined herein) to
the Paying Agent. Following such extension and amendment and the Fixed-Rate
Conversion described herein, the aggregate amount of the Letter of Credit, as
so amended, will be $41,748,000 (the "Stated Amount"), of which (i)
$39,500,000 shall support the payment of principal of the Taxable Bonds (or
the portion of the purchase or redemption price of Bonds corresponding to
principal), (ii) $2,248,000 shall support the payment of up to 128 days'
interest on the principal amount of Taxable Bonds (or the portion of the
purchase or redemption price of Taxable Bonds corresponding to interest),
computed at a maximum interest rate of 16% per annum on the basis of the
actual days elapsed and a year of 360 days, subject to modification as
provided in Section 2.06 hereof, and (iii) $0.00 shall support the payment of
premium on Taxable Bonds. The Issuing Bank has agreed to issue the Letter of
Credit Amendment subject to the terms and conditions set forth herein and in
the Amendment to which this Agreement is appended as Exhibit A (including the
terms and conditions relating to the rights and obligations of the
Participating Banks).
NOW, THEREFORE, in consideration of the premises set forth herein, the
parties hereto agree as follows:
ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS
SECTION I.1. Certain Defined Terms. In addition to the terms defined in the
Preliminary Statement hereto, as used in this Agreement, the following terms
shall have the following meanings (such meanings to be applicable to the
singular and plural forms of the terms defined):
"Advances" means Initial Advances and Term Advances, without differentiation;
individually, an "Advance".
"Affiliate" means, with respect to a specified Person, another Person that
directly or indirectly through one or more intermediaries controls or is
controlled by or is directly or indirectly under common control with such
Person. A Person shall be deemed to control another entity if such Person
possesses, directly or indirectly, the power to direct or cause the direction
of the management and policies of such entity, whether through the ownership
of voting securities, by contract or otherwise.
"Agreement for Capacity Transfer" means the Agreement for Capacity Transfer,
dated as of December 1, 1989, between The Connecticut Light and Power Company
("CL&P") and the Account Party, as amended by the First Amendment to
Agreement for Capacity Transfer, dated as of May 1, 1992 between CL&P and the
Account Party, which provides for capacity transfers from the Account Party
to CL&P.
"Alternate Base Rate" means, for any period, a fluctuating interest rate per
annum equal at all times to the higher from time to time of:
(a) the rate of interest announced publicly by Barclays in New York, New
York, from time to time, as Barclays' prime rate; and
(b) 1/2 of one percent per annum above the Federal Funds Rate from time to
time;
plus, in either case, the Applicable Margin for Base Rate Advances. Each
change in the Alternate Base Rate shall take effect concurrently with any
change in such prime rate or Federal Funds Rate, as the case may be.
"Amendment" means the First Amendment to the Existing Reimbursement
Agreement, to which this Agreement is appended as Exhibit A.
"Amendment Closing Date" means the Business Day upon which each of the
conditions precedent enumerated in Sections 3.01 and 3.02 of the Amendment
shall be fulfilled to the satisfaction of the Agent, the Issuing Bank, the
Participating Banks and the Account Party. All transactions contemplated to
occur on the Amendment Closing Date shall occur contemporaneously on or prior
to April 23, 1998, at the offices of King & Spalding, 1185 Avenue of the
Americas, New York, New York 10036, at 12:01 A.M. (New York City time), or at
such other place and time as the parties hereto may mutually agree.
"Applicable Commission" means, for any day, two and one-quarter percent
(2.25%).
"Applicable Lending Office" means, with respect to each Participating Bank,
(i) (A) such Participating Bank's "Domestic Lending Office", in the case of a
Base Rate Advance, and (B) such Participating Bank's "Eurodollar Lending
Office," in the case of a Eurodollar Rate Advance, in each case as specified
opposite such Participating Bank's name on Schedule I hereto (in the case of
a Participating Bank initially party to this Agreement) or in the
Participation Assignment pursuant to which such Participating Bank became a
Participating Bank (in the case of any other Participating Bank), or (ii)
such other office or affiliate of such Participating Bank as such
Participating Bank may from time to time specify to the Account Party and the
Agent.
"Applicable Margin" means, for any day: (i) two and one-quarter percent
(2.25%), for any outstanding Eurodollar Rate Advance, and (ii) one and one-
quarter percent (1.25%), for any outstanding Base Rate Advance.
"Arrangers" means Barclays Bank PLC and SBC Warburg Dillon Read, Inc.
"Available Amount" in effect at any time means the maximum aggregate amount
available to be drawn at such time under the Letter of Credit, the
determination of such maximum amount to assume compliance with all conditions
for drawing and no reduction for (i) any amount drawn by the Paying Agent to
make a regularly scheduled payment of interest on the Bonds (unless such
amount will not be reinstated under the Letter of Credit) or (ii) any amount
not available to be drawn because Bonds are held by or for the account of the
Account Party and/or in pledge for the benefit of the Issuing Bank, but after
giving effect nevertheless, to any reduction in the Stated Amount effected
pursuant to Section 2.06 hereof.
"Bankruptcy Code" means Title 11 of the United States Code, as the same may
be amended from time to time, or any successor bankruptcy law of the United
States.
"Base Rate Advance" means an Advance in respect of which the Account Party
has selected in accordance with Article III hereof, or this Agreement
otherwise provides for, interest to be computed on the basis of the Alternate
Base Rate.
"Bonds" means (i) the Taxable Bonds outstanding as of the date hereof, (ii)
the Existing Tax-Exempt Refunding Bonds and (iii) any further Tax-Exempt
Refunding Bonds (as defined in the Indenture) that may be issued in
accordance with the Indenture and this Agreement to refund any of such
remaining Taxable Bonds; provided, however, that upon the Fixed-Rate
Conversion and reimbursement to the Issuing Bank and the Participating Banks
of the Fixed-Rate Conversion Drawing, the Existing Tax-Exempt Refunding Bonds
shall cease to be Bonds hereunder.
"Business Day" means a day of the year that is not a Sunday, legal holiday or
a day on which banks are required or authorized to close in New York City
and, (i) if the applicable Business Day relates to any Eurodollar Rate
Advance, is a day on which dealings are carried on in the London interbank
market and/or (ii) if the applicable Business Day relates to any action to be
taken by, or notice furnished to or by, or payment to be made to or by, the
Trustee, the Paying Agent, the Remarketing Agent or the First Mortgage
Trustee, is a day on which (A) banking institutions are not authorized
pursuant to law to close, (B) the corporate trust office of the First
Mortgage Trustee is open for business, (C) banking institutions in all of the
cities in which the principal offices of the Issuing Bank, the Trustee, the
Paying Agent, the First Mortgage Trustee and, if applicable, the Remarketing
Agent are located are not required or authorized to remain closed and (D) the
New York Stock Exchange is not closed.
"Cash Account" has the meaning assigned to that term in Section 7.05(a).
"CL&P" has the meaning assigned to that term in the definition of Agreement
for Capacity Transfer.
"Citibank" means Citibank, N.A.
"Collateral" means all of the collateral in which liens, mortgages or
security interests are purported to be granted by any or all of the Security
Documents.
"Collateral Agent" means The Chase Manhattan Bank and any successor as
collateral agent under the Intercreditor Agreement.
"Commitment" means, for each Participating Bank, such Participating Bank's
Percentage of the Available Amount. "Commitments" shall refer to the
aggregate of the Commitments.
"Common Equity" means, at any date, an amount equal to the sum of the
aggregate of the par value of or stated capital represented by, the
outstanding shares of common stock of the Account Party and the surplus,
paid-in, earned and other, if any, of the Account Party.
"Confidential Information" has the meaning assigned to that term in Section
10.09 hereof.
"Conversion", "Convert" or "Converted" each refers to a conversion of Term
Advances pursuant to Section 3.04 hereof, including, but not limited to any
selection of a longer or shorter Interest Period to be applicable to such
Term Advances or any conversion of a Term Advance as described in Section
3.04(c) hereof.
"Credit Termination Date" means the date on which the Letter of Credit shall
terminate in accordance with its terms.
"date hereof" means April 23, 1998.
"Debt" means, for any Person, without duplication, (i) indebtedness of such
Person for borrowed money, (ii) obligations of such Person evidenced by
bonds, debentures, notes or other similar instruments, (iii) obligations of
such Person to pay the deferred purchase price of property or services, (iv)
obligations of such Person as lessee under leases which shall have been or
should be, in accordance with generally accepted accounting principles,
recorded as capital leases (not including the Unit Contract), (v) obligations
(contingent or otherwise) of such Person under reimbursement or similar
agreements with respect to the issuance of letters of credit (vi) net
obligations (contingent or otherwise) of such Person under interest rate
swap, "cap", "collar" or other hedging agreements, (vii) obligations of such
person to pay rent or other amounts under leases entered into in connection
with sale and leaseback transactions involving assets of such Person being
sold in connection therewith, (viii) obligations under direct or indirect
guaranties in respect of, and obligations (contingent or otherwise) to
purchase or otherwise acquire, or otherwise to assure a creditor against loss
in respect of, indebtedness or obligations of others of the kinds referred to
in clauses (i) through (vii), above, and (ix) liabilities in respect of
unfunded vested benefits under ERISA Plans.
"Default Rate" means a fluctuating interest rate equal at all times to 2% per
annum above the rate applicable to Base Rate Advances at such time.
"Disclosure Documents" means the Information Memorandum, the 1997 10-K and
any Current Report on Form 8-K filed by the Account Party with the Securities
and Exchange Commission after December 31, 1997 furnished to the
Participating Banks prior to the execution and delivery of the Amendment.
"ERISA" means the Employee Retirement Income Security Act of 1974, as amended
from time to time.
"ERISA Affiliate" means any trade or business (whether or not incorporated,
that, together with the Account Party is treated as a single employer under
Section 414(b) or (c) of the Code or, solely for purposes of Section 302 of
ERISA and Section 412 of the Code, is treated as a single employer under
Section 414 of the Code.
"ERISA Multiemployer Plan" means a "multiemployer plan" subject to Title IV
of ERISA.
"ERISA Plan" means an employee benefit plan (other than an ERISA
Multiemployer Plan) maintained for employees of the Account Party or any
ERISA Affiliate and covered by Title IV of ERISA.
"ERISA Plan Termination Event" means (i) a "reportable event", as defined in
Section 4043 of ERISA or the regulations issued thereunder (other than an
event for which the 30-day notice period is waived) with respect to an ERISA
Plan or an ERISA Multiemployer Plan, or (ii) the existence with respect to
any ERISA plan of an "accumulated funding deficiency" (as defined in Section
412(d) of the Code or Section 302 of ERISA), whether or not waived; (iii) the
filing pursuant to Section 412(d) of the Code or Section 303(d) of ERISA of
an application for a waiver of the minimum funding standard with respect to
any ERISA Plan; (iv) the incurrence by the Account Party or any of its ERISA
Affiliates of any liability under Title IV or ERISA with respect to the
termination of any ERISA Plan; (v) the receipt by Account Party or any of its
ERISA Affiliates from the PBGC or a plan administrator of any notice relating
to an intention to terminate any ERISA Plan or an ERISA Multiemployer Plan
under Section 4041 of ERISA or to appoint a trustee to administer any ERISA
Plan or ERISA Multiemployer Plan; (vi) the receipt by the Account Party or
any of its ERISA Affiliates of any notice, or the receipt by an ERISA
Multiemployer Plan from the Account Party or any of its ERISA Affiliates of
any notice, concerning the imposition of liability due to any withdrawal of
the Account Party or any of its ERISA Affiliates from an ERISA Plan or an
ERISA Multiemployer Plan during a plan year in which it was a "substantial
employer" as defined in Section 4001(a)(2) of ERISA, or a determination that
an ERISA Multiemployer Plan is, or is expected to be, insolvent or in
reorganization, within the meaning of Title IV of ERISA or (vii) any other
event or condition which might constitute grounds under Section 4042 of ERISA
for the termination of, or the appointment of a trustee to administer, any
ERISA Plan or ERISA Multiemployer Plan.
"Eurocurrency Liabilities" has the meaning assigned to that term in
Regulation D of the Board of Governors of the Federal Reserve System, as in
effect from time to time.
"Eurodollar Rate" means for any Interest Period for any Eurodollar Rate
Advances comprising part of the same Term Borrowing, an interest rate per
annum equal at all times during such Interest Period to the sum of:
(i) the rate per annum (rounded upward to the nearest whole multiple of
1/100 of 1% per annum, if such rate is not such a multiple) determined by the
Agent at which deposits in United States dollars in amounts comparable to the
Eurodollar Rate Advance of Barclays comprising part of such Term Borrowing
and for comparable periods as such Interest Period are offered by the
principal office of Barclays in London, England to prime banks in the London
interbank market at 11:00 A.M. (London time) two Business Days before the
first day of such Interest Period, plus
(ii) the Applicable Margin.
"Eurodollar Rate Advance" means an Advance in respect of which the Account
Party has selected in accordance with Article III hereof, and this Agreement
provides for, interest to be computed on the basis of the Eurodollar Rate.
"Eurodollar Reserve Percentage" of any Participating Bank for each Interest
Period for each Eurodollar Rate Advance means the reserve percentage
applicable during such Interest Period (or if more than one such percentage
shall be so applicable, the daily average of such percentages for those days
in such Interest Period during which any such percentage shall be so
applicable) under Regulation D or other regulations issued from time to time
by the Board of Governors of the Federal Reserve System (or any successor)
for determining the maximum reserve requirement (including, without
limitation, any emergency, supplemental or other marginal reserve
requirement, without benefit of or credit for proration, exemptions or
offsets) for such Participating Bank with respect to liabilities or assets
consisting of or including "eurocurrency liabilities" having a term equal to
such Interest Period.
"Event of Default" has the meaning assigned to that term in Section 8.01.
"Existing Letter of Credit" has the meaning assigned to that term in the
Preliminary Statement.
"Existing Reimbursement Agreement" has the meaning assigned to that term in
the Preliminary Statement.
"Existing Tax-Exempt Refunding Bonds" has the meaning assigned to that term
in the Preliminary Statement.
"Extension Collateral" has the meaning assigned to that term in Section
7.05(b).
"Federal Funds Rate" means, for any period, a fluctuating interest rate per
annum equal for each day during such period to the weighted average of the
rates on overnight Federal funds transactions with members of the Federal
Reserve System arranged by Federal funds brokers, as published on the next
succeeding Business Day by the Federal Reserve Bank of New York, or, if such
rate is not so published on the next succeeding Business Day, the average of
the quotations for such day on such transactions received by the Agent from
three Federal funds brokers of recognized standing selected by it.
"Final Plan" means the "Final Plan" implementing Chapter 374-F of the Revised
Statutes Annotated of New Hampshire, adopted by the NHPUC on February 28,
1997, and any successor plan or proposal.
"First Mortgage Bonds" means first mortgage bonds issued or to be issued by
the Account Party and secured, directly or indirectly, collectively or
severally, by one or more first-priority liens on all or part of the
Indenture Assets pursuant to the First Mortgage Indenture or another
indenture in form and substance satisfactory to the Majority Lenders. For
purposes hereof, all or part of the First Mortgage Bonds may be issued as
collateral for pollution control revenue bonds or industrial revenue bonds,
whether taxable or tax exempt issued by the Account Party or by a
governmental authority at the Account Party's request.
"First Mortgage Indenture" means the General and Refunding Mortgage
Indenture, between the Account Party and New England Merchants National Bank,
as trustee and to which First Union National Bank is successor trustee, dated
as of August 15, 1978, as amended and supplemented through the date hereof
and as the same may thereafter be amended, supplemented or modified from time
to time.
"First Mortgage Trustee" means the trustee from time to time under the First
Mortgage Indenture.
"Fixed-Rate Conversion" means the Conversion (as defined in the Indenture) of
the Existing Tax-Exempt Refunding Bonds to the Fixed-Rate Mode (as defined in
the Indenture), which Conversion is proposed to occur on May 1, 1998.
"Fixed-Rate Conversion Drawing" means the Tender Drawing and the related
Interest Drawing (as those terms are defined in the Letter of Credit) to
effect the purchase on May 1, 1998 of the Existing Tax-Exempt Refunding Bonds
immediately prior to the Fixed-Rate Conversion.
"Governmental Approval" means any authorization, consent, approval, license,
permit, certificate, exemption of, or filing or registration with, any
governmental authority or other legal or regulatory body required in
connection with any of: (i) the execution, delivery or performance of the
Rate Agreement, any Transaction Document, Loan Document, Related Document or
Significant Contract, (ii) the grant and perfection of any security interest,
lien or mortgage contemplated by the Security Documents, (iii) the nature of
the Account Party's business as conducted or the nature of the property owned
or leased by it or (iv) any NUG Settlement. For purposes of this Agreement,
Chapter 362-C of the Revised Statutes Annotated of New Hampshire, in effect
on the Original Closing Date, shall be deemed to be a Governmental Approval.
"Hazardous Substance" means any waste, substance or material identified as
hazardous, dangerous or toxic by any office, agency, department, commission,
board, bureau or instrumentality of the United States of America or of the
State or locality in which the same is located having or exercising
jurisdiction over such waste, substance or material.
"Indemnified Person" has the meaning assigned to that term in Section
10.04(b) hereof.
"Indenture" has the meaning assigned to that term in the Preliminary
Statement.
"Indenture Assets" means fixed assets of the Account Party (including related
Governmental Approvals and regulatory assets) which from time to time are
subject to the first-priority lien under the First Mortgage Indenture.
"Information Memorandum" means the Confidential Information Memorandum, dated
February, 1998 regarding the Account Party, as distributed to the Issuing
Bank and the Participating Banks, including, without limitation, all
schedules, attachments and supplements, if any, thereto.
"Initial Advance" has the meaning assigned to that term in Section 3.02(a)
hereof.
"Initial Repayment Date" has the meaning assigned to that term in Section
3.02(a) hereof.
"Intercreditor Agreement" means the Collateral Agency and Intercreditor
Agreement, dated as of the date hereof, among the Agent, Swiss Bank
Corporation, Stamford Branch as "Agent" under the Other Reimbursement
Agreement and The Chase Manhattan Bank, as Administrative Agent under the
Revolving Credit Agreement and as Collateral Agent.
"Interest Component" has the meaning assigned to that term in the Letter of
Credit.
"Interest Drawing" has the meaning assigned to that term in the Letter of
Credit.
"Interest Expense" means, for any period, the aggregate amount of any
interest on Debt (including long-term and short-term Debt).
"Interest Period" has the meaning assigned to that term in Section 3.03(b)
hereof.
"Issuer" has the meaning assigned to that term in the Preliminary Statement.
"Issuer Resolution" means the resolution adopted by the Issuer that
authorized the issuance of the Bonds, approved the terms and provisions of
the Bonds, and approved those of the documents related to the Bonds to which
the Issuer is a party.
"Letter of Credit" means the Existing Letter of Credit, issued in the form of
Exhibit 1.01A to the Existing Agreement, as extended and amended by the
Letter of Credit Amendment, and as it may from time to time be further
extended, amended or otherwise modified pursuant to the terms of this
Agreement.
"Letter of Credit Amendment" means the First Amendment to Irrevocable Letter
of Credit issued by the Issuing Bank in favor of the Paying Agent, in
substantially the form of Exhibit 1.01A-2 hereto.
"Lien" has the meaning assigned to that term in Section 7.02(a) hereof.
"Loan Documents" means this Agreement and the Security Documents, as each may
be amended, supplemented or otherwise modified from time to time.
"Major Electric Generating Plants" means the following nuclear, combustion
turbine and coal, oil or diesel-fired generating stations of the Account
Party: the Merrimack generating station located in Bow, New Hampshire; the
Newington generating station located in Newington, New Hampshire; the
Schiller generating station located in Portsmouth, New Hampshire; the White
Lake combustion turbine located in Tamworth, New Hampshire; the Millstone
Unit No. 3 generating station located in Waterford, Connecticut, and the
Wyman Unit No. 4 generating station located in Yarmouth, Maine.
"Majority Lenders" means on any date of determination, (i) the Issuing Bank
and (ii) Participating Banks who, collectively, on such date, have
Participation Percentages in the aggregate of at least 66-2/3%. Determination
of those Participating Banks satisfying the criteria specified above for
action by the Majority Lenders shall be made by the Agent and shall be
conclusive and binding on all parties absent manifest error.
"Material Adverse Effect" means a material adverse effect upon: (i) the
Account Party's business, prospects, operations, properties, assets, or
condition (financial or otherwise), (ii) the Account Party's ability to
perform under any Loan Document, Related Document, the Rate Agreement or any
Significant Contract, (iii) the value, validity, perfection and
enforceability of the any Lien granted under or in connection with any
Security Document, or (iv) the ability of the Collateral Agent, the Agent or
the Issuing Bank to enforce any of the obligations or any of their material
rights and remedies under the Loan Documents; provided, that, any material
adverse development with respect to the Rate Proceeding, the Rate Agreement
or the Final Plan that results in a material adverse effect on the Account
Party other than as described in the Disclosure Documents shall automatically
be deemed to be a Material Adverse Effect.
"Merger" means (i) the merger on June 5, 1992 of NU Acquisition Corp., a
wholly-owned subsidiary of NU, with and into the Account Party and (ii) the
transfer on the same date by the Account Party, as so merged, of its right,
title and interest in Seabrook to NAEC.
"Moody's" means Moody's Investors Service, Inc. or any successor thereto.
"NAEC" means North Atlantic Energy Corporation, a wholly-owned subsidiary of
NU.
"NHPUC" means the New Hampshire Public Utilities Commission.
"1997 10-K" means the Account Party's 1997 Annual Report and its Annual
Report on Form 10-K for the fiscal year ended December 31, 1997.
"NU" means Northeast Utilities, an unincorporated voluntary business
association organized under the laws of the Commonwealth of Massachusetts.
"NUG Settlement" means any buy-out, buy-down or other transaction, or any
other arrangement or agreement, entered into or proposed to be entered into
by the Account Party to terminate or reduce, or to resolve a dispute
concerning, an obligation of the Account Party to purchase power and/or
capacity from a non-utility generator.
"NUSCO" means Northeast Utilities Service Company, a Connecticut corporation
and a wholly-owned subsidiary of NU.
"Official Statement" means any Official Statement, Preliminary Official
Statement or similar disclosure document relating to the Bonds (including in
connection with the Fixed-Rate Conversion), and shall include any amendment,
supplement or "sticker" thereto.
"Operating Income" means, for any period, the Account Party's operating
income for such period, adjusted as follows:
(i) increased by the amount of income taxes (including New Hampshire
Business Profits Tax and other comparable taxes) paid by the Account Party
during such period, if and to the extent they are deducted in the computation
of the Account Party's operating income for such period; and
(ii) increased by the amount of any depreciation deducted by the Account
Party during such period; and
(iii) increased by the amount of any amortization of acquisition
adjustment deducted by the Account Party during such period; and
(iv) decreased by the amount of any capital expenditures paid by the Account
Party during such period.
"Original Closing Date" means the Business Day upon which each of the
conditions precedent enumerated in Sections 5.01 and 5.02 of the Existing
Reimbursement Agreement were fulfilled to the satisfaction of the Agent, the
Issuing Bank, the Participating Banks and the Account Party, which date was
May 2, 1995.
"Original Indenture" has the meaning assigned to that term in the Preliminary
Statement.
"Other Reimbursement Agreement" means (i) the Second Series E Letter of
Credit and Reimbursement Agreement, dated as of May 1, 1995, among the
Account Party, Swiss Bank Corporation, New York Branch, as issuing bank and
agent thereunder and the Participating Banks referred to therein relating to
the Issuer's Pollution Control Revenue Bonds (Public Service Company of New
Hampshire Project-1991 Taxable Series E) and the Issuer's Pollution Control
Refunding Revenue Bonds (Public Service Company of New Hampshire Project-1993
Tax-Exempt Series E), as amended by the Other Reimbursement Agreement
Amendment and as the same may from time to time be further amended, modified
or supplemented or (ii) any reimbursement agreement or similar agreement
relating to a substitute credit facility applicable to such bonds.
"Other Reimbursement Agreement Amendment" means the First Amendment, dated
the date hereof, to the Other Reimbursement Agreement.
"Participant" shall have the meaning assigned to that term in Section
10.06(b) hereof.
"Participating Banks" means: (i) as of any date of determination prior to the
Letter of Credit Amendment becoming effective in accordance with its terms,
the Participating Banks parties to the Existing Reimbursement Agreement and
(ii) thereafter, the Persons listed on the signature pages to the Amendment
following the heading "Participating Banks" and any other Person who becomes
a party hereto pursuant to Section 10.06 hereof.
"Participation Assignment" means a participation assignment entered into
pursuant to Section 10.06 hereof by any Participating Bank and an assignee,
in substantially the form of Exhibit 1.01B hereto.
"Participation Percentage" means, with respect to any Participating Bank: (i)
as of any date of determination prior to the Letter of Credit Amendment
becoming effective in accordance with its terms, such Participating Bank's
Participation Percentage as determined pursuant to the Existing Reimbursement
Agreement (which, in the case of Swiss Bank Corporation, Stamford Branch is
zero); (ii) thereafter, (A) with respect to a Participating Bank initially a
party to this Agreement, the percentage set forth opposite such Participating
Bank's name on Schedule II to the Amendment, except as provided in clause
(iii), below and (B) with respect to a Participating Bank that becomes a
party hereto by operation of Section 10.06(a) hereof, the Participation
Percentage stated to be assumed by such assignee Participating Bank in the
relevant Participation Assignment, except as provided in clause (iii), below,
and (iii) at any time, with respect to any Participating Bank that assigns a
percentage of its interests in accordance with Section 10.06(a) hereof, its
Participation Percentage determined in accordance with clause (i) or clause
(ii), above, as reduced by the percentage so assigned.
"Paying Agent" means (i) U.S. Bank Trust National Association (formerly First
Trust of New York, National Association), and (ii) any successor paying agent
for the Bonds under the Indenture.
"PBGC" means the Pension Benefit Guaranty Corporation (or any successor
entity) established under ERISA.
"Permitted Investments" means (i) securities issued or directly and fully
guaranteed or insured by the United States or any agency or instrumentality
thereof (provided that the full faith and credit of the United States is
pledged in support thereof) having maturities of not more than six (6) months
from the date of acquisition by such Person; (ii) time deposits and
certificates of deposit, with maturities of not more than six (6) months from
the date of acquisition by such Person, of any international commercial bank
of recognized standing having capital and surplus in excess of $500,000,000
and having a rating on its commercial paper of at least A-1 or the equivalent
thereof by S&P or at least P-1 or the equivalent thereof by Moody's; (iii)
commercial paper issued by any Person, which commercial paper is rated at
least A-1 or the equivalent thereof by S&P or at least P-1 or the equivalent
thereof by Moody's and matures not more than six (6) months after the date of
acquisition by such Person; (iv) investments in money market funds
substantially all the assets of which are comprised of securities of the
types described in clauses (i) and (ii) above and (v) United States
Securities and Exchange Commission registered money market mutual funds
conforming to Rule 2a-7 of the Investment Company Act of 1940 in effect in
the United States, that invest primarily in direct obligations issued by the
United States Treasury and repurchase obligations backed by those
obligations, and rated in the highest category by S&P and Moody's.
"Person" means an individual, partnership, corporation (including a business
trust), limited liability company, joint stock company, trust, estate,
unincorporated association, joint venture or other entity, or a government or
any political subdivision or agency thereof.
"Plan" means that certain Third Amended Joint Plan of Reorganization of the
Account Party, dated December 28, 1989, as confirmed by order of the United
States Bankruptcy Court for the District of New Hampshire on April 20, 1990.
"Pledge Agreement" means the Series D Pledge Agreement, dated as of May 1,
1991, by the Account Party in favor of Citibank, as amended by a First
Amendment thereto, dated as of October 1, 1992, and by a Second Amendment
thereto, dated as of May 1, 1995 among the Account Party, Citibank and
Barclays, as agent and issuing bank under the Existing Reimbursement
Agreement, and as the same may from time to time be amended, modified or
supplemented.
"Pledged Bonds" shall have the meaning assigned to that term in the Pledge
Agreement.
"Preferred Stock" means 5,000,000 shares of Series A Preferred Stock of the
Account Party (par value $25).
"Premium Component" has the meaning assigned to that term in the Letter of
Credit.
"Principal Component" has the meaning assigned to that term in the Letter of
Credit.
"Rate Agreement" means the Agreement dated as of November 22, 1989, as
amended by the First Amendment to Rate Agreement dated as of December 5,
1989, the Second Amendment to Rate Agreement dated as of December 12, 1989,
the Third Amendment to Rate Agreement dated as of December 28, 1993, the
Fourth Amendment to Rate Agreement dated as of September 21, 1994 and the
Fifth Amendment to Rate Agreement dated as of September 9, 1994, among NUSCO,
the Governor and Attorney General of the State of New Hampshire and adopted
by the Account Party as of July 10,1990 (excluding the Unit Contract appended
as Exhibit A thereto subsequent to the effectiveness of such contract).
"Rate Proceeding" means all regulatory proceedings relating to the Account
Party and resulting from the NHPUC's adoption of the Final Plan, together
with the Federal litigation commenced by the Account Party and certain of its
Affiliates in response thereto.
"Recipient" has the meaning assigned to that term in Section 10.09 hereto.
"Related Documents" means the Letter of Credit, the Bonds, the Indenture and
any Remarketing Agreement.
"Remarketing Agent" has the meaning assigned to that term in the Indenture.
"Remarketing Agreement" means (i) the Remarketing Agreement, dated as of May
1, 1991, between the Account Party and Goldman, Sachs Money Markets Inc.
relating to the Taxable Bonds, (ii) the Remarketing Agreement, dated as of
December 1, 1992, between the Account Party and Goldman, Sachs & Co. relating
to the Existing Tax-Exempt Refunding Bonds, (iii) any similar agreement
subsequently entered into with respect to any other Tax-Exempt Refunding
Bonds and (iv) any successor agreement to any of the foregoing or any similar
agreement between the Account Party and a successor Remarketing Agent as
shall be in effect from time to time in accordance with the terms of the
Indenture.
"Restricted Payment" has the meaning assigned to that term in Section 7.02(e)
hereof.
"Revolving Credit Agent" means The Chase Manhattan Bank and any successor as
"Administrative Agent" under (and as defined in) the Revolving Credit
Agreement.
"Revolving Credit Agreement" means the $75,000,000 (original principal
amount) Revolving Credit Agreement, dated as of the date hereof, among the
Account Party, the Banks and Co-Agents named therein, and The Chase Manhattan
Bank, as Administrative Agent; in each case as amended, modified or
supplemented to the date hereof and as the same may be further amended,
modified or supplemented from and after the date hereof.
"Revolving Credit Lenders" means the Lenders from time to time under (and as
defined in) the Revolving Credit Agreement.
"S&P" means Standard and Poor's Ratings Group or any successor thereto.
"Seabrook" means the nuclear-fueled, steam-electric generating plant at a
site located in Seabrook, New Hampshire, and the related real property
interests and other fixed assets of such plant.
"Secured Party" has the meaning assigned to that term in the Intercreditor
Agreement.
"Security Agreement" means the Assignment and Security Agreement, dated as of
the date hereof, between the Account Party and the Collateral Agent, pursuant
to which the Account Party has granted to the Collateral Agent a security
interest in certain of the Account Party's accounts receivable, as the same
may be amended, modified or supplemented from time to time in accordance with
this Agreement and the Intercreditor Agreement.
"Security Documents" means the Pledge Agreement, the Security Agreement, the
Intercreditor Agreement, the Indenture, the First Mortgage Indenture and the
Series F First Mortgage Bonds.
"Series F First Mortgage Bonds" means the Account Party's Series F First
Mortgage Bonds.
"Sharing Agreement" means the Sharing Agreement, dated as of June 1, 1992,
among CL&P, Western Massachusetts Electric Company, Holyoke Water Power
Company, Holyoke Power and Electric Company, the Account Party and NUSCO.
"Significant Contract" means the following contracts, in each case as the
same may be amended, modified or supplemented from time to time in accordance
with this Agreement:
(i) the Agreement for Capacity Transfer;
(ii) the Sharing Agreement;
(iii) the Tax Allocation Agreement; and
(iv) the Unit Contract.
"Stated Amount" has the meaning assigned to that term in the Preliminary
Statement hereto.
"Stated Termination Date" means the expiration date specified in clause (i)
of the first paragraph of Paragraph (1) of the Letter of Credit, as such date
may be extended pursuant to Section 2.05 hereof
"Tax Allocation Agreement" means the Amended and Restated Tax Allocation
Agreement, dated as of January 1, 1990, among NU and the members of the
consolidated group of which NU is the common parent, including, without
limitation, the Account Party.
"Taxable Bonds" has the meaning assigned to that term in the Preliminary
Statement.
"Tender Drawing" has the meaning assigned to that term in the Letter of
Credit.
"Term Advance" has the meaning assigned to that term in Section 3.02(b)
hereof, and refers to a Base Rate Advance or a Eurodollar Rate Advance (each
of which shall be a "Type" of Term Advance). The Type of a Term Advance may
change from time to time when such Term Advance is Converted. For purposes
of this Agreement, all Term Advances of a Participating Bank (or portions
thereof) made as, or Converted to, the same Type and Interest Period on the
same day shall be deemed a single Term Advance by such Participating Bank
until repaid or next Converted.
"Term Borrowing" means a borrowing consisting of Term Advances of the same
Type and Interest Period made on the same day by the Participating Banks,
ratably in accordance with their respective Participation Percentages. A
Term Borrowing may be referred to herein as being a "Type" of Term Borrowing,
corresponding to the Type of Term Advances comprising such Term Borrowing.
For purposes of this Agreement, all Term Advances made as, or Converted to,
the same Type and Interest Period on the same day shall be deemed a single
Term Borrowing until repaid or next Converted.
"Termination Date" means the Stated Termination Date or the earlier date of
termination of the Commitments pursuant to Sections 2.02 or 8.02 hereunder.
"Total Capitalization" means, as of any day, the aggregate of all amounts
that would, in accordance with generally accepted accounting principles
applied on a basis consistent with the standards referred to in Section 1.03
hereof, appear on the balance sheet of the Account Party as at such day as
the sum of (i) the principal amount of all long-term Debt of the Account
Party on such day, (ii) the par value of, or stated capital represented by,
the outstanding shares of all classes of common and preferred shares of the
Account Party on such day, (iii) the surplus of the Account Party, paid-in,
earned and other, if any, on such day and (iv) the unpaid principal amount of
all short-term Debt of the Account Party on such day.
"Transaction Documents" means the Amendment, this Agreement, the
Intercreditor Agreement, the Security Agreement, the Revolving Credit
Agreement, the Other Reimbursement Agreement Amendment and the other
documents to be delivered by or on behalf of the Account Party on or in
connection with the Amendment Closing Date.
"Trustee" has the meaning assigned to that term in the Preliminary Statement
hereto.
"Type" has the meaning assigned to such term in the definitions of "Term
Advance" and "Term Borrowing" herein.
"Unit Contract" means the Unit Contract, dated as of June 1, 1992, between
the Account Party and NAEC.
"Unmatured Default" means the occurrence and continuance of an event which,
with the giving of notice or lapse of time or both, would constitute an Event
of Default.
SECTION I.2. Computation of Time Periods. In the computation of periods of
time under this Agreement any period of a specified number of days or months
shall be computed by including the first day or month occurring during such
period and excluding the last such day or month. In the case of a period of
time "from" a specified date "to" or "until" a later specified date, the word
"from" means "from and including" and the words "to" and "until" each means
"to but excluding".
SECTION I.3. Accounting Terms. All accounting terms not specifically defined
herein shall be construed in accordance with generally accepted accounting
principles applied on a basis consistent with the application employed in the
preparation of the financial projections and pro formas referred to in
Section 5.01 hereof.
SECTION I.4. Computations of Outstandings. Whenever reference is made in
this Agreement to the principal amount outstanding on any date under this
Agreement, such reference shall refer to the sum of (i) the Available Amount
on such date, (ii) the aggregate principal amount of all Advances outstanding
on such date and (iii) the aggregate amount of all demand loans under Section
3.01 hereunder on such date, in each case after giving effect to all
transactions to be made on such date and the application of the proceeds
thereof.
ARTICLE II
THE LETTER OF CREDIT
SECTION II.1. The Letter of Credit. The Issuing Bank issued the Existing
Letter of Credit on the Original Closing Date. The Issuing Bank agrees, on
the terms and conditions hereinafter set forth (including, without
limitation, the applicable conditions precedent set forth in the Amendment),
to issue the Letter of Credit Amendment to the Paying Agent, upon not less
than three Business Days prior notice from the Account Party, on the
Amendment Closing Date.
SECTION II.2. Termination of the Commitments. The obligation of the Issuing
Bank to issue the Letter of Credit Amendment shall automatically terminate if
not delivered at or prior to 5:00 P.M. (New York City time) on May 1, 1998.
SECTION II.3. Commissions and Fees. (a) The Account Party hereby agrees to
pay to the Agent, for the account of the Participating Banks ratably in
accordance with their respective Participation Percentages, a letter of
credit commission on the Available Amount in effect from time to time from
the date hereof until the Letter of Credit shall be surrendered for
cancellation (disregarding for such purpose any temporary diminution thereof
arising from drawings under the Letter of Credit to pay interest (or purchase
price corresponding to interest) on the Bonds, regardless of whether the
amount so drawn shall be thereafter reinstated), at a rate per annum equal to
the Applicable Commission, payable on the last business day of each month and
upon such surrender ; provided that if an Event of Default shall have
occurred and is continuing, the Applicable Commission in effect from time to
time shall be increased by a further 2%.
(b) The Account Party also agrees to pay to the Agent for the account of the
Participating Banks ratably in accordance with their respective Participation
Percentages, such participation fees as have been agreed among them, the
Account Party and the Agent, such participation fee to be payable in full
simultaneously with the issuance of the Letter of Credit Amendment.
(c) The Account Party also agrees to pay to the Agent, for the account of
the Issuing Bank, such other fees as have been agreed upon by the Account
Party and the Issuing Bank in that certain Fee Letter, dated February 25,
1998, between the Account Party and the Arrangers (the "Fee Agreement").
(d) The Account Party also agrees to pay to the Agent, for its own account
and/or the account of Barclays, such other fees as have been agreed upon by
the Account Party and the Agent in the Fee Agreement.
SECTION II.4. Reinstatement of the Letter of Credit. (a) The Interest
Component and the Principal Component shall, from time to time, be reinstated
by the Issuing Bank in accordance with, and only to the extent provided in,
the Letter of Credit. In no event shall reductions in the Premium Component
be reinstated.
(b) Interest Component. With respect to reinstatement of reductions in the
Interest Component resulting from Interest Drawings:
(i) The Issuing Bank may only deliver to the Paying Agent any notice of non-
reinstatement pursuant to Paragraph 5(i)(A) of the Letter of Credit if (A)
the Issuing Bank and/or the Participating Banks have not been reimbursed in
full by the Account Party for one or more drawings, together with interest if
any, owing thereon pursuant to this Agreement or (B) an Event of Default has
occurred and is then continuing.
(ii) if, subsequent to any such delivery of a notice of non-reinstatement,
the circumstances giving rise to the delivery of such notice of non-
reinstatement shall have ceased to exist (whether as a result of
reimbursement of unreimbursed drawings, or waiver or cure of an Event of
Default, or otherwise), then, provided that no other Event of Default shall
have occurred and be continuing, the Issuing Bank shall deliver to the Paying
Agent, by hand delivery or facsimile transmission, a Notice of Reinstatement
in the form of Exhibit 5 to the Letter of Credit reinstating that portion of
the Interest Component in respect of which such notice of non-reinstatement
was given.
(c) Principal Component. With respect to reinstatement of a reduction in
the Principal Component resulting from any Tender Drawing, IF:
(i) such reduction has not been reinstated pursuant to Paragraph 5(ii)(A) of
the Letter of Credit;
(ii) the Issuing Bank and/or the Participating Banks shall have been
reimbursed by the Account Party for such Tender Drawing;
(iii) any demand loan(s) and Advance(s) made in respect of such Tender
Drawing shall have been repaid by the Account Party, together with any
interest thereon and any other amounts payable hereunder in connection
therewith; AND
(iv) no Event of Default shall have occurred and then be continuing;
THEN, the Issuing Bank shall deliver to the Paying Agent, by hand delivery or
facsimile transmission, a Notice of Reinstatement in the form of Exhibit 5 to
the Letter of Credit reinstating the Principal Component to the extent of
such Tender Drawing.
SECTION II.5. Extension of the Stated Termination Date. Unless the Letter
of Credit shall have previously expired in accordance with its terms, at
least 105 days but not more than 120 days before the Stated Termination Date,
the Account Party may, by notice to the Agent (any such notice being
irrevocable), request the Issuing Bank and the Participating Banks to extend
the Stated Termination Date of the Letter of Credit for a period of one year.
If the Account Party shall make such request, the Agent shall promptly inform
the Issuing Bank and the Participating Banks and, no later than 60 days prior
to the Stated Termination Date, the Agent shall notify the Account Party in
writing (with a copy of such notice to the Trustee and the Paying Agent) if
the Issuing Bank and the Participating Banks consent to such request and the
conditions of such consent (including conditions relating to legal
documentation). The granting of any such consent shall be in the sole and
absolute discretion of the Issuing Bank and the Participating Banks, and if
the Agent shall not so notify the Account Party, such lack of notification
shall be deemed to be a determination not to consent to such request. No
such extension shall occur unless the Issuing Bank and all of the
Participating Banks consent thereto (or if less than all the Participating
Banks consent thereto, unless one or more other Participating Banks agree to
assume all of the Commitments of the non-consenting Participating Banks).
SECTION II.6. Modification of the Letter of Credit. In the event that the
Account Party elects to cause the issuance of any additional series of Tax-
Exempt Refunding Bonds (as defined in the Indenture) pursuant to Article IV
of the Indenture, the Account Party may, but shall not be obligated to,
propose amendments to the Letter of Credit to change the method of computing
the Interest Component or such other terms thereof as may be necessary or
appropriate in connection with such issuance. Any such proposal shall be
furnished to the Issuing Bank in writing not later than 60 days prior to the
date proposed for such issuance. If the Issuing Bank shall consent to such
amendments (which consent, subject to the provisions of the next succeeding
sentence, shall not be unreasonably withheld) the Issuing Bank shall, upon
surrender of the Letter of Credit by the beneficiary thereof for amendment
(or replacement, as the Issuing Bank may elect), amend the Letter of Credit
accordingly (or issue a replacement Letter of Credit therefor reflecting such
amendments but otherwise identical to the Letter of Credit so surrendered).
Notwithstanding the foregoing, without the consent of the requisite
Participating Banks as determined in accordance with Section 10.01, the
Issuing Bank shall not consent to any amendment or amendments that (i)
increase the Stated Amount or the then-existing Available Amount, (ii) change
or modify in any respect the Credit Termination Date or any provision for
determining the expiry or other termination of the Letter of Credit, (iii)
change or modify in any respect the times, places or manner at or in which
drawings under the Letter of Credit are to be presented or paid, (iv) change
or modify in any respect the forms of drawing certificates and other annexes
to the Letter of Credit, (v) change the beneficiary of the Letter of Credit
or the method prescribed therein for the transfer of the Letter of Credit or
(vi) as determined in the good faith discretion of the Issuing Bank and its
counsel, increase or enlarge the scope, or modify the nature, of the Issuing
Bank's and the Participating Banks' credit exposure to the Account Party or
any legal risks related thereto or expose the Issuing Bank to any additional
liability. In furtherance of the foregoing, the Issuing Bank may condition
the granting of such consent on the receipt by the Issuing Bank of such
certificates, opinions of counsel and other assurances of the Account Party
and its counsel, or bond counsel or the Trustee or Paying Agent, as the
Issuing Bank may reasonably require. Each Participating Bank, by its
execution of this Agreement, or of the Participation Assignment pursuant to
which it became a Participating Bank, consents to, ratifies and affirms all
actions taken and to be taken by the Issuing Bank pursuant to this Section
2.06.
ARTICLE III
REIMBURSEMENT AND ADVANCES
SECTION III.1. Reimbursement on Demand. Subject to the provisions of
Section 3.02 hereof, the Account Party hereby agrees to pay (whether with the
proceeds of Initial Advances made pursuant to this Agreement or otherwise) to
the Issuing Bank on demand (a) on and after each date on which the Issuing
Bank shall pay any amount under the Letter of Credit pursuant to any draft,
but only after so paid by the Issuing Bank, a sum equal to such amount so
paid (which sum shall constitute a demand loan from the Issuing Bank to the
Account Party from the date of such payment by the Issuing Bank until so paid
by the Account Party), plus (b) interest on any amount remaining unpaid by
the Account Party to the Issuing Bank under clause (a), above, from the date
such amount becomes payable on demand until payment in full, at the Default
Rate in effect from time to time. No reinstatement of the Interest Component
or the Principal Component despite the failure by the Account Party to
reimburse the Issuing Bank for any previous drawing to pay interest on the
Bonds shall limit or impair the Account Party's obligations under this
Section 3.01.
SECTION III.2. Advances. Each Participating Bank agrees to make Initial
Advances and Term Advances for the account of the Account Party from time to
time upon the terms and subject to the conditions set forth in this
Agreement; provided, that no Initial Advance or Term Advance shall be made
in respect of the Fixed-Rate Conversion Drawing without the consent of the
Issuing Bank and all of the Participating Banks.
(a) Initial Advances; Repayment of Initial Advances. If the Issuing Bank
shall honor any Tender Drawing and if the conditions precedent set forth in
Section 5.03 of this Agreement have been satisfied as of the date of such
honor, then, each Participating Bank's payment made to the Issuing Bank
pursuant to Section 3.07 hereof in respect of such Tender Drawing shall be
deemed to constitute an advance made for the account of the Account Party by
such Participating Bank (each such advance being an "Initial Advance" made by
such Participating Bank). Each Initial Advance shall be made as a Base Rate
Advance, shall bear interest at the Alternate Base Rate and shall not be
entitled to be Converted. Subject to Article VIII of this Agreement, each
Initial Advance and all interest thereon shall be due and payable on the
earlier to occur of (i) the date 30 days from the date of such Initial
Advance (such repayment date being the "Initial Repayment Date" for such
Initial Advance) and (ii) the Termination Date. The Account Party may repay
the principal amount of any Initial Advance with (and to the extent of) the
proceeds of a Term Advance made pursuant to subsection (b), below, and may
prepay Initial Advances in accordance with Section 3.06 hereof.
(b) Term Advances; Repayment. Subject to the satisfaction of the conditions
precedent set forth in Section 5.04 hereof and the other conditions of this
subsection (b), each Participating Bank agrees to make one or more advances
for the account of the Account Party ("Term Advances") on each Initial
Repayment Date in an aggregate principal amount equal to the amount of such
Participating Bank's Initial Advances maturing on such Initial Repayment
Date. All Term Advances comprising a single Term Borrowing shall be made
upon written notice given by the Account Party to the Agent not later than
11:00 A.M. (New York City time) (A) in the case of a Term Borrowing comprised
of Base Rate Advances, on the Business Day of such proposed Term Borrowing or
(B) in the case of a Term Borrowing comprised of Eurodollar Rate Advances,
three Business Days prior to the date of such proposed Term Borrowing. The
Agent shall notify each Participating Bank of the contents of such notice
promptly after receipt thereof. Each such notice shall specify therein the
following information: (W) the date on which such Term Borrowing is to be
made, (X) the principal amount of Term Advances comprising such Term
Borrowing, (Y) the Type of Term Borrowing and (Z) subject to Section 3.05(c),
the duration of the initial Interest Period, if applicable, proposed to apply
to the Term Advances comprising such Term Borrowing. The proceeds of each
Participating Bank's Term Advances shall be applied solely to the repayment
of the Initial Advances made by such Participating Bank and shall in no event
be made available to the Account Party. The principal amount of each Term
Advance, together with all accrued and unpaid interest thereon, shall be due
and payable on the earlier to occur of (x) the same calendar date occurring
12 months following the date upon which such Term Advance is made (or, if
such month does not have a corresponding date, on the last day of such month)
and (y) the Termination Date.
SECTION III.3. Interest on Advances. The Account Party shall pay interest
on the unpaid principal amount of each Advance from the date of such Advance
until such principal amount is paid in full at the applicable rate set forth
below:
(a) Alternate Base Rate. Except to the extent that the Account Party shall
elect to pay interest on any Advance for any Interest Period pursuant to
paragraph (c) of this Section 3.03, the Account Party shall pay interest on
each Advance (including all Initial Advances) from the date thereof until the
date such Advance is due, at a fluctuating interest rate per annum in effect
from time to time equal to the Alternate Base Rate in effect from time to
time. The Account Party shall pay interest on each Advance bearing interest
in accordance with this subsection monthly in arrears on the last business
day of each month and on the Termination Date or the earlier date for
repayment of such Advance (including the Initial Repayment Date therefor, in
the case of an Initial Advance); provided that if an Event of Default shall
have occurred and is continuing, any principal amounts outstanding shall bear
interest during such period, payable on demand, at a rate per annum equal at
all times to 2% per annum above the Alternate Base Rate in effect from time
to time.
(b) Interest Periods. Subject to the other requirements of this Section
3.03 and to Section 3.05(c), the Account Party may from time to time elect to
have the interest on all Term Advances comprising part of the same Term
Borrowing determined and payable for a specified period (an "Interest Period"
for such Term Advances) in accordance with paragraph (c) of this Section
3.03. The first day of an Interest Period for such Term Advances shall be
the date such Advance is made or most recently Converted, which shall be a
Business Day. All Interest Periods shall end on or prior to the Stated
Termination Date. Any Interest Period for a Term Advance that would
otherwise end after the Termination Date or earlier date for the repayment of
such Advance shall be deemed to end on the Termination Date or such earlier
repayment date, as the case may be.
(c) Eurodollar Rate. Subject to the requirements of this Section 3.03 and
Article V hereof, the Account Party may from time to time elect to have any
Term Advances comprising part of the same Term Borrowing made as, or
Converted to, Eurodollar Rate Advances. Subject to Section 3.05(c), the
Interest Period applicable to such Eurodollar Rate Advances shall be of one,
two, three or six whole months' duration, as the Account Party shall select
in its notice delivered to the Agent pursuant to Section 3.02(b) or 3.04
hereof, as applicable. If the Account Party shall have made such election,
the Account Party shall pay interest on such Eurodollar Rate Advances at the
Eurodollar Rate for the applicable Interest Period for such Eurodollar Rate
Advances, which interest shall be payable on the last day of such Interest
Period, on the date for repayment for such Eurodollar Rate Advances and also,
in the case of any Interest Period of six months' duration, on that day of
the third month of such Interest Period which corresponds with the first day
of such Interest Period (or, if any such month does not have a corresponding
day, then on the last day of such month); provided that if an Event of
Default shall have occurred and is continuing, any principal amounts
outstanding shall bear interest during such period, payable on demand, at a
rate per annum equal at all times to (A) for the remaining term, if any, of
the Interest Period for such Advance, 2% per annum above the Eurodollar Rate
for such Interest Period, and (B) thereafter, 2% per annum above the
Alternate Base Rate in effect from time to time. Any Interest Period
pertaining to Eurodollar Rate Advances that begins on the last Business Day
of a calendar month (or on a day for which there is no numerically
corresponding day in the calendar month at the end of such Interest Period)
shall end on the last Business Day of a calendar month.
(d) Interest Rate Determinations. The Agent shall give prompt notice to the
Account Party and the Participating Banks of the Eurodollar Rate determined
from time to time by the Agent to be applicable to each Eurodollar Rate
Advance.
SECTION III.4. Conversion of Term Advances. Subject to the satisfaction of
the conditions precedent set forth in Section 5.03 hereof, the Account Party
may elect to Convert one or more Term Advances of any Type to one or more
Term Advances of the same or any other Type on the following terms and
subject to the following conditions:
(a) Each Conversion shall be made as to all Term Advances comprising a
single Term Borrowing upon written notice given by the Account Party to the
Agent not later than 11:00 A.M. (New York City time) on the third Business
Day prior to the date of the proposed Conversion. The Agent shall notify
each Participating Bank of the contents of such notice promptly after receipt
thereof. Each such notice shall specify therein the following information:
(A) the date of such proposed Conversion (which in the case of Eurodollar
Rate Advances shall be last day of the Interest Period then applicable to
such Term Advances to be Converted), (B) Type of, and Interest Period, if
any, applicable to the Term Advances proposed to be Converted, (C) the
aggregate principal amount of Term Advances proposed to be Converted, and (D)
the Type of Term Advances to which such Term Advances are proposed to be
Converted and, subject to Section 3.05(c), the Interest Period, if any, to be
applicable thereto.
(b) During the continuance of an Unmatured Default or an Event of Default,
the right of the Account Party to Convert Term Advances to Eurodollar Rate
Advances shall be suspended, and all Eurodollar Rate Advances then
outstanding shall be Converted to Base Rate Advances on the last day of the
Interest Period then in effect, if, on such day, an Unmatured Default or an
Event of Default shall be continuing.
(c) If no notice of Conversion is received by the Agent as provided in
subsection (a) above with respect to any outstanding Eurodollar Rate
Advances, the Agent shall treat such absence of notice as a deemed notice of
Conversion providing for such Advances to be Converted to Base Rate Advances
on the last day of the Interest Period then in effect for such Eurodollar
Rate Advances.
SECTION III.5. Other Terms Relating to the Making and Conversion of
Advances. (a) Notwithstanding anything in Section 3.02, 3.03 or 3.04, above,
to the contrary:
(i) at no time shall more than six different Term Borrowings be outstanding
hereunder; and
(ii) each Term Borrowing consisting of Eurodollar Rate Advances shall be in
the aggregate principal amount of $10,000,000 or an integral multiple of
$1,000,000 in excess thereof.
(b) Each notice of borrowing pursuant to Section 3.02(b) hereof and each
notice of Conversion pursuant to Section 3.04 hereof shall be irrevocable and
binding on the Account Party.
(c) Until such time, if any, as the Majority Lenders shall otherwise agree,
the Interest Period for all Eurodollar Rate Advances shall be one month.
SECTION III.6. Prepayment of Advances. (a) The Account Party shall have no
right to prepay any principal amount of any Advances except in accordance
with subsections (b) and (c) below.
(b) The Account Party may, upon at least one Business Day's notice to the
Agent stating the proposed date and aggregate principal amount of the
prepayment (and if such notice is given the Account Party shall), prepay, in
whole or ratably in part, together with accrued interest to the date of such
prepayment on the principal amount prepaid, the outstanding principal amount
of (i) all Initial Advances made on the same date or (ii) all Term Advances
comprising the same Term Borrowing, in each case as the Account Party shall
designate in such notice; provided, however, that each partial prepayment
shall be in an aggregate principal amount not less than $10,000,000, or, if
less, the aggregate principal amount of all Advances then outstanding.
(c) Prior to or simultaneously with the resale of all of the Bonds purchased
with the proceeds of a Tender Drawing, the Account Party shall prepay, or
cause to be prepaid, in full, the then outstanding principal amount of all
Initial Advances and of all Term Advances comprising the same Term
Borrowing(s) arising pursuant to such Tender Drawing, together with all
interest thereon to the date of such prepayment. If less than all of such
Bonds are resold, then prior to or simultaneously with such resale the
Account Party shall prepay or cause to be prepaid that portion of such
Advances, together with all interest thereon to the date of such prepayment,
equal to the then outstanding principal amount thereof multiplied by a
fraction, the numerator of which shall be the principal amount of the Bonds
resold and the denominator of which shall be the principal amount of all of
the Bonds purchased with the proceeds of the relevant Tender Drawing.
SECTION III.7. Participation; Reimbursement of Issuing Bank. (a) The
Issuing Bank hereby sells and transfers to each Participating Bank, and each
Participating Bank hereby acquires from the Issuing Bank, an undivided
interest and participation to the extent of such Participating Bank's
Participation Percentage in and to (i) the Letter of Credit, including the
obligations of the Issuing Bank under and in respect thereof and the Account
Party's reimbursement and other obligations in respect thereof and (ii) each
demand loan or deemed demand loan made by the Issuing Bank, whether now
existing or hereafter arising.
(b) if the Issuing Bank (i) shall not have been reimbursed in full for any
payment made by the Issuing Bank under the Letter of Credit on the date of
such payment or (ii) shall make any demand loan to the Account Party, the
Issuing Bank shall promptly notify the Agent and the Agent shall promptly
notify each Participating Bank of such non-reimbursement or demand loan and
the amount thereof. Upon receipt of such notice from the Agent, each
Participating Bank shall pay to the Issuing Bank, directly, an amount equal
to such Participating Bank's ratable portion (according to such Participating
Bank's Participation Percentage) of such unreimbursed amount or demand loan
paid or made by the Issuing Bank, plus interest on such amount at a rate per
annum equal to the Federal Funds Rate from the date of such payment by the
Issuing Bank to the date of payment to the Issuing Bank by such Participating
Bank. All such payments by each Participating Bank shall be made in United
States dollars and in same day funds:
(x) not later than 2:45 P.M. (New York City time) on the day such notice is
received by such Participating Bank if such notice is received at or prior to
12:30 P.M. (New York City nine) on a Business Day; or
(y) not later than 12:00 Noon (New York City time) on the Business Day next
succeeding the day such notice is received by such Participating Bank, if
such notice is received after 12:30 P.M. (New York City time) on a Business
Day.
If a Participating Bank shall have paid to the Issuing Bank its ratable
portion of any unreimbursed amount or demand loan paid or made by the Issuing
Bank, together with all interest thereon required by the second sentence of
this subsection (b), such Participating Bank shall be entitled to receive its
ratable share of all interest paid by the Account Party in respect of such
unreimbursed amount or demand loan from the date paid or made by the Issuing
Bank. If such Participating Bank shall have made such payment to the Issuing
Bank, but without all such interest thereon required by the second sentence
of this subsection (b), such Participating Bank shall be entitled to receive
its ratable share of the interest paid by the Account Party in respect of
such unreimbursed amount or demand loan only from the date it shall have paid
all interest required by the second sentence of this subsection (b).
(c) Each Participating Bank's obligation to make each payment to the Issuing
Bank, and the Issuing Bank's right to receive the same, shall be absolute and
unconditional and shall not be affected by any circumstance whatsoever,
including, without limitation, the foregoing or Section 4.06 hereof, or the
occurrence or continuance of an Event of Default, or the non-satisfaction of
any condition precedent set forth in Sections 5.03 or 5.04 hereof, or the
failure of any other Participating Bank to make any payment under this
Section 3.07. Each Participating Bank further agrees that each such payment
shall be made without any offset abatement, withholding or reduction
whatsoever.
(d) The failure of any Participating Bank to make any payment to the Issuing
Bank in accordance with subsection (b) above, shall not relieve any other
Participating Bank of its obligation to make payment, but neither the Issuing
Bank nor any Participating Bank shall be responsible for the failure of any
other Participating Bank to make such payment. If any Participating Bank
shall fail to make any payment to the Issuing Bank in accordance with
subsection (b) above, then such Participating Bank shall pay to the Issuing
Bank forthwith on demand such corresponding amount together with interest
thereon, for each day until the date such amount is repaid to the Issuing
Bank at the Federal Funds Rate. Nothing herein shall in any way limit, waive
or otherwise reduce any claims that any party hereto may have against any
non-performing Participating Bank.
(e) If any Participating Bank shall fail to make any payment to the Issuing
Bank in accordance with subsection (b) above, then, in addition to other
rights and remedies which the Issuing Bank may have, the Agent is hereby
authorized, at the request of the Issuing Bank, to withhold and to apply the
payment of such amounts owing to such Participating Bank to the Issuing Bank
and any related interest, that portion of any payment received by the Agent
that would otherwise be payable to such Participating Bank. In furtherance
of the foregoing, if any Participating Bank shall fail to make any payment to
the Issuing Bank in accordance with subsection (b), above, and such failure
shall continue for five Business Days following written notice of such
failure from the Issuing Bank to such Participating Bank, the Issuing Bank
may acquire, or transfer to a third party in exchange for the sum or sums due
from such Participating Bank, such Participating Bank's interest in the
related unreimbursed amounts and demand loans and all other rights of such
Participating Bank hereunder in respect thereof, without, however, relieving
such Participating Bank from any liability for damages, costs and expenses
suffered by the Issuing Bank as a result of such failure. The purchaser of
any such interest shall be deemed to have acquired an interest senior to the
interest of such Participating Bank and shall be entitled to receive all
subsequent payments which the Issuing Bank or the Agent would otherwise have
made hereunder to such Participating Bank in respect of such interest.
ARTICLE IV
PAYMENTS
SECTION IV.1. Payments and Computations. (a) The Account Party shall make
each payment hereunder (i) in the case of reimbursement obligations pursuant
to Section 3.01 hereof (excluding any portion thereof in respect of which an
Initial Advance is to be made), not later than 2:30 P.M. (New York City time)
on the day the related drawing under the Letter of Credit is paid by the
Issuing Bank, and (ii) in all other cases, not later than 12:30 P.M. (New
York City time) on the day when due, in each case in lawful money of the
United States of America to the Agent at its address referred to in Section
10.02 hereof in same day funds. The Agent will promptly thereafter cause to
be distributed like funds relating to the payment of reimbursements,
principal, interest, fees or other amounts payable to the Issuing Bank and
the Participating Banks to whom the same are payable, ratably, at its address
set forth in Section 10.02 hereof (in the case of the Issuing Bank) or for
the account of their respective Applicable Lending Offices (in the case of
the Participating Banks), in each case to be applied in accordance with the
terms of this Agreement.
(b) The Account Party hereby authorizes the Issuing Bank, and each
Participating Bank, if and to the extent payment owed to the Issuing Bank, or
such Participating Bank, as the case may be, is not made when due hereunder,
to charge from time to time against any or all of the Account Party's
accounts with the Issuing Bank or such Participating Bank, as the case may
be, any amount so due.
(c) All computations of interest based on the Alternate Base Rate when based
on Barclays' prime rate referred to in the definition of "Alternate Base
Rate" shall be made by the Agent on the basis of a year of 365 or 366 days,
as the case may be, for the actual days elapsed. All other computations of
interest hereunder (including computations of interest based on the
Eurodollar Rate and the Federal Funds Rate (including the Alternate Base Rate
if and so long as such Rate is based on the Federal Funds Rate)), all
computations of commissions and fees hereunder and all computations of other
amounts pursuant to Section 4.03 hereof, shall be made by the Agent or the
party claiming such other amounts, as the case may be, on the basis of a year
of 360 days for the actual days elapsed. In each such case, such computation
shall be made for the actual number of days (including the first day, but
excluding the last day) occurring in the period for which such interest,
commissions or fees are payable. Each such determination by the Agent or a
Participating Bank, as the case may be, shall be conclusive and binding for
all purposes, absent manifest error.
(d) Whenever any payment hereunder shall be stated to be due, or the last
day of an Interest Period hereunder shall be stated to occur, on a day other
than a Business Day, such payment shall be made and the last day of such
Interest Period shall occur on the next succeeding Business Day, and such
extension of time shall in such case be included in the computation of
payment of interest, commissions and fees hereunder; provided, however, that
if such extension would cause payment of interest on or principal of
Eurodollar Rate Advances to be made, or the last day of an Interest Period
for a Eurodollar Rate Advance to occur, in the next following calendar month,
such payment shall be made on the next preceding Business Day and such
reduction of time shall in such case be included in the computation of
payment of interest hereunder.
(e) Unless the Agent shall have received notice from the Account Party prior
to the date on which any payment is due to the Issuing Bank or the
Participating Banks hereunder that the Account Party will not make such
payment in full, the Agent may assume that the Account Party has made such
payment in full to the Agent on such date and the Agent may, in reliance upon
such assumption, cause to be distributed to the Issuing Bank and/or each
Participating Bank on such due date an amount equal to the amount then due
the Issuing Bank and/or such Participating Bank. If and to the extent the
Account Party shall not have so made such payment in full to the Agent, the
Issuing Bank and/or each such Participating Bank shall repay to the Agent
forthwith on demand such amount distributed to the Issuing Bank and/or such
Participating Bank, together with interest thereon, for each day from the
date such amount is distributed to the Issuing Bank and/or such Participating
Bank until the date the Issuing Bank and/or such Participating Bank repays
such amount to the Agent, at the Federal Funds Rate.
(f) If, after the Agent has paid to the Issuing Bank or any Participating
Bank any amount pursuant to subsection (a) above, such payment is rescinded
or must otherwise be returned or must be paid over by the Agent or the
Issuing Bank to any Person, whether pursuant to any bankruptcy or insolvency
law, Section 4.04 hereof or otherwise, such Participating Bank shall, at the
request of the Agent or the Issuing Bank, promptly repay to the Agent or the
Issuing Bank, as the case may be, an amount equal to its ratable share of
such payment, together with any interest required to be paid by the Agent or
the Issuing Bank with respect to such payment.
SECTION IV.2. Default Interest. Any amounts payable hereunder that are not
paid when due shall (to the fullest extent permitted by law) bear interest,
from the date when due until paid in full, at the Default Rate, payable on
demand.
SECTION IV.3. Yield Protection. (a) Change in Circumstances.
Notwithstanding any other provision herein, if after the date hereof; the
adoption of or any change in applicable law or regulation or in the
interpretation or administration thereof by any governmental authority
charged with the interpretation or administration thereof (whether or not
having the force of law) shall (i) change the basis of taxation of payments
to the Issuing Bank or any Participating Bank of the principal of or interest
on any Eurodollar Rate Advance made by such Participating Bank or any fees or
other amounts payable hereunder (other than changes in respect of taxes
imposed on the overall net income of the Issuing Bank or such Participating
Bank, or its Applicable Lending Office, by the jurisdiction in which the
Issuing Bank or such Participating Bank has its principal office or in which
such Applicable Lending Office is located or by any political subdivision or
taxing authority therein), or (ii) shall impose, modify or deem applicable
any reserve, special deposit or similar requirement against letters of credit
(or participatory interests therein) issued by, commitments or assets of,
deposits with or for the account of, or credit extended by, the Issuing Bank
or such Participating Bank, or (iii) shall impose on the Issuing Bank or such
Participating Bank any other condition affecting this Agreement, the Letter
of Credit or participatory interests therein or Eurodollar Rate Advances, and
the result of any of the foregoing shall be (A) to increase the cost to the
Issuing Bank or such Participating Bank of issuing, maintaining or
participating in this Agreement or the Letter of Credit or of agreeing to
make, making or maintaining any Advance or (B) to reduce the amount of any
sum received or receivable by the Issuing Bank or such Participating Bank
hereunder (whether of principal, interest or otherwise), then the Account
Party will pay to the Issuing Bank or such Participating Bank, upon demand,
such additional amount or amounts as will compensate the Issuing Bank or such
Participating Bank for such additional costs incurred or reduction suffered.
(b) Capital. If the Issuing Bank or any Participating Bank shall have
determined that the applicability of any law, rule, regulation or guideline
adopted pursuant to or arising out of the July 1988 report of the Basle
Committee on Banking Regulations and Supervisory Practices entitled
"International Convergence of Capital Measurement and Capital Standards", or
the adoption after the date hereof of any law, rule, regulation or guideline
regarding capital adequacy, or any change in any of the foregoing or in the
interpretation or administration of any of the foregoing by any governmental
authority, central bank or comparable agency charged with the interpretation
or administration thereof, or compliance by the Issuing Bank or any
Participating Bank (or any Applicable Lending Office of the Issuing Bank or
such Participating Bank), or any holding company of any such entity, with any
request or directive regarding capital adequacy (whether or not having the
force of law) of any such authority, central bank or comparable agency, has
or would have the effect (i) of reducing the rate of return on such entity's
capital or on the capital of such entity's holding company, if any, as a
consequence of this Agreement, the Letter of Credit or such entity's
participatory interest therein, any Commitment hereunder or the portion of
the Advances made by such entity pursuant hereto to a level below that which
such entity or such entity's holding company could have achieved, but for
such applicability, adoption, change or compliance (taking into consideration
such entity's policies and the policies of such entity's holding company with
respect to capital adequacy), or (ii) of increasing or otherwise determining
the amount of capital required or expected to be maintained by such entity or
such entity's holding company based upon the existence of this Agreement, the
Letter of Credit or such entity's participatory interest therein, any
Commitment hereunder, the portion of the Advances made by such entity
pursuant hereto and other similar such credits, participations, commitments,
agreements or assets, then from time to time the Account Party shall pay to
the Issuing Bank or such Participating Bank, upon demand, such additional
amount or amounts as will compensate such entity or such entity's holding
company for any such reduction or allocable capital cost suffered.
(c) Eurodollar Reserves. The Account Party shall pay to each Participating
Bank upon demand, so long as such Participating Bank shall be required under
regulations of the Board of Governors of the Federal Reserve System to
maintain reserves with respect to liabilities or assets consisting of or
including Eurocurrency Liabilities, additional interest on the unpaid
principal amount of such Participating Bank's portion of each Eurodollar Rate
Advance, from the date of such Advance until such principal amount is paid in
full, at an interest rate per annum equal at all times to the remainder
obtained by subtracting (i) the rate described in clause (i) of the
definition of "Eurodollar Rate" for the Interest Period for such Advance from
(ii) the rate obtained by dividing such rate by a percentage equal to 100%
minus the Eurodollar Reserve Percentage of such Participating Bank for such
Interest Period. Such additional interest shall be determined by such
Participating Bank and notified to the Account Party and the Issuing Bank.
(d) Breakage Indemnity. The Account Party shall indemnify each Participating
Bank against any loss, cost or reasonable expense which such Participating
Bank may sustain or incur as a consequence of (i) any failure by the Account
Party to fulfill on the date of any Advance or Conversion hereunder the
applicable conditions set forth in Articles III and V, (ii) any failure by
the Account Party to Convert any Advance hereunder after irrevocable notice
of Conversion has been given pursuant to Section 3.04 hereof, (iii) any
payment, prepayment or Conversion of a Eurodollar Rate Advance required or
permitted by any other provision of this Agreement or otherwise made or
deemed made on a date other than the last day of the Interest Period
applicable thereto, (iv) any default in payment or prepayment of the
principal amount of any Advance or any part thereof or interest accrued
thereon, as and when due and payable (at the due date thereof, by irrevocable
notice of prepayment or otherwise) or (v) the occurrence of any Event of
Default, including, in each such case, any loss or reasonable expense
sustained or incurred or to be sustained or incurred in liquidating or
employing deposits from third parties acquired to effect or maintain such
Advance or any part thereof as a Eurodollar Rate Advance. Such loss, cost or
reasonable expense shall include an amount equal to the excess, if any, as
reasonably determined by such Participating Bank, of (A) its cost of
obtaining the funds for the Advance being paid, prepaid, Converted or not
borrowed (based on the Eurodollar Rate) for the period from the date of such
payment, prepayment, Conversion or failure to borrow to the last day of the
Interest Period for such Advance (or, in the case of a failure to borrow, the
Interest Period for such Advance which would have commenced on the date of
such failure) over (B) the amount of interest (as reasonably determined by
such Participating Bank) that would be realized by such Participating Bank in
reemploying the funds so paid, prepaid, Converted or not borrowed for such
period or Interest Period, as the case may be. For purposes of this
subsection (d), it shall be presumed that each Participating Bank shall have
funded each such Advance with a fixed-rate instrument bearing the rates and
maturities designated in the determination of the applicable interest rate
for such Advance.
(e) Notices. A certificate of the Issuing Bank or any Participating Bank
setting forth such entity's claim for compensation hereunder and the amount
necessary to compensate such entity or its holding company pursuant to
subsections (a) through (d) of this Section 4.03 shall be submitted to the
Account Party and the Issuing Bank and shall be conclusive and binding for
all purposes, absent manifest error. The Account Party shall pay the Issuing
Bank or such Participating Bank directly the amount shown as due on any such
certificate within ten days after its receipt of the same. The failure of any
entity to provide such notice or to make demand for payment under this
Section 4.03 shall not constitute a waiver of such Participating Bank's
rights hereunder; provided, that such entity shall not be entitled to demand
payment pursuant to subsections (a) through (d) of this Section 4.03 in
respect of any loss, cost, expense, reduction or reserve if such demand is
made more than one year following the later of such entity's incurrence or
sufferance thereof or such entity's actual knowledge of the event giving rise
to such entity's rights pursuant to such subsections. The protection of this
Section 4.03 shall be available to the Issuing Bank and each Participating
Bank regardless of any possible contention of the invalidity or
inapplicability of the law, rule, regulation, guideline or other change or
condition which shall have occurred or been imposed.
(f) Change in Legality. Notwithstanding any other provision herein, if the
adoption of or any change in any law or regulation or in the interpretation
or administration thereof by any governmental authority charged with the
administration or interpretation thereof shall make it unlawful for any
Participating Bank to make or maintain any Eurodollar Rate Advance or to give
effect to its obligations as contemplated hereby with respect to any
Eurodollar Rate Advance, then, by written notice to the Account Party and the
Issuing Bank, such Participating Bank may:
(i) declare that Eurodollar Rate Advances will not thereafter be made by
such Participating Bank hereunder, whereupon the right of the Account Party
to select Eurodollar Rate Advances for any Advance or Conversion shall be
forthwith suspended until such Participating Bank shall withdraw such notice
as provided hereinbelow or shall cease to be a Participating Bank hereunder;
and
(ii) require that all outstanding Eurodollar Rate Advances be Converted to
Base Rate Advances, in which event all Eurodollar Rate Advances shall be
automatically Converted to Base Rate Advances as of the effective date of
such notice as provided hereinbelow.
Upon receipt of any such notice, the Agent shall promptly notify the
Participating Banks thereof. Promptly upon becoming aware that the
circumstances that caused such Participating Bank to deliver such notice no
longer exist, such Participating Bank shall deliver notice thereof to the
Account Party and the Agent withdrawing such prior notice (but the failure to
do so shall impose no liability upon such Participating Bank). Promptly upon
receipt of such withdrawing notice from such Participating Bank, the Agent
shall deliver notice thereof to the Account Party and the Participating Banks
and such suspension shall terminate. Prior to any Participating Bank giving
notice to the Account Party under this subsection (f), such Participating
Bank shall use reasonable efforts to change the jurisdiction of its
Applicable Lending Office, if such change would avoid such unlawfulness and
would not, in the sole determination of such Participating Bank, be otherwise
disadvantageous to such Participating Bank. Any notice to the Account Party
by any Participating Bank shall be effective as to each Eurodollar Rate
Advance on the last day of the Interest Period currently applicable to such
Eurodollar Rate Advance; provided that if such notice shall state that the
maintenance of such Advance until such last day would be unlawful, such
notice shall be effective on the date of receipt by the Account Party and the
Agent.
(g) Market Rate Disruptions. If, (i) the Agent determines that an
adequate basis does not exist for the determination of the Eurodollar Rate
for Eurodollar Rate Advances or (ii) if the Majority Lenders shall notify the
Agent that the Eurodollar Rate will not adequately reflect the cost to such
Majority Lenders of making, funding or maintaining their respective
Eurodollar Rate Advances, the right of the Account Party to select or receive
or Convert into Eurodollar Rate Advances shall be forthwith suspended until
the Agent shall notify the Account Party and the Participating Banks that the
circumstances causing such suspension no longer exist, and until such
notification from the Agent, each request for or Conversion into Eurodollar
Rate Advances hereunder shall be deemed to be a request for or Conversion
into Base Rate Advances.
SECTION IV.4. Sharing of Payments, Etc. If any Participating Bank shall
obtain any payment (whether voluntary, involuntary, through the exercise of
any right of set-off, or otherwise, but excluding any proceeds received by
assignments or sales of participations in accordance with Section 10.06
hereof to a Person that is not an Affiliate of the Account Party) on account
of the Advances owing to it (other than pursuant to Section 4.03 hereof) in
excess of its ratable share of payments on account of the Advances obtained
by all the Participating Banks, such Participating Batik shall forthwith
purchase from the other Participating Banks such participation in the
portions of the Advances owing to them as shall be necessary to cause such
purchasing Participating Bank to share the excess payment ratably with each
of them; provided, however, that if all or any portion of such excess payment
is thereafter recovered from such purchasing Participating Bank, such
purchase from each Participating Bank shall be rescinded and such
Participating Bank shall repay to the purchasing Participating Bank the
purchase price to the extent of such recovery together with an amount equal
to such Participating Bank's ratable share (according to the proportion of
(i) the amount of such Participating Bank's required repayment to (ii) the
total amount so recovered from the purchasing Participating Bank) of any
interest or other amount paid or payable by the purchasing Participating Bank
in respect of the total amount so recovered. The Account Party agrees that
any Participating Bank so purchasing a participation from another
Participating Bank pursuant to this Section 4.04 may, to the fullest extent
permitted by law, exercise all its rights of payment (including the right of
set-off) with respect to such participation as fully as if such Participating
Bank were the direct creditor of the Account Party in the amount of such
participation. Notwithstanding the foregoing, if any Participating Bank
shall obtain any such excess payment involuntarily, such Participating Bank
may, in lieu of purchasing participation from the other Participating Banks
in accordance with this Section 4.04, on the date of receipt of such excess
payment, return such excess payment to the Agent for distribution in
accordance with Section 4.01(a) hereof.
SECTION IV.5. Taxes. (a) All payments by the Account Party hereunder shall
be made in accordance with Section 4.01, free and clear of and without
deduction for all present or future taxes, levies, imposts, deductions,
charges or withholdings, and all liabilities with respect thereto, excluding,
in the case of each Participating Bank and the Issuing Bank, taxes imposed on
its overall net income, and franchise taxes imposed on it, by the
jurisdiction under the laws of which such Participating Bank or the Issuing
Bank (as the case may be) is organized or any political subdivision thereof
and, in the case of each Participating Bank, taxes imposed on its overall net
income, and franchise taxes imposed on it, by the jurisdiction of such
Participating Bank's Applicable Lending Office or any political subdivision
thereof (all such non-excluded taxes, levies, imposts, deductions, charges,
withholdings and liabilities being hereinafter referred to as "Taxes"). If
the Account Party shall be required by law to deduct any Taxes from or in
respect of any sum payable hereunder to any Participating Bank or the Issuing
Bank, (i) the sum payable shall be increased as may be necessary so that
after making all required deductions (including deductions applicable to
additional sums payable under this Section 4.05) such Participating Bank or
the Issuing Bank (as the case may be) receives an amount equal to the sum it
would have received had no such deductions been made, (ii) the Account Party
shall make such deductions and (iii) the Account Party shall pay the full
amount deducted to the relevant taxation authority or other authority in
accordance with applicable law.
(b) In addition, the Account Party agrees to pay any present or future stamp
or documentary taxes or any other excise or property taxes, charges or
similar levies that arise from any payment made hereunder or from the
execution, delivery or registration of, or otherwise with respect to, this
Agreement (hereinafter referred to as "Other Taxes").
(c) The Account Party will indemnify each Participating Bank and the Issuing
Bank for the full amount of Taxes and Other Taxes (including, without
limitation, any Taxes and any Other Taxes imposed by any jurisdiction on
amounts payable under this Section 4.05) paid by such Participating Bank or
the Issuing Bank (as the case may be) and any liability (including penalties,
interest and expenses) arising therefrom or with respect thereto, whether or
not such Taxes or Other Taxes were correctly or legally asserted. This
indemnification shall be made within 30 days from the date such Participating
Bank or the Issuing Bank (as the case may be) makes written demand therefor.
If any Taxes or Other Taxes for which a Participating Bank or the Issuing
Bank has received payments from the Account Party hereunder shall be finally
determined to have been incorrectly or illegally asserted and are refunded to
such Participating Bank, such Participating Bank shall promptly forward to
the Account Party any such refunded amount. The Account Party's, the Issuing
Bank's and each Participating Bank's obligations under this Section 4.05
shall survive the payment in full of the Advances.
(d) Within 30 days after the date of any payment of Taxes, the Account Party
will furnish to the Issuing Bank, at its address referred to in Section 10.02
hereof the original or a certified copy of a receipt evidencing payment
thereof.
(e) Each Participating Bank not incorporated in the United States or a
jurisdiction within the United States shall, on or prior to the date it
becomes a Participating Bank hereunder, deliver to the Account Party and the
Issuing Bank such certificates, documents or other evidence, as required by
the Internal Revenue Code of 1986, as amended from time to time (the "Code"),
or treasury regulations issued pursuant thereto, including Internal Revenue
Service Form 4224 and any other certificate or statement of exemption
required by Treasury Regulation Section l.1441-1(a) or Section 1.1441-6(c) or
any subsequent version thereof, properly completed and duly executed by such
Participating Bank establishing that it is (i) not subject to withholding
under the Code or (ii) totally exempt from United States of America tax under
a provision of an applicable tax treaty. Each Participating Bank shall
promptly notify the Account Party and the Issuing Bank of any change in its
Applicable Lending Office and shall deliver to the Account Party and the
Issuing Bank together with such notice such certificates, documents or other
evidence referred to in the immediately preceding sentence. Unless the
Account Party and the Issuing Bank have received forms or other documents
satisfactory to them indicating that payments hereunder are not subject to
United States of America withholding tax or are subject to such tax at a rate
reduced by an applicable tax treaty, the Account Party or the Issuing Bank
shall withhold taxes from such payments at the applicable statutory rate in
the case of payments to or for any Participating Bank organized under the
laws of a jurisdiction outside the United States of America. Each
Participating Bank represents and warrants that each such form supplied by it
to the Issuing Bank and the Account Party pursuant to this Section 4.05, and
not superseded by another form supplied by it is or will be, as the case may
be, complete and accurate.
(f) Any Participating Bank claiming any additional amounts payable pursuant
to this Section 4.05 shall use reasonable efforts (consistent with legal and
regulatory restrictions) to file any certificate or document requested by the
Account Party or to change the jurisdiction of its Applicable Lending Office
if the making of such a filing or change would avoid the need for or reduce
the amount of any such additional amounts which may thereafter accrue and
would not, in the sole determination of such Participating Bank, be otherwise
disadvantageous to such Participating Bank.
(g) Notwithstanding anything to the contrary set forth in this Section 4.05,
the failure of any Participating Bank to provide any of the forms referred to
therein shall not relieve the Account Party from its obligations under
Sections 4.05(a), 4.05(b) and 4.05(c).
SECTION IV.6. Obligations Absolute. The obligations of the Account Party
under this Agreement shall be unconditional and irrevocable, and shall be
paid strictly in accordance with the terms of this Agreement (as the same may
be amended from time to time) under all circumstances, including, without
limitation, the following circumstances:
(i) any lack of validity or enforceability of this Agreement or any of the
Security Documents or Related Documents or any document or agreement
delivered in connection therewith;
(ii) any change in the time, manner or place of payment of, or in any other
term of, all or any of the obligations of the Account Party in respect of the
Letter of Credit or any other amendment or waiver of or any consent to
departure from all or any of the Loan Documents or the Related Documents or
any document or agreement delivered in connection therewith;
(iii) the existence of any claim, set-off, defense or other right which
the Account Party may have at any time against the Paying Agent, the Trustee
or any other beneficiary, or any transferee, of the Letter of Credit (or any
persons or entities for whom the Paying Agent, the Trustee, any such
beneficiary or any such transferee may be acting), the Agent, the Issuing
Bank, or any other person or entity, whether in connection with this
Agreement, the transactions contemplated in any of the Loan Documents or the
Related Documents, or any unrelated transaction;
(iv) any statement or any other document presented under the Letter of Credit
proving to be forged, fraudulent, invalid or insufficient in any respect or
any statement therein being untrue or inaccurate in any respect except to the
extent that a court of competent jurisdiction shall determine that the
Issuing Bank shall have engaged in gross negligence or willful misconduct
with respect thereto;
(v) payment by the Issuing Bank under the Letter of Credit against
presentation of a draft or certificate which does not comply with the terms
of the Letter of Credit, except to the extent that a court of competent
jurisdiction shall determine that the Issuing Bank shall have engaged in
gross negligence or willful misconduct with respect thereto;
(vi) any exchange of, release of or non-perfection of any interest in any
collateral, or any release or amendment or waiver of or consent to departure
from any guarantee, for all or any of the obligations of the Account Party in
respect of the Letter of Credit; or
(vii) any other circumstance or happening whatsoever, whether or not
similar to any of the foregoing.
SECTION IV.7. Evidence of Indebtedness. The Issuing Bank and each
Participating Bank shall maintain, in accordance with their usual practice,
an account or accounts evidencing the indebtedness of the Account Party
resulting from each drawing under the Letter of Credit (in the case of the
Issuing Bank) and from each Advance (in the case of each Participating Bank)
made from time to time hereunder and the amounts of principal and interest
payable and paid from time to time hereunder. In any legal action or
proceeding in respect of this Agreement, the entries made in such account or
accounts shall, in the absence of manifest error, be conclusive evidence of
the existence and amounts of the obligations of the Account Party therein
recorded.
ARTICLE V
CONDITIONS PRECEDENT
SECTION V.1. Conditions Precedent to the Issuance of the Letter of Credit.
The obligation of the Issuing Bank to issue the Letter of Credit and of each
Participating Bank to make the Advances to be made by it is subject to the
fulfillment of the conditions precedent that the Agent shall have received on
or before the day of such issuance the following, each dated such day (except
where specified otherwise below), in form and substance satisfactory to each
Participating Bank (except where specified otherwise below) and in sufficient
copies for each Participating Bank:
(a) Agreements:
(i) Counterparts of this Agreement, duly executed and delivered by the
Account Party, the Agent, the Issuing Bank and each Participating Bank.
(ii) Counterparts of the Pledge Amendment, duly executed by the Account
Party, Barclays, the Agent and the Issuing Bank, and copies of the Pledge
Agreement.
(iii) For each Participating Bank who shall so request, executed copies
(or duplicate copies thereof certified as of the Closing Date by the Account
Party in a manner satisfactory to the Agent to be a true copy) of each other
Security Document, duly executed by the parties thereto.
(iv) For each Participating Bank who shall so request, executed copies (or
duplicate copies thereof certified as of the Closing Date by the Account
Party in a manner satisfactory to the Agent to be a true copy) of the Rate
Agreement and each Significant Contract and all amendments, modifications and
supplements thereto, in each such case duly executed by the respective
parties thereto.
(b) Corporate Matters:
(i) A certificate of the Secretary or an Assistant Secretary of the Account
Party certifying that (A) there has been delivered to the Agent, and to each
other Participating Bank known to such officers to have so requested, true
and correct copies of the Articles of Incorporation of the Account Party and
the By-laws of the Account Party, in each case as in effect on the Closing
Date and (B) attached to such certificate are true and correct copies of the
resolutions of the Boards of Directors of the Account Party approving, if and
to the extent necessary, this Agreement, the other Loan Documents, the
Related Documents to which it is a party and the other documents to be
delivered by or on behalf of the Account Party hereunder and thereunder, and
of all documents evidencing other necessary corporate action, if any, with
respect to the execution, delivery and performance by or on behalf of the
Account Party of this Agreement, the other Loan Documents and such Related
Documents and certifying that such resolutions and other corporate actions,
if any, are in full force and effect and have not been revoked, rescinded or
modified.
(ii) A certificate of the Secretary or an Assistant Secretary of the Account
Party certifying the names and true signatures of the officers of the Account
Party authorized to sign this Agreement, the other Loan Documents and the
other documents to be delivered hereunder and thereunder.
(c) Governmental Approvals, Litigation and the Merger:
(i) A certificate of a duly authorized officer of the Account Party
certifying that attached thereto are true and correct copies of all
Governmental Approvals referred to in clause (i) of the definition of
"Governmental Approval" required to be obtained or made by the Account Party
in connection with the execution and delivery of this Agreement and the
issuance of the Letter of Credit.
(ii) A certificate signed by the Assistant General Counsel of NUSCO
certifying that no court has granted a motion for stay or any request for
similar relief in connection with the Plan, the Merger, the Loan Documents,
the Related Documents or the transactions contemplated thereunder.
(iii) A certificate of a duly authorized officer of the Account Party to
the effect that there is no pending or known threatened action or proceeding
(including, without limitation, any action or proceeding relating to any
environmental protection laws or regulations) affecting the Account Party or
its properties before any court, governmental agency or arbitrator (A) which
affects or purports to affect the legality, validity or enforceability of the
Loan Documents or the Related Documents or any of them or (B) as to which
there is a reasonable possibility of an adverse determination and which, if
adversely determined, would materially adversely affect the financial
condition, properties, prospects or operations of the Account Party; except,
for purposes of clause (B) only, such as is described in the Account Party's
Annual Report on Form 10-K for the fiscal year ended December 31, 1994 or in
Schedule II hereto.
(iv) Certificates signed by duly authorized officers of the Account Party and
NU to the effect that all conditions to the occurrence of the Merger were
satisfied or waived and the Merger was consummated on June 5, 1992.
(d) Financial Accounting and Compliance Matters:
(i) An audited balance sheet of the Account Party as at December 31, 1994
and the related statements of the Account Party's results of operations,
retained earnings and cash flows for and as of the year then ended, together
with copies of all Current Reports, if any, filed by the Account Party with
the Securities and Exchange Commission on or after December 31, 1994.
(ii) A certificate signed by the Treasurer or Assistant Treasurer of the
Account Party, certifying as to the absence of any material adverse change in
the financial condition, operations, properties or prospects of the Account
Party since December 31, 1994.
(iii) Financial projections, on assumptions acceptable to the
Participating Banks, demonstrating projected compliance with Section 7.01(i)
of the Existing Agreement and the terms of this Agreement and the Financing
Agreements.
(iv) A certificate signed by the Chief Financial Officer, Treasurer or
Assistant Treasurer of NU, certifying as to the absence of any material
adverse change in the financial condition, operations, properties or
prospects of NU since December 31, 1994.
(v) A certificate of a duly authorized officer of the Account Party to the
effect that:
(A) the representations and warranties contained in Section 6.01 are correct
in all material respects on and as of the Closing Date before and after
giving effect to the issuance of the Letter of Credit;
(B) no event has occurred and is continuing which constitutes an Event of
Default or Unmatured Default, or would result from the issuance of the Letter
of Credit;
(C) the Financing Agreements are in full force and effect and no "Event of
Default" or "Unmatured Default" (as defined therein) has occurred and is
continuing; and
(D) the Series F First Mortgage Bonds were duly issued to the Trustee in
accordance with the Indenture, are presently outstanding, and no "Event of
Default" (as defined in the First Mortgage Indenture) has occurred and is
continuing.
(e) Relating to the Issuance of the Bonds:
(i) A letter from Palmer & Dodge, Bond Counsel, addressed to the Agent, the
Issuing Bank and the Participating Banks and stating therein that the Agent,
the Issuing Bank and the Participating Banks may rely on the opinions of such
firm rendered in connection with the respective issuances of the Taxable
Bonds and the Existing Tax-Exempt Refunding Bonds, together with copies of
all such opinions.
(ii) A letter from Palmer & Dodge, counsel to the Issuer, addressed to the
Agent, the Issuing Bank and the Participating Banks and stating therein that
the Agent, the Issuing Bank and the Participating Banks may rely on the
opinions of such firm rendered in connection with the respective issuances of
the Taxable Bonds and the Existing Tax-Exempt Refunding Bonds, together with
copies of all such opinions.
(iii) A letter from Sulloway & Hollis, New Hampshire counsel to the
Account Party, addressed to the Agent, the Issuing Bank and the Participating
Banks and stating therein that the Agent, the Issuing Bank and the
Participating Banks may rely on the opinion of such firm rendered in
connection with the issuance of the Taxable Bonds, together with a copy of
such opinion.
(iv) A letter from Day, Berry & Howard, counsel to the Account Party,
addressed to the Agent, the Issuing Bank and the Participating Banks and
stating therein that the Agent, the Issuing Bank and the Participating Banks
may rely on the opinions of such firm rendered in connection with the
respective issuances of the Taxable Bonds and the Existing Tax-Exempt
Refunding Bonds, together with copies of all such opinions.
(v) Copies of the opinions of Drummond Woodsum & MacMahon, special Maine
counsel to the Account Party, rendered in connection with the respective
issuances of the Taxable Bonds and the Existing Tax-Exempt Refunding Bonds,
authorizing reliance thereon by (A) Day, Berry & Howard in connection with
the corresponding opinions of that firm referred to in clause (iv), above,
and (B) by any party authorized to rely on such opinions of Day, Berry &
Howard.
(vi) Copies of the opinions of Zuccaro, Willis & Bent special Vermont counsel
to the Account Party, rendered in connection with the respective issuances of
the Taxable Bonds and the Existing Tax-Exempt Refunding Bonds, authorizing
reliance thereon by (A) Day, Berry & Howard in connection with the
corresponding opinions of that firm referred to in clause (iv), above, and
(B) by any party authorized to rely on such opinions of Day, Berry & Howard.
(vii) Copies of all such other agreements, documents and materials
(including opinions of counsel or reliance letters in respect thereof) as the
Agent, the Issuing Bank or any Participating Bank may reasonably request
relating to the issuance, offering and sale of the Taxable Bonds, the
Existing Tax-Exempt Refunding Bonds and the Series F First Mortgage Bonds.
(f) Opinions of Counsel:
Favorable opinions of:
(i) Day, Berry & Howard, counsel to the Account Party, in substantially the
form of Exhibit 5.01A and as to such other matters as the Majority Lenders,
through the Agent, may reasonably request;
(ii) Rath, Young and Pignatelli, P.A., special New Hampshire counsel to the
Account Party, in substantially the form of Exhibit 5.01B and as to such
other matters as the Majority Lenders, through the Agent, may reasonably
request;
(iii) Jeffrey C. Miller, Assistant General Counsel of NUSCO, in
substantially the form of Exhibit 5.01C and as to such other matters as the
Majority Lenders, through the Agent, may reasonably request;
(iv) Drummond Woodsum & MacMahon, special Maine counsel to the Account Party,
in substantially the form of Exhibit 5.01D and as to such other matters as
the Majority Lenders, through the Agent, may reasonably request;
(v) Zuccaro Willis & Bent, special Vermont counsel to the Account Party, in
substantially the form of Exhibit 5.01E and as to such other matters as the
Majority Lenders, through the Agent, may reasonably request; and
(vi) King & Spalding, special New York counsel to the Agent and the Issuing
Bank, in substantially the form of Exhibit 5.01F.
(g) Miscellaneous:
(i) A certificate of Barclays, as agent thereunder, to the effect that (A)
all amounts payable in connection with the Existing Reimbursement Agreement
and the letter of credit issued thereunder have been paid to it and (B) it
thereby surrenders any and all rights it may have under the Related Documents
arising in connection with the Existing Reimbursement Agreement and the
letter of credit issued thereunder, except for any such rights it may have as
an indemnified party thereunder.
(ii) Letters from S&P and Moody's to the effect that the Taxable Bonds have
been rated A-1+ and P-1, respectively, and the Tax-Exempt Refunding Bonds
have been rated A-1+ and VMIG-1, respectively, and that the issuance of the
Letter of Credit in substitution for the Existing Letter of Credit will not,
by itself, result in a lowering of such ratings, such letters to be in form
and substance satisfactory to the Issuing Bank.
(iii) Such other approvals, opinions and documents as the Majority
Lenders, through the Issuing Bank, may reasonably request as to the legality,
validity, binding effect or enforceability of the Loan Documents or the
financial condition, properties, operations or prospects of the Account
Party.
SECTION V.2. Additional Conditions Precedent to the Issuance of the Letter
of Credit. The obligation of the Issuing Bank to issue the Letter of Credit
and of each Participating Bank to make the Advances to be made by it shall be
subject to the further conditions precedent that, on the date of the issuance
of the Letter of Credit:
(a) the representations and warranties contained in Section 6.01 shall be
correct in all material respects on and as of the Closing Date before and
after giving effect to the issuance of the Letter of Credit;
(b) no event shall have occurred and be continuing which constitutes an
Event of Default or Unmatured Default, or would result from the issuance of
the Letter of Credit;
(c) no "Event of Default" (as defined in the First Mortgage Indenture) shall
have occurred and be continuing;
(d) the Series F First Mortgage Bonds shall have been duly issued to the
Trustee in accordance with the Indenture, and be outstanding, and no "Event
of Default" (as defined in the First Mortgage Indenture) shall have occurred
and be continuing; and
(e) The Account Party shall have paid all fees under or referenced in
Section 2.03 hereof, to the extent then due and payable.
SECTION V.3. Conditions Precedent to Initial Advances and Conversions of
Advances. The obligation of each Participating Bank to make any Initial
Advance or to Convert any Term Advance shall be subject to the conditions
precedent that, on the date of such Initial Advance or Conversion, the
following statements shall be true:
(a) the representations and warranties contained in Section 6.01 of this
Agreement (other than the last sentence of subsection (e) and clause (ii) of
subsection (f) thereof) are true and correct on and as of the date of such
Initial Advance or Conversion, before and after giving effect to such Initial
Advance or Conversion and to the application of the proceeds (if any)
therefrom, as though made on and as of such date; and
(b) no event has occurred and is continuing which constitutes an Event of
Default.
Unless the Account Party shall have previously advised the Agent in writing
that one or more of the statements contained in subsections (a) and (b) of
this Section 5.03 is no longer true, the Account Party shall be deemed to
have represented and warranted, on and as of the date of any Initial Advance
or Conversion, that the above statements are true.
SECTION V.4. Conditions Precedent to Term Advances. The obligation of each
Participating Bank to make any Term Advance shall be subject to the
conditions precedent that, on the date of such Term Advance the following
statements shall be true:
(a) the representations and warranties contained in Section 6.01 of this
Agreement (including the last sentence of subsection (e) and clause (ii) of
subsection (f) thereof) are true and correct on and as of the date of such
Term Advance, before and after giving effect to such Term Advance and to the
application of the proceeds therefrom, as though made on and as of such date;
and
(b) no event has occurred and is continuing which constitutes an Event of
Default or an Unmatured Default.
Unless the Account Party shall have previously advised the Agent in writing
that one or more of the statements contained in subsections (a) and (b) of
this Section 5.04 is no longer true, the Account Party shall be deemed to
have represented and warranted, on and as of the date of any Term Advance,
that the above statements are true.
SECTION V.5. Reliance on Certificates. The Agent, the Issuing Bank and the
Participating Banks shall be entitled to rely conclusively upon the
certificates delivered from time to time by officers of the Account Party,
NU, NUSCO and the other parties to the Loan Documents, Related Documents and
the Significant Contracts as to the names, incumbency, authority and
signatures of the respective persons named therein until such time as the
Agent may receive a replacement certificate, in form acceptable to the Agent,
from an officer of such Person identified to the Agent as having authority to
deliver such certificate, setting forth the names and true signatures of the
officers and other representatives of such Person thereafter authorized to
act on behalf of such Person.
ARTICLE VI
REPRESENTATIONS AND WARRANTIES
SECTION VI.1. Representations and Warranties of the Account Party. The
Account Party represents and warrants as follows:
(a) The Account Party is a corporation duly organized and validly existing
under the laws of the State of New Hampshire. The Account Party is duly
qualified to do business in, and is in good standing in, all other
jurisdictions where the nature of its business or the nature of property
owned or used by it makes such qualifications necessary.
(b) The execution, delivery and performance by the Account Party of the Rate
Agreement and of each Transaction Document, Loan Document, Related Document
and Significant Contract to which it is a party, are within the Account
Party's corporate powers, have been duly authorized by all necessary
corporate action, and do not and will not contravene (i) the Account Party's
charter or bylaws or (ii) any law or legal or contractual restriction binding
on or affecting the Account Party; and such execution, delivery and
performance do not or will not result in or require the creation of any Lien
(other than pursuant hereto or pursuant to the Security Documents) upon or
with respect to any of its properties.
(c) All Governmental Approvals referred to in clauses (i) and (ii) of the
definition of "Governmental Approvals" have been duly obtained or made, and
all applicable periods of time for review, rehearing or appeal with respect
thereto have expired, except as described in the several opinions of counsel
delivered pursuant to Article III of the Amendment. The Account Party has
obtained or made all Governmental Approvals referred to in clause (iii) of
the definition of "Governmental Approvals", except those which are not yet
required but which are obtainable in the ordinary course of business as and
when required and those the absence of which would not materially adversely
affect the financial condition, properties, prospects or operations of the
Account Party as a whole.
(d) This Agreement, the Rate Agreement, each other Transaction Document,
Loan Document, Related Document and each Significant Contract to which the
Account Party is a party have been duly executed and delivered by or on
behalf of the Account Party and are legal, valid and binding obligations of
the Account Party enforceable against the Account Party in accordance with
their respective terms; subject to the qualifications, however, that the
enforcement of the rights and remedies herein and therein is subject to
bankruptcy and other similar laws of general application affecting rights and
remedies of creditors and the application of general principles of equity
(regardless of whether considered in a proceeding in equity or law), that the
remedy of specific performance or of injunctive relief is subject to the
discretion of the court before which any proceedings therefor may be brought
and that indemnification against violations of securities and similar laws
may be subject to matters of public policy.
(e) The audited balance sheet of the Account Party as at December 31, 1997
and the related statements of the Account Party setting forth the results of
operations, retained earnings and cash flows of the Account Party for the
fiscal year then ended, copies of which have been furnished to each
Participating Bank, fairly present in all material respects the financial
condition, results of operations, retained earnings and cash flows of the
Account Party at and for the year ended on such date, and have been prepared
in accordance with generally accepted accounting principles consistently
applied. Except as reflected in such financial statements, the Account Party
has no material non-contingent liabilities, and all contingent liabilities
have been appropriately reserved. The financial projections referred to in
Section 3.02(d)(ii) of the Amendment have been prepared in good faith and on
reasonable assumptions. Since December 31, 1997, there has been no material
adverse change in the financial condition, operations, properties or
prospects of the Account Party, other than as disclosed in the Disclosure
Documents; provided, however, that the existence of the Rate Proceeding shall
not be deemed in and of itself to be a material adverse change; provided,
further, however, that notwithstanding the foregoing, a material adverse
change shall be deemed to have occurred and be continuing upon the occurrence
of a material adverse change or development in the Rate Proceeding.
(f) Except as set forth in the Disclosure Documents, there is no pending or
known threatened action or proceeding (including, without limitation, any
action or proceeding relating to any environmental protection laws or
regulations) affecting the Account Party or its properties before any court,
governmental agency or arbitrator (i) which affects or purports to affect the
legality, validity or enforceability of the Transaction Documents, the Loan
Documents or the Related Documents, the Rate Agreement, or any Significant
Contract, or any of them or (ii) which, if adversely determined, would
materially adversely affect the financial condition, operations, properties
or prospects of the Account Party as a whole. Notwithstanding the foregoing,
any material adverse development in respect of the Rate Proceeding, the Rate
Agreement or the Final Plan that results, or would reasonably be expected to
result, in a material adverse effect on the financial condition, operations,
properties or prospects of the Account Party as a whole, shall be deemed to
be an event within clause (ii) of the preceding sentence.
(g) All insurance required by Section 7.01(c) hereof is in full force and
effect.
(h) No ERISA Plan Termination Event has occurred nor is reasonably expected
to occur with respect to any ERISA Plan which would materially adversely
affect the financial condition, properties, prospects or operations of the
Account Party, except as disclosed to and consented by the Majority Lenders
in writing. Since the date of the most recent Schedule B (Actuarial
Information) to the annual report of the Account Party (Form 5500 Series), if
any, there has been no material adverse change in the funding status of the
ERISA Plans referred to therein and no "prohibited transaction" has occurred
with respect thereto, except as described in the 1997 10-K and except as the
same may be exempt pursuant to Section 408 of ERISA and regulations and
orders thereunder. Neither the Account Party nor any of its ERISA Affiliates
has incurred nor reasonably expects to incur any material withdrawal
liability under ERISA to any ERISA Multiemployer Plan, except as disclosed to
and consented by the Majority Lenders in writing.
(i) The Major Electric Generating Plants are on land in which the Account
Party owns a full or an undivided fee interest subject only to Liens
permitted by Section 7.02(a) hereof, which do not materially impair the
usefulness to the Account Party of such properties; the electric transmission
and distribution lines of the Account Party in the main are located in New
Hampshire and on land owned in fee by the Account Party or over which the
Account Party has easements, or are in or over public highways or public
waters pursuant to adequate statutory or regulatory authority, and any
defects in the title to such transmission and distribution lands or easements
are in the main curable by the exercise of the Account Party's right of
eminent domain upon a finding that such eminent domain proceedings are
necessary to meet the reasonable requirements of service to the public; the
Account Party enjoys peaceful and undisturbed possession under all of the
leases under which it is operating, none of which contains any unusual or
burdensome provision which will materially affect or impair the operation of
the Account Party; and the Security Documents will create valid Liens in the
Collateral, subject only to Liens permitted by Section 7.02(a) hereof, and
all filings and other actions necessary to perfect and protect such security
interests (to the extent such security interests may be perfected or
protected by filing) have been taken; provided, however, that no
representation is made as to any Lien purported to be created in favor of the
Trustee with respect to any interest of the Issuer in the Indenture.
(j) No material part of the properties, business or operations of the
Account Party are materially adversely affected by any fire, explosion,
accident, strike, lockout or other labor disputes, drought, storm, hail,
earthquake, embargo, act of God or of the public enemy or other casualty
(except for any such circumstance, if any, which is covered by insurance
which coverage has been confirmed and not disputed by the relevant insurer or
by fully-funded self-insurance programs).
(k) The Account Party has filed all tax returns (Federal, state and local)
required to be filed and paid taxes shown thereon to be due, including
interest and penalties, or, to the extent the Account Party is contesting in
good faith an assertion of liability based on such returns, has provided
adequate reserves in accordance with generally accepted accounting principles
for payment thereof.
(l) No exhibit, schedule, report or other written information provided by
the Account Party or its agents to the Agent, the Issuing Bank or the
Participating Banks in connection with the negotiation, execution and closing
of this Agreement and the other Transaction Documents, or the issuance of the
Bonds (including, without limitation, the Information Memorandum and the
Official Statements) knowingly contained when made any material misstatement
of fact or knowingly omitted to state any material fact necessary to make the
statements contained therein not misleading in light of the circumstances
under which they were made.
(m) No event has occurred and is continuing which constitutes a material
default under the Rate Agreement or any Significant Contract.
(n) The Account Party has not, either directly or indirectly, made any
investment in, or loans to, any Affiliate of the Account Party, other than
such investments or loans as were outstanding on the date hereof.
(o) No proceeds of any Advance will be used (i) to acquire any equity
security of a class which is registered pursuant to Section 12 of the
Securities Exchange Act of 1934 or (ii) to buy or carry any margin stock
(within the meaning of Regulation U issued by the Board of Governors of the
Federal Reserve System) or to extend credit to others for such purpose. The
Account Party (X) is not an "investment company" within the meaning ascribed
to that term in the Investment Company Act of 1940 or (Y) is not engaged in
the business of extending credit for the purpose of buying or carrying margin
stock.
ARTICLE VII
COVENANTS OF THE ACCOUNT PARTY
SECTION VII.1. Affirmative Covenants. So long as any amounts shall remain
available to be drawn under the Letter of Credit or any Advance or other
amounts shall remain unpaid hereunder or any Participating Bank shall have
any Commitment, the Account Party will, unless the Majority Lenders shall
otherwise consent in writing:
(a) Use of Proceeds. Apply all proceeds of each Advance solely as specified
in Section 3.02 and Section 6.01(o) hereof.
(b) Payment of Taxes, Etc. Pay and discharge before the same shall become
delinquent all taxes, assessments and governmental charges, royalties or
levies imposed upon it or upon its property except to the extent the Account
Party is contesting the same in good faith by appropriate proceedings and has
set aside adequate reserves for the payment thereof.
(c) Maintenance of Insurance. Maintain, or cause to be maintained, insurance
(including appropriate plans of seif-insurance) covering the Account Party
and its properties in effect at all times in such amounts and covering such
risks as may be required by law and in addition as is usually carried by
companies engaged in similar businesses and owning similar properties.
(d) Preservation of Existence, Etc. Preserve and maintain its corporate
existence, material rights (statutory and otherwise) and franchises except as
otherwise expressly provided for in the Security Documents.
(e) Compliance with Laws, Etc. Comply in all material respects with the
requirements of all applicable laws, rules, regulations and orders of any
governmental authority, including without limitation any such laws, rules,
regulations and orders relating to utilities, zoning, environmental
protection, use and disposal of Hazardous Substances, land use, construction
and building restrictions, and employee safety and health matters relating to
business operations, except to the extent (i) that the Account Party is
contesting the same in good faith by appropriate proceedings or (ii) that any
such non-compliance, and the enforcement or correction thereof, would not
materially adversely affect the financial condition, properties, prospects or
operations of the Account Party as a whole.
(f) Inspection Rights. At any time and from time to time upon reasonable
notice, permit the Agent and its agents and representatives to examine and
make copies of and abstracts from the records and books of account of, and
the properties of, the Account Party and to discuss the affairs, finances and
accounts of the Account Party with the Account Party and of its officers,
directors and accountants.
(g) Keeping of Books. Keep proper records and books of account, in which
full and correct entries shall be made of all financial transactions of the
Account Party and the assets and business of the Account Party, in accordance
with good accounting practices consistently applied.
(h) Performance of Related Agreements. Perform and observe all material
terms and provisions of the Revolving Credit Agreement, the Rate Agreement
and each Significant Contract to be performed or observed by the Account
Party and take all reasonable steps to enforce such agreements substantially
in accordance with their terms and to preserve the rights of the Account
Party thereunder; provided, that the foregoing provisions of this Section
7.01(h) shall not preclude the Account Party from any waiver, amendment,
modification, consent or termination (i) made in accordance with the
provisions of Section 7.04 hereof (in the case of the Revolving Credit
Agreement) or (ii) permitted under Section 7.02(g) hereof (in the case of the
Rate Agreement or any Significant Contract).
(i) Collection of Accounts Receivable. Promptly bill, and diligently pursue
collection of, in accordance with customary utility practices, all accounts
receivable owing to the Account Party and all other amounts that may from
time to time be owing to the Account Party for services rendered or goods
sold.
(j) Maintenance of Financial Covenants:
(i) Operating Income to Interest Expense. Maintain a ratio of Operating
Income to Interest Expense of not less than 2.35 to 1.00 for each period of
four consecutive fiscal quarters on each quarter-end ending after December
31, 1997.
(ii) Common Equity to Total Capitalization Ratio. Maintain at all times
a ratio of Common Equity to Total Capitalization of not less than 0.325 to
1.00.
(k) Maintenance of Properties, Etc. (i) As to properties of the type
described in Section 6.01(i) hereof, maintain title of the quality described
therein; and (ii) preserve, maintain, develop, and operate in substantial
conformity with all laws, material contractual obligations and prudent
practices prevailing in the industry, all of its properties which are used or
useful in the conduct of its business in good working order and condition,
ordinary wear and tear excepted, except to the extent such non-conformity
would not materially adversely affect the financial condition, properties,
prospects or operations of the Account Party as a whole.
(l) Governmental Approvals. Duly obtain on or prior to such date as the
same may become legally required, and thereafter maintain in effect at all
times, all Governmental Approvals on its part to be obtained, except those
the absence of which would not materially adversely affect the financial
condition, properties, prospects or operations of the Account Party as a
whole.
(m) Further Assurances. Promptly execute and deliver all further
instruments and documents, and take all further action, that may be necessary
or that any Participating Bank through the Issuing Bank may reasonably
request in order to fully give effect to the interests and properties
purported to be covered by the Security Documents.
(n) Related Documents. Perform and comply in all material respects with each
of the provisions of each Related Document to which it is a party.
SECTION VII.2. Negative Covenants. So long as any amount shall remain
available to be drawn under the Letter of Credit or any Advance or other
amounts shall remain unpaid hereunder or any Participating Bank shall have
any Commitment, the Account Party will not without the written consent of the
Majority Lenders:
(a) Liens, Etc. Create, incur, assume or suffer to exist any lien, security
interest, or other charge or encumbrance (including the lien or retained
security title of a conditional vendor) of any kind, or any other type of
preferential arrangement the intent or effect of which is to assure a
creditor against loss or to prefer one creditor over another creditor upon or
with respect to any of its properties of any character (any of the foregoing
being referred to herein as a "Lien") whether now owned or hereafter
acquired, or sign or file under the Uniform Commercial Code of any
jurisdiction a financing statement which names the Account Party as debtor,
sign any security agreement authorizing any secured party thereunder to file
such financing statement, or assign accounts, excluding, however, from the
operation of the foregoing restrictions the following, whether now existing
or hereafter created or perfected:
(i) The Liens of the First Mortgage Indenture, the Security Agreement, the
Pledge Agreement, the "Pledge Agreement" referred to in the Other
Reimbursement Agreement, and any lien created pursuant hereto; and
(ii) Permitted Liens (as defined in the First Mortgage Indenture as in
effect on the date hereof) on the Indenture Assets; provided, however, that
(A) the exclusion contained in clause (a) of such definition with respect to
Liens junior to the Lien of the First Mortgage Indenture shall not apply to
any Lien created after the date hereof; (B) the exclusion contained in
clauses (g) and (h) of such definition shall apply only to the extent that
all Liens of the type described therein from time to time existing do not, in
the aggregate, materially and adversely affect the value of the security
granted under the First Mortgage Indenture and no such Lien secures Debt of
the Account Party for borrowed money; and (C) the Account Party shall not, on
or after the date hereof, create, incur or assume any purchase money Debt
secured by Liens of the type described in clause (o) of such definition;
provided, however, that this Section 7.02(a) shall not be construed to
authorize the Account Party to incur, assume, be liable for or suffer to
exist any Debt not otherwise permitted hereunder.
(b) Debt. From and after the Amendment Closing Date, create, incur or
assume any Debt, other than pursuant to this Agreement, the Other
Reimbursement Agreement, the Revolving Credit Agreement and unsecured debt in
an aggregate amount not to exceed $25,000,000, and then only if, after giving
effect thereto, (i) no Event of Default or Unmatured Default shall have
occurred and be continuing on the date of such creation, incurrence or
assumption and (ii) the Account Party shall have determined that on the basis
of the assumptions and forecasts set forth in the most recent operating
budget/forecast of operations delivered pursuant to Section 7.03(iv) hereof
(which the Account Party continues to believe to be reasonable), the Account
Party will continue to be in compliance at all times with the provisions of
Section 7.01(j) hereof. The Account Party will furnish evidence of its
compliance with this subsection (b) for each fiscal quarter pursuant to
Section 7.03(ii) hereof.
(c) Mergers, Etc. Merge with or into or consolidate with or into, or
acquire all or substantially all of the assets of, any Person.
(d) Sales, Etc., of Assets. Sell, lease, transfer or otherwise dispose of
all or any substantial part of its assets, whether in a single transaction or
series of transactions during any consecutive 12-month period, except for (i)
the sale of the Account Party's generating assets on an arms'-length basis in
a transaction (or series of transactions) subject to approval by the NHPUC as
part of a settlement of the Rate Proceeding and (ii) sales, leases, transfers
or other dispositions in the ordinary course of the Account Party's business
in accordance with ordinary and customary terms and conditions. For purposes
of this subsection (d), any transaction or series of transactions during any
consecutive 12-month period shall be deemed to involve a "substantial part"
of the Account Party's assets if, in the aggregate, (A) the book value of
such assets equals or exceeds 7.5% of the total assets, net of regulatory
assets, of the Account Party reflected in the financial statements of the
Account Party delivered pursuant to Section 7.03(ii) or 7.03(iii) hereof in
respect of the fiscal quarter or year ending on or immediately prior to the
commencement of such 12-month period or (B) for the four calendar quarters
ending on or immediately prior to commencement of such 12-month period, the
gross revenue derived by the Account Party from such assets shall equal or
exceed 7.5% of the total gross revenue of the Account Party.
(e) Restricted Payments and NUG Settlements. Declare or pay any dividend,
or make any payment or other distribution of assets, properties, cash,
rights, obligations or securities on account of any share of any class of
capital stock of the Account Party (other than stock splits and dividends
payable solely in equity securities of the Account Party), or purchase,
redeem, retire, or otherwise acquire for value any shares of any class of
capital stock of the Account Party or any warrants, rights, or options to
acquire any such Debt or shares, now or hereafter outstanding, or make any
distribution of assets to any of its shareholders (any such transaction being
a "Restricted Payment"), or make any payment of or on account of any NUG
Settlement (a "NUG Settlement Payment"); provided, that the Account Party may
make one or more Restricted Payments or NUG Settlement Payments after July 1,
1998 if:
(i) at the time such payment is made and after giving effect thereto, no
advances will be outstanding under the Revolving Credit Agreement;
(ii) the aggregate amount of all such payments shall not exceed
$40,000,000;
(iii) without limitation of the foregoing, the aggregate amount of all
Restricted Payments shall not exceed $25,000,000;
(iv) in the case of a NUG Settlement Payment, such NUG Settlement shall
have been approved by the NHPUC and all other Governmental Approvals related
thereto shall have been obtained and be in full force and effect;
(v) no Event of Default or Unmatured Default shall have occurred and be
continuing;
(vi) after giving effect to such payment, the Account Party shall be in full
compliance with Section 7.01(j) hereof (for purposes of determining
compliance with Section 7.01(j) under this clause (vi), computations under
Section 7.01(j) shall be made as of the date of such payment, except that,
retained earnings shall be determined as of the last day of the immediately
preceding fiscal quarter (adjusted for all Restricted Payments made after the
last day of such preceding fiscal quarter)); and
(vii) the Account Party shall have determined that, on the basis of the
assumptions and forecasts set forth in the most recent operating
budget/forecast of operations delivered pursuant to Section 7.03(iv) hereof
(which the Account Party continues to believe to be reasonable) and after
giving effect to such payment, the Account Party will continue to be in
compliance at all times with the provisions of Section 7.01(j) hereof.
Notwithstanding anything to the contrary contained in this Section 7.02(e),
the Account Party may declare and pay regularly scheduled quarterly dividends
and regularly scheduled sinking fund payments on the Preferred Stock, if,
immediately prior to and after giving effect to any such payment, no Event of
Default or Unmatured Default shall have occurred and be continuing.
(f) Compliance with ERISA. (i) terminate, or permit any ERISA Affiliate to
terminate, any ERISA Plan so as to result in any material (in the opinion of
the Majority Lenders) liability of the Account Party to the PBGC, or (ii)
permit to exist any occurrence of any event described in clause (i) of the
definition of ERISA Plan Termination Event, or any other event or condition,
which presents a material (in the opinion of the Majority Lenders) risk of
such a termination by the PBGC of any ERISA Plan and such a material
liability to the Account Party.
(g) Related Agreements.
(i) Amendments. Amend, modify or supplement or give any consent, acceptance
or approval to any amendment, modification or supplement or deviation by any
party from the terms of, the Rate Agreement or any Significant Contract,
except, with respect only to the Significant Contracts, any amendment,
modification or supplement thereto that would not reduce the rights or
entitlements of the Account Party thereunder in any material way.
(ii) Termination. Cancel or terminate (or consent to any cancellation or
termination of) the Rate Agreement or any Significant Contract prior to the
expiration of its stated term, provided that this subsection (ii) shall not
restrict the rights of the Account Party to enforce any remedy against any
obligor under any Significant Contract in the event of a material breach or
default by such obligor thereunder if and so long as the Account Party shall
have provided to the Agent at least 30 days prior written notice of the
enforcement action proposed to be undertaken by the Account Party.
(h) Change in Nature of Business. Engage in any material business activity
other than those established and engaged in on the date hereof.
(i) Ownership in Nuclear Plants. Acquire, directly or indirectly, any
ownership interest or any additional ownership interest of any kind in any
nuclear-powered electric generating plant.
(j) Subsidiaries. Create or suffer to exist any active subsidiaries other
than Properties, Inc., a New Hampshire corporation; or permit any material
assets or business to be maintained at or conducted by any subsidiary except
for the assets owned by Properties, Inc. not exceeding $20,000,000.
(k) Prepayment or Alteration of Debt. (i) Prepay, redeem, reduce or
voluntarily retire, or make or agree to make any change in the terms of, any
Debt of the Account Party, other than repayments and prepayments of advances
under, and modifications of, the Revolving Credit Agreement, in each case to
the extent permitted by Section 7.04; (ii) without limitation of the
foregoing, amend, modify or supplement the Indenture or the First Mortgage
Indenture or (iii) issue any First Mortgage Bonds as collateral security for
any existing or future debt, or grant any other security to any holder of
existing Debt of the Account Party, except to the extent permitted by Section
7.04.
(l) Loans and Investments. Make any loans to or investments in any Person,
other than investments in Permitted Investments.
(m) Affiliate Receivables. Permit the aggregate balance of accounts
receivable from Affiliates (other than such receivables constituting
receivables for wholesale sales of power) to equal or exceed $12,500,000 as
of the end of any calendar month.
SECTION VII.3. Reporting Obligations. So long as any amount shall remain
available to be drawn under the Letter of Credit or any Advance or other
amounts shall remain unpaid hereunder or any Participating Bank shall have
any Commitment, the Account Party will, unless the Majority Lenders shall
otherwise consent in writing, furnish to the Agent in sufficient copies for
the Issuing Bank and each Participating Bank, the following:
(i) as soon as possible and in any event within five (5) days after the
occurrence of each Event of Default or Unmatured Default continuing on the
date of such statement, a statement of the Chief Financial Officer, Treasurer
or Assistant Treasurer of the Account Party setting forth details of such
Event of Default or Unmatured Default and the action which the Account Party
proposes to take with respect thereto;
(ii) as soon as available and in any event within fifty (50) days after the
end of each of the first three quarters of each fiscal year of the Account
Party, (A) if and so long as the Account Party is required to submit to the
Securities and Exchange Commission a report on Form 10-Q, a copy of the
Account Party's report on Form 10-Q submitted to the Securities and Exchange
Commission with respect to such quarter and (B) if the Account Party ceases
to be required to submit such report, a balance sheet of the Account Party as
of the end of such quarter and statements of income and retained earnings and
of cash flows of the Account Party for the period commencing at the end of
the previous fiscal year and ending with the end of such quarter, all in
reasonable detail and duly certified (subject to year-end audit adjustments)
by the Chief Financial Officer, Treasurer or Assistant Treasurer of the
Account Party as having been prepared in accordance with generally accepted
accounting principles consistent with those applied in the preparation of the
financial statements referred to in Section 6.01(e) hereof, in each such
case, delivered together with a certificate of said officer (x) stating that
no Event of Default or Unmatured Default has occurred and is continuing or,
if an Event of Default or Unmatured Default has occurred and is continuing, a
statement as to the nature thereof and the action which the Account Party
proposes to take with respect thereto, (y) demonstrating compliance with
Section 7.01(j) hereof for and as of the end of such fiscal quarter and
compliance with Sections 7.02(b) and (e) hereof, as of the dates on which any
Debt was created, incurred or assumed (using the Account Party's most recent
annual actuarial determinations in the computation of Debt referred to in
clause (ix) in the definition of "Debt") or any Restricted Payment or NUG
Settlement Payment was made during such quarter, and (z) demonstrating, after
giving effect to the incurrence of any Debt created, incurred or assumed
during such fiscal quarter (using the Account Party's most recent annual
actuarial determinations in the computation of Debt referred to in clause
(ix) in the definition of "Debt") and after giving effect to any Restricted
Payments or NUG Settlement Payments made during such fiscal quarter,
compliance with Section 7.01(j) hereof for the remainder of the fiscal year
of the Account Party based on the operating budget/forecast of operations
delivered pursuant to Section 7.03 (iv) hereof for such fiscal year, such
demonstrations to be in a schedule (in form satisfactory to the Majority
Lenders) which sets forth the computations used by the Account Party in
determining such compliance;
(iii) as soon as available and in any event within 105 days after the end
of each fiscal year of the Account Party, (A) if and so long as the Account
Party is required to submit to the Securities and Exchange Commission a
report on Form 10-K, a copy of the Account Party's report on Form 10-K
submitted to the Securities and Exchange Commission with respect to such year
and (B) if the Account Party ceases to be required to submit such report, a
copy of the annual audit report for such year for the Account Party including
therein a balance sheet of the Account Party as of the end of such fiscal
year and statements of income and retained earnings and of cash flows of the
Account Party for such fiscal year, in each case certified by a nationally-
recognized independent public accountant, in each such case delivered
together with a certificate of the Chief Financial Officer, Treasurer or
Assistant Treasurer (x) stating that the financial statements were prepared
in accordance with generally accepted accounting principles consistent with
those applied in the preparation of financial statements referred to in
Section 6.01(e) hereof, and that no Event of Default or Unmatured Default has
occurred and is continuing, or if an Event of Default or Unmatured Default
has occurred and is continuing, stating the nature thereof and the action
which the Account Party proposes to take with respect thereto and (y)
demonstrating compliance with Section 7.01(j) hereof for and as of the end of
such fiscal year and compliance with Sections 7.02(b) and (e) hereof, as of
the dates on which any Debt was created, incurred or assumed (using the
Account Party's most recent annual actuarial determinations in the
computation of Debt referred to in clause (ix) in the definition of "Debt")
or any Restricted Payment or NUG Settlement Payment was made during the last
fiscal quarter of the Account Party, such demonstrations to be in a schedule
(in form satisfactory to the Majority Lenders) which sets forth the
computations used by the Account Party in determining such compliance.
(iv) as soon as available and in any event before March 31 of each fiscal
year, a copy of an operating budget/forecast of operations of the Account
Party as approved by the Board of Directors of the Account Party in form
satisfactory to the Participating Banks for such fiscal year of the Account
Party, together with a certificate of the Chief Financial Officer, Treasurer
or Assistant Treasurer of the Account Party stating that such budget/forecast
was prepared in good faith and on reasonable assumptions;
(v) not later than ten days following the end of each fiscal quarter of the
Account Party, a report on the progress of and developments in the Rate
Proceeding, the Final Plan and any negotiations concerning the foregoing;
(vi) as soon as available and in any event no later than the New Hampshire
Public Utilities Commission shall have received the Account Party's annual
submission, if any, relating to the "return on equity collar" referred to in
the Rate Agreement, a copy of such annual submission of the Account Party;
(vii) as soon as possible and in any event (A) within 30 days after the
Account Party knows or has reason to know that any ERISA Plan Termination
Event described in clause (i) of the definition of ERISA Plan Termination
Event with respect to any ERISA Plan or ERISA Multiemployer Plan has occurred
and (B) within 10 days after the Account Party knows or has reason to know
that any other ERISA Plan Termination Event with respect to any ERISA Plan or
ERISA Multiemployer Plan has occurred, a statement of the Chief Financial
Officer, Treasurer or Assistant Treasurer of the Account Party describing
such ERISA Plan Termination Event and the action, if any, which the Account
Party proposes to take with respect thereto;
(viii) promptly after receipt thereof by the Account Party or any of its
ERISA Affiliates from the PBGC, copies of each notice received by the Account
Party or any such ERISA Affiliate of the PBGC's intention to terminate any
ERISA Plan or ERISA Multiemployer Plan or to have a trustee appointed to
administer any ERISA Plan or ERISA Multiemployer Plan;
(ix) promptly and in any event within 30 days after the filing thereof with
the Internal Revenue Service, copies of each Schedule B (Actuarial
Information) to the annual report (Form 5500 Series) with respect to each
ERISA Plan (if any) to which the Account Party is a contributing employer;
(x) promptly after receipt thereof by the Account Party or any of its ERISA
Affiliates from an ERISA Multiemployer Plan sponsor, a copy of each notice
received by the Account Party or any of its ERISA Affiliates concerning the
imposition or amount of withdrawal liability in an aggregate principal amount
of at least $10,000,000 pursuant to Section 4202 of ERISA in respect of which
the Account Party may be liable;
(xi) promptly after the Account Party becomes aware of the occurrence
thereof, notice of all actions, suits, proceedings or other events (A) of the
type described in Section 6.01(f), or (B) which purport to affect the
legality, validity or enforceability of the Rate Agreement, or any
Transaction Document, Loan Document, Related Document or Significant
Contract;
(xii) promptly after the sending or filing thereof, copies of all such
proxy statements, financial statements, and reports which the Account Party
sends to its public security holders (if any) or files with, and copies of
all regular, periodic and special reports and all registration statements and
periodic or special reports, if any, which the Account Party files with, the
Securities and Exchange Commission or any governmental authority which may be
substituted therefor, or with any national securities exchange;
(xiii) promptly after receipt thereof, any assertion of the character
described in Section 8.01(h) hereof and the action the Account Party proposes
to take with respect thereto;
(xiv) promptly after knowledge of any material default under the Rate
Agreement or any Significant Contract, notice of such default and the action
the Account Party proposes to take with respect thereto;
(xv) promptly after knowledge of any amendment, modification, or other change
to the Rate Agreement or any Significant Contract or to any Governmental
Approval affecting the Rate Agreement, notice of such amendment, modification
or other change, it being understood that for purposes of this clause (xiv)
any filing by the Account Party in the ordinary course of the Account Party's
business with, or order issued or action taken by, a governmental authority
or regulatory body after May 16, 1991 to implement the terms of the Rate
Agreement shall not be considered an amendment, modification or change to a
Governmental Approval affecting the Rate Agreement; and
(xvi) promptly after requested, such other information respecting the
financial condition, operations, properties, prospects or otherwise, of the
Account Party as the Issuing Bank or Majority Lenders may from time to time
reasonably request in writing.
SECTION VII.4. Most Favored Lender Covenants. So long as any amount shall
remain available to be drawn under the Letter of Credit or any Advance or
other amounts shall remain unpaid hereunder or any Participating Bank shall
have any Commitment:
(a) The Account Party will not amend, modify or supplement, or consent to
any amendment, modification or supplement to, the Other Reimbursement
Agreement or the Revolving Credit Agreement (whether the same relates to
pricing, tenor, reduction, prepayment, covenants, other credit terms or
otherwise), unless the Account Party shall first have offered to amend,
modify or supplement the Loan Documents in a like manner, subject however, to
the provisions of subsection (b), to the extent applicable.
(b) If at any time the Account Party shall be unable to borrow under the
Revolving Credit Agreement (or any successor revolving facility) because the
Account Party is unable to satisfy any "material adverse change" or other
condition precedent to borrowing (a "Funding Suspension"), and (x) the
failure to satisfy such condition does not itself constitute an Event of
Default hereunder and (y) no Event of Default or Unmatured Default shall
have occurred and be continuing hereunder, the provisions of subsection (a)
shall be subject to the following:
(i) The Account Party will be free to negotiate with the lenders under the
Revolving Credit Agreement (or the lenders under such successor facility)
(the"Non-Funding Lenders") and may resolve or not resolve such Funding
Suspension in such manner as it may see fit, without any requirement that the
Agent, the Issuing Bank or the Participating Banks consent thereto;
(ii) Any improvement in pricing, covenants or other credit terms
afforded to the Non-Funding Lenders to resolve the Funding Suspension shall
be offered to the Agent, the Issuing Bank and the Participating Banks in the
manner prescribed by subsection (a). Any additional security granted to the
Non-Funding Lenders to resolve the Funding Suspension shall be afforded
equally and ratably to the Agent, the Issuing Bank and the Participating
Banks, subject to the provisions of Section 7.05; and
(iii) If in connection with the resolution of a Funding Suspension, the
Non-Funding Lenders' facility shall be permanently reduced such that any
amounts repaid or prepaid as part of such resolution are not available to be
re-borrowed, the Account Party will pay to the Agent, for the benefit of the
Issuing Bank and the Participating Banks an amount equal to such repayment or
prepayment, dollar-for-dollar, to be applied to the reduction of the
Available Amount or to be held as cash collateral for the obligations of the
Account Party under the Loan Documents. For the avoidance of doubt:
(A) a reduction in the unfunded portion of the Non-Funding Lenders'
commitments will not, by itself, entitle the Agent, the Issuing Bank and the
Participating Banks to any such payment or to any reduction in the Available
Amount; and
(B) the Agent, the Issuing Bank and the Participating Banks will not be
entitled to any payment or reduction in the Available Amount solely as a
result of repayments and prepayments of advances under such facility, if
such repayment or prepayment results in the Non-Funding Lenders' commitments
becoming again available to the Account Party in at least the amount of the
repayment or prepayment.
(c) The provisions of subsection (b) shall not apply during the continuance
of an Event of Default.
SECTION VII.5. Covenants Concerning Certain Collateral.
(a) Cash Account. Subject to the provisions of subsection (b), below, upon
the occurrence and during the continuance of any Event of Default, the Agent
shall at the request, or may with the consent, of the Majority Lenders,
direct the Account Party to, and if so directed, the Account Party shall,
deposit with the Agent an amount in the cash account (the "Cash Account")
described below equal to the Available Amount of the Letter of Credit. Such
Cash Account shall at all times be free and clear of all rights or claims of
third parties. The Cash Account shall be maintained with the Agent in the
name of, and under the sole dominion and control of, the Agent, and amounts
deposited in the Cash Account shall bear interest at a rate equal to the rate
generally offered by Barclays for deposits equal to the balance in the Cash
Account, for a term to be agreed to between the Account Party and the Agent.
If any Letter of Credit drawings then outstanding or thereafter made are not
reimbursed in full immediately after being made and upon demand, then, in any
such event, the Agent may apply the amounts then on deposit in the Cash
Account, in such priority as the Agent shall elect, toward the payment in
full of any or all of the Account Party's obligations hereunder as and when
such obligations shall become due and payable. Upon payment in full, after
the termination of the Letters of Credit, of all such obligations, the Agent
will repay to the Account Party any cash then on deposit in the Cash Account.
The Issuing Bank hereby confirms its obligation as set forth in the Letter of
Credit to make all payments under the Letter of Credit with its own funds and
not with any funds of the Account Party or the Issuer, and nothing in this
subsection (a) or otherwise shall in any way limit such obligation.
(b) Waiver and Surrender of Rights to Certain Collateral. Without in any
way modifying the payment provisions of Article III, and subject in all
respects to the provisions of subsection (c), below, the Agent, the Issuing
Bank and the Participating Banks hereby waive and surrender, effective upon
the commencement of any case by or against the Account Party seeking relief
in respect of the Account Party under the Bankruptcy Code, any and all right,
title and interest of the Agent, the Issuing Bank and the Participating Banks
in and to the Cash Account, the Collateral described in the Security
Agreement and all other collateral security, if any, granted to the Agent,
the Issuing Bank or the Participating Banks on or after April 23, 1998 (all
of the foregoing being hereinafter referred to as the "Extension Collateral",
which term shall exclude absolutely the Account Party's Series F First
Mortgage Bonds), and agree that upon any such commencement, the rights of
the Agent, the Issuing Bank and the Banks in and to the Extension Collateral
shall be null and void and the Agent, the Issuing Bank and the Banks shall
not thereafter seek or accept any benefits they may have in and to the
Extension Collateral; provided that the foregoing shall not apply to any
benefit to Agent, the Issuing Bank or any Participating Bank of any Extension
Collateral, if and only if: (i) a valid and perfected lien on or security
interest in such Extension Collateral was granted to one or more other
Secured Parties under the Intercreditor Agreement, (ii) such benefit to the
Agent, the Issuing Bank or any Participating Bank is no greater than such as
derives from its rights under the Intercreditor Agreement to share in the
benefits of all Collateral referred to therein on the terms and subject to
the conditions thereof, and (iii) after giving effect to such sharing, the
aggregate amount of secured claims against the bankruptcy estate of the
Account Party would not be increased.
(c) The waiver, surrender and agreement set forth in subsection (b), above,
shall terminate and be of no force and effect (i) if and to the extent that
such termination and the retention and enjoyment by the Agent, the Issuing
Bank and the Participating Banks of such right, title and interest would not
result in the grant of the Extension Collateral to the Agent, the Issuing
Bank and the Participating Banks being deemed to (X) constitute a transfer of
property of the Account Party avoidable under Section 547(b) of the
Bankruptcy Code or (Y) otherwise constitute a basis for the recovery of any
amounts realized with respect to the Collateral or the value thereof from the
Trustee or any holder of the Bonds as an avoidable transfer under Section
547(b) of the Bankruptcy Code and (ii) in any case, as to any item of
Extension Collateral, on the 91st day following the date on which a lien on
or security interest in such Extension Collateral in favor of the Agent, the
Issuing Bank or the Participating Banks was first perfected under applicable
law, so long as no such case has been commenced and is pending.
(d) Acknowledgment. The Agent, the Issuing Bank and the Participating
Banks, each by its execution and delivery of this Agreement, acknowledge and
agree to the provisions of this Section 7.05.
ARTICLE VIII
DEFAULTS
SECTION VIII.1. Events of Default. The following events shall each
constitute an "Event of Default" if the same shall occur and be continuing
after the grace period and notice requirement (if any) applicable thereto:
(a) The Account Party shall fail to pay any interest on any Advance or
pursuant to Section 4.02 hereof within two days after the same becomes due;
the Account Party shall fail to reimburse the Issuing Bank for any Interest
Drawing (as defined in the Letter of Credit) within two days after such
reimbursement becomes due; or the Account Party shall fail to make any other
payment required to be made pursuant to Article II or Article III hereof when
due; or
(b) Any representation or warranty made by the Account Party (or any of its
officers or agents) in any Loan Document or Transaction Document or in any
certificate or other writing delivered pursuant to any Loan Document or
Transaction Document shall prove to have been incorrect in any material
respect when made or deemed made; or
(c) The Account Party shall fail to perform or observe any term or covenant
on its part to be performed or observed contained in Sections 7.01(a), (d) or
(j), Section 7.02 or Section 7.03(i) hereof; or
(d) The Account Party shall fail to perform or observe any other term or
covenant on its part to be performed or observed contained in any Loan
Document or Transaction Document and such failure shall remain unremedied,
after written notice thereof shall have been given to the Account Party by
the Agent, the Issuing Bank or any Participating Bank, for a period of 30
days; or
(e) The Account Party shall fail to pay any of its Debt when due (including
any interest or premium thereon but excluding Debt arising hereunder and
excluding other Debt aggregating in no event more than $10,000,000 in
principal amount at any one time) whether by scheduled maturity, required
prepayment, acceleration, demand or otherwise, and such failure shall
continue after the applicable grace period, if any, specified in any
agreement or instrument relating to such Debt; or any other default under any
agreement or instrument relating to any such Debt, or any other event, shall
occur and shall continue after the applicable grace period, if any, specified
in such agreement or instrument, if the effect of such default or event is to
accelerate, or to permit the acceleration of, the maturity of such Debt; or
any such Debt shall be declared to be due and payable, or required to be
prepaid (other than by a regularly scheduled required prepayment or as a
result of the Account Party's exercise of a prepayment option) prior to the
stated maturity thereof; unless in each such case the obligee under or holder
of such Debt or the trustee with respect to such Debt shall have waived in
writing such circumstance without consideration having been paid by the
Account Party so that such circumstance is no longer continuing; or
(f) The Account Party shall generally not pay its debts as such debts become
due, or shall admit in writing its inability to pay its debts generally, or
shall make an assignment for the benefit of creditors; or any proceeding
shall be instituted by or against the Account Party seeking to adjudicate it
a bankrupt or insolvent, or seeking liquidation, winding up, reorganization,
arrangement, adjustment, protection, relief, or composition of its debts
under any law relating to bankruptcy, insolvency, or reorganization or relief
of debtors, or seeking the entry of an order for relief or the appointment of
a receiver, trustee, or other similar official for it or for any substantial
part of its property and, in the case of a proceeding instituted against the
Account Party, either the Account Party shall consent thereto or such
proceeding shall remain undismissed or unstayed for a period of 90 days or
any of the actions sought in such proceeding (including without limitation
the entry of an order for relief against the Account Party or the appointment
of a receiver, trustee, custodian or other similar official for the Account
Party or any of its property) shall occur; or the Account Party shall take
any corporate or other action to authorize any of the actions set forth above
in this subsection (f); or
(g) Any judgment or order for the payment of money in excess of $10,000,000
shall be rendered against the Account Party or its properties and either
enforcement proceedings shall have been commenced by any creditor upon such
judgment or order and shall not have been stayed or there shall be any period
of 15 consecutive days during which a stay of enforcement of such judgment or
order, by reason of a pending appeal or otherwise, shall not be in effect; or
(h) Any material provision of any Loan Document, the Rate Agreement, any
Significant Contract or any Related Document shall for any reason other than
the express terms thereof or the exercise of any right or option expressly
contained therein cease to be valid and binding on any party thereto except
as otherwise expressly permitted by the exceptions and provisions contained
in Section 7.02(g) hereof; or any party thereto other than the Participating
Banks shall so assert in writing, provided that in the case of any party
other than the Account Party making such assertion in respect of the Rate
Agreement, any Significant Contract or any Related Document, such assertion
shall not in and of itself constitute an Event of Default hereunder until (i)
such asserting party shall cease to perform under and in compliance with the
Rate Agreement, such Significant Contract or such Related Document, (ii) the
Account Party shall fail to diligently prosecute, by appropriate action or
proceedings, a rescission of such assertion or a binding determination as to
the merits thereof or (iii) such a binding determination shall have been made
in favor of such asserting party's position; or
(i) The Security Documents shall for any reason, except to the extent
permitted by the terms thereof, fail or cease to create valid and perfected
Liens (to the extent purported to be granted by such documents and subject to
the exceptions permitted thereunder) in any of the applicable Collateral
(other than Liens in favor of the Trustee with respect to the interests of
the Issuer under the Indenture), provided, that such failure or cessation
relating to any non-material portion of such Collateral shall not constitute
an Event of Default hereunder unless the same shall not have been corrected
within 30 days after the Account Party becomes aware thereof; or
(j) The Account Party shall not have in full force and effect any or all
insurance required under Section 7.01(c) hereof or there shall be incurred
any uninsured damage, loss or destruction of or to the Account Party's
properties in an amount not covered by insurance (including fully-funded
self-insurance programs) which the Majority Lenders consider to be material;
or
(k) A default by the Account Party shall have occurred under the Rate
Agreement and shall not have been effectively cured within the time period
specified therein for such cure (or, if no such time period is specified
therein, 10 days); or a default by any party shall have occurred under any
Significant Contract and such default shall not have been effectively cured
within 30 days after notice from the Agent to the Account Party stating that,
in the opinion of the Majority Lenders, such default may have a material
adverse effect upon the financial condition, operations, properties or
prospects of the Account Party as a whole; or
(l) Any Governmental Approval (whether federal, state or local) required to
give effect to the Rate Agreement (including, without limitation, Chapter
362-C of the New Hampshire Revised Statutes and the enabling order of the
NHPUC issued pursuant thereto) shall be amended, modified or supplemented, or
any other regulatory or legislative action or change (whether federal, state
or local) having the effect, directly or indirectly, of modifying the
benefits or entitlements of the Account Party under the Rate Agreement shall
occur, and in any such case such amendment, modification, supplement, action
or change may have, in the opinion of the Majority Lenders, a material
adverse effect upon the financial condition, operations, properties or
prospects of the Account Party as a whole; or
(m) NU shall cease to own all of the outstanding common stock of the Account
Party, free and clear of any Liens; or
(n) An event of default (as defined therein) shall have occurred and be
continuing under the Indenture or the First Mortgage Indenture; or
(o) An event of default (as defined therein) shall have occurred and be
continuing under the Revolving Credit Agreement or the Other Reimbursement
Agreement; or
(p) The Fixed-Rate Conversion shall fail to be consummated on May 1,1998.
SECTION VIII.2. Remedies Upon Events of Default. Upon the occurrence and
during the continuance of any Event of Default, then, and in any such event
the Agent with the concurrence of the Issuing Bank may, and upon the
direction of the Majority Lenders the Agent shall (i) if the Letter of Credit
Amendment shall not have been issued, instruct the Issuing Bank to (whereupon
the Issuing Bank shall) by notice to the Account Party declare its commitment
to issue the Letter of Credit Amendment to be terminated, whereupon the same
shall forthwith terminate, (ii) instruct the Issuing Bank to (whereupon the
Issuing Bank shall) furnish to the Trustee and the Paying Agent written
notice of such Event of Default in accordance with Section 6.01(a)(iv) of the
Indenture and of the Issuing Bank's determination to terminate the Letter of
Credit on the fifth business day (as defined in the Indenture) following the
Trustee's and Paying Agent's receipt of such notice, (iii) instruct the
Issuing Bank to (whereupon the Issuing Bank shall) furnish to the Trustee and
the Paying Agent written notice that the Interest Component will not be
reinstated in the amount of one or more Interest Drawings, all as provided in
the Letter of Credit; (iv) direct the Account party to pay cash into the Cash
Account in accordance with Section 7.05(a); (v) declare the Advances and all
other principal amounts outstanding hereunder, all interest thereon and all
other amounts payable hereunder to be forthwith due and payable, whereupon
the Advances and all other principal amounts outstanding hereunder, all such
interest and all such other amounts shall become and be forthwith due and
payable, without presentment, demand, protest or further notice of any kind,
all of which are hereby expressly waived by the Account Party, and (vi)
instruct the Issuing Bank to (whereupon the Issuing Bank shall) exercise all
the rights and remedies provided herein and under and in respect of the
Security Documents; provided, however, that in the event of an actual or
deemed entry of an order for relief with respect to the Account Party under
the Federal Bankruptcy Code, (A) the commitment of the Issuing Bank to issue
the Letter of Credit, the Commitments and the obligations of the
Participating Banks to make Advances shall automatically be terminated, and
(B) the Advances and all other principal amounts outstanding hereunder, all
interest accrued and unpaid thereon and all other amounts payable hereunder
shall automatically become due and payable, without presentment, demand,
protest or any notice of any kind, all of which are hereby expressly waived
by the Account Party.
SECTION VIII.3. Issuing Bank to Notify First Mortgage Trustee, Others. The
Issuing Bank shall, if so directed by the Majority Lenders, promptly notify
the First Mortgage Trustee by telephone, confirmed in writing, of the
occurrence of any Event of Default. In addition, the Issuing Bank shall
furnish to the Agent, the Account Party, the Paying Agent and the Issuer a
copy of (a) any notice furnished to the First Mortgage Trustee pursuant to
the preceding sentence and (b) any notice delivered to the Trustee pursuant
to clause (ii) or clause (iii) of Section 8.02. Notwithstanding the
foregoing, no failure of the Issuing Bank to give any notice (or copy of a
notice) as contemplated by this Section 8.03 shall limit or impair any rights
of the Issuing Bank, the Agent or any Participating Bank or the exercise of
any remedy hereunder, nor shall the Issuing Bank, the Agent or any
Participating Bank incur any liability as a result of any such failure.
ARTICLE IX
THE AGENT, THE PARTICIPATING BANKS AND THE ISSUING BANK
SECTION IX.1. Authorization of Agent; Actions of Agent and Issuing Bank. The
Issuing Bank and each Participating Bank hereby appoint and authorize the
Agent to take such action as agent on their behalf and to exercise such
powers under this Agreement as are delegated to the Agent by the terms
hereof, together with such powers as are reasonably incidental thereto;
provided, however, that neither the Agent nor the Issuing Bank shall be
required to take any action which exposes the Agent or the Issuing Bank to
personal liability or which is contrary to this Agreement or applicable law.
As to any matters not expressly provided for by any Related Document
(including, without limitation, enforcement or collection thereof), neither
the Agent nor the Issuing Bank shall be required to exercise any discretion
or take any action. The Agent agrees to deliver promptly (i) to the Issuing
Bank and each Participating Bank copies of each notice delivered to it by the
Account Party and (ii) to each Participating Bank copies of each notice
delivered to it by the Issuing Bank, in each case pursuant to the terms of
this Agreement.
SECTION IX.2. Reliance, Etc. Neither the Agent, the Issuing Bank, nor any
of their directors, officers, agents or employees shall be liable for any
action taken or omitted to be taken by it or them under or in connection with
this Agreement or any Related Document, except for its or their own gross
negligence or willful misconduct as determined by a court of competent
jurisdiction. Without limitation of the generality of the foregoing, each of
the Agent and the Issuing Bank (i) may consult with legal counsel (including
counsel for the Account Party), independent public accountants and other
experts selected by it and shall not be liable for any action taken or
omitted to be taken in good faith by it in accordance with the advice of such
counsel, accountants or experts; (ii) makes no warranty or representation to
any Participating Bank and shall not be responsible to any Participating Bank
for any statements, warranties or representations made in or in connection
with this Agreement or any Related Document; (iii) shall not have any duty to
ascertain or to inquire as to the performance or observance of any of the
terms, covenants or conditions of this Agreement or any Related Document on
the part of the Account Party to be performed or observed, or to inspect any
property (including the books and records) of the Account Party; (iv) shall
not be responsible to any Participating Bank for the due execution, legality,
validity, enforceability, genuineness, sufficiency or value of this Agreement
or any Related Document or any other instrument or document furnished
pursuant hereto and thereto; and (v) shall incur no liability under or in
respect of this Agreement or any Related Document by acting upon any notice,
consent certificate or other instrument or writing (which may be by telegram,
cable or telex), including, without limitation, any thereof from time to time
purporting to be from the Trustee, believed by it to be genuine and signed or
sent by the proper party or parties.
SECTION IX.3. The Agent, the Issuing Bank and Affiliates. The Agent and the
Issuing Bank shall have the same rights and powers under this Agreement as
any other Participating Bank and may exercise (or omit from exercising) the
same as though they were not the Agent and the Issuing Bank, respectively,
and the term "Participating Bank" shall, unless otherwise expressly
indicated, include Barclays in its individual capacity. The Agent, the
Issuing Bank and their respective Affiliates may accept deposits from, lend
money to, act as trustee under indentures of, and generally engage in any
kind of business with, the Account Party, any of its subsidiaries and any
Person who may do business with or own securities of the Account Party or any
such subsidiary, all as if Barclays was not the Agent or the Issuing Bank,
and without any duty to account therefor to the Participating Banks.
SECTION IX.4. Participating Bank Credit Decision. Each of the Issuing Bank
and each Participating Bank acknowledges that it has, independently and
without reliance upon the Arrangers, the Agent, the Issuing Bank or any other
Participating Bank and based on the financial information referred to in
Section 6.01(e) hereof and such other documents and information as it has
deemed appropriate, made its own credit analysis and decision to enter into
this Agreement. Each of the Issuing Bank and each Participating Bank also
acknowledges that it will, independently and without reliance upon the
Arrangers, the Agent, the Issuing Bank or any other Participating Bank and
based on such documents and information as it shall deem appropriate at the
time, continue to make its own credit decisions in taking or not taking
action under this Agreement.
SECTION IX.5. Indemnification. The Participating Banks agree to indemnity
the Arrangers, the Agent and the Issuing Bank (to the extent not reimbursed
by the Account Party), ratably according to their respective Participation
Percentages, from and against any and all liabilities, obligations, losses,
damages, penalties, actions, judgments, suits, costs, expenses or
disbursements of any kind or nature whatsoever which may be imposed on,
incurred by, or asserted against the Arrangers, the Agent or the Issuing Bank
in any way relating to or arising out of this Agreement or any action taken
or omitted by the Arrangers, the Agent or the Issuing Bank under or in
connection with this Agreement, provided that no Participating Bank shall be
liable for any portion of such liabilities, obligations, losses, damages,
penalties, actions, judgments, suits, costs, expenses or disbursements
resulting from the Arrangers', the Agent's or the Issuing Bank's (as the case
may be) gross negligence or willful misconduct. Without limitation of the
foregoing, each Participating Bank agrees to reimburse the Arrangers, the
Agent and the Issuing Bank promptly upon demand for its ratable share of any
out-of-pocket expenses (including counsel fees) incurred by the Arrangers,
the Agent and the Issuing Bank in connection with the preparation, execution,
delivery, administration, modification, amendment, waiver or enforcement
(whether through negotiations, legal proceedings or otherwise) of, or legal
advice in respect of rights or responsibilities under, this Agreement to the
extent that the Arrangers, the Agent and the Issuing Bank (as the case may
be) are entitled to reimbursement for such expenses pursuant to Section 10.04
hereof but are not reimbursed for such expenses by the Account Party.
SECTION IX.6. Successor Agent. The Agent may resign at any time by giving
written notice thereof to the Issuing Bank, the Participating Banks and the
Account Party, with any such resignation to become effective only upon the
appointment of a successor Agent pursuant to this Section 9.06. Upon any
such resignation, the Issuing Bank shall have the right to appoint a
successor Agent, which shall be another commercial bank or trust company
reasonably acceptable to the Account Party, organized or licensed under the
laws of the United States, or of any State thereof. Upon the acceptance of
any appointment as Agent hereunder by a successor Agent and the execution and
delivery by the Account Party and the successor Agent of an agreement
relating to the fees, if any, to be paid to the successor Agent in connection
with its acting as Agent hereunder, such successor Agent shall thereupon
succeed to and become vested with all the rights, powers, privileges and
duties of the retiring Agent, and the retiring Agent shall be discharged from
its duties and obligations under this Agreement. After any retiring Agent's
resignation hereunder as Agent, the provisions of this Article IX shall inure
to its benefit as to any actions taken or omitted to be taken by it while it
was Agent under this Agreement.
SECTION IX.7. Issuing Bank. (a) All notices received by the Issuing Bank
pursuant to this Agreement or any Related Document (other than the Letter of
Credit) shall be promptly delivered to the Agent for distribution to the
Participating Banks.
(b) Except to the extent permitted by Section 2.06, the Issuing Bank shall
not amend or waive any provision or consent to the amendment or waiver of any
Related Document without the written consent of the Majority Lenders.
Notwithstanding the foregoing, each Participating Bank, by its execution and
delivery of this Agreement, authorizes and directs the Issuing Bank to
execute and deliver the Second Supplement, dated as of May 1, 1995, to the
Original Indenture.
(c) Upon receipt by the Issuing Bank from time to time of any amount
pursuant to the terms of any Related Document (other than pursuant to the
terms of this Agreement), the Issuing Bank shall promptly deliver to the
Agent such amount.
SECTION IX.8. Certain Authorizations and Consent. The Issuing Bank and each
Participating Bank, by its acceptance hereof, and each other Participating
Bank by its execution and delivery of the Participant Assignment pursuant to
which it became a Participating Bank, consents to, authorizes, ratifies and
confirms in all respects:
(i) the execution, delivery, acceptance and performance by the Agent and by
the Collateral Agent of the Intercreditor Agreement, as the same may be from
time to time amended in accordance with the terms thereof and Section 10.01
hereof;
(ii) the execution, delivery and acceptance by the Collateral Agent of, and
the taking by the Collateral Agent of all actions under, the Security
Agreement, as the same may be from time to time amended in accordance with
the terms thereof and Section 10.01 hereof;
the execution and delivery of this Agreement by the Issuing Bank or such
Participating Bank, or the execution and delivery of such Participant
Assignment by such Participating Bank, as the case may be, constituting
(without further act or deed) the Issuing Bank or such Participating Bank's
acceptance and approval of, and agreement to the terms of, the Intercreditor
Agreement and the Security Agreement with the same effect as if the Issuing
Bank or such Participating Bank were itself a party thereto.
ARTICLE X
MISCELLANEOUS
SECTION X.1. Amendments, Etc. No amendment or waiver of any provision of
this Agreement or the Pledge Agreement, nor consent to any departure by the
Account Party therefrom, shall in any event be effective unless the same
shall be in writing and signed by the Majority Lenders, and then such waiver
or consent shall be effective only in the specific instance and for the
specific purpose for which given; provided, however, that no amendment,
waiver or consent shall, unless in writing and signed by the Issuing Bank and
all the Participating Banks, do any of the following: (a) waive, modify or
eliminate any of the conditions specified in Article V of this Agreement or
Article III of the Amendment, (b) increase the Commitments of the
Participating Banks that may be maintained hereunder or subject the
Participating Banks to any additional obligations, (c) reduce the principal
of, or interest on, the Advances, any amount reimbursable on demand pursuant
to Section 3.01, or any fees or other amounts payable hereunder, (d) postpone
any date fixed for any payment of principal of, or interest on, the Advances,
such reimbursable amounts or any fees or other amounts payable hereunder
(other than fees payable to the Issuing Bank or the Agent pursuant to Section
2.03 hereof), (e) change the percentage of the Commitments or of the
aggregate unpaid principal amount of the Advances, or the number of
Participating Banks which shall be required for the Participating Banks or
any of them to take any action hereunder, (f) amend this Agreement or the
Pledge Agreement in a manner intended to prefer one or more Participating
Banks over any other Participating Banks, (g) amend this Section 10.01, or
(h) release any of the Collateral otherwise than in accordance with any
provisions for such release contained in the Security Documents, or change
any provision of any Security Document providing for the release of all or
substantially all of the Collateral; and provided, further, that (i) no
amendment, waiver or consent shall, unless in writing and signed by the
Issuing Bank or the Agent in addition to the Participating Banks required
above to take such action, affect the rights or duties of the Issuing Bank or
the Agent, as the case may be, under this Agreement or the Pledge Agreement
and (ii) no amendment, waiver or consent shall, unless in writing and signed
by the "Majority Lenders" under the Other Reimbursement Agreement and the
"Majority Lenders" under the Revolving Credit Agreement, shall change the
percentage of the Commitments or of the aggregate unpaid principal amount of
the Advances, or the number of Participating Banks which shall be required
for the Participating Banks or any of them to take, or to direct the
Collateral Agent to take, any action under the Intercreditor Agreement and
the Security Agreement.
SECTION X.2. Notices, Etc. All notices and other communications provided for
hereunder and under the other Loan Documents shall be in writing (including
telegraphic, telex, telecopy or cable communication) and mailed, telegraphed,
telexed, telecopied, cabled or delivered:
(i) if to the Account Party, to it in care of NUSCO at NUSCO's address at
107 Selden Street, Berlin, Connecticut 06037 (telecopy: (860) 665-5457),
Attention: Assistant Treasurer - Finance;
(ii) if to the Issuing Bank or the Agent, to it at its address at 222
Broadway, 12th Floor, New York, New York 10038, Attention: Customer Service
Unit, (telephone: (212) 412-3363, telecopy: (212) 412-3080, Telex: 12-6946),
with a copy to: Utilities Finance Group, (telephone (212) 412-2551, telecopy:
(212) 412-7575) and with a further copy to Credit Enhancement Unit (telephone
(212) 412-3578, telecopy (212) 412-6969);
(iii) if to any Participating Bank, to it at its address set forth on the
signature pages to the Amendment or in the Participation Assignment pursuant
to which it became a Participating Bank; or
as to each party other than any Participating Bank, at such other address as
shall be designated by such party in a written notice to the other parties,
and, as to any Participating Bank, at such other address as shall be
designated by such Participating Bank in a written notice to the Account
Party and the Agent. All such notices and communications shall, when mailed,
telegraphed, telexed, telecopied or cabled, be effective five days after when
deposited in the mails, or when delivered to the telegraph company, confirmed
by telex answerback, telecopied or delivered to the cable company,
respectively, except that notices and communications to the Agent or the
Issuing Bank pursuant to Article II, III or IV shall not be effective until
received by the Agent or the Issuing Bank, as the case may be.
SECTION X.3. No Waiver of Remedies. No failure on the part of any
Participating Bank or the Issuing Bank to exercise, and no delay in
exercising, any right hereunder or under any Loan Document shall operate as a
waiver thereof; nor shall any single or partial exercise of any such right
preclude any other or further exercise thereof or the exercise of any other
right. The remedies herein provided are cumulative and not exclusive of any
remedies provided by law.
SECTION X.4. Cost; Expenses and Indemnification. (a) The Account Party
agrees to pay on demand all costs and expenses, if any (including, without
limitation, reasonable counsel fees and expenses), of (i) the Arrangers, the
Agent and the Issuing Bank in connection with the preparation, negotiation,
execution and delivery of the Loan Documents and Transaction Documents and
the administration of the Loan Documents and Transaction Documents, the care
and custody of any and all collateral, and any proposed modification,
amendment, or consent relating thereto; and (ii) the Arrangers, the Agent,
the Issuing Bank and each Participating Bank in connection with the
enforcement (whether through negotiations, legal proceedings or otherwise) of
this Agreement or any other Loan Document or Transaction Document.
(b) The Account Party hereby agrees to indemnify and hold the Arrangers, the
Agent, the Issuing Bank and each Participating Bank and their respective
officers, directors, employees, professional advisors and affiliates (each,
an "Indemnified Person") harmless from and against any and all claims,
damages, losses, liabilities, costs or expenses (including reasonable
attorney's fees and expenses, whether or not such Indemnified Person is named
as a party to any proceeding or investigation or is otherwise subjected to
judicial or legal process arising from any such proceeding or investigation)
which any of them may incur or which may be claimed against any of them by
any person or entity (except to the extent such claims, damages, losses,
liabilities, costs or expenses arise from the gross negligence or willful
misconduct of the Indemnified Person):
(i) by reason of or in connection with the execution, delivery or
performance of any of the Loan Documents, the Transaction Documents or the
Related Documents or any transaction contemplated thereby, or the use by the
Account Party of the proceeds of any Advance or the use by the Paying Agent
or the Trustee of the proceeds of any drawing under the Letter of Credit;
(ii) in connection with or resulting from the utilization, storage, disposal,
treatment, generation, transportation, release or ownership of any Hazardous
Substance (A) at, upon or under any property of the Account Party or any of
its Affiliates or (B) by or on behalf of the Account Party or any of its
Affiliates at any time and in any place;
(iii) in connection with any documentary taxes, assessments or charges
made by any governmental authority by reason of the execution and delivery of
any of the Loan Documents;
(iv) by reason of or in connection with the execution and delivery or
transfer of, or payment or failure to make payment under, the Letter of
Credit; provided, however, that the Account Party shall not be required to
indemnity the Arrangers, the Agent, the Issuing Bank or any Participating
Bank pursuant to this Section for any claims, damages, losses, liabilities,
costs or expenses to the extent caused by (A) the Issuing Bank's willful
misconduct or gross negligence, as determined by a court of competent
jurisdiction, in determining whether documents presented under the Letter of
Credit are genuine or comply with the terms of the Letter of Credit or (B)
the Issuing Bank's willful or grossly negligent failure, as determined by a
court of competent jurisdiction, to make lawful payment under the Letter of
Credit after the presentation to it by the Paying Agent of a draft and
certificate strictly complying with the terms and conditions of the Letter of
Credit; or
(v) by reason of any inaccuracy or alleged inaccuracy in any material
respect, or any untrue statement or alleged untrue statement of any material
fact, contained in any Official Statement, except to the extent contained in
or arising from information in such Official Statement supplied in writing by
and describing the Issuing Bank or any previous issuer of a letter of credit
relating to the Bonds.
(c) Nothing contained in this Section 10.04 is intended to limit the Account
Party's obligations set forth in Articles II, III and IV. The Account
Party's obligations under this Section 10.04 shall survive the creation and
sale of any participation interest pursuant to Section 10.06 hereof and shall
survive as well the repayment of all amounts owing to the Agent, the Issuing
Bank and the Participating Banks under the Loan Documents and the termination
of the Commitments. If and to the extent that the obligations of the Account
Party under this Section 10.04 are unenforceable for any reason, the Account
Party agrees to make the maximum contribution to the payment and satisfaction
thereof which is permissible under applicable law.
SECTION X.5. Right of Set-off. (a) Upon (i) the occurrence and during the
continuance of any Event of Default and (ii) the taking of any action or the
giving of any instruction by the Agent as specified by Section 8.02 hereof,
the Issuing Bank and each Participating Bank are hereby authorized at any
time and from time to time, to the fullest extent permitted by law, to set
off and apply any and all deposits (general or special, time or demand,
provisional or final) at any time held and other indebtedness at any time
owing by the Issuing Bank or such Participating Bank to or for the credit or
the account of the Account Party against any and all of the obligations of
the Account Party now or hereafter existing under this Agreement in favor of
the Issuing Bank or such Participating Bank, irrespective of whether or not
the Issuing Bank or such Participating Bank shall have made any demand under
this Agreement and although such obligations may be unmatured. The Issuing
Bank and each Participating Bank agrees promptly to notify the Account Party
after any such set-off and application provided that the failure to give such
notice shall not affect the validity of such set-off and application. The
rights of the Issuing Bank and each Participating Bank under this Section are
in addition to other rights and remedies (including, without limitation,
other rights of set-off) which the Issuing Bank and/or such Participating
Bank may have.
(b) The Account Party agrees that it shall have no right of off-set,
deduction or counterclaim in respect of its obligations hereunder, and that
the obligations of the Issuing Bank and of the several Participating Banks
hereunder are several and not joint. Nothing contained herein shall
constitute a relinquishment or waiver of the Account Party's rights to any
independent claim that the Account Party may have against the Issuing Bank or
any Participating Bank, but no Participating Bank shall be liable for the
conduct of the Issuing Bank or any other Participating Bank, and the Issuing
Bank shall not be liable for the conduct of any Participating Bank.
SECTION X.6. Binding Effect; Assignments and Participants. (a) This
Agreement shall become effective when it shall have been executed and
delivered by the Account Party, the Agent, the Issuing Bank and each
Participating Bank named on the signature pages to the Amendment and
thereafter shall be binding upon and inure to the benefit of the Account
Party, the Agent, the Issuing Bank and each Participating Bank and their
respective successors and assigns, except that the Account Party shall not
have the right to assign its rights hereunder or any interest herein without
the prior written consent of the Issuing Bank and each Participating Bank,
and the Issuing Bank may not assign its commitment to issue the Letter of
Credit or its obligations under or in respect of the Letter of Credit.
(b) Each Participating Bank may assign all or any portion of its rights
under this Agreement, under the Letter of Credit or in any security
hereunder, including, without limitation, any instruments securing the
Account Party's obligations hereunder; provided that (i) no assignment by any
Participating Bank may be made to any Person, other than to another
Participating Bank, except with the prior written consent of the Issuing Bank
and the Account Party (which consent in the case of the Account Party, (A)
shall not be unreasonably withheld and (B) shall not be required if an Event
of Default shall have occurred and be continuing and the Agent or the Issuing
Bank shall have exercised any remedy described in clause (ii), (iii) or (v)
of Section 8.02), (ii) any assignment shall be of a constant and not a
varying percentage of all of the assignor's rights and obligations hereunder
and (iii) the parties to each such assignment shall execute and deliver to
the Agent a Participation Assignment, together with a processing fee of
$2,500. Upon receipt of a completed Participation Assignment and the
processing fee, the Agent will record in a register maintained for such
purpose the name of the assignee and the percentage participation interest
assigned by the assignor and assumed by the assignee for purposes of the
determination of such assignor's and assignee's respective Participation
Percentages. Upon such execution, delivery, acceptance and recording, from
and after the effective date specified in each Participation Assignment,
which effective date shall be at least five Business Days after the execution
thereof, the assignee shall, to the extent of such assignment, become a party
hereto and have all of the rights and obligations of a Participating Bank
hereunder and, to the extent of such assignment, such assigning Participating
Bank shall be released from its obligations hereunder (without relieving such
Participating Bank from any liability for damages, costs and expenses
suffered by the Issuing Bank or the Account Party as a result of the failure
by such Participating Bank to perform its obligations hereunder).
(c) Each Participating Bank may grant participations to one or more Persons
in all or any part of, or any interest (undivided or divided) in, such
Participating Bank's rights and obligations under this Agreement (any such
Person being referred to hereinafter as a "Participant" and such interests
are collectively, referred to hereinafter as the "Rights"); provided,
however, that (i) such Participating Bank's obligations under this Agreement
shall remain unchanged; (ii) any such Participant shall be entitled to the
benefits and cost protections provided for in Section 4.03 hereof on the same
basis as if it were a Participating Bank hereunder; (iii) the Account Party,
the Agent and the Issuing Bank shall continue to deal solely and directly
with such Participating Bank in connection with such Participating Bank's
rights and obligations under this Agreement; and (iv) no such Participant,
other than an Affiliate of such Participating Bank, shall be entitled to
require such Participating Bank to take or omit to take any action hereunder,
unless such action or omission would have an effect of the type described in
subsections (c), (d) or (h) of Section 10.01 hereof.
(d) Notwithstanding anything contained in this Section 10.06 to the
contrary, the Issuing Bank and any Participating Bank may assign and pledge
all or any portion of the Advances (or participating interests therein) owing
to the Issuing Bank or such Participating Bank to any Federal Reserve Bank
(and its transferees) as collateral security pursuant to Regulation A of the
Board of Governors of the Federal Reserve System and any Operating Circular
issued by such Federal Reserve Bank. No such assignment shall release the
Issuing Bank or such Participating Bank from its obligations hereunder.
SECTION X.7. Relation of the Parties; No Beneficiary. No term, provision or
requirement, whether express or implied, of any Loan Document, or actions
taken or to be taken by any party thereunder, shall be construed to create a
partnership, association, or joint venture between such parties or any of
them. No term or provision of the Loan Documents shall be construed to
confer a benefit upon, or grant a right or privilege to, any Person other
than the parties hereto.
SECTION X.8. Issuing Bank Not Liable. As between the Agent, the Issuing
Bank and the Participating Banks on the one hand, and the Account Party on
the other, the Account Party assumes all risks of the acts or omissions of
the Paying Agent, the Trustee and any other beneficiary or transferee of the
Letter of Credit with respect to its use of the Letter of Credit. Neither the
Agent, the Issuing Bank, any Participating Bank, nor any of their respective
officers or directors shall be liable or responsible for: (a) the use which
may be made of the Letter of Credit or any acts or omissions of the Paying
Agent, the Trustee and any other beneficiary or transferee in connection
therewith; (b) the validity, sufficiency or genuineness of documents, or of
any endorsement thereon, even if such documents should prove to be in any or
all respects invalid, insufficient, fraudulent or forged; (c) payment by the
Issuing Bank against presentation of documents which do not comply with the
terms of the Letter of Credit, including failure of any documents to bear any
reference or adequate reference to the Letter of Credit; or (d) any other
circumstances whatsoever in making or failing to make payment under the
Letter of Credit, except that the Account Party shall have a claim against
the Issuing Bank, and the Issuing Bank shall be liable to the Account Party,
to the extent of any direct, as opposed to consequential, damages suffered by
the Account Party which the Account Party proves were caused by (i) the
Issuing Bank's willful misconduct or gross negligence, as determined by a
court of competent jurisdiction, in determining whether documents presented
under the Letter of Credit are genuine or comply with the terms of the Letter
of Credit or (ii) the Issuing Bank's willful or grossly negligent failure, as
determined by a court of competent jurisdiction, to make lawful payment under
the Letter of Credit after the presentation to it by the Paying Agent of a
draft and certificate strictly complying with the terms and conditions of the
Letter of Credit. In furtherance and not in limitation of the foregoing, the
Issuing Bank may accept original or facsimile (including telecopy) sight
drafts and accompanying certificates presented under the Letter of Credit
that appear on their face to be in order, without responsibility for further
investigation, regardless of any notice or information to the contrary.
SECTION X.9. Confidentiality. In connection with the negotiation and
administration of this Agreement and the other Loan Documents, the Account
Party has furnished and will from time to time furnish to the Agent, the
Issuing Bank and the Participating Banks (each, a "Recipient") written
information which is identified to the Recipient when delivered as
confidential (such information, other than any such information which (i) was
publicly available, or otherwise known to the Recipient at the time of
disclosure, (ii) subsequently becomes publicly available other than through
any act or omission by the Recipient or (iii) otherwise subsequently becomes
known to the Recipient other than through a Person whom the Recipient knows
to be acting in violation of his or its obligations to the Account Party,
being hereinafter referred to as "Confidential Information"). The Recipient
will not knowingly disclose any such Confidential Information to any third
party (other than to those persons who have a confidential relationship with
the Recipient), and will take all reasonable steps to restrict access to such
information in a manner designed to maintain the confidential nature of such
information, in each case until such time as the same ceases to be
Confidential Information or as the Account Party may otherwise instruct. It
is understood, however, that the foregoing will not restrict the Recipient's
ability to freely exchange such Confidential Information with prospective
assignees of or participants in the Recipient's position herein, but the
Recipient's ability to so exchange Confidential Information shall be
conditioned upon any such prospective assignee's or participant's entering
into an understanding as to confidentiality similar to this provision. It is
further understood that the foregoing will not prohibit the disclosure of any
or all Confidential Information if and to the extent that such disclosure may
be required (i) by a regulatory agency or otherwise in connection with an
examination of the Recipient's records by appropriate authorities, (ii)
pursuant to court order, subpoena or other legal process or (iii) otherwise,
as required by law; in the event of any required disclosure under clause (ii)
or (iii) above, the Recipient agrees to use reasonable efforts to inform the
Account Party as promptly as practicable.
SECTION X.10. Waiver of Jury Trial. The Account Party, the Arrangers, the
Agent, the Issuing Bank, and the Participating Banks each hereby irrevocably
waives all right to trial by jury in any action, proceeding or counterclaim
arising out of or relating to this Agreement or any other Loan Document, any
Transaction Document or any other instrument or document delivered hereunder
or thereunder.
SECTION X.11. Governing Law. This Agreement, the Amendment and the Pledge
Agreement shall be governed by, and construed in accordance with, the laws of
the State of New York. The Account Party, the Arrangers, the Agent, the
Issuing Bank and each Participating Bank each (i) irrevocably submits to the
jurisdiction of any New York State Court or Federal court sitting in New York
City in any action arising out of any Loan Document, (ii) agrees that all
claims in such action may be decided in such court, (iii) waives, to the
fullest extent it may effectively do so, the defense of an inconvenient forum
and (iv) consents to the service of process by mail. A final judgment in any
such action shall be conclusive and may be enforced in other jurisdictions.
Nothing herein shall affect the right of any party to serve legal process in
any manner permitted by law or affect its right to bring any action in any
other court.
SECTION X.12. Execution in Counterparts. This Agreement may be executed in
any number of counterparts and by different parties hereto in separate
counterparts, each of which when so executed shall be deemed to be an
original and all of which taken together shall constitute one and the same
agreement.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed by their respective officers thereunto duly authorized, as of the
date first above written, such execution being conclusively evidenced by the
execution and delivery by such parties of the Amendment to which this Amended
and Restated Second Series D Letter of Credit and Reimbursement Agreement is
attached.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
executed by their respective officers thereunto duly authorized, as of the
date first above written.
THE ACCOUNT PARTY:
PUBLIC SERVICE COMPANY OF
NEW HAMPSHIRE
By: /S/David R. McHale
Title: Assistant Treasurer
THE AGENT AND ISSUING BANK:
BARCLAYS BANK PLC,
NEW YORK BRANCH,
as Agent and as Issuing Bank
By: /S/ Managing Director
THE PARTICIPATING BANKS:
BARCLAYS BANK PLC,
NEW YORK BRANCH
By: /S/ SYDNEY DENNIS
Title: Managing Director
Address for Notices
Barclays Bank PLC
222 Broadway
New York, New York 10038
Attention: Sydney Dennis
Telephone: (212) 412-2570
Fax: (212) 412-6709
SWISS BANK CORPORATION,
STAMFORD BRANCH
By: /S/ WILLIAM A. ROCHE
Title: Director
By: /S/ DAVID C. HEMINGWAY
Title: Director
Address for Notices
Swiss Bank Corporation
677 Washington Boulevard
Stamford, Connecticut 06912
Attention: Darryl M. Monasebian
Telephone: (203) 819-8005
Fax: (203) 819-8610
BANK OF AMERICA NATIONAL
TRUST AND SAVINGS ASSOCIATION
By: /S/ VERN HOWARD
Title: Managing Director
Address for Notices
Bank of America NT & SA
555 California Street
San Francisco, California 94104
Attention: Vern Howard
Telephone: (415) 953-0590
Fax: (415) 622-0632
LTCB TRUST COMPANY
By: /S/ GREGORY L. HONG
Title: Senior Vice President
Address for Notices
LTCB Trust Company
165 Broadway, 49th Floor
New York, New York 10006
Attention: Gregory H. Hong
Telephone: (212) 335-4534
Fax: (212) 608-2371
TORONTO DOMINION (NEW YORK), INC.
By: /S/ DEBBIE A. GREENE
Title: Vice President
Address for Notices
The Toronto-Dominion Bank
909 Fannin Street, Suite 1700
Houston, Texas 77010
Attention: Debbie Greene
Telephone: (713) 653-8250
Fax: (713) 951-9921
UNION BANK OF CALIFORNIA
By: /S/ KARYSSA M. BRITTON
Title: Vice President
Address for Notices
Union Bank of California
445 S. Figueroa Street, 15th Floor
Los Angeles, CA 90071
Attention: John M. Edmonston
Telephone: (213) 236-5809
Fax: (213) 236-4096
THE BANK OF NOVA SCOTIA
By: /S/FRAN PITCHLEY
Title:
Address for Notices
The Bank of Nova Scotia
28 State Street, 17th Floor
Boston, Massachusetts 02109
Attention: Paula A. MacDonald
Telephone: (617) 624-7613
Fax: (617) 624-7607
THE CHASE MANHATTAN BANK
By: /S/ PAUL V. FARRELL
Title: Vice President
Address for Notices
The Chase Manhattan Bank
270 Park Avenue
New York, New York 10017
Attention: Paul V. Farrell
Telephone: (212) 270-7653
Fax: (212) 270-3089
CITIBANK, N.A.
By: /S/ ROBERT J. HARRITY, JR.
Title: Managing Director
Address for Notices
Citibank, N.A.
399 Park Avenue
4th Floor, Zone 20
New York, New York 10043
Attention: Robert J. Harrity, Jr.
Telephone: (212) 559-6482
Fax: (212) 793-6130
BANKBOSTON, N.A.
By: /S/ MICHAEL M. PARKER
Title: Managing Director
Address for Notices
BankBoston, N.A.
100 Federal Street, M/S 01-08-04
Boston, MA 02110
Attention: Michael M. Parker
Telephone: (617) 434-7829
Fax: (617) 434-3652
THE FIRST NATIONAL BANK OF CHICAGO
By: /S/ MADELEINE N. PEMBER
Title: Assistant Vice President
Address for Notices
The First National Bank of Chicago
One First National Plaza, Suite 0363
Chicago, Illinois 60670
Attention: Kenneth J. Bauer
Telephone: (312) 732-6282
Fax: (312) 732-3055
THE FUJI BANK, LIMITED
By: /S/ RAYMOND VENTURA
Title: Vice President & Manager
Address for Notices
The Fuji Bank, Limited
Two World Trade Center
New York, New York 10048
Attention: Michael Gebauer
Telephone: (212) 898-2064
Fax: (212) 321-9407
THE INDUSTRIAL BANK OF JAPAN
TRUST COMPANY
By: /S/ JOHN DIPPO
Title: Senior Vice President
Address for Notices
The Industrial Bank of Japan Trust Company
1251 Avenue of the Americas
New York, New York 10020-1104
Attention: John Cunningham
Telephone: (212) 282-3411
Fax: (212) 282-4988
THE NIPPON CREDIT BANK, LTD.
By: /S/ KOICHI SUNAGAWA
Title: Representative
Address for Notices
The Nippon Credit Bank, Ltd.
101 East 52nd Street, 14th Floor
New York, New York 10022
Attention: Koichi Sunagawa
Telephone: (212) 751-7330
Fax: (212) 751-0987
FLEET NATIONAL BANK
By: /S/ DANIEL D. BUTLER
Title: Vice President
Address for Notices
Fleet Bank
40 Westminster Street
Mail Stop: RI OP T05A
Providence, Rhode Island 02903-4963
Attention: Fred N. Manning
Telephone: (401) 459-4845
Fax: (401) 459-4963
SOCIETE GENERALE
By: /S/GORDON EADON
Title:VICE PRESIDENT
Address for Notices
Societe Generale
1221 Avenue of the Americas
New York, New York 10020
Attention: Gordon Eadon
Telephone: (212) 278-6880
Fax: (212) 278-7430
THE SUMITOMO BANK, LIMITED,
NEW YORK BRANCH
By: /S/ KAZUYOSHI OGAWA
Title: Joint General Manager
Address for Notices
The Sumitomo Bank, Limited,
New York Branch
277 Park Avenue
New York, New York 10172
Attention: J. Bruce Meredith
Telephone: (212) 244-4129
Fax: (212) 224-5188
MELLON BANK, N.A.
By: /S/ KURT HEWETT
Title: Vice President
Address for Notices
Mellon Bank, N.A.
One Mellon Bank Center, Room 4425
Pittsburgh, Pennsylvania 15258
Attention: Kurt Hewett
Telephone: (412) 234-7355
Fax: (412) 234-0286
CREDIT LYONNAIS (NEW YORK)
By: /S/ ALAN SIDRANE
Title: Senior Vice President
Address for Notices
Credit Lyonnais (New York)
1301 Avenue of the Americas
New York, New York 10019
Attention: David Bonington
Telephone: (212) 261-7861
Fax: (212) 261-3259
THE YASUDA TRUST AND BANKING
CO., LTD., NEW YORK BRANCH
By: /S/ ROHN LAUDENSCHLAGER
Title: Senior Vice President
Address for Notices
The Yasuda Trust and Banking Co., Ltd.,
New York Branch
666 Fifth Avenue, Suite 801
New York, New York 10103
Attention: Rohn Laudenschlager
Telephone: (212) 373-5713
Fax: (212) 373-5796
Exhibit 4.3.7.2
SECOND SUPPLEMENT
Dated as of May 1, 1995
among
BUSINESS FINANCE AUTHORITY OF THE
STATE OF NEW HAMPSHIRE
and
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
and
STATE STREET BANK AND TRUST COMPANY, as Trustee
Supplementing and Amending the Series E Loan and Trust Agreement
Dated as of May 1, 1991, as amended by a First Supplement
Dated as of December 1, 1993
TABLE OF CONTENTS
ARTICLE I: INTRODUCTION AND DEFINITIONS
Section 101. Description of the Agreement and the Parties
Section 102. Definitions
ARTICLE II: BOOK-ENTRY ONLY SYSTEM
Section 201. Registration of Bonds in the Book-Entry Only System
ARTICLE III: MISCELLANEOUS
Section 301. Original Agreement Affirmed
Section 302. Severability
Section 303. Counterparts
Section 304. Receipt of Documents
Section 305. Captions
Section 306. Governing Law
EXHIBIT A
EXHIBIT B
ARTICLE I: INTRODUCTION AND DEFINITIONS
Section 101. Description of the Agreement and the Parties. This SECOND
SUPPLEMENT (the "Second Supplement") is entered into as of May 1, 1995 by the
Business Finance Authority of the State of New Hampshire (with its
successors, the "Authority"), a body corporate and politic created under New
Hampshire Revised Statutes Annotated 162-A:3 formerly known as The Industrial
Development Authority of the State of New Hampshire; Public Service Company
of New Hampshire (with its successors, the "Company"), a New Hampshire
corporation, and State Street Bank and Trust Company, a Massachusetts trust
company, as Trustee (with its successors, the "Trustee"). This Second
Supplement supplements and amends the Series E Loan and Trust Agreement dated
as of May 1, 1991 (the "Original Agreement") among the Authority, the Company
and the Trustee, as previously amended by a First Supplement dated as of
December 1, 1993 (the "First Supplement" and collectively with the Original
Agreement and this Second Supplement, the "Agreement"), and is entered into
pursuant to Clauses 1101(a)(v) and (viii) of the Original Agreement. The
primary purpose of this Second Supplement is to provide for the establishment
of a book-entry system of registration for the outstanding $69,700,000
principal amount of The Industrial Development Authority of the State of New
Hampshire Pollution Control Revenue Bonds (Public Service Company of New
Hampshire Project-1991 Taxable Series E), and at the election of the Company,
for other Bonds outstanding under the Agreement from time to time.
In consideration of the mutual promises contained in this Second Supplement,
the rights conferred and the obligations assumed hereby, and other good and
valuable consideration, the receipt of which is hereby acknowledged, each of
the Company, the Authority and the Trustee agree, assign, covenant, grant,
pledge, promise, represent and warrant as set forth herein for their own
benefit and for the benefit of the Bondowners and the Bank.
Section 102. Definitions. (a) Words. Unless otherwise defined in this
Second Supplement, or unless the context otherwise requires, the terms
defined in the Original Agreement, as amended by the First Supplement, shall
have the same meaning in this Second Supplement.
ARTICLE II: BOOK-ENTRY ONLY SYSTEM
Section 201. Registration of Bonds in the Book-Entry Only System.
(a) Notwithstanding any provision of the Agreement to the contrary, the
provisions of this Section 201 shall apply with respect to any Bonds (except
the 1993 Series E Bonds) registered to CEDE & CO. or any other nominee of The
Depository Trust Company ("DTC") while the Book-Entry Only System (meaning
the system of registration described in this Section 201) is in effect. The
Book-Entry Only System shall be in effect for any series of Bonds or portion
thereof issued in or converted to any Mode or Rate Period within the
Multiannual Mode if so specified by the Company prior to the issuance in or
conversion to that Mode or Rate Period, subject to the provisions below
concerning termination of the Book-Entry Only System. Until it revokes such
specification in its discretion, the Company hereby specifies that the Book-
Entry Only System shall be in effect while the 1991 Series E Bonds are in
Flexible Mode. Notwithstanding any provision of this Section 201 to the
contrary, the provisions of this Section 201 shall not apply to the 1993
Series E Bonds, which are subject to the Book-Entry Only System described in
Section 303 of the First Supplement.
(b) The Bonds in or to be in the Book-Entry Only System shall be issued in
the form of a separate single authenticated fully registered Bond for each
separate Mode or Rate Period. Any legend required to be on the Bonds by DTC
may be added by the Trustee or Paying Agent. The form of Book-Entry Only
System 1991 Series E Bond in the Flexible Mode is attached hereto as Exhibit
A. On the date of original delivery thereof or date of conversion of the any
Bonds to a Mode or Rate Period in which the Book-Entry Only System is in
effect, as applicable, such Bonds shall be registered in the registry books
of the Paying Agent in the name of CEDE & CO., as nominee of The Depository
Trust Company as agent for the Authority in maintaining the Book-Entry Only
System. With respect to Bonds registered in the registry books kept by the
Paying Agent in the name of CEDE & CO., as nominee of DTC, the Authority, the
Paying Agent, the Company, the Remarketing Agent and the Trustee shall have
no responsibility or obligation to any Participant (which means securities
brokers and dealers, banks, trust companies, clearing corporations and
various other entities, some of whom or their representatives own DTC) or to
any Beneficial Owner (which means, when used with reference to the Book-Entry
Only System, the person who is considered the beneficial owner of the Bonds
pursuant to the arrangements for book entry determination of ownership
applicable to DTC) with respect to the following: (A) the accuracy of the
records of DTC, CEDE & CO. or any Participant with respect to any ownership
interest in the Bonds, (B) the delivery to or from any Participant, any
Beneficial Owner or any other person, other than DTC, of any notice with
respect to the Bonds, including any notice of redemption or tender (whether
mandatory or optional), or (C) the payment to any Participant, any Beneficial
Owner or any other person, other than DTC, of any amount with respect to the
principal or premium, if any, or interest on the Bonds. The Paying Agent
shall pay all principal of and premium, if any, and interest on the Bonds
only to or upon the order of DTC, and all such payments shall be valid and
effective fully to satisfy and discharge the Authority's obligations with
respect to the principal of and premium, if any, and interest on Bonds to the
extent of the sum or sums so paid. No person other than DTC shall be
entitled to receive an authenticated Bond evidencing the obligation of the
Authority to make payments of principal and premium, if any, and interest
pursuant to this Agreement. Upon delivery by DTC to the Paying Agent of
written notice to the effect that DTC has determined to substitute a new
nominee in place of CEDE & CO., the words "CEDE & CO." in the Agreement shall
refer to such new nominee of DTC.
(c) Upon receipt by the Trustee or the Paying Agent of written notice from
DTC to the effect that DTC is unable or unwilling to discharge its
responsibilities with respect to any Bonds, the Authority shall issue and the
Paying Agent shall transfer and exchange such Bonds as requested by DTC in
appropriate amounts and in authorized denominations, and whenever DTC
requests the Authority, the Paying Agent and the Trustee to do so, the
Trustee, the Paying Agent and the Authority will, at the expense of the
Company, cooperate with DTC in taking appropriate action after reasonable
notice (A) to arrange for a substitute bond depository willing and able upon
reasonable and customary terms to maintain custody of such Bonds or (B) to
make available for transfer and exchange such Bonds registered in whatever
name or names and in whatever authorized denominations as DTC shall
designate.
(d) In the event the Company determines that the Beneficial Owners of any
Bonds in the Book-Entry Only System should be able to obtain Bond
certificates, the Company may so notify DTC, the Paying Agent and the
Trustee, whereupon DTC will notify the Participants of the availability
through DTC of such Bond certificates. In such event, the Authority shall
issue and the Paying Agent shall transfer and exchange Bond certificates as
requested by DTC in appropriate amounts and in authorized denominations.
Whenever DTC requests the Paying Agent to do so, the Paying Agent will
cooperate with DTC in taking appropriate action after reasonable notice to
make available for transfer and exchange Bonds registered in whatever name or
names and in whatever authorized denominations as DTC shall designate.
(e) Notwithstanding any other provision of the Agreement to the contrary, so
long as any 1991 Series E Bond is registered in the name of CEDE & CO., as
nominee of DTC, all payments with respect to the principal of, Purchase
Price, premium, if any, and interest on such 1991 Series E Bond and all
notices with respect to such 1991 Series E Bond shall be made and given,
respectively, to DTC as provided in the Letter of Representation (the
"Representation Letter"), the form of which is included as Exhibit B attached
to this Second Supplement. The form of such Representation Letter may be
modified or replaced in a manner consistent with the provisions of the
Agreement upon conversion or reconversion of the 1991 Series E Bonds to a
Mode or Rate Period in which the Book-Entry Only System is in effect.
(f) Notwithstanding any provision in Subsection 301(h) or Section 310 of the
Original Agreement to the contrary, so long as any of the Bonds outstanding
are held in the Book-Entry Only System, if less than all of such Bonds are to
be converted or redeemed upon any conversion or redemption of Bonds
hereunder, the particular Bonds or portions of Bonds to be converted or
redeemed shall be selected by DTC in such manner as DTC may determine.
(g) So long as the Book-Entry Only System is in effect, a Beneficial Owner
who elects to have its Bonds purchased or tendered pursuant to the Agreement
shall effect delivery by causing a Participant to transfer the Beneficial
Owner's interest in the Bonds pursuant to the Book-Entry Only System. The
requirement for physical delivery of Bonds in connection with a demand for
purchase or a mandatory purchase will be deemed satisfied when the ownership
rights in the Bonds are transferred in accordance with the Book-Entry Only
System.
(h) So long as the Book-Entry Only System is in effect, the Remarketing
Agent shall communicate to DTC information concerning the purchasers of
Tendered Bonds as may be necessary or appropriate, and, notwithstanding any
provision in the Representation Letter to the contrary, the Remarketing Agent
shall continue to remit to the Paying Agent interest rate determination
information pursuant to the terms of the Agreement.
ARTICLE III: MISCELLANEOUS
Section 301. Original Agreement Affirmed. Except as otherwise expressly
supplemented and amended by this Second Supplement, the provisions of the
Original Agreement, the First Supplement and the Assumption Agreement remain
unchanged, binding, and in full force and effect.
Section 302. Severability. In the event that any provision of this Second
Supplement shall be held to be invalid in any circumstance, such invalidity
shall not affect any other provisions or circumstances.
Section 303. Counterparts. This Second Supplement may be executed and
delivered in any number of counterparts, each of which shall be deemed to be
an original, but such counterparts together shall constitute one and the same
instrument.
Section 304. Receipt of Documents. By its execution and delivery of this
Second Supplement the Trustee acknowledges receipt of the opinion of Bond
Counsel required to accompany this Second Supplement pursuant to Subsection
1101(c) of the Original Agreement.
Section 305. Captions. The captions and table of contents of this Second
Supplement are for convenience only and shall not affect the construction
hereof.
Section 306. Governing Law. This instrument shall be governed by the laws
of State of New Hampshire.
IN WITNESS WHEREOF, the Business Finance Authority of the State of New
Hampshire has caused this Second Supplement to be signed and its official
seal to be impressed hereon by its Executive Director; Public Service Company
of New Hampshire has caused this Second Supplement to be signed and its
corporate seal to be impressed hereon by an authorized officer; and State
Street Bank and Trust Company, as Trustee, has caused this Second Supplement
to be signed and its corporate seal to be impressed hereon by an authorized
officer.
BUSINESS FINANCE AUTHORITY OF
THE STATE OF NEW HAMPSHIRE
(Seal)
By:
/s/Jack Donovan
Executive Director
PUBLIC SERVICE COMPANY OF
NEW HAMPSHIRE
(Seal)
By:
/s/John B. Keane
Treasurer
STATE STREET BANK AND TRUST COMPANY
as Trustee
(Seal)
By:
/s/Daniel Golden
Assistant Vice President
The undersigned hereby consents
to this Second Supplement.
SWISS BANK CORPORATION, NEW YORK BRANCH
By:
Name:/s/Darryl M. Monasebian
Title:Associate Director
/s/Teresa A. Portela
Associate Director
Exhibit 4.3.7.3
EXECUTION COPY
AMENDED AND RESTATED
SECOND SERIES E LETTER OF CREDIT
AND REIMBURSEMENT AGREEMENT
Dated as of April 23, 1998
Among
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
as Account Party
SWISS BANK CORPORATION, STAMFORD BRANCH
(Successor to Swiss Bank Corporation, New York Branch)
as Issuing Bank and as Agent
and
THE PARTICIPATING BANKS
REFERRED TO HEREIN
Relating to
The Industrial Development Authority of the State of New Hampshire
Pollution Control Revenue Bonds (Public Service Company of
New Hampshire Project - 1991 Taxable Series E)
AMENDED AND RESTATED
SECOND SERIES E LETTER OF CREDIT
AND REIMBURSEMENT AGREEMENT
Dated as of April 23, 1998
This AMENDED AND RESTATED SECOND SERIES E LETTER OF CREDIT AND REIMBURSEMENT
AGREEMENT, dated as of April 23, 1998 (this "Agreement") is made by and
among:
(i) Public Service Company of New Hampshire, a corporation duly organized
and validly existing under the laws of the State of New Hampshire (the
"Account Party");
(ii) Swiss Bank Corporation, Stamford Branch (as successor to Swiss Bank
Corporation, New York Branch) ("Swiss Bank"), as issuer of the Letter of
Credit (the "Issuing Bank");
(iii) The Participating Banks (as hereinafter defined) from time to time
party hereto; and
(iv) Swiss Bank as agent (together with any successor agent hereunder, the
"Agent") for such Participating Banks and the Issuing Bank.
and restates in its entirety the Existing Reimbursement Agreement referred to
herein.
PRELIMINARY STATEMENT
The Business Finance Authority (formerly The Industrial Development
Authority) of the State of New Hampshire (the "Issuer"), pursuant to a Series
E Loan and Trust Agreement, dated as of May 1, 1991 (the "Original
Indenture"), by and among the Issuer, the Account Party and State Street Bank
and Trust Company, as trustee (such entity, or its successor as trustee,
being the "Trustee"), previously issued $114,500,000 aggregate principal
amount of The Industrial Development Authority of the State of New Hampshire
Pollution Control Revenue Bonds (Public Service Company of New Hampshire
Project - 1991 Taxable Series E) (such bonds being herein referred to as the
"Taxable Bonds"). Pursuant to the Original Indenture, a First Supplement
thereto, dated as of December 1, 1993 and a Second Supplement thereto, dated
as of May 1, 1995 (the Original Indenture, as so supplemented by such First
Supplement and such Second Supplement and as the same may be further
supplemented, amended or modified from time to time with the written consent
of the Issuing Bank, being herein referred to as the "Indenture"), the Issuer
refunded $44,800,000 aggregate principal amount of the Taxable Bonds through
the issuance of $44,800,000 aggregate principal amount of Business Finance
Authority of the State of New Hampshire Pollution Control Refunding Revenue
Bonds (Public Service Company of New Hampshire Project - 1993 Tax-Exempt
Series E) (such bonds being herein referred to as the "Existing Tax-Exempt
Refunding Bonds").
The Account Party previously caused Swiss Bank to issue its Irrevocable
Letter of Credit No. S561992, dated May 2, 1995 in a stated amount of
$119,129,000 (the "Existing Letter of Credit"), in support of the Taxable
Bonds and the Existing Tax-Exempt Refunding Bonds, and, in connection
therewith, the Account Party entered into a Second Series E Letter of Credit
and Reimbursement Agreement dated as of May 1, 1995 (the "Existing
Reimbursement Agreement") with Swiss Bank as issuing bank and agent
thereunder and the participating banks referred to therein.
The Account Party now wishes to extend and amend the Existing Letter of
Credit and, in furtherance thereof, the Account Party has requested the
Issuing Bank to issue the Letter of Credit Amendment (as defined herein) to
the Paying Agent. Following such extension and amendment and the Fixed-Rate
Conversion described herein, the aggregate amount of the Letter of Credit, as
so amended, will be $73,666,000 (the "Stated Amount"), of which (i)
$69,700,000 shall support the payment of principal of the Taxable Bonds (or
the portion of the purchase or redemption price of Bonds corresponding to
principal), (ii) $3,966,000 shall support the payment of up to 128 days'
interest on the principal amount of Taxable Bonds (or the portion of the
purchase or redemption price of Taxable Bonds corresponding to interest),
computed at a maximum interest rate of 16% per annum on the basis of the
actual days elapsed and a year of 360 days, subject to modification as
provided in Section 2.06 hereof, and (iii) $0.00 shall support the payment of
premium on Taxable Bonds. The Issuing Bank has agreed to issue the Letter of
Credit Amendment subject to the terms and conditions set forth herein and in
the Amendment to which this Agreement is appended as Exhibit A (including the
terms and conditions relating to the rights and obligations of the
Participating Banks).
NOW, THEREFORE, in consideration of the premises set forth herein, the
parties hereto agree as follows:
ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS
SECTION I.1. Certain Defined Terms. In addition to the terms defined in the
Preliminary Statement hereto, as used in this Agreement, the following terms
shall have the following meanings (such meanings to be applicable to the
singular and plural forms of the terms defined):
"Advances" means Initial Advances and Term Advances, without differentiation;
individually, an "Advance".
"Affiliate" means, with respect to a specified Person, another Person that
directly or indirectly through one or more intermediaries controls or is
controlled by or is directly or indirectly under common control with such
Person. A Person shall be deemed to control another entity if such Person
possesses, directly or indirectly, the power to direct or cause the direction
of the management and policies of such entity, whether through the ownership
of voting securities, by contract or otherwise.
"Agreement for Capacity Transfer" means the Agreement for Capacity Transfer,
dated as of December 1, 1989, between The Connecticut Light and Power Company
("CL&P") and the Account Party, as amended by the First Amendment to
Agreement for Capacity Transfer, dated as of May 1, 1992 between CL&P and the
Account Party, which provides for capacity transfers from the Account Party
to CL&P.
"Alternate Base Rate" means, for any period, a fluctuating interest rate per
annum equal at all times to the higher from time to time of:
(a) the rate of interest announced publicly by Swiss Bank in New York, New
York, from time to time, as Swiss Bank's prime rate; and
(b) 1/2 of one percent per annum above the Federal Funds Rate from time to
time;
plus, in either case, the Applicable Margin for Base Rate Advances. Each
change in the Alternate Base Rate shall take effect concurrently with any
change in such prime rate or Federal Funds Rate, as the case may be.
"Amendment" means the First Amendment to the Existing Reimbursement
Agreement, to which this Agreement is appended as Exhibit A.
"Amendment Closing Date" means the Business Day upon which each of the
conditions precedent enumerated in Sections 3.01 and 3.02 of the Amendment
shall be fulfilled to the satisfaction of the Agent, the Issuing Bank, the
Participating Banks and the Account Party. All transactions contemplated to
occur on the Amendment Closing Date shall occur contemporaneously on or prior
to April 23, 1998, at the offices of King & Spalding, 1185 Avenue of the
Americas, New York, New York 10036, at 12:01 A.M. (New York City time), or at
such other place and time as the parties hereto may mutually agree.
"Applicable Commission" means, for any day, two and one-quarter percent
(2.25%).
"Applicable Lending Office" means, with respect to each Participating Bank,
(i) (A) such Participating Bank's "Domestic Lending Office", in the case of a
Base Rate Advance, and (B) such Participating Bank's "Eurodollar Lending
Office," in the case of a Eurodollar Rate Advance, in each case as specified
opposite such Participating Bank's name on Schedule I hereto (in the case of
a Participating Bank initially party to this Agreement) or in the
Participation Assignment pursuant to which such Participating Bank became a
Participating Bank (in the case of any other Participating Bank), or (ii)
such other office or affiliate of such Participating Bank as such
Participating Bank may from time to time specify to the Account Party and the
Agent.
"Applicable Margin" means, for any day: (i) two and one-quarter percent
(2.25%), for any outstanding Eurodollar Rate Advance, and (ii) one and one-
quarter percent (1.25%), for any outstanding Base Rate Advance.
"Arrangers" means Barclays Bank PLC and SBC Warburg Dillon Read, Inc.
"Available Amount" in effect at any time means the maximum aggregate amount
available to be drawn at such time under the Letter of Credit, the
determination of such maximum amount to assume compliance with all conditions
for drawing and no reduction for (i) any amount drawn by the Paying Agent to
make a regularly scheduled payment of interest on the Bonds (unless such
amount will not be reinstated under the Letter of Credit) or (ii) any amount
not available to be drawn because Bonds are held by or for the account of the
Account Party and/or in pledge for the benefit of the Issuing Bank, but after
giving effect nevertheless, to any reduction in the Stated Amount effected
pursuant to Section 2.06 hereof.
"Bankruptcy Code" means Title 11 of the United States Code, as the same may
be amended from time to time, or any successor bankruptcy law of the United
States.
"Base Rate Advance" means an Advance in respect of which the Account Party
has selected in accordance with Article III hereof, or this Agreement
otherwise provides for, interest to be computed on the basis of the Alternate
Base Rate.
"Bonds" means (i) the Taxable Bonds outstanding as of the date hereof, (ii)
the Existing Tax-Exempt Refunding Bonds and (iii) any further Tax-Exempt
Refunding Bonds (as defined in the Indenture) that may be issued in
accordance with the Indenture and this Agreement to refund any of such
remaining Taxable Bonds; provided, however, that upon the Fixed-Rate
Conversion and reimbursement to the Issuing Bank and the Participating Banks
of the Fixed-Rate Conversion Drawing, the Existing Tax-Exempt Refunding Bonds
shall cease to be Bonds hereunder.
"Business Day" means a day of the year that is not a Sunday, legal holiday or
a day on which banks are required or authorized to close in New York City
and, (i) if the applicable Business Day relates to any Eurodollar Rate
Advance, is a day on which dealings are carried on in the London interbank
market and/or (ii) if the applicable Business Day relates to any action to be
taken by, or notice furnished to or by, or payment to be made to or by, the
Trustee, the Paying Agent, the Remarketing Agent or the First Mortgage
Trustee, is a day on which (A) banking institutions are not authorized
pursuant to law to close, (B) the corporate trust office of the First
Mortgage Trustee is open for business, (C) banking institutions in all of the
cities in which the principal offices of the Issuing Bank, the Trustee, the
Paying Agent, the First Mortgage Trustee and, if applicable, the Remarketing
Agent are located are not required or authorized to remain closed and (D) the
New York Stock Exchange is not closed.
"Cash Account" has the meaning assigned to that term in Section 7.05(a).
"CL&P" has the meaning assigned to that term in the definition of Agreement
for Capacity Transfer.
"Citibank" means Citibank, N.A.
"Collateral" means all of the collateral in which liens, mortgages or
security interests are purported to be granted by any or all of the Security
Documents.
"Collateral Agent" means The Chase Manhattan Bank and any successor as
collateral agent under the Intercreditor Agreement.
"Commitment" means, for each Participating Bank, such Participating Bank's
Percentage of the Available Amount. "Commitments" shall refer to the
aggregate of the Commitments.
"Common Equity" means, at any date, an amount equal to the sum of the
aggregate of the par value of or stated capital represented by, the
outstanding shares of common stock of the Account Party and the surplus,
paid-in, earned and other, if any, of the Account Party.
"Confidential Information" has the meaning assigned to that term in Section
10.09 hereof.
"Conversion", "Convert" or "Converted" each refers to a conversion of Term
Advances pursuant to Section 3.04 hereof, including, but not limited to any
selection of a longer or shorter Interest Period to be applicable to such
Term Advances or any conversion of a Term Advance as described in Section
3.04(c) hereof.
"Credit Termination Date" means the date on which the Letter of Credit shall
terminate in accordance with its terms.
"date hereof" means April 23, 1998.
"Debt" means, for any Person, without duplication, (i) indebtedness of such
Person for borrowed money, (ii) obligations of such Person evidenced by
bonds, debentures, notes or other similar instruments, (iii) obligations of
such Person to pay the deferred purchase price of property or services, (iv)
obligations of such Person as lessee under leases which shall have been or
should be, in accordance with generally accepted accounting principles,
recorded as capital leases (not including the Unit Contract), (v) obligations
(contingent or otherwise) of such Person under reimbursement or similar
agreements with respect to the issuance of letters of credit (vi) net
obligations (contingent or otherwise) of such Person under interest rate
swap, "cap", "collar" or other hedging agreements, (vii) obligations of such
person to pay rent or other amounts under leases entered into in connection
with sale and leaseback transactions involving assets of such Person being
sold in connection therewith, (viii) obligations under direct or indirect
guaranties in respect of, and obligations (contingent or otherwise) to
purchase or otherwise acquire, or otherwise to assure a creditor against loss
in respect of, indebtedness or obligations of others of the kinds referred to
in clauses (i) through (vii), above, and (ix) liabilities in respect of
unfunded vested benefits under ERISA Plans.
"Default Rate" means a fluctuating interest rate equal at all times to 2% per
annum above the rate applicable to Base Rate Advances at such time.
"Disclosure Documents" means the Information Memorandum, the 1997 10-K and
any Current Report on Form 8-K filed by the Account Party with the Securities
and Exchange Commission after December 31, 1997 furnished to the
Participating Banks prior to the execution and delivery of the Amendment.
"ERISA" means the Employee Retirement Income Security Act of 1974, as amended
from time to time.
"ERISA Affiliate" means any trade or business (whether or not incorporated,
that, together with the Account Party is treated as a single employer under
Section 414(b) or (c) of the Code or, solely for purposes of Section 302 of
ERISA and Section 412 of the Code, is treated as a single employer under
Section 414 of the Code.
"ERISA Multiemployer Plan" means a "multiemployer plan" subject to Title IV
of ERISA.
"ERISA Plan" means an employee benefit plan (other than an ERISA
Multiemployer Plan) maintained for employees of the Account Party or any
ERISA Affiliate and covered by Title IV of ERISA.
"ERISA Plan Termination Event" means (i) a "reportable event", as defined in
Section 4043 of ERISA or the regulations issued thereunder (other than an
event for which the 30-day notice period is waived) with respect to an ERISA
Plan or an ERISA Multiemployer Plan, or (ii) the existence with respect to
any ERISA plan of an "accumulated funding deficiency" (as defined in Section
412(d) of the Code or Section 302 of ERISA), whether or not waived; (iii) the
filing pursuant to Section 412(d) of the Code or Section 303(d) of ERISA of
an application for a waiver of the minimum funding standard with respect to
any ERISA Plan; (iv) the incurrence by the Account Party or any of its ERISA
Affiliates of any liability under Title IV or ERISA with respect to the
termination of any ERISA Plan; (v) the receipt by Account Party or any of its
ERISA Affiliates from the PBGC or a plan administrator of any notice relating
to an intention to terminate any ERISA Plan or an ERISA Multiemployer Plan
under Section 4041 of ERISA or to appoint a trustee to administer any ERISA
Plan or ERISA Multiemployer Plan; (vi) the receipt by the Account Party or
any of its ERISA Affiliates of any notice, or the receipt by an ERISA
Multiemployer Plan from the Account Party or any of its ERISA Affiliates of
any notice, concerning the imposition of liability due to any withdrawal of
the Account Party or any of its ERISA Affiliates from an ERISA Plan or an
ERISA Multiemployer Plan during a plan year in which it was a "substantial
employer" as defined in Section 4001(a)(2) of ERISA, or a determination that
an ERISA Multiemployer Plan is, or is expected to be, insolvent or in
reorganization, within the meaning of Title IV of ERISA or (vii) any other
event or condition which might constitute grounds under Section 4042 of ERISA
for the termination of, or the appointment of a trustee to administer, any
ERISA Plan or ERISA Multiemployer Plan.
"Eurocurrency Liabilities" has the meaning assigned to that term in
Regulation D of the Board of Governors of the Federal Reserve System, as in
effect from time to time.
"Eurodollar Rate" means for any Interest Period for any Eurodollar Rate
Advances comprising part of the same Term Borrowing, an interest rate per
annum equal at all times during such Interest Period to the sum of:
(i) the rate per annum (rounded upward to the nearest whole multiple of
1/100 of 1% per annum, if such rate is not such a multiple) determined by the
Agent at which deposits in United States dollars in amounts comparable to the
Eurodollar Rate Advance of Swiss Bank comprising part of such Term Borrowing
and for comparable periods as such Interest Period are offered by the
principal office of Swiss Bank in London, England to prime banks in the
London interbank market at 11:00 A.M. (London time) two Business Days before
the first day of such Interest Period, plus
(ii) the Applicable Margin.
"Eurodollar Rate Advance" means an Advance in respect of which the Account
Party has selected in accordance with Article III hereof, and this Agreement
provides for, interest to be computed on the basis of the Eurodollar Rate.
"Eurodollar Reserve Percentage" of any Participating Bank for each Interest
Period for each Eurodollar Rate Advance means the reserve percentage
applicable during such Interest Period (or if more than one such percentage
shall be so applicable, the daily average of such percentages for those days
in such Interest Period during which any such percentage shall be so
applicable) under Regulation D or other regulations issued from time to time
by the Board of Governors of the Federal Reserve System (or any successor)
for determining the maximum reserve requirement (including, without
limitation, any emergency, supplemental or other marginal reserve
requirement, without benefit of or credit for proration, exemptions or
offsets) for such Participating Bank with respect to liabilities or assets
consisting of or including "eurocurrency liabilities" having a term equal to
such Interest Period.
"Event of Default" has the meaning assigned to that term in Section 8.01.
"Existing Letter of Credit" has the meaning assigned to that term in the
Preliminary Statement.
"Existing Reimbursement Agreement" has the meaning assigned to that term in
the Preliminary Statement.
"Existing Tax-Exempt Refunding Bonds" has the meaning assigned to that term
in the Preliminary Statement.
"Extension Collateral" has the meaning assigned to that term in Section
7.05(b).
"Federal Funds Rate" means, for any period, a fluctuating interest rate per
annum equal for each day during such period to the weighted average of the
rates on overnight Federal funds transactions with members of the Federal
Reserve System arranged by Federal funds brokers, as published on the next
succeeding Business Day by the Federal Reserve Bank of New York, or, if such
rate is not so published on the next succeeding Business Day, the average of
the quotations for such day on such transactions received by the Agent from
three Federal funds brokers of recognized standing selected by it.
"Final Plan" means the "Final Plan" implementing Chapter 374-F of the Revised
Statutes Annotated of New Hampshire, adopted by the NHPUC on February 28,
1997, and any successor plan or proposal.
"First Mortgage Bonds" means first mortgage bonds issued or to be issued by
the Account Party and secured, directly or indirectly, collectively or
severally, by one or more first-priority liens on all or part of the
Indenture Assets pursuant to the First Mortgage Indenture or another
indenture in form and substance satisfactory to the Majority Lenders. For
purposes hereof, all or part of the First Mortgage Bonds may be issued as
collateral for pollution control revenue bonds or industrial revenue bonds,
whether taxable or tax exempt issued by the Account Party or by a
governmental authority at the Account Party's request.
"First Mortgage Indenture" means the General and Refunding Mortgage
Indenture, between the Account Party and New England Merchants National Bank,
as trustee and to which First Union National Bank is successor trustee, dated
as of August 15, 1978, as amended and supplemented through the date hereof
and as the same may thereafter be amended, supplemented or modified from time
to time.
"First Mortgage Trustee" means the trustee from time to time under the First
Mortgage Indenture.
"Fixed-Rate Conversion" means the Conversion (as defined in the Indenture) of
the Existing Tax-Exempt Refunding Bonds to the Fixed-Rate Mode (as defined in
the Indenture), which Conversion is proposed to occur on May 1, 1998.
"Fixed-Rate Conversion Drawing" means the Tender Drawing and the related
Interest Drawing (as those terms are defined in the Letter of Credit) to
effect the purchase on May 1, 1998 of the Existing Tax-Exempt Refunding Bonds
immediately prior to the Fixed-Rate Conversion.
"Governmental Approval" means any authorization, consent, approval, license,
permit, certificate, exemption of, or filing or registration with, any
governmental authority or other legal or regulatory body required in
connection with any of: (i) the execution, delivery or performance of the
Rate Agreement, any Transaction Document, Loan Document, Related Document or
Significant Contract, (ii) the grant and perfection of any security interest,
lien or mortgage contemplated by the Security Documents, (iii) the nature of
the Account Party's business as conducted or the nature of the property owned
or leased by it or (iv) any NUG Settlement. For purposes of this Agreement,
Chapter 362-C of the Revised Statutes Annotated of New Hampshire, in effect
on the Original Closing Date, shall be deemed to be a Governmental Approval.
"Hazardous Substance" means any waste, substance or material identified as
hazardous, dangerous or toxic by any office, agency, department, commission,
board, bureau or instrumentality of the United States of America or of the
State or locality in which the same is located having or exercising
jurisdiction over such waste, substance or material.
"Indemnified Person" has the meaning assigned to that term in Section
10.04(b) hereof.
"Indenture" has the meaning assigned to that term in the Preliminary
Statement.
"Indenture Assets" means fixed assets of the Account Party (including related
Governmental Approvals and regulatory assets) which from time to time are
subject to the first-priority lien under the First Mortgage Indenture.
"Information Memorandum" means the Confidential Information Memorandum, dated
February, 1998 regarding the Account Party, as distributed to the Issuing
Bank and the Participating Banks, including, without limitation, all
schedules, attachments and supplements, if any, thereto.
"Initial Advance" has the meaning assigned to that term in Section 3.02(a)
hereof.
"Initial Repayment Date" has the meaning assigned to that term in Section
3.02(a) hereof.
"Intercreditor Agreement" means the Collateral Agency and Intercreditor
Agreement, dated as of the date hereof, among the Agent, Barclays Bank PLC,
New York Branch as "Agent" under the Other Reimbursement Agreement and The
Chase Manhattan Bank, as Administrative Agent under the Revolving Credit
Agreement and as Collateral Agent.
"Interest Component" has the meaning assigned to that term in the Letter of
Credit.
"Interest Drawing" has the meaning assigned to that term in the Letter of
Credit.
"Interest Expense" means, for any period, the aggregate amount of any
interest on Debt (including long-term and short-term Debt).
"Interest Period" has the meaning assigned to that term in Section 3.03(b)
hereof.
"Issuer" has the meaning assigned to that term in the Preliminary Statement.
"Issuer Resolution" means the resolution adopted by the Issuer that
authorized the issuance of the Bonds, approved the terms and provisions of
the Bonds, and approved those of the documents related to the Bonds to which
the Issuer is a party.
"Letter of Credit" means the Existing Letter of Credit, issued in the form of
Exhibit 1.01A to the Existing Agreement, as extended and amended by the
Letter of Credit Amendment, and as it may from time to time be further
extended, amended or otherwise modified pursuant to the terms of this
Agreement.
"Letter of Credit Amendment" means the First Amendment to Irrevocable Letter
of Credit issued by the Issuing Bank in favor of the Paying Agent, in
substantially the form of Exhibit 1.01A-2 hereto.
"Lien" has the meaning assigned to that term in Section 7.02(a) hereof.
"Loan Documents" means this Agreement and the Security Documents, as each may
be amended, supplemented or otherwise modified from time to time.
"Major Electric Generating Plants" means the following nuclear, combustion
turbine and coal, oil or diesel-fired generating stations of the Account
Party: the Merrimack generating station located in Bow, New Hampshire; the
Newington generating station located in Newington, New Hampshire; the
Schiller generating station located in Portsmouth, New Hampshire; the White
Lake combustion turbine located in Tamworth, New Hampshire; the Millstone
Unit No. 3 generating station located in Waterford, Connecticut, and the
Wyman Unit No. 4 generating station located in Yarmouth, Maine.
"Majority Lenders" means on any date of determination, (i) the Issuing Bank
and (ii) Participating Banks who, collectively, on such date, have
Participation Percentages in the aggregate of at least 66-2/3%. Determination
of those Participating Banks satisfying the criteria specified above for
action by the Majority Lenders shall be made by the Agent and shall be
conclusive and binding on all parties absent manifest error.
"Material Adverse Effect" means a material adverse effect upon: (i) the
Account Party's business, prospects, operations, properties, assets, or
condition (financial or otherwise), (ii) the Account Party's ability to
perform under any Loan Document, Related Document, the Rate Agreement or any
Significant Contract, (iii) the value, validity, perfection and
enforceability of the any Lien granted under or in connection with any
Security Document, or (iv) the ability of the Collateral Agent, the Agent or
the Issuing Bank to enforce any of the obligations or any of their material
rights and remedies under the Loan Documents; provided, that, any material
adverse development with respect to the Rate Proceeding, the Rate Agreement
or the Final Plan that results in a material adverse effect on the Account
Party other than as described in the Disclosure Documents shall automatically
be deemed to be a Material Adverse Effect.
"Merger" means (i) the merger on June 5, 1992 of NU Acquisition Corp., a
wholly-owned subsidiary of NU, with and into the Account Party and (ii) the
transfer on the same date by the Account Party, as so merged, of its right,
title and interest in Seabrook to NAEC.
"Moody's" means Moody's Investors Service, Inc. or any successor thereto.
"NAEC" means North Atlantic Energy Corporation, a wholly-owned subsidiary of
NU.
"NHPUC" means the New Hampshire Public Utilities Commission.
"1997 10-K" means the Account Party's 1997 Annual Report and its Annual
Report on Form 10-K for the fiscal year ended December 31, 1997.
"NU" means Northeast Utilities, an unincorporated voluntary business
association organized under the laws of the Commonwealth of Massachusetts.
"NUG Settlement" means any buy-out, buy-down or other transaction, or any
other arrangement or agreement, entered into or proposed to be entered into
by the Account Party to terminate or reduce, or to resolve a dispute
concerning, an obligation of the Account Party to purchase power and/or
capacity from a non-utility generator.
"NUSCO" means Northeast Utilities Service Company, a Connecticut corporation
and a wholly-owned subsidiary of NU.
"Official Statement" means any Official Statement, Preliminary Official
Statement or similar disclosure document relating to the Bonds (including in
connection with the Fixed-Rate Conversion), and shall include any amendment,
supplement or "sticker" thereto.
"Operating Income" means, for any period, the Account Party's operating
income for such period, adjusted as follows:
(i) increased by the amount of income taxes (including New Hampshire
Business Profits Tax and other comparable taxes) paid by the Account Party
during such period, if and to the extent they are deducted in the computation
of the Account Party's operating income for such period; and
(ii) increased by the amount of any depreciation deducted by the Account
Party during such period; and
(iii) increased by the amount of any amortization of acquisition
adjustment deducted by the Account Party during such period; and
(iv) decreased by the amount of any capital expenditures paid by the Account
Party during such period.
"Original Closing Date" means the Business Day upon which each of the
conditions precedent enumerated in Sections 5.01 and 5.02 of the Existing
Reimbursement Agreement were fulfilled to the satisfaction of the Agent, the
Issuing Bank, the Participating Banks and the Account Party, which date was
May 2, 1995.
"Original Indenture" has the meaning assigned to that term in the Preliminary
Statement.
"Other Reimbursement Agreement" means (i) the Second Series D Letter of
Credit and Reimbursement Agreement, dated as of May 1, 1995, among the
Account Party, Barclays Bank PLC, New York Branch, as issuing bank and agent
thereunder and the Participating Banks referred to therein relating to the
Issuer's Pollution Control Revenue Bonds (Public Service Company of New
Hampshire Project-1991 Taxable Series D) and the Issuer's Pollution Control
Refunding Revenue Bonds (Public Service Company of New Hampshire Project-1992
Tax-Exempt Series D), as amended by the Other Reimbursement Agreement
Amendment and as the same may from time to time be further amended, modified
or supplemented or (ii) any reimbursement agreement or similar agreement
relating to a substitute credit facility applicable to such bonds.
"Other Reimbursement Agreement Amendment" means the First Amendment, dated
the date hereof, to the Other Reimbursement Agreement.
"Participant" shall have the meaning assigned to that term in Section
10.06(b) hereof.
"Participating Banks" means: (i) as of any date of determination prior to the
Letter of Credit Amendment becoming effective in accordance with its terms,
the Participating Banks parties to the Existing Reimbursement Agreement and
(ii) thereafter, the Persons listed on the signature pages to the Amendment
following the heading "Participating Banks" and any other Person who becomes
a party hereto pursuant to Section 10.06 hereof.
"Participation Assignment" means a participation assignment entered into
pursuant to Section 10.06 hereof by any Participating Bank and an assignee,
in substantially the form of Exhibit 1.01B hereto.
"Participation Percentage" means, with respect to any Participating Bank: (i)
as of any date of determination prior to the Letter of Credit Amendment
becoming effective in accordance with its terms, such Participating Bank's
Participation Percentage as determined pursuant to the Existing Reimbursement
Agreement (which, in the case of Barclays Bank PLC, New York Branch is zero);
(ii) thereafter, (A) with respect to a Participating Bank initially a party
to this Agreement, the percentage set forth opposite such Participating
Bank's name on Schedule II to the Amendment, except as provided in clause
(iii), below and (B) with respect to a Participating Bank that becomes a
party hereto by operation of Section 10.06(a) hereof, the Participation
Percentage stated to be assumed by such assignee Participating Bank in the
relevant Participation Assignment, except as provided in clause (iii), below,
and (iii) at any time, with respect to any Participating Bank that assigns a
percentage of its interests in accordance with Section 10.06(a) hereof, its
Participation Percentage determined in accordance with clause (i) or clause
(ii), above, as reduced by the percentage so assigned.
"Paying Agent" means (i) U.S. Bank Trust National Association (formerly First
Trust of New York, National Association), as the paying agent for the Bonds
under the Indenture, and (ii) any successor paying agent for the Bonds under
the Indenture.
"PBGC" means the Pension Benefit Guaranty Corporation (or any successor
entity) established under ERISA.
"Permitted Investments" means (i) securities issued or directly and fully
guaranteed or insured by the United States or any agency or instrumentality
thereof (provided that the full faith and credit of the United States is
pledged in support thereof) having maturities of not more than six (6) months
from the date of acquisition by such Person; (ii) time deposits and
certificates of deposit, with maturities of not more than six (6) months from
the date of acquisition by such Person, of any international commercial bank
of recognized standing having capital and surplus in excess of $500,000,000
and having a rating on its commercial paper of at least A-1 or the equivalent
thereof by S&P or at least P-1 or the equivalent thereof by Moody's; (iii)
commercial paper issued by any Person, which commercial paper is rated at
least A-1 or the equivalent thereof by S&P or at least P-1 or the equivalent
thereof by Moody's and matures not more than six (6) months after the date of
acquisition by such Person; (iv) investments in money market funds
substantially all the assets of which are comprised of securities of the
types described in clauses (i) and (ii) above and (v) United States
Securities and Exchange Commission registered money market mutual funds
conforming to Rule 2a-7 of the Investment Company Act of 1940 in effect in
the United States, that invest primarily in direct obligations issued by the
United States Treasury and repurchase obligations backed by those
obligations, and rated in the highest category by S&P and Moody's.
"Person" means an individual, partnership, corporation (including a business
trust), limited liability company, joint stock company, trust, estate,
unincorporated association, joint venture or other entity, or a government or
any political subdivision or agency thereof.
"Plan" means that certain Third Amended Joint Plan of Reorganization of the
Account Party, dated December 28, 1989, as confirmed by order of the United
States Bankruptcy Court for the District of New Hampshire on April 20, 1990.
"Pledge Agreement" means the Series E Pledge Agreement, dated as of May 1,
1991, by the Account Party in favor of Citibank, as amended by a First
Amendment thereto, dated as of May 1, 1995 among the Account Party, Citibank
and Swiss Bank, as agent and issuing bank under the Existing Reimbursement
Agreement, and as the same may from time to time be amended, modified or
supplemented.
"Pledged Bonds" shall have the meaning assigned to that term in the Pledge
Agreement.
"Preferred Stock" means 5,000,000 shares of Series A Preferred Stock of the
Account Party (par value $25).
"Premium Component" has the meaning assigned to that term in the Letter of
Credit.
"Principal Component" has the meaning assigned to that term in the Letter of
Credit.
"Rate Agreement" means the Agreement dated as of November 22, 1989, as
amended by the First Amendment to Rate Agreement dated as of December 5,
1989, the Second Amendment to Rate Agreement dated as of December 12, 1989,
the Third Amendment to Rate Agreement dated as of December 28, 1993, the
Fourth Amendment to Rate Agreement dated as of September 21, 1994 and the
Fifth Amendment to Rate Agreement dated as of September 9, 1994, among NUSCO,
the Governor and Attorney General of the State of New Hampshire and adopted
by the Account Party as of July 10,1990 (excluding the Unit Contract appended
as Exhibit A thereto subsequent to the effectiveness of such contract).
"Rate Proceeding" means all regulatory proceedings relating to the Account
Party and resulting from the NHPUC's adoption of the Final Plan, together
with the Federal litigation commenced by the Account Party and certain of its
Affiliates in response thereto.
"Recipient" has the meaning assigned to that term in Section 10.09 hereto.
"Related Documents" means the Letter of Credit, the Bonds, the Indenture and
any Remarketing Agreement.
"Remarketing Agent" has the meaning assigned to that term in the Indenture.
"Remarketing Agreement" means (i) the Remarketing Agreement, dated as of May
1, 1991, between the Account Party and Goldman, Sachs Money Markets Inc.
relating to the Taxable Bonds, (ii) the Remarketing Agreement, dated as of
December 1, 1992, between the Account Party and Goldman, Sachs & Co. relating
to the Existing Tax-Exempt Refunding Bonds, (iii) any similar agreement
subsequently entered into with respect to any other Tax-Exempt Refunding
Bonds and (iv) any successor agreement to any of the foregoing or any similar
agreement between the Account Party and a successor Remarketing Agent as
shall be in effect from time to time in accordance with the terms of the
Indenture.
"Restricted Payment" has the meaning assigned to that term in Section 7.02(e)
hereof.
"Revolving Credit Agent" means The Chase Manhattan Bank and any successor as
"Administrative Agent" under (and as defined in) the Revolving Credit
Agreement.
"Revolving Credit Agreement" means the $75,000,000 (original principal
amount) Revolving Credit Agreement, dated as of the date hereof, among the
Account Party, the Banks and Co-Agents named therein, and The Chase Manhattan
Bank, as Administrative Agent; in each case as amended, modified or
supplemented to the date hereof and as the same may be further amended,
modified or supplemented from and after the date hereof.
"Revolving Credit Lenders" means the Lenders from time to time under (and as
defined in) the Revolving Credit Agreement.
"S&P" means Standard and Poor's Ratings Group or any successor thereto.
"Seabrook" means the nuclear-fueled, steam-electric generating plant at a
site located in Seabrook, New Hampshire, and the related real property
interests and other fixed assets of such plant.
"Secured Party" has the meaning assigned to that term in the Intercreditor
Agreement.
"Security Agreement" means the Assignment and Security Agreement, dated as of
the date hereof, between the Account Party and the Collateral Agent, pursuant
to which the Account Party has granted to the Collateral Agent a security
interest in certain of the Account Party's accounts receivable, as the same
may be amended, modified or supplemented from time to time in accordance with
this Agreement and the Intercreditor Agreement.
"Security Documents" means the Pledge Agreement, the Security Agreement, the
Intercreditor Agreement, the Indenture, the First Mortgage Indenture and the
Series F First Mortgage Bonds.
"Series F First Mortgage Bonds" means the Account Party's Series F First
Mortgage Bonds.
"Sharing Agreement" means the Sharing Agreement, dated as of June 1, 1992,
among CL&P, Western Massachusetts Electric Company, Holyoke Water Power
Company, Holyoke Power and Electric Company, the Account Party and NUSCO.
"Significant Contract" means the following contracts, in each case as the
same may be amended, modified or supplemented from time to time in accordance
with this Agreement:
(i) the Agreement for Capacity Transfer;
(ii) the Sharing Agreement;
(iii) the Tax Allocation Agreement; and
(iv) the Unit Contract.
"Stated Amount" has the meaning assigned to that term in the Preliminary
Statement hereto.
"Stated Termination Date" means the expiration date specified in clause (i)
of the first paragraph of Paragraph (1) of the Letter of Credit, as such date
may be extended pursuant to Section 2.05 hereof
"Tax Allocation Agreement" means the Amended and Restated Tax Allocation
Agreement, dated as of January 1, 1990, among NU and the members of the
consolidated group of which NU is the common parent, including, without
limitation, the Account Party.
"Taxable Bonds" has the meaning assigned to that term in the Preliminary
Statement.
"Tender Drawing" has the meaning assigned to that term in the Letter of
Credit.
"Term Advance" has the meaning assigned to that term in Section 3.02(b)
hereof, and refers to a Base Rate Advance or a Eurodollar Rate Advance (each
of which shall be a "Type" of Term Advance). The Type of a Term Advance may
change from time to time when such Term Advance is Converted. For purposes
of this Agreement, all Term Advances of a Participating Bank (or portions
thereof) made as, or Converted to, the same Type and Interest Period on the
same day shall be deemed a single Term Advance by such Participating Bank
until repaid or next Converted.
"Term Borrowing" means a borrowing consisting of Term Advances of the same
Type and Interest Period made on the same day by the Participating Banks,
ratably in accordance with their respective Participation Percentages. A
Term Borrowing may be referred to herein as being a "Type" of Term Borrowing,
corresponding to the Type of Term Advances comprising such Term Borrowing.
For purposes of this Agreement, all Term Advances made as, or Converted to,
the same Type and Interest Period on the same day shall be deemed a single
Term Borrowing until repaid or next Converted.
"Termination Date" means the Stated Termination Date or the earlier date of
termination of the Commitments pursuant to Sections 2.02 or 8.02 hereunder.
"Total Capitalization" means, as of any day, the aggregate of all amounts
that would, in accordance with generally accepted accounting principles
applied on a basis consistent with the standards referred to in Section 1.03
hereof, appear on the balance sheet of the Account Party as at such day as
the sum of (i) the principal amount of all long-term Debt of the Account
Party on such day, (ii) the par value of, or stated capital represented by,
the outstanding shares of all classes of common and preferred shares of the
Account Party on such day, (iii) the surplus of the Account Party, paid-in,
earned and other, if any, on such day and (iv) the unpaid principal amount of
all short-term Debt of the Account Party on such day.
"Transaction Documents" means the Amendment, this Agreement, the
Intercreditor Agreement, the Security Agreement, the Revolving Credit
Agreement, the Other Reimbursement Agreement Amendment and the other
documents to be delivered by or on behalf of the Account Party on or in
connection with the Amendment Closing Date.
"Trustee" has the meaning assigned to that term in the Preliminary Statement
hereto.
"Type" has the meaning assigned to such term in the definitions of "Term
Advance" and "Term Borrowing" herein.
"Unit Contract" means the Unit Contract, dated as of June 1, 1992, between
the Account Party and NAEC.
"Unmatured Default" means the occurrence and continuance of an event which,
with the giving of notice or lapse of time or both, would constitute an Event
of Default.
SECTION I.2. Computation of Time Periods. In the computation of periods of
time under this Agreement any period of a specified number of days or months
shall be computed by including the first day or month occurring during such
period and excluding the last such day or month. In the case of a period of
time "from" a specified date "to" or "until" a later specified date, the word
"from" means "from and including" and the words "to" and "until" each means
"to but excluding".
SECTION I.3. Accounting Terms. All accounting terms not specifically defined
herein shall be construed in accordance with generally accepted accounting
principles applied on a basis consistent with the application employed in the
preparation of the financial projections and pro formas referred to in
Section 5.01 hereof.
SECTION I.4. Computations of Outstandings. Whenever reference is made in
this Agreement to the principal amount outstanding on any date under this
Agreement, such reference shall refer to the sum of (i) the Available Amount
on such date, (ii) the aggregate principal amount of all Advances outstanding
on such date and (iii) the aggregate amount of all demand loans under Section
3.01 hereunder on such date, in each case after giving effect to all
transactions to be made on such date and the application of the proceeds
thereof.
ARTICLE II
THE LETTER OF CREDIT
SECTION II.1. The Letter of Credit. The Issuing Bank issued the Existing
Letter of Credit on the Original Closing Date. The Issuing Bank agrees, on
the terms and conditions hereinafter set forth (including, without
limitation, the applicable conditions precedent set forth in the Amendment),
to issue the Letter of Credit Amendment to the Paying Agent, upon not less
than three Business Days prior notice from the Account Party, on the
Amendment Closing Date.
SECTION II.2. Termination of the Commitments. The obligation of the Issuing
Bank to issue the Letter of Credit Amendment shall automatically terminate if
not delivered at or prior to 5:00 P.M. (New York City time) on May 1, 1998.
SECTION II.3. Commissions and Fees. (a) The Account Party hereby agrees to
pay to the Agent, for the account of the Participating Banks ratably in
accordance with their respective Participation Percentages, a letter of
credit commission on the Available Amount in effect from time to time from
the date hereof until the Letter of Credit shall be surrendered for
cancellation (disregarding for such purpose any temporary diminution thereof
arising from drawings under the Letter of Credit to pay interest (or purchase
price corresponding to interest) on the Bonds, regardless of whether the
amount so drawn shall be thereafter reinstated), at a rate per annum equal to
the Applicable Commission, payable on the last business day of each month and
upon such surrender ; provided that if an Event of Default shall have
occurred and is continuing, the Applicable Commission in effect from time to
time shall be increased by a further 2%.
(b) The Account Party also agrees to pay to the Agent for the account of the
Participating Banks ratably in accordance with their respective Participation
Percentages, such participation fees as have been agreed among them, the
Account Party and the Agent, such participation fee to be payable in full
simultaneously with the issuance of the Letter of Credit Amendment.
(c) The Account Party also agrees to pay to the Agent, for the account of
the Issuing Bank, such other fees as have been agreed upon by the Account
Party and the Issuing Bank in that certain Fee Letter, dated February 25,
1998, between the Account Party and the Arrangers (the "Fee Agreement").
(d) The Account Party also agrees to pay to the Agent, for its own account
and/or the account of Swiss Bank, such other fees as have been agreed upon by
the Account Party and the Agent in the Fee Agreement.
SECTION II.4. Reinstatement of the Letter of Credit. (a) The Interest
Component and the Principal Component shall, from time to time, be reinstated
by the Issuing Bank in accordance with, and only to the extent provided in,
the Letter of Credit. In no event shall reductions in the Premium Component
be reinstated.
(b) Interest Component. With respect to reinstatement of reductions in the
Interest Component resulting from Interest Drawings:
(i) The Issuing Bank may only deliver to the Paying Agent any notice of non-
reinstatement pursuant to Paragraph 5(i)(A) of the Letter of Credit if (A)
the Issuing Bank and/or the Participating Banks have not been reimbursed in
full by the Account Party for one or more drawings, together with interest if
any, owing thereon pursuant to this Agreement or (B) an Event of Default has
occurred and is then continuing.
(ii) if, subsequent to any such delivery of a notice of non-reinstatement,
the circumstances giving rise to the delivery of such notice of non-
reinstatement shall have ceased to exist (whether as a result of
reimbursement of unreimbursed drawings, or waiver or cure of an Event of
Default, or otherwise), then, provided that no other Event of Default shall
have occurred and be continuing, the Issuing Bank shall deliver to the Paying
Agent, by hand delivery or facsimile transmission, a Notice of Reinstatement
in the form of Exhibit 5 to the Letter of Credit reinstating that portion of
the Interest Component in respect of which such notice of non-reinstatement
was given.
(c) Principal Component. With respect to reinstatement of a reduction in
the Principal Component resulting from any Tender Drawing, IF:
(i) such reduction has not been reinstated pursuant to Paragraph 5(ii)(A) of
the Letter of Credit;
(ii) the Issuing Bank and/or the Participating Banks shall have been
reimbursed by the Account Party for such Tender Drawing;
(iii) any demand loan(s) and Advance(s) made in respect of such Tender
Drawing shall have been repaid by the Account Party, together with any
interest thereon and any other amounts payable hereunder in connection
therewith; AND
(iv) no Event of Default shall have occurred and then be continuing;
THEN, the Issuing Bank shall deliver to the Paying Agent, by hand delivery or
facsimile transmission, a Notice of Reinstatement in the form of Exhibit 5 to
the Letter of Credit reinstating the Principal Component to the extent of
such Tender Drawing.
SECTION II.5. Extension of the Stated Termination Date. Unless the Letter
of Credit shall have previously expired in accordance with its terms, at
least 105 days but not more than 120 days before the Stated Termination Date,
the Account Party may, by notice to the Agent (any such notice being
irrevocable), request the Issuing Bank and the Participating Banks to extend
the Stated Termination Date of the Letter of Credit for a period of one year.
If the Account Party shall make such request, the Agent shall promptly inform
the Issuing Bank and the Participating Banks and, no later than 60 days prior
to the Stated Termination Date, the Agent shall notify the Account Party in
writing (with a copy of such notice to the Trustee and the Paying Agent) if
the Issuing Bank and the Participating Banks consent to such request and the
conditions of such consent (including conditions relating to legal
documentation). The granting of any such consent shall be in the sole and
absolute discretion of the Issuing Bank and the Participating Banks, and if
the Agent shall not so notify the Account Party, such lack of notification
shall be deemed to be a determination not to consent to such request. No
such extension shall occur unless the Issuing Bank and all of the
Participating Banks consent thereto (or if less than all the Participating
Banks consent thereto, unless one or more other Participating Banks agree to
assume all of the Commitments of the non-consenting Participating Banks).
SECTION II.6. Modification of the Letter of Credit. In the event that the
Account Party elects to cause the issuance of any additional series of Tax-
Exempt Refunding Bonds (as defined in the Indenture) pursuant to Article IV
of the Indenture, the Account Party may, but shall not be obligated to,
propose amendments to the Letter of Credit to change the method of computing
the Interest Component or such other terms thereof as may be necessary or
appropriate in connection with such issuance. Any such proposal shall be
furnished to the Issuing Bank in writing not later than 60 days prior to the
date proposed for such issuance. If the Issuing Bank shall consent to such
amendments (which consent, subject to the provisions of the next succeeding
sentence, shall not be unreasonably withheld) the Issuing Bank shall, upon
surrender of the Letter of Credit by the beneficiary thereof for amendment
(or replacement, as the Issuing Bank may elect), amend the Letter of Credit
accordingly (or issue a replacement Letter of Credit therefor reflecting such
amendments but otherwise identical to the Letter of Credit so surrendered).
Notwithstanding the foregoing, without the consent of the requisite
Participating Banks as determined in accordance with Section 10.01, the
Issuing Bank shall not consent to any amendment or amendments that (i)
increase the Stated Amount or the then-existing Available Amount, (ii) change
or modify in any respect the Credit Termination Date or any provision for
determining the expiry or other termination of the Letter of Credit, (iii)
change or modify in any respect the times, places or manner at or in which
drawings under the Letter of Credit are to be presented or paid, (iv) change
or modify in any respect the forms of drawing certificates and other annexes
to the Letter of Credit, (v) change the beneficiary of the Letter of Credit
or the method prescribed therein for the transfer of the Letter of Credit or
(vi) as determined in the good faith discretion of the Issuing Bank and its
counsel, increase or enlarge the scope, or modify the nature, of the Issuing
Bank's and the Participating Banks' credit exposure to the Account Party or
any legal risks related thereto or expose the Issuing Bank to any additional
liability. In furtherance of the foregoing, the Issuing Bank may condition
the granting of such consent on the receipt by the Issuing Bank of such
certificates, opinions of counsel and other assurances of the Account Party
and its counsel, or bond counsel or the Trustee or Paying Agent, as the
Issuing Bank may reasonably require. Each Participating Bank, by its
execution of this Agreement, or of the Participation Assignment pursuant to
which it became a Participating Bank, consents to, ratifies and affirms all
actions taken and to be taken by the Issuing Bank pursuant to this Section
2.06.
ARTICLE III
REIMBURSEMENT AND ADVANCES
SECTION III.1. Reimbursement on Demand. Subject to the provisions of
Section 3.02 hereof, the Account Party hereby agrees to pay (whether with the
proceeds of Initial Advances made pursuant to this Agreement or otherwise) to
the Issuing Bank on demand (a) on and after each date on which the Issuing
Bank shall pay any amount under the Letter of Credit pursuant to any draft,
but only after so paid by the Issuing Bank, a sum equal to such amount so
paid (which sum shall constitute a demand loan from the Issuing Bank to the
Account Party from the date of such payment by the Issuing Bank until so paid
by the Account Party), plus (b) interest on any amount remaining unpaid by
the Account Party to the Issuing Bank under clause (a), above, from the date
such amount becomes payable on demand until payment in full, at the Default
Rate in effect from time to time. No reinstatement of the Interest Component
or the Principal Component despite the failure by the Account Party to
reimburse the Issuing Bank for any previous drawing to pay interest on the
Bonds shall limit or impair the Account Party's obligations under this
Section 3.01.
SECTION III.2. Advances. Each Participating Bank agrees to make Initial
Advances and Term Advances for the account of the Account Party from time to
time upon the terms and subject to the conditions set forth in this
Agreement; provided, that no Initial Advance or Term Advance shall be made
in respect of the Fixed-Rate Conversion Drawing without the consent of the
Issuing Bank and all of the Participating Banks.
(a) Initial Advances; Repayment of Initial Advances. If the Issuing Bank
shall honor any Tender Drawing and if the conditions precedent set forth in
Section 5.03 of this Agreement have been satisfied as of the date of such
honor, then, each Participating Bank's payment made to the Issuing Bank
pursuant to Section 3.07 hereof in respect of such Tender Drawing shall be
deemed to constitute an advance made for the account of the Account Party by
such Participating Bank (each such advance being an "Initial Advance" made by
such Participating Bank). Each Initial Advance shall be made as a Base Rate
Advance, shall bear interest at the Alternate Base Rate and shall not be
entitled to be Converted. Subject to Article VIII of this Agreement, each
Initial Advance and all interest thereon shall be due and payable on the
earlier to occur of (i) the date 30 days from the date of such Initial
Advance (such repayment date being the "Initial Repayment Date" for such
Initial Advance) and (ii) the Termination Date. The Account Party may repay
the principal amount of any Initial Advance with (and to the extent of) the
proceeds of a Term Advance made pursuant to subsection (b), below, and may
prepay Initial Advances in accordance with Section 3.06 hereof.
(b) Term Advances; Repayment. Subject to the satisfaction of the conditions
precedent set forth in Section 5.04 hereof and the other conditions of this
subsection (b), each Participating Bank agrees to make one or more advances
for the account of the Account Party ("Term Advances") on each Initial
Repayment Date in an aggregate principal amount equal to the amount of such
Participating Bank's Initial Advances maturing on such Initial Repayment
Date. All Term Advances comprising a single Term Borrowing shall be made
upon written notice given by the Account Party to the Agent not later than
11:00 A.M. (New York City time) (A) in the case of a Term Borrowing comprised
of Base Rate Advances, on the Business Day of such proposed Term Borrowing or
(B) in the case of a Term Borrowing comprised of Eurodollar Rate Advances,
three Business Days prior to the date of such proposed Term Borrowing. The
Agent shall notify each Participating Bank of the contents of such notice
promptly after receipt thereof. Each such notice shall specify therein the
following information: (W) the date on which such Term Borrowing is to be
made, (X) the principal amount of Term Advances comprising such Term
Borrowing, (Y) the Type of Term Borrowing and (Z) subject to Section 3.05(c),
the duration of the initial Interest Period, if applicable, proposed to apply
to the Term Advances comprising such Term Borrowing. The proceeds of each
Participating Bank's Term Advances shall be applied solely to the repayment
of the Initial Advances made by such Participating Bank and shall in no event
be made available to the Account Party. The principal amount of each Term
Advance, together with all accrued and unpaid interest thereon, shall be due
and payable on the earlier to occur of (x) the same calendar date occurring
12 months following the date upon which such Term Advance is made (or, if
such month does not have a corresponding date, on the last day of such month)
and (y) the Termination Date.
SECTION III.3. Interest on Advances. The Account Party shall pay interest
on the unpaid principal amount of each Advance from the date of such Advance
until such principal amount is paid in full at the applicable rate set forth
below:
(a) Alternate Base Rate. Except to the extent that the Account Party shall
elect to pay interest on any Advance for any Interest Period pursuant to
paragraph (c) of this Section 3.03, the Account Party shall pay interest on
each Advance (including all Initial Advances) from the date thereof until the
date such Advance is due, at a fluctuating interest rate per annum in effect
from time to time equal to the Alternate Base Rate in effect from time to
time. The Account Party shall pay interest on each Advance bearing interest
in accordance with this subsection monthly in arrears on the last business
day of each month and on the Termination Date or the earlier date for
repayment of such Advance (including the Initial Repayment Date therefor, in
the case of an Initial Advance); provided that if an Event of Default shall
have occurred and is continuing, any principal amounts outstanding shall bear
interest during such period, payable on demand, at a rate per annum equal at
all times to 2% per annum above the Alternate Base Rate in effect from time
to time.
(b) Interest Periods. Subject to the other requirements of this Section
3.03 and to Section 3.05(c), the Account Party may from time to time elect to
have the interest on all Term Advances comprising part of the same Term
Borrowing determined and payable for a specified period (an "Interest Period"
for such Term Advances) in accordance with paragraph (c) of this Section
3.03. The first day of an Interest Period for such Term Advances shall be
the date such Advance is made or most recently Converted, which shall be a
Business Day. All Interest Periods shall end on or prior to the Stated
Termination Date. Any Interest Period for a Term Advance that would
otherwise end after the Termination Date or earlier date for the repayment of
such Advance shall be deemed to end on the Termination Date or such earlier
repayment date, as the case may be.
(c) Eurodollar Rate. Subject to the requirements of this Section 3.03 and
Article V hereof, the Account Party may from time to time elect to have any
Term Advances comprising part of the same Term Borrowing made as, or
Converted to, Eurodollar Rate Advances. Subject to Section 3.05(c), the
Interest Period applicable to such Eurodollar Rate Advances shall be of one,
two, three or six whole months' duration, as the Account Party shall select
in its notice delivered to the Agent pursuant to Section 3.02(b) or 3.04
hereof, as applicable. If the Account Party shall have made such election,
the Account Party shall pay interest on such Eurodollar Rate Advances at the
Eurodollar Rate for the applicable Interest Period for such Eurodollar Rate
Advances, which interest shall be payable on the last day of such Interest
Period, on the date for repayment for such Eurodollar Rate Advances and also,
in the case of any Interest Period of six months' duration, on that day of
the third month of such Interest Period which corresponds with the first day
of such Interest Period (or, if any such month does not have a corresponding
day, then on the last day of such month); provided that if an Event of
Default shall have occurred and is continuing, any principal amounts
outstanding shall bear interest during such period, payable on demand, at a
rate per annum equal at all times to (A) for the remaining term, if any, of
the Interest Period for such Advance, 2% per annum above the Eurodollar Rate
for such Interest Period, and (B) thereafter, 2% per annum above the
Alternate Base Rate in effect from time to time. Any Interest Period
pertaining to Eurodollar Rate Advances that begins on the last Business Day
of a calendar month (or on a day for which there is no numerically
corresponding day in the calendar month at the end of such Interest Period)
shall end on the last Business Day of a calendar month.
(d) Interest Rate Determinations. The Agent shall give prompt notice to the
Account Party and the Participating Banks of the Eurodollar Rate determined
from time to time by the Agent to be applicable to each Eurodollar Rate
Advance.
SECTION III.4. Conversion of Term Advances. Subject to the satisfaction of
the conditions precedent set forth in Section 5.03 hereof, the Account Party
may elect to Convert one or more Term Advances of any Type to one or more
Term Advances of the same or any other Type on the following terms and
subject to the following conditions:
(a) Each Conversion shall be made as to all Term Advances comprising a
single Term Borrowing upon written notice given by the Account Party to the
Agent not later than 11:00 A.M. (New York City time) on the third Business
Day prior to the date of the proposed Conversion. The Agent shall notify
each Participating Bank of the contents of such notice promptly after receipt
thereof. Each such notice shall specify therein the following information:
(A) the date of such proposed Conversion (which in the case of Eurodollar
Rate Advances shall be last day of the Interest Period then applicable to
such Term Advances to be Converted), (B) Type of, and Interest Period, if
any, applicable to the Term Advances proposed to be Converted, (C) the
aggregate principal amount of Term Advances proposed to be Converted, and (D)
the Type of Term Advances to which such Term Advances are proposed to be
Converted and, subject to Section 3.05(c), the Interest Period, if any, to be
applicable thereto.
(b) During the continuance of an Unmatured Default or an Event of Default,
the right of the Account Party to Convert Term Advances to Eurodollar Rate
Advances shall be suspended, and all Eurodollar Rate Advances then
outstanding shall be Converted to Base Rate Advances on the last day of the
Interest Period then in effect, if, on such day, an Unmatured Default or an
Event of Default shall be continuing.
(c) If no notice of Conversion is received by the Agent as provided in
subsection (a) above with respect to any outstanding Eurodollar Rate
Advances, the Agent shall treat such absence of notice as a deemed notice of
Conversion providing for such Advances to be Converted to Base Rate Advances
on the last day of the Interest Period then in effect for such Eurodollar
Rate Advances.
SECTION III.5. Other Terms Relating to the Making and Conversion of
Advances. (a) Notwithstanding anything in Section 3.02, 3.03 or 3.04, above,
to the contrary:
(i) at no time shall more than six different Term Borrowings be outstanding
hereunder; and
(ii) each Term Borrowing consisting of Eurodollar Rate Advances shall be in
the aggregate principal amount of $10,000,000 or an integral multiple of
$1,000,000 in excess thereof.
(b) Each notice of borrowing pursuant to Section 3.02(b) hereof and each
notice of Conversion pursuant to Section 3.04 hereof shall be irrevocable and
binding on the Account Party.
(c) Until such time, if any, as the Majority Lenders shall otherwise agree,
the Interest Period for all Eurodollar Rate Advances shall be one month.
SECTION III.6. Prepayment of Advances. (a) The Account Party shall have no
right to prepay any principal amount of any Advances except in accordance
with subsections (b) and (c) below.
(b) The Account Party may, upon at least one Business Day's notice to the
Agent stating the proposed date and aggregate principal amount of the
prepayment (and if such notice is given the Account Party shall), prepay, in
whole or ratably in part, together with accrued interest to the date of such
prepayment on the principal amount prepaid, the outstanding principal amount
of (i) all Initial Advances made on the same date or (ii) all Term Advances
comprising the same Term Borrowing, in each case as the Account Party shall
designate in such notice; provided, however, that each partial prepayment
shall be in an aggregate principal amount not less than $10,000,000, or, if
less, the aggregate principal amount of all Advances then outstanding.
(c) Prior to or simultaneously with the resale of all of the Bonds purchased
with the proceeds of a Tender Drawing, the Account Party shall prepay, or
cause to be prepaid, in full, the then outstanding principal amount of all
Initial Advances and of all Term Advances comprising the same Term
Borrowing(s) arising pursuant to such Tender Drawing, together with all
interest thereon to the date of such prepayment. If less than all of such
Bonds are resold, then prior to or simultaneously with such resale the
Account Party shall prepay or cause to be prepaid that portion of such
Advances, together with all interest thereon to the date of such prepayment,
equal to the then outstanding principal amount thereof multiplied by a
fraction, the numerator of which shall be the principal amount of the Bonds
resold and the denominator of which shall be the principal amount of all of
the Bonds purchased with the proceeds of the relevant Tender Drawing.
SECTION III.7. Participation; Reimbursement of Issuing Bank. (a) The
Issuing Bank hereby sells and transfers to each Participating Bank, and each
Participating Bank hereby acquires from the Issuing Bank, an undivided
interest and participation to the extent of such Participating Bank's
Participation Percentage in and to (i) the Letter of Credit, including the
obligations of the Issuing Bank under and in respect thereof and the Account
Party's reimbursement and other obligations in respect thereof and (ii) each
demand loan or deemed demand loan made by the Issuing Bank, whether now
existing or hereafter arising.
(b) if the Issuing Bank (i) shall not have been reimbursed in full for any
payment made by the Issuing Bank under the Letter of Credit on the date of
such payment or (ii) shall make any demand loan to the Account Party, the
Issuing Bank shall promptly notify the Agent and the Agent shall promptly
notify each Participating Bank of such non-reimbursement or demand loan and
the amount thereof. Upon receipt of such notice from the Agent, each
Participating Bank shall pay to the Issuing Bank, directly, an amount equal
to such Participating Bank's ratable portion (according to such Participating
Bank's Participation Percentage) of such unreimbursed amount or demand loan
paid or made by the Issuing Bank, plus interest on such amount at a rate per
annum equal to the Federal Funds Rate from the date of such payment by the
Issuing Bank to the date of payment to the Issuing Bank by such Participating
Bank. All such payments by each Participating Bank shall be made in United
States dollars and in same day funds:
(x) not later than 2:45 P.M. (New York City time) on the day such notice is
received by such Participating Bank if such notice is received at or prior to
12:30 P.M. (New York City nine) on a Business Day; or
(y) not later than 12:00 Noon (New York City time) on the Business Day next
succeeding the day such notice is received by such Participating Bank, if
such notice is received after 12:30 P.M. (New York City time) on a Business
Day.
If a Participating Bank shall have paid to the Issuing Bank its ratable
portion of any unreimbursed amount or demand loan paid or made by the Issuing
Bank, together with all interest thereon required by the second sentence of
this subsection (b), such Participating Bank shall be entitled to receive its
ratable share of all interest paid by the Account Party in respect of such
unreimbursed amount or demand loan from the date paid or made by the Issuing
Bank. If such Participating Bank shall have made such payment to the Issuing
Bank, but without all such interest thereon required by the second sentence
of this subsection (b), such Participating Bank shall be entitled to receive
its ratable share of the interest paid by the Account Party in respect of
such unreimbursed amount or demand loan only from the date it shall have paid
all interest required by the second sentence of this subsection (b).
(c) Each Participating Bank's obligation to make each payment to the Issuing
Bank, and the Issuing Bank's right to receive the same, shall be absolute and
unconditional and shall not be affected by any circumstance whatsoever,
including, without limitation, the foregoing or Section 4.06 hereof, or the
occurrence or continuance of an Event of Default, or the non-satisfaction of
any condition precedent set forth in Sections 5.03 or 5.04 hereof, or the
failure of any other Participating Bank to make any payment under this
Section 3.07. Each Participating Bank further agrees that each such payment
shall be made without any offset abatement, withholding or reduction
whatsoever.
(d) The failure of any Participating Bank to make any payment to the Issuing
Bank in accordance with subsection (b) above, shall not relieve any other
Participating Bank of its obligation to make payment, but neither the Issuing
Bank nor any Participating Bank shall be responsible for the failure of any
other Participating Bank to make such payment. If any Participating Bank
shall fail to make any payment to the Issuing Bank in accordance with
subsection (b) above, then such Participating Bank shall pay to the Issuing
Bank forthwith on demand such corresponding amount together with interest
thereon, for each day until the date such amount is repaid to the Issuing
Bank at the Federal Funds Rate. Nothing herein shall in any way limit, waive
or otherwise reduce any claims that any party hereto may have against any
non-performing Participating Bank.
(e) If any Participating Bank shall fail to make any payment to the Issuing
Bank in accordance with subsection (b) above, then, in addition to other
rights and remedies which the Issuing Bank may have, the Agent is hereby
authorized, at the request of the Issuing Bank, to withhold and to apply the
payment of such amounts owing to such Participating Bank to the Issuing Bank
and any related interest, that portion of any payment received by the Agent
that would otherwise be payable to such Participating Bank. In furtherance
of the foregoing, if any Participating Bank shall fail to make any payment to
the Issuing Bank in accordance with subsection (b), above, and such failure
shall continue for five Business Days following written notice of such
failure from the Issuing Bank to such Participating Bank, the Issuing Bank
may acquire, or transfer to a third party in exchange for the sum or sums due
from such Participating Bank, such Participating Bank's interest in the
related unreimbursed amounts and demand loans and all other rights of such
Participating Bank hereunder in respect thereof, without, however, relieving
such Participating Bank from any liability for damages, costs and expenses
suffered by the Issuing Bank as a result of such failure. The purchaser of
any such interest shall be deemed to have acquired an interest senior to the
interest of such Participating Bank and shall be entitled to receive all
subsequent payments which the Issuing Bank or the Agent would otherwise have
made hereunder to such Participating Bank in respect of such interest.
ARTICLE IV
PAYMENTS
SECTION IV.1. Payments and Computations. (a) The Account Party shall make
each payment hereunder (i) in the case of reimbursement obligations pursuant
to Section 3.01 hereof (excluding any portion thereof in respect of which an
Initial Advance is to be made), not later than 2:30 P.M. (New York City time)
on the day the related drawing under the Letter of Credit is paid by the
Issuing Bank, and (ii) in all other cases, not later than 12:30 P.M. (New
York City time) on the day when due, in each case in lawful money of the
United States of America to the Agent at its address referred to in Section
10.02 hereof in same day funds. The Agent will promptly thereafter cause to
be distributed like funds relating to the payment of reimbursements,
principal, interest, fees or other amounts payable to the Issuing Bank and
the Participating Banks to whom the same are payable, ratably, at its address
set forth in Section 10.02 hereof (in the case of the Issuing Bank) or for
the account of their respective Applicable Lending Offices (in the case of
the Participating Banks), in each case to be applied in accordance with the
terms of this Agreement.
(b) The Account Party hereby authorizes the Issuing Bank, and each
Participating Bank, if and to the extent payment owed to the Issuing Bank, or
such Participating Bank, as the case may be, is not made when due hereunder,
to charge from time to time against any or all of the Account Party's
accounts with the Issuing Bank or such Participating Bank, as the case may
be, any amount so due.
(c) All computations of interest based on the Alternate Base Rate when based
on Swiss Bank's prime rate referred to in the definition of "Alternate Base
Rate" shall be made by the Agent on the basis of a year of 365 or 366 days,
as the case may be, for the actual days elapsed. All other computations of
interest hereunder (including computations of interest based on the
Eurodollar Rate and the Federal Funds Rate (including the Alternate Base Rate
if and so long as such Rate is based on the Federal Funds Rate)), all
computations of commissions and fees hereunder and all computations of other
amounts pursuant to Section 4.03 hereof, shall be made by the Agent or the
party claiming such other amounts, as the case may be, on the basis of a year
of 360 days for the actual days elapsed. In each such case, such computation
shall be made for the actual number of days (including the first day, but
excluding the last day) occurring in the period for which such interest,
commissions or fees are payable. Each such determination by the Agent or a
Participating Bank, as the case may be, shall be conclusive and binding for
all purposes, absent manifest error.
(d) Whenever any payment hereunder shall be stated to be due, or the last
day of an Interest Period hereunder shall be stated to occur, on a day other
than a Business Day, such payment shall be made and the last day of such
Interest Period shall occur on the next succeeding Business Day, and such
extension of time shall in such case be included in the computation of
payment of interest, commissions and fees hereunder; provided, however, that
if such extension would cause payment of interest on or principal of
Eurodollar Rate Advances to be made, or the last day of an Interest Period
for a Eurodollar Rate Advance to occur, in the next following calendar month,
such payment shall be made on the next preceding Business Day and such
reduction of time shall in such case be included in the computation of
payment of interest hereunder.
(e) Unless the Agent shall have received notice from the Account Party prior
to the date on which any payment is due to the Issuing Bank or the
Participating Banks hereunder that the Account Party will not make such
payment in full, the Agent may assume that the Account Party has made such
payment in full to the Agent on such date and the Agent may, in reliance upon
such assumption, cause to be distributed to the Issuing Bank and/or each
Participating Bank on such due date an amount equal to the amount then due
the Issuing Bank and/or such Participating Bank. If and to the extent the
Account Party shall not have so made such payment in full to the Agent, the
Issuing Bank and/or each such Participating Bank shall repay to the Agent
forthwith on demand such amount distributed to the Issuing Bank and/or such
Participating Bank, together with interest thereon, for each day from the
date such amount is distributed to the Issuing Bank and/or such Participating
Bank until the date the Issuing Bank and/or such Participating Bank repays
such amount to the Agent, at the Federal Funds Rate.
(f) If, after the Agent has paid to the Issuing Bank or any Participating
Bank any amount pursuant to subsection (a) above, such payment is rescinded
or must otherwise be returned or must be paid over by the Agent or the
Issuing Bank to any Person, whether pursuant to any bankruptcy or insolvency
law, Section 4.04 hereof or otherwise, such Participating Bank shall, at the
request of the Agent or the Issuing Bank, promptly repay to the Agent or the
Issuing Bank, as the case may be, an amount equal to its ratable share of
such payment, together with any interest required to be paid by the Agent or
the Issuing Bank with respect to such payment.
SECTION IV.2. Default Interest. Any amounts payable hereunder that are not
paid when due shall (to the fullest extent permitted by law) bear interest,
from the date when due until paid in full, at the Default Rate, payable on
demand.
SECTION IV.3. Yield Protection. (a) Change in Circumstances.
Notwithstanding any other provision herein, if after the date hereof; the
adoption of or any change in applicable law or regulation or in the
interpretation or administration thereof by any governmental authority
charged with the interpretation or administration thereof (whether or not
having the force of law) shall (i) change the basis of taxation of payments
to the Issuing Bank or any Participating Bank of the principal of or interest
on any Eurodollar Rate Advance made by such Participating Bank or any fees or
other amounts payable hereunder (other than changes in respect of taxes
imposed on the overall net income of the Issuing Bank or such Participating
Bank, or its Applicable Lending Office, by the jurisdiction in which the
Issuing Bank or such Participating Bank has its principal office or in which
such Applicable Lending Office is located or by any political subdivision or
taxing authority therein), or (ii) shall impose, modify or deem applicable
any reserve, special deposit or similar requirement against letters of credit
(or participatory interests therein) issued by, commitments or assets of,
deposits with or for the account of, or credit extended by, the Issuing Bank
or such Participating Bank, or (iii) shall impose on the Issuing Bank or such
Participating Bank any other condition affecting this Agreement, the Letter
of Credit or participatory interests therein or Eurodollar Rate Advances, and
the result of any of the foregoing shall be (A) to increase the cost to the
Issuing Bank or such Participating Bank of issuing, maintaining or
participating in this Agreement or the Letter of Credit or of agreeing to
make, making or maintaining any Advance or (B) to reduce the amount of any
sum received or receivable by the Issuing Bank or such Participating Bank
hereunder (whether of principal, interest or otherwise), then the Account
Party will pay to the Issuing Bank or such Participating Bank, upon demand,
such additional amount or amounts as will compensate the Issuing Bank or such
Participating Bank for such additional costs incurred or reduction suffered.
(b) Capital. If the Issuing Bank or any Participating Bank shall have
determined that the applicability of any law, rule, regulation or guideline
adopted pursuant to or arising out of the July 1988 report of the Basle
Committee on Banking Regulations and Supervisory Practices entitled
"International Convergence of Capital Measurement and Capital Standards", or
the adoption after the date hereof of any law, rule, regulation or guideline
regarding capital adequacy, or any change in any of the foregoing or in the
interpretation or administration of any of the foregoing by any governmental
authority, central bank or comparable agency charged with the interpretation
or administration thereof, or compliance by the Issuing Bank or any
Participating Bank (or any Applicable Lending Office of the Issuing Bank or
such Participating Bank), or any holding company of any such entity, with any
request or directive regarding capital adequacy (whether or not having the
force of law) of any such authority, central bank or comparable agency, has
or would have the effect (i) of reducing the rate of return on such entity's
capital or on the capital of such entity's holding company, if any, as a
consequence of this Agreement, the Letter of Credit or such entity's
participatory interest therein, any Commitment hereunder or the portion of
the Advances made by such entity pursuant hereto to a level below that which
such entity or such entity's holding company could have achieved, but for
such applicability, adoption, change or compliance (taking into consideration
such entity's policies and the policies of such entity's holding company with
respect to capital adequacy), or (ii) of increasing or otherwise determining
the amount of capital required or expected to be maintained by such entity or
such entity's holding company based upon the existence of this Agreement, the
Letter of Credit or such entity's participatory interest therein, any
Commitment hereunder, the portion of the Advances made by such entity
pursuant hereto and other similar such credits, participations, commitments,
agreements or assets, then from time to time the Account Party shall pay to
the Issuing Bank or such Participating Bank, upon demand, such additional
amount or amounts as will compensate such entity or such entity's holding
company for any such reduction or allocable capital cost suffered.
(c) Eurodollar Reserves. The Account Party shall pay to each Participating
Bank upon demand, so long as such Participating Bank shall be required under
regulations of the Board of Governors of the Federal Reserve System to
maintain reserves with respect to liabilities or assets consisting of or
including Eurocurrency Liabilities, additional interest on the unpaid
principal amount of such Participating Bank's portion of each Eurodollar Rate
Advance, from the date of such Advance until such principal amount is paid in
full, at an interest rate per annum equal at all times to the remainder
obtained by subtracting (i) the rate described in clause (i) of the
definition of "Eurodollar Rate" for the Interest Period for such Advance from
(ii) the rate obtained by dividing such rate by a percentage equal to 100%
minus the Eurodollar Reserve Percentage of such Participating Bank for such
Interest Period. Such additional interest shall be determined by such
Participating Bank and notified to the Account Party and the Issuing Bank.
(d) Breakage Indemnity. The Account Party shall indemnify each Participating
Bank against any loss, cost or reasonable expense which such Participating
Bank may sustain or incur as a consequence of (i) any failure by the Account
Party to fulfill on the date of any Advance or Conversion hereunder the
applicable conditions set forth in Articles III and V, (ii) any failure by
the Account Party to Convert any Advance hereunder after irrevocable notice
of Conversion has been given pursuant to Section 3.04 hereof, (iii) any
payment, prepayment or Conversion of a Eurodollar Rate Advance required or
permitted by any other provision of this Agreement or otherwise made or
deemed made on a date other than the last day of the Interest Period
applicable thereto, (iv) any default in payment or prepayment of the
principal amount of any Advance or any part thereof or interest accrued
thereon, as and when due and payable (at the due date thereof, by irrevocable
notice of prepayment or otherwise) or (v) the occurrence of any Event of
Default, including, in each such case, any loss or reasonable expense
sustained or incurred or to be sustained or incurred in liquidating or
employing deposits from third parties acquired to effect or maintain such
Advance or any part thereof as a Eurodollar Rate Advance. Such loss, cost or
reasonable expense shall include an amount equal to the excess, if any, as
reasonably determined by such Participating Bank, of (A) its cost of
obtaining the funds for the Advance being paid, prepaid, Converted or not
borrowed (based on the Eurodollar Rate) for the period from the date of such
payment, prepayment, Conversion or failure to borrow to the last day of the
Interest Period for such Advance (or, in the case of a failure to borrow, the
Interest Period for such Advance which would have commenced on the date of
such failure) over (B) the amount of interest (as reasonably determined by
such Participating Bank) that would be realized by such Participating Bank in
reemploying the funds so paid, prepaid, Converted or not borrowed for such
period or Interest Period, as the case may be. For purposes of this
subsection (d), it shall be presumed that each Participating Bank shall have
funded each such Advance with a fixed-rate instrument bearing the rates and
maturities designated in the determination of the applicable interest rate
for such Advance.
(e) Notices. A certificate of the Issuing Bank or any Participating Bank
setting forth such entity's claim for compensation hereunder and the amount
necessary to compensate such entity or its holding company pursuant to
subsections (a) through (d) of this Section 4.03 shall be submitted to the
Account Party and the Issuing Bank and shall be conclusive and binding for
all purposes, absent manifest error. The Account Party shall pay the Issuing
Bank or such Participating Bank directly the amount shown as due on any such
certificate within ten days after its receipt of the same. The failure of any
entity to provide such notice or to make demand for payment under this
Section 4.03 shall not constitute a waiver of such Participating Bank's
rights hereunder; provided, that such entity shall not be entitled to demand
payment pursuant to subsections (a) through (d) of this Section 4.03 in
respect of any loss, cost, expense, reduction or reserve if such demand is
made more than one year following the later of such entity's incurrence or
sufferance thereof or such entity's actual knowledge of the event giving rise
to such entity's rights pursuant to such subsections. The protection of this
Section 4.03 shall be available to the Issuing Bank and each Participating
Bank regardless of any possible contention of the invalidity or
inapplicability of the law, rule, regulation, guideline or other change or
condition which shall have occurred or been imposed.
(f) Change in Legality. Notwithstanding any other provision herein, if the
adoption of or any change in any law or regulation or in the interpretation
or administration thereof by any governmental authority charged with the
administration or interpretation thereof shall make it unlawful for any
Participating Bank to make or maintain any Eurodollar Rate Advance or to give
effect to its obligations as contemplated hereby with respect to any
Eurodollar Rate Advance, then, by written notice to the Account Party and the
Issuing Bank, such Participating Bank may:
(i) declare that Eurodollar Rate Advances will not thereafter be made by
such Participating Bank hereunder, whereupon the right of the Account Party
to select Eurodollar Rate Advances for any Advance or Conversion shall be
forthwith suspended until such Participating Bank shall withdraw such notice
as provided hereinbelow or shall cease to be a Participating Bank hereunder;
and
(ii) require that all outstanding Eurodollar Rate Advances be Converted to
Base Rate Advances, in which event all Eurodollar Rate Advances shall be
automatically Converted to Base Rate Advances as of the effective date of
such notice as provided hereinbelow.
Upon receipt of any such notice, the Agent shall promptly notify the
Participating Banks thereof. Promptly upon becoming aware that the
circumstances that caused such Participating Bank to deliver such notice no
longer exist, such Participating Bank shall deliver notice thereof to the
Account Party and the Agent withdrawing such prior notice (but the failure to
do so shall impose no liability upon such Participating Bank). Promptly upon
receipt of such withdrawing notice from such Participating Bank, the Agent
shall deliver notice thereof to the Account Party and the Participating Banks
and such suspension shall terminate. Prior to any Participating Bank giving
notice to the Account Party under this subsection (f), such Participating
Bank shall use reasonable efforts to change the jurisdiction of its
Applicable Lending Office, if such change would avoid such unlawfulness and
would not, in the sole determination of such Participating Bank, be otherwise
disadvantageous to such Participating Bank. Any notice to the Account Party
by any Participating Bank shall be effective as to each Eurodollar Rate
Advance on the last day of the Interest Period currently applicable to such
Eurodollar Rate Advance; provided that if such notice shall state that the
maintenance of such Advance until such last day would be unlawful, such
notice shall be effective on the date of receipt by the Account Party and the
Agent.
(g) Market Rate Disruptions. If, (i) the Agent determines that an
adequate basis does not exist for the determination of the Eurodollar Rate
for Eurodollar Rate Advances or (ii) if the Majority Lenders shall notify the
Agent that the Eurodollar Rate will not adequately reflect the cost to such
Majority Lenders of making, funding or maintaining their respective
Eurodollar Rate Advances, the right of the Account Party to select or receive
or Convert into Eurodollar Rate Advances shall be forthwith suspended until
the Agent shall notify the Account Party and the Participating Banks that the
circumstances causing such suspension no longer exist, and until such
notification from the Agent, each request for or Conversion into Eurodollar
Rate Advances hereunder shall be deemed to be a request for or Conversion
into Base Rate Advances.
SECTION IV.4. Sharing of Payments, Etc. If any Participating Bank shall
obtain any payment (whether voluntary, involuntary, through the exercise of
any right of set-off, or otherwise, but excluding any proceeds received by
assignments or sales of participations in accordance with Section 10.06
hereof to a Person that is not an Affiliate of the Account Party) on account
of the Advances owing to it (other than pursuant to Section 4.03 hereof) in
excess of its ratable share of payments on account of the Advances obtained
by all the Participating Banks, such Participating Batik shall forthwith
purchase from the other Participating Banks such participation in the
portions of the Advances owing to them as shall be necessary to cause such
purchasing Participating Bank to share the excess payment ratably with each
of them; provided, however, that if all or any portion of such excess payment
is thereafter recovered from such purchasing Participating Bank, such
purchase from each Participating Bank shall be rescinded and such
Participating Bank shall repay to the purchasing Participating Bank the
purchase price to the extent of such recovery together with an amount equal
to such Participating Bank's ratable share (according to the proportion of
(i) the amount of such Participating Bank's required repayment to (ii) the
total amount so recovered from the purchasing Participating Bank) of any
interest or other amount paid or payable by the purchasing Participating Bank
in respect of the total amount so recovered. The Account Party agrees that
any Participating Bank so purchasing a participation from another
Participating Bank pursuant to this Section 4.04 may, to the fullest extent
permitted by law, exercise all its rights of payment (including the right of
set-off) with respect to such participation as fully as if such Participating
Bank were the direct creditor of the Account Party in the amount of such
participation. Notwithstanding the foregoing, if any Participating Bank
shall obtain any such excess payment involuntarily, such Participating Bank
may, in lieu of purchasing participation from the other Participating Banks
in accordance with this Section 4.04, on the date of receipt of such excess
payment, return such excess payment to the Agent for distribution in
accordance with Section 4.01(a) hereof.
SECTION IV.5. Taxes. (a) All payments by the Account Party hereunder shall
be made in accordance with Section 4.01, free and clear of and without
deduction for all present or future taxes, levies, imposts, deductions,
charges or withholdings, and all liabilities with respect thereto, excluding,
in the case of each Participating Bank and the Issuing Bank, taxes imposed on
its overall net income, and franchise taxes imposed on it, by the
jurisdiction under the laws of which such Participating Bank or the Issuing
Bank (as the case may be) is organized or any political subdivision thereof
and, in the case of each Participating Bank, taxes imposed on its overall net
income, and franchise taxes imposed on it, by the jurisdiction of such
Participating Bank's Applicable Lending Office or any political subdivision
thereof (all such non-excluded taxes, levies, imposts, deductions, charges,
withholdings and liabilities being hereinafter referred to as "Taxes"). If
the Account Party shall be required by law to deduct any Taxes from or in
respect of any sum payable hereunder to any Participating Bank or the Issuing
Bank, (i) the sum payable shall be increased as may be necessary so that
after making all required deductions (including deductions applicable to
additional sums payable under this Section 4.05) such Participating Bank or
the Issuing Bank (as the case may be) receives an amount equal to the sum it
would have received had no such deductions been made, (ii) the Account Party
shall make such deductions and (iii) the Account Party shall pay the full
amount deducted to the relevant taxation authority or other authority in
accordance with applicable law.
(b) In addition, the Account Party agrees to pay any present or future stamp
or documentary taxes or any other excise or property taxes, charges or
similar levies that arise from any payment made hereunder or from the
execution, delivery or registration of, or otherwise with respect to, this
Agreement (hereinafter referred to as "Other Taxes").
(c) The Account Party will indemnify each Participating Bank and the Issuing
Bank for the full amount of Taxes and Other Taxes (including, without
limitation, any Taxes and any Other Taxes imposed by any jurisdiction on
amounts payable under this Section 4.05) paid by such Participating Bank or
the Issuing Bank (as the case may be) and any liability (including penalties,
interest and expenses) arising therefrom or with respect thereto, whether or
not such Taxes or Other Taxes were correctly or legally asserted. This
indemnification shall be made within 30 days from the date such Participating
Bank or the Issuing Bank (as the case may be) makes written demand therefor.
If any Taxes or Other Taxes for which a Participating Bank or the Issuing
Bank has received payments from the Account Party hereunder shall be finally
determined to have been incorrectly or illegally asserted and are refunded to
such Participating Bank, such Participating Bank shall promptly forward to
the Account Party any such refunded amount. The Account Party's, the Issuing
Bank's and each Participating Bank's obligations under this Section 4.05
shall survive the payment in full of the Advances.
(d) Within 30 days after the date of any payment of Taxes, the Account Party
will furnish to the Issuing Bank, at its address referred to in Section 10.02
hereof the original or a certified copy of a receipt evidencing payment
thereof.
(e) Each Participating Bank not incorporated in the United States or a
jurisdiction within the United States shall, on or prior to the date it
becomes a Participating Bank hereunder, deliver to the Account Party and the
Issuing Bank such certificates, documents or other evidence, as required by
the Internal Revenue Code of 1986, as amended from time to time (the "Code"),
or treasury regulations issued pursuant thereto, including Internal Revenue
Service Form 4224 and any other certificate or statement of exemption
required by Treasury Regulation Section l.1441-1(a) or Section 1.1441-6(c) or
any subsequent version thereof, properly completed and duly executed by such
Participating Bank establishing that it is (i) not subject to withholding
under the Code or (ii) totally exempt from United States of America tax under
a provision of an applicable tax treaty. Each Participating Bank shall
promptly notify the Account Party and the Issuing Bank of any change in its
Applicable Lending Office and shall deliver to the Account Party and the
Issuing Bank together with such notice such certificates, documents or other
evidence referred to in the immediately preceding sentence. Unless the
Account Party and the Issuing Bank have received forms or other documents
satisfactory to them indicating that payments hereunder are not subject to
United States of America withholding tax or are subject to such tax at a rate
reduced by an applicable tax treaty, the Account Party or the Issuing Bank
shall withhold taxes from such payments at the applicable statutory rate in
the case of payments to or for any Participating Bank organized under the
laws of a jurisdiction outside the United States of America. Each
Participating Bank represents and warrants that each such form supplied by it
to the Issuing Bank and the Account Party pursuant to this Section 4.05, and
not superseded by another form supplied by it is or will be, as the case may
be, complete and accurate.
(f) Any Participating Bank claiming any additional amounts payable pursuant
to this Section 4.05 shall use reasonable efforts (consistent with legal and
regulatory restrictions) to file any certificate or document requested by the
Account Party or to change the jurisdiction of its Applicable Lending Office
if the making of such a filing or change would avoid the need for or reduce
the amount of any such additional amounts which may thereafter accrue and
would not, in the sole determination of such Participating Bank, be otherwise
disadvantageous to such Participating Bank.
(g) Notwithstanding anything to the contrary set forth in this Section 4.05,
the failure or inability of any Participating Bank to provide any of the
forms referred to therein shall not relieve the Account Party from its
obligations under Sections 4.05(a), 4.05(b) and 4.05(c).
SECTION IV.6. Obligations Absolute. The obligations of the Account Party
under this Agreement shall be unconditional and irrevocable, and shall be
paid strictly in accordance with the terms of this Agreement (as the same may
be amended from time to time) under all circumstances, including, without
limitation, the following circumstances:
(i) any lack of validity or enforceability of this Agreement or any of the
Security Documents or Related Documents or any document or agreement
delivered in connection therewith;
(ii) any change in the time, manner or place of payment of, or in any other
term of, all or any of the obligations of the Account Party in respect of the
Letter of Credit or any other amendment or waiver of or any consent to
departure from all or any of the Loan Documents or the Related Documents or
any document or agreement delivered in connection therewith;
(iii) the existence of any claim, set-off, defense or other right which
the Account Party may have at any time against the Paying Agent, the Trustee
or any other beneficiary, or any transferee, of the Letter of Credit (or any
persons or entities for whom the Paying Agent, the Trustee, any such
beneficiary or any such transferee may be acting), the Agent, the Issuing
Bank, or any other person or entity, whether in connection with this
Agreement, the transactions contemplated in any of the Loan Documents or the
Related Documents, or any unrelated transaction;
(iv) any statement or any other document presented under the Letter of Credit
proving to be forged, fraudulent, invalid or insufficient in any respect or
any statement therein being untrue or inaccurate in any respect except to the
extent that a court of competent jurisdiction shall determine that the
Issuing Bank shall have engaged in gross negligence or willful misconduct
with respect thereto;
(v) payment by the Issuing Bank under the Letter of Credit against
presentation of a draft or certificate which does not comply with the terms
of the Letter of Credit, except to the extent that a court of competent
jurisdiction shall determine that the Issuing Bank shall have engaged in
gross negligence or willful misconduct with respect thereto;
(vi) any exchange of, release of or non-perfection of any interest in any
collateral, or any release or amendment or waiver of or consent to departure
from any guarantee, for all or any of the obligations of the Account Party in
respect of the Letter of Credit; or
(vii) any other circumstance or happening whatsoever, whether or not
similar to any of the foregoing.
SECTION IV.7. Evidence of Indebtedness. The Issuing Bank and each
Participating Bank shall maintain, in accordance with their usual practice,
an account or accounts evidencing the indebtedness of the Account Party
resulting from each drawing under the Letter of Credit (in the case of the
Issuing Bank) and from each Advance (in the case of each Participating Bank)
made from time to time hereunder and the amounts of principal and interest
payable and paid from time to time hereunder. In any legal action or
proceeding in respect of this Agreement, the entries made in such account or
accounts shall, in the absence of manifest error, be conclusive evidence of
the existence and amounts of the obligations of the Account Party therein
recorded.
ARTICLE V
CONDITIONS PRECEDENT
SECTION V.1. Conditions Precedent to the Issuance of the Letter of Credit.
The obligation of the Issuing Bank to issue the Letter of Credit and of each
Participating Bank to make the Advances to be made by it is subject to the
fulfillment of the conditions precedent that the Agent shall have received on
or before the day of such issuance the following, each dated such day (except
where specified otherwise below), in form and substance satisfactory to each
Participating Bank (except where specified otherwise below) and in sufficient
copies for each Participating Bank:
(a) Agreements:
(i) Counterparts of this Agreement, duly executed and delivered by the
Account Party, the Agent, the Issuing Bank and each Participating Bank.
(ii) Counterparts of the Pledge Amendment, duly executed by the Account
Party, Citibank, the Agent and the Issuing Bank, and copies of the Pledge
Agreement.
(iii) For each Participating Bank who shall so request, executed copies
(or duplicate copies thereof certified as of the Closing Date by the Account
Party in a manner satisfactory to the Agent to be a true copy) of each other
Security Document, duly executed by the parties thereto.
(iv) For each Participating Bank who shall so request, executed copies (or
duplicate copies thereof certified as of the Closing Date by the Account
Party in a manner satisfactory to the Agent to be a true copy) of the Rate
Agreement and each Significant Contract and all amendments, modifications and
supplements thereto, in each such case duly executed by the respective
parties thereto.
(b) Corporate Matters:
(i) A certificate of the Secretary or an Assistant Secretary of the Account
Party certifying that (A) there has been delivered to the Agent, and to each
other Participating Bank known to such officers to have so requested, true
and correct copies of the Articles of Incorporation of the Account Party and
the By-laws of the Account Party, in each case as in effect on the Closing
Date and (B) attached to such certificate are true and correct copies of the
resolutions of the Boards of Directors of the Account Party approving, if and
to the extent necessary, this Agreement, the other Loan Documents, the
Related Documents to which it is a party and the other documents to be
delivered by or on behalf of the Account Party hereunder and thereunder, and
of all documents evidencing other necessary corporate action, if any, with
respect to the execution, delivery and performance by or on behalf of the
Account Party of this Agreement, the other Loan Documents and such Related
Documents and certifying that such resolutions and other corporate actions,
if any, are in full force and effect and have not been revoked, rescinded or
modified.
(ii) A certificate of the Secretary or an Assistant Secretary of the Account
Party certifying the names and true signatures of the officers of the Account
Party authorized to sign this Agreement, the other Loan Documents and the
other documents to be delivered hereunder and thereunder.
(c) Governmental Approvals, Litigation and the Merger:
(i) A certificate of a duly authorized officer of the Account Party
certifying that attached thereto are true and correct copies of all
Governmental Approvals referred to in clause (i) of the definition of
"Governmental Approval" required to be obtained or made by the Account Party
in connection with the execution and delivery of this Agreement and the
issuance of the Letter of Credit.
(ii) A certificate signed by the Assistant General Counsel of NUSCO
certifying that no court has granted a motion for stay or any request for
similar relief in connection with the Plan, the Merger, the Loan Documents,
the Related Documents or the transactions contemplated thereunder.
(iii) A certificate of a duly authorized officer of the Account Party to
the effect that there is no pending or known threatened action or proceeding
(including, without limitation, any action or proceeding relating to any
environmental protection laws or regulations) affecting the Account Party or
its properties before any court, governmental agency or arbitrator (A) which
affects or purports to affect the legality, validity or enforceability of the
Loan Documents or the Related Documents or any of them or (B) as to which
there is a reasonable possibility of an adverse determination and which, if
adversely determined, would materially adversely affect the financial
condition, properties, prospects or operations of the Account Party; except,
for purposes of clause (B) only, such as is described in the Account Party's
Annual Report on Form 10-K for the fiscal year ended December 31, 1994 or in
Schedule II hereto.
(iv) Certificates signed by duly authorized officers of the Account Party and
NU to the effect that all conditions to the occurrence of the Merger were
satisfied or waived and the Merger was consummated on June 5, 1992.
(d) Financial Accounting and Compliance Matters:
(i) An audited balance sheet of the Account Party as at December 31, 1994
and the related statements of the Account Party's results of operations,
retained earnings and cash flows for and as of the year then ended, together
with copies of all Current Reports, if any, filed by the Account Party with
the Securities and Exchange Commission on or after December 31, 1994.
(ii) A certificate signed by the Treasurer or Assistant Treasurer of the
Account Party, certifying as to the absence of any material adverse change in
the financial condition, operations, properties or prospects of the Account
Party since December 31, 1994.
(iii) Financial projections, on assumptions acceptable to the
Participating Banks, demonstrating projected compliance with Section 7.01(i)
of the Existing Agreement and the terms of this Agreement and the Financing
Agreements.
(iv) A certificate signed by the Chief Financial Officer, Treasurer or
Assistant Treasurer of NU, certifying as to the absence of any material
adverse change in the financial condition, operations, properties or
prospects of NU since December 31, 1994.
(v) A certificate of a duly authorized officer of the Account Party to the
effect that:
(A) the representations and warranties contained in Section 6.01 are correct
in all material respects on and as of the Closing Date before and after
giving effect to the issuance of the Letter of Credit;
(B) no event has occurred and is continuing which constitutes an Event of
Default or Unmatured Default, or would result from the issuance of the Letter
of Credit;
(C) the Financing Agreements are in full force and effect and no "Event of
Default" or "Unmatured Default" (as defined therein) has occurred and is
continuing; and
(D) the Series F First Mortgage Bonds were duly issued to the Trustee in
accordance with the Indenture, are presently outstanding, and no "Event of
Default" (as defined in the First Mortgage Indenture) has occurred and is
continuing.
(e) Relating to the Issuance of the Bonds:
(i) A letter from Palmer & Dodge, Bond Counsel, addressed to the Agent, the
Issuing Bank and the Participating Banks and stating therein that the Agent,
the Issuing Bank and the Participating Banks may rely on the opinions of such
firm rendered in connection with the respective issuances of the Taxable
Bonds and the Existing Tax-Exempt Refunding Bonds, together with copies of
all such opinions.
(ii) A letter from Palmer & Dodge, counsel to the Issuer, addressed to the
Agent, the Issuing Bank and the Participating Banks and stating therein that
the Agent, the Issuing Bank and the Participating Banks may rely on the
opinions of such firm rendered in connection with the respective issuances of
the Taxable Bonds and the Existing Tax-Exempt Refunding Bonds, together with
copies of all such opinions.
(iii) A letter from Sulloway & Hollis, New Hampshire counsel to the
Account Party, addressed to the Agent, the Issuing Bank and the Participating
Banks and stating therein that the Agent, the Issuing Bank and the
Participating Banks may rely on the opinion of such firm rendered in
connection with the issuance of the Taxable Bonds, together with a copy of
such opinion.
(iv) A letter from Day, Berry & Howard, counsel to the Account Party,
addressed to the Agent, the Issuing Bank and the Participating Banks and
stating therein that the Agent, the Issuing Bank and the Participating Banks
may rely on the opinions of such firm rendered in connection with the
respective issuances of the Taxable Bonds and the Existing Tax-Exempt
Refunding Bonds, together with copies of all such opinions.
(v) Copies of the opinions of Drummond Woodsum & MacMahon, special Maine
counsel to the Account Party, rendered in connection with the respective
issuances of the Taxable Bonds and the Existing Tax-Exempt Refunding Bonds,
authorizing reliance thereon by (A) Day, Berry & Howard in connection with
the corresponding opinions of that firm referred to in clause (iv), above,
and (B) by any party authorized to rely on such opinions of Day, Berry &
Howard.
(vi) Copies of the opinions of Zuccaro, Willis & Bent special Vermont counsel
to the Account Party, rendered in connection with the respective issuances of
the Taxable Bonds and the Existing Tax-Exempt Refunding Bonds, authorizing
reliance thereon by (A) Day, Berry & Howard in connection with the
corresponding opinions of that firm referred to in clause (iv), above, and
(B) by any party authorized to rely on such opinions of Day, Berry & Howard.
(vii) Copies of all such other agreements, documents and materials
(including opinions of counsel or reliance letters in respect thereof) as the
Agent, the Issuing Bank or any Participating Bank may reasonably request
relating to the issuance, offering and sale of the Taxable Bonds, the
Existing Tax-Exempt Refunding Bonds and the Series F First Mortgage Bonds.
(f) Opinions of Counsel:
Favorable opinions of:
(i) Day, Berry & Howard, counsel to the Account Party, in substantially the
form of Exhibit 5.01A and as to such other matters as the Majority Lenders,
through the Agent, may reasonably request;
(ii) Rath, Young and Pignatelli, P.A., special New Hampshire counsel to the
Account Party, in substantially the form of Exhibit 5.01B and as to such
other matters as the Majority Lenders, through the Agent, may reasonably
request;
(iii) Jeffrey C. Miller, Assistant General Counsel of NUSCO, in
substantially the form of Exhibit 5.01C and as to such other matters as the
Majority Lenders, through the Agent, may reasonably request;
(iv) Drummond Woodsum & MacMahon, special Maine counsel to the Account Party,
in substantially the form of Exhibit 5.01D and as to such other matters as
the Majority Lenders, through the Agent, may reasonably request;
(v) Zuccaro Willis & Bent, special Vermont counsel to the Account Party, in
substantially the form of Exhibit 5.01E and as to such other matters as the
Majority Lenders, through the Agent, may reasonably request; and
(vi) King & Spalding, special New York counsel to the Agent and the Issuing
Bank, in substantially the form of Exhibit 5.01F.
(g) Miscellaneous:
(i) A certificate of Citibank, as agent thereunder, to the effect that (A)
all amounts payable in connection with the Existing Reimbursement Agreement
and the letter of credit issued thereunder have been paid to it and (B) it
thereby surrenders any and all rights it may have under the Related Documents
arising in connection with the Existing Reimbursement Agreement and the
letter of credit issued thereunder, except for any such rights it may have as
an indemnified party thereunder.
(ii) Letters from S&P and Moody's to the effect that the Taxable Bonds have
been rated A-1+ and P-1, respectively, and the Tax-Exempt Refunding Bonds
have been rated A-1+ and VMIG-1, respectively, and that the issuance of the
Letter of Credit in substitution for the Existing Letter of Credit will not,
by itself, result in a lowering of such ratings, such letters to be in form
and substance satisfactory to the Issuing Bank.
(iii) Such other approvals, opinions and documents as the Majority
Lenders, through the Issuing Bank, may reasonably request as to the legality,
validity, binding effect or enforceability of the Loan Documents or the
financial condition, properties, operations or prospects of the Account
Party.
SECTION V.2. Additional Conditions Precedent to the Issuance of the Letter
of Credit. The obligation of the Issuing Bank to issue the Letter of Credit
and of each Participating Bank to make the Advances to be made by it shall be
subject to the further conditions precedent that, on the date of the issuance
of the Letter of Credit:
(a) the representations and warranties contained in Section 6.01 shall be
correct in all material respects on and as of the Closing Date before and
after giving effect to the issuance of the Letter of Credit;
(b) no event shall have occurred and be continuing which constitutes an
Event of Default or Unmatured Default, or would result from the issuance of
the Letter of Credit;
(c) no "Event of Default" (as defined in the First Mortgage Indenture) shall
have occurred and be continuing;
(d) the Series F First Mortgage Bonds shall have been duly issued to the
Trustee in accordance with the Indenture, and be outstanding, and no "Event
of Default" (as defined in the First Mortgage Indenture) shall have occurred
and be continuing; and
(e) The Account Party shall have paid all fees under or referenced in
Section 2.03 hereof, to the extent then due and payable.
SECTION V.3. Conditions Precedent to Initial Advances and Conversions of
Advances. The obligation of each Participating Bank to make any Initial
Advance or to Convert any Term Advance shall be subject to the conditions
precedent that, on the date of such Initial Advance or Conversion, the
following statements shall be true:
(a) the representations and warranties contained in Section 6.01 of this
Agreement (other than the last sentence of subsection (e) and clause (ii) of
subsection (f) thereof) are true and correct on and as of the date of such
Initial Advance or Conversion, before and after giving effect to such Initial
Advance or Conversion and to the application of the proceeds (if any)
therefrom, as though made on and as of such date; and
(b) no event has occurred and is continuing which constitutes an Event of
Default.
Unless the Account Party shall have previously advised the Agent in writing
that one or more of the statements contained in subsections (a) and (b) of
this Section 5.03 is no longer true, the Account Party shall be deemed to
have represented and warranted, on and as of the date of any Initial Advance
or Conversion, that the above statements are true.
SECTION V.4. Conditions Precedent to Term Advances. The obligation of each
Participating Bank to make any Term Advance shall be subject to the
conditions precedent that, on the date of such Term Advance the following
statements shall be true:
(a) the representations and warranties contained in Section 6.01 of this
Agreement (including the last sentence of subsection (e) and clause (ii) of
subsection (f) thereof) are true and correct on and as of the date of such
Term Advance, before and after giving effect to such Term Advance and to the
application of the proceeds therefrom, as though made on and as of such date;
and
(b) no event has occurred and is continuing which constitutes an Event of
Default or an Unmatured Default.
Unless the Account Party shall have previously advised the Agent in writing
that one or more of the statements contained in subsections (a) and (b) of
this Section 5.04 is no longer true, the Account Party shall be deemed to
have represented and warranted, on and as of the date of any Term Advance,
that the above statements are true.
SECTION V.5. Reliance on Certificates. The Agent, the Issuing Bank and the
Participating Banks shall be entitled to rely conclusively upon the
certificates delivered from time to time by officers of the Account Party,
NU, NUSCO and the other parties to the Loan Documents, Related Documents and
the Significant Contracts as to the names, incumbency, authority and
signatures of the respective persons named therein until such time as the
Agent may receive a replacement certificate, in form acceptable to the Agent,
from an officer of such Person identified to the Agent as having authority to
deliver such certificate, setting forth the names and true signatures of the
officers and other representatives of such Person thereafter authorized to
act on behalf of such Person.
ARTICLE VI
REPRESENTATIONS AND WARRANTIES
SECTION VI.1. Representations and Warranties of the Account Party. The
Account Party represents and warrants as follows:
(a) The Account Party is a corporation duly organized and validly existing
under the laws of the State of New Hampshire. The Account Party is duly
qualified to do business in, and is in good standing in, all other
jurisdictions where the nature of its business or the nature of property
owned or used by it makes such qualifications necessary.
(b) The execution, delivery and performance by the Account Party of the Rate
Agreement and of each Transaction Document, Loan Document, Related Document
and Significant Contract to which it is a party, are within the Account
Party's corporate powers, have been duly authorized by all necessary
corporate action, and do not and will not contravene (i) the Account Party's
charter or bylaws or (ii) any law or legal or contractual restriction binding
on or affecting the Account Party; and such execution, delivery and
performance do not or will not result in or require the creation of any Lien
(other than pursuant hereto or pursuant to the Security Documents) upon or
with respect to any of its properties.
(c) All Governmental Approvals referred to in clauses (i) and (ii) of the
definition of "Governmental Approvals" have been duly obtained or made, and
all applicable periods of time for review, rehearing or appeal with respect
thereto have expired, except as described in the several opinions of counsel
delivered pursuant to Article III of the Amendment. The Account Party has
obtained or made all Governmental Approvals referred to in clause (iii) of
the definition of "Governmental Approvals", except those which are not yet
required but which are obtainable in the ordinary course of business as and
when required and those the absence of which would not materially adversely
affect the financial condition, properties, prospects or operations of the
Account Party as a whole.
(d) This Agreement, the Rate Agreement, each other Transaction Document,
Loan Document, Related Document and each Significant Contract to which the
Account Party is a party have been duly executed and delivered by or on
behalf of the Account Party and are legal, valid and binding obligations of
the Account Party enforceable against the Account Party in accordance with
their respective terms; subject to the qualifications, however, that the
enforcement of the rights and remedies herein and therein is subject to
bankruptcy and other similar laws of general application affecting rights and
remedies of creditors and the application of general principles of equity
(regardless of whether considered in a proceeding in equity or law), that the
remedy of specific performance or of injunctive relief is subject to the
discretion of the court before which any proceedings therefor may be brought
and that indemnification against violations of securities and similar laws
may be subject to matters of public policy.
(e) The audited balance sheet of the Account Party as at December 31, 1997
and the related statements of the Account Party setting forth the results of
operations, retained earnings and cash flows of the Account Party for the
fiscal year then ended, copies of which have been furnished to each
Participating Bank, fairly present in all material respects the financial
condition, results of operations, retained earnings and cash flows of the
Account Party at and for the year ended on such date, and have been prepared
in accordance with generally accepted accounting principles consistently
applied. Except as reflected in such financial statements, the Account Party
has no material non-contingent liabilities, and all contingent liabilities
have been appropriately reserved. The financial projections referred to in
Section 3.02(d)(ii) of the Amendment have been prepared in good faith and on
reasonable assumptions. Since December 31, 1997, there has been no material
adverse change in the financial condition, operations, properties or
prospects of the Account Party, other than as disclosed in the Disclosure
Documents; provided, however, that the existence of the Rate Proceeding shall
not be deemed in and of itself to be a material adverse change; provided,
further, however, that notwithstanding the foregoing, a material adverse
change shall be deemed to have occurred and be continuing upon the occurrence
of a material adverse change or development in the Rate Proceeding.
(f) Except as set forth in the Disclosure Documents, there is no pending or
known threatened action or proceeding (including, without limitation, any
action or proceeding relating to any environmental protection laws or
regulations) affecting the Account Party or its properties before any court,
governmental agency or arbitrator (i) which affects or purports to affect the
legality, validity or enforceability of the Transaction Documents, the Loan
Documents or the Related Documents, the Rate Agreement, or any Significant
Contract, or any of them or (ii) which, if adversely determined, would
materially adversely affect the financial condition, operations, properties
or prospects of the Account Party as a whole. Notwithstanding the foregoing,
any material adverse development in respect of the Rate Proceeding, the Rate
Agreement or the Final Plan that results, or would reasonably be expected to
result, in a material adverse effect on the financial condition, operations,
properties or prospects of the Account Party as a whole, shall be deemed to
be an event within clause (ii) of the preceding sentence.
(g) All insurance required by Section 7.01(c) hereof is in full force and
effect.
(h) No ERISA Plan Termination Event has occurred nor is reasonably expected
to occur with respect to any ERISA Plan which would materially adversely
affect the financial condition, properties, prospects or operations of the
Account Party, except as disclosed to and consented by the Majority Lenders
in writing. Since the date of the most recent Schedule B (Actuarial
Information) to the annual report of the Account Party (Form 5500 Series), if
any, there has been no material adverse change in the funding status of the
ERISA Plans referred to therein and no "prohibited transaction" has occurred
with respect thereto, except as described in the 1997 10-K and except as the
same may be exempt pursuant to Section 408 of ERISA and regulations and
orders thereunder. Neither the Account Party nor any of its ERISA Affiliates
has incurred nor reasonably expects to incur any material withdrawal
liability under ERISA to any ERISA Multiemployer Plan, except as disclosed to
and consented by the Majority Lenders in writing.
(i) The Major Electric Generating Plants are on land in which the Account
Party owns a full or an undivided fee interest subject only to Liens
permitted by Section 7.02(a) hereof, which do not materially impair the
usefulness to the Account Party of such properties; the electric transmission
and distribution lines of the Account Party in the main are located in New
Hampshire and on land owned in fee by the Account Party or over which the
Account Party has easements, or are in or over public highways or public
waters pursuant to adequate statutory or regulatory authority, and any
defects in the title to such transmission and distribution lands or easements
are in the main curable by the exercise of the Account Party's right of
eminent domain upon a finding that such eminent domain proceedings are
necessary to meet the reasonable requirements of service to the public; the
Account Party enjoys peaceful and undisturbed possession under all of the
leases under which it is operating, none of which contains any unusual or
burdensome provision which will materially affect or impair the operation of
the Account Party; and the Security Documents will create valid Liens in the
Collateral, subject only to Liens permitted by Section 7.02(a) hereof, and
all filings and other actions necessary to perfect and protect such security
interests (to the extent such security interests may be perfected or
protected by filing) have been taken; provided, however, that no
representation is made as to any Lien purported to be created in favor of the
Trustee with respect to any interest of the Issuer in the Indenture.
(j) No material part of the properties, business or operations of the
Account Party are materially adversely affected by any fire, explosion,
accident, strike, lockout or other labor disputes, drought, storm, hail,
earthquake, embargo, act of God or of the public enemy or other casualty
(except for any such circumstance, if any, which is covered by insurance
which coverage has been confirmed and not disputed by the relevant insurer or
by fully-funded self-insurance programs).
(k) The Account Party has filed all tax returns (Federal, state and local)
required to be filed and paid taxes shown thereon to be due, including
interest and penalties, or, to the extent the Account Party is contesting in
good faith an assertion of liability based on such returns, has provided
adequate reserves in accordance with generally accepted accounting principles
for payment thereof.
(l) No exhibit, schedule, report or other written information provided by
the Account Party or its agents to the Agent, the Issuing Bank or the
Participating Banks in connection with the negotiation, execution and closing
of this Agreement and the other Transaction Documents, or the issuance of the
Bonds (including, without limitation, the Information Memorandum and the
Official Statements) knowingly contained when made any material misstatement
of fact or knowingly omitted to state any material fact necessary to make the
statements contained therein not misleading in light of the circumstances
under which they were made.
(m) No event has occurred and is continuing which constitutes a material
default under the Rate Agreement or any Significant Contract.
(n) The Account Party has not, either directly or indirectly, made any
investment in, or loans to, any Affiliate of the Account Party, other than
such investments or loans as were outstanding on the date hereof.
(o) No proceeds of any Advance will be used (i) to acquire any equity
security of a class which is registered pursuant to Section 12 of the
Securities Exchange Act of 1934 or (ii) to buy or carry any margin stock
(within the meaning of Regulation U issued by the Board of Governors of the
Federal Reserve System) or to extend credit to others for such purpose. The
Account Party (X) is not an "investment company" within the meaning ascribed
to that term in the Investment Company Act of 1940 or (Y) is not engaged in
the business of extending credit for the purpose of buying or carrying margin
stock.
ARTICLE VII
COVENANTS OF THE ACCOUNT PARTY
SECTION VII.1. Affirmative Covenants. So long as any amounts shall remain
available to be drawn under the Letter of Credit or any Advance or other
amounts shall remain unpaid hereunder or any Participating Bank shall have
any Commitment, the Account Party will, unless the Majority Lenders shall
otherwise consent in writing:
(a) Use of Proceeds. Apply all proceeds of each Advance solely as specified
in Section 3.02 and Section 6.01(o) hereof.
(b) Payment of Taxes, Etc. Pay and discharge before the same shall become
delinquent all taxes, assessments and governmental charges, royalties or
levies imposed upon it or upon its property except to the extent the Account
Party is contesting the same in good faith by appropriate proceedings and has
set aside adequate reserves for the payment thereof.
(c) Maintenance of Insurance. Maintain, or cause to be maintained, insurance
(including appropriate plans of seif-insurance) covering the Account Party
and its properties in effect at all times in such amounts and covering such
risks as may be required by law and in addition as is usually carried by
companies engaged in similar businesses and owning similar properties.
(d) Preservation of Existence, Etc. Preserve and maintain its corporate
existence, material rights (statutory and otherwise) and franchises except as
otherwise expressly provided for in the Security Documents.
(e) Compliance with Laws, Etc. Comply in all material respects with the
requirements of all applicable laws, rules, regulations and orders of any
governmental authority, including without limitation any such laws, rules,
regulations and orders relating to utilities, zoning, environmental
protection, use and disposal of Hazardous Substances, land use, construction
and building restrictions, and employee safety and health matters relating to
business operations, except to the extent (i) that the Account Party is
contesting the same in good faith by appropriate proceedings or (ii) that any
such non-compliance, and the enforcement or correction thereof, would not
materially adversely affect the financial condition, properties, prospects or
operations of the Account Party as a whole.
(f) Inspection Rights. At any time and from time to time upon reasonable
notice, permit the Agent and its agents and representatives to examine and
make copies of and abstracts from the records and books of account of, and
the properties of, the Account Party and to discuss the affairs, finances and
accounts of the Account Party with the Account Party and of its officers,
directors and accountants.
(g) Keeping of Books. Keep proper records and books of account, in which
full and correct entries shall be made of all financial transactions of the
Account Party and the assets and business of the Account Party, in accordance
with good accounting practices consistently applied.
(h) Performance of Related Agreements. Perform and observe all material
terms and provisions of the Revolving Credit Agreement, the Rate Agreement
and each Significant Contract to be performed or observed by the Account
Party and take all reasonable steps to enforce such agreements substantially
in accordance with their terms and to preserve the rights of the Account
Party thereunder; provided, that the foregoing provisions of this Section
7.01(h) shall not preclude the Account Party from any waiver, amendment,
modification, consent or termination (i) made in accordance with the
provisions of Section 7.04 hereof (in the case of the Revolving Credit
Agreement) or (ii) permitted under Section 7.02(g) hereof (in the case of the
Rate Agreement or any Significant Contract).
(i) Collection of Accounts Receivable. Promptly bill, and diligently pursue
collection of, in accordance with customary utility practices, all accounts
receivable owing to the Account Party and all other amounts that may from
time to time be owing to the Account Party for services rendered or goods
sold.
(j) Maintenance of Financial Covenants:
(i) Operating Income to Interest Expense. Maintain a ratio of Operating
Income to Interest Expense of not less than 2.35 to 1.00 for each period of
four consecutive fiscal quarters on each quarter-end ending after December
31, 1997.
(ii) Common Equity to Total Capitalization Ratio. Maintain at all times
a ratio of Common Equity to Total Capitalization of not less than 0.325 to
1.00.
(k) Maintenance of Properties, Etc. (i) As to properties of the type
described in Section 6.01(i) hereof, maintain title of the quality described
therein; and (ii) preserve, maintain, develop, and operate in substantial
conformity with all laws, material contractual obligations and prudent
practices prevailing in the industry, all of its properties which are used or
useful in the conduct of its business in good working order and condition,
ordinary wear and tear excepted, except to the extent such non-conformity
would not materially adversely affect the financial condition, properties,
prospects or operations of the Account Party as a whole.
(l) Governmental Approvals. Duly obtain on or prior to such date as the
same may become legally required, and thereafter maintain in effect at all
times, all Governmental Approvals on its part to be obtained, except those
the absence of which would not materially adversely affect the financial
condition, properties, prospects or operations of the Account Party as a
whole.
(m) Further Assurances. Promptly execute and deliver all further
instruments and documents, and take all further action, that may be necessary
or that any Participating Bank through the Issuing Bank may reasonably
request in order to fully give effect to the interests and properties
purported to be covered by the Security Documents.
(n) Related Documents. Perform and comply in all material respects with each
of the provisions of each Related Document to which it is a party.
SECTION VII.2. Negative Covenants. So long as any amount shall remain
available to be drawn under the Letter of Credit or any Advance or other
amounts shall remain unpaid hereunder or any Participating Bank shall have
any Commitment, the Account Party will not without the written consent of the
Majority Lenders:
(a) Liens, Etc. Create, incur, assume or suffer to exist any lien, security
interest, or other charge or encumbrance (including the lien or retained
security title of a conditional vendor) of any kind, or any other type of
preferential arrangement the intent or effect of which is to assure a
creditor against loss or to prefer one creditor over another creditor upon or
with respect to any of its properties of any character (any of the foregoing
being referred to herein as a "Lien") whether now owned or hereafter
acquired, or sign or file under the Uniform Commercial Code of any
jurisdiction a financing statement which names the Account Party as debtor,
sign any security agreement authorizing any secured party thereunder to file
such financing statement, or assign accounts, excluding, however, from the
operation of the foregoing restrictions the following, whether now existing
or hereafter created or perfected:
(i) The Liens of the First Mortgage Indenture, the Security Agreement, the
Pledge Agreement, the "Pledge Agreement" referred to in the Other
Reimbursement Agreement, and any lien created pursuant hereto; and
(ii) Permitted Liens (as defined in the First Mortgage Indenture as in
effect on the date hereof) on the Indenture Assets; provided, however, that
(A) the exclusion contained in clause (a) of such definition with respect to
Liens junior to the Lien of the First Mortgage Indenture shall not apply to
any Lien created after the date hereof; (B) the exclusion contained in
clauses (g) and (h) of such definition shall apply only to the extent that
all Liens of the type described therein from time to time existing do not, in
the aggregate, materially and adversely affect the value of the security
granted under the First Mortgage Indenture and no such Lien secures Debt of
the Account Party for borrowed money; and (C) the Account Party shall not, on
or after the date hereof, create, incur or assume any purchase money Debt
secured by Liens of the type described in clause (o) of such definition;
provided, however, that this Section 7.02(a) shall not be construed to
authorize the Account Party to incur, assume, be liable for or suffer to
exist any Debt not otherwise permitted hereunder.
(b) Debt. From and after the Amendment Closing Date, create, incur or
assume any Debt, other than pursuant to this Agreement, the Other
Reimbursement Agreement, the Revolving Credit Agreement and unsecured debt in
an aggregate amount not to exceed $25,000,000, and then only if, after giving
effect thereto, (i) no Event of Default or Unmatured Default shall have
occurred and be continuing on the date of such creation, incurrence or
assumption and (ii) the Account Party shall have determined that on the basis
of the assumptions and forecasts set forth in the most recent operating
budget/forecast of operations delivered pursuant to Section 7.03(iv) hereof
(which the Account Party continues to believe to be reasonable), the Account
Party will continue to be in compliance at all times with the provisions of
Section 7.01(j) hereof. The Account Party will furnish evidence of its
compliance with this subsection (b) for each fiscal quarter pursuant to
Section 7.03(ii) hereof.
(c) Mergers, Etc. Merge with or into or consolidate with or into, or
acquire all or substantially all of the assets of, any Person.
(d) Sales, Etc., of Assets. Sell, lease, transfer or otherwise dispose of
all or any substantial part of its assets, whether in a single transaction or
series of transactions during any consecutive 12-month period, except for (i)
the sale of the Account Party's generating assets on an arms'-length basis in
a transaction (or series of transactions) subject to approval by the NHPUC as
part of a settlement of the Rate Proceeding and (ii) sales, leases, transfers
or other dispositions in the ordinary course of the Account Party's business
in accordance with ordinary and customary terms and conditions. For purposes
of this subsection (d), any transaction or series of transactions during any
consecutive 12-month period shall be deemed to involve a "substantial part"
of the Account Party's assets if, in the aggregate, (A) the book value of
such assets equals or exceeds 7.5% of the total assets, net of regulatory
assets, of the Account Party reflected in the financial statements of the
Account Party delivered pursuant to Section 7.03(ii) or 7.03(iii) hereof in
respect of the fiscal quarter or year ending on or immediately prior to the
commencement of such 12-month period or (B) for the four calendar quarters
ending on or immediately prior to commencement of such 12-month period, the
gross revenue derived by the Account Party from such assets shall equal or
exceed 7.5% of the total gross revenue of the Account Party.
(e) Restricted Payments and NUG Settlements. Declare or pay any dividend,
or make any payment or other distribution of assets, properties, cash,
rights, obligations or securities on account of any share of any class of
capital stock of the Account Party (other than stock splits and dividends
payable solely in equity securities of the Account Party), or purchase,
redeem, retire, or otherwise acquire for value any shares of any class of
capital stock of the Account Party or any warrants, rights, or options to
acquire any such Debt or shares, now or hereafter outstanding, or make any
distribution of assets to any of its shareholders (any such transaction being
a "Restricted Payment"), or make any payment of or on account of any NUG
Settlement (a "NUG Settlement Payment"); provided, that the Account Party may
make one or more Restricted Payments or NUG Settlement Payments after July 1,
1998 if:
(i) at the time such payment is made and after giving effect thereto, no
advances will be outstanding under the Revolving Credit Agreement;
(ii) the aggregate amount of all such payments shall not exceed $40,000,000;
(iii) without limitation of the foregoing, the aggregate amount of all
Restricted Payments shall not exceed $25,000,000;
(iv) in the case of a NUG Settlement Payment, such NUG Settlement shall have
been approved by the NHPUC and all other Governmental Approvals related
thereto shall have been obtained and be in full force and effect;
(v) no Event of Default or Unmatured Default shall have occurred and be
continuing;
(vi) after giving effect to such payment, the Account Party shall be in full
compliance with Section 7.01(j) hereof (for purposes of determining
compliance with Section 7.01(j) under this clause (vi), computations under
Section 7.01(j) shall be made as of the date of such payment, except that,
retained earnings shall be determined as of the last day of the immediately
preceding fiscal quarter (adjusted for all Restricted Payments made after the
last day of such preceding fiscal quarter)); and
(vii) the Account Party shall have determined that, on the basis of the
assumptions and forecasts set forth in the most recent operating
budget/forecast of operations delivered pursuant to Section 7.03(iv) hereof
(which the Account Party continues to believe to be reasonable) and after
giving effect to such payment, the Account Party will continue to be in
compliance at all times with the provisions of Section 7.01(j) hereof.
Notwithstanding anything to the contrary contained in this Section 7.02(e),
the Account Party may declare and pay regularly scheduled quarterly dividends
and regularly scheduled sinking fund payments on the Preferred Stock, if,
immediately prior to and after giving effect to any such payment, no Event of
Default or Unmatured Default shall have occurred and be continuing.
(f) Compliance with ERISA. (i) terminate, or permit any ERISA Affiliate to
terminate, any ERISA Plan so as to result in any material (in the opinion of
the Majority Lenders) liability of the Account Party to the PBGC, or (ii)
permit to exist any occurrence of any event described in clause (i) of the
definition of ERISA Plan Termination Event, or any other event or condition,
which presents a material (in the opinion of the Majority Lenders) risk of
such a termination by the PBGC of any ERISA Plan and such a material
liability to the Account Party.
(g) Related Agreements.
(i) Amendments. Amend, modify or supplement or give any consent, acceptance
or approval to any amendment, modification or supplement or deviation by any
party from the terms of, the Rate Agreement or any Significant Contract,
except, with respect only to the Significant Contracts, any amendment,
modification or supplement thereto that would not reduce the rights or
entitlements of the Account Party thereunder in any material way.
(ii) Termination. Cancel or terminate (or consent to any cancellation or
termination of) the Rate Agreement or any Significant Contract prior to the
expiration of its stated term, provided that this subsection (ii) shall not
restrict the rights of the Account Party to enforce any remedy against any
obligor under any Significant Contract in the event of a material breach or
default by such obligor thereunder if and so long as the Account Party shall
have provided to the Agent at least 30 days prior written notice of the
enforcement action proposed to be undertaken by the Account Party.
(h) Change in Nature of Business. Engage in any material business activity
other than those established and engaged in on the date hereof.
(i) Ownership in Nuclear Plants. Acquire, directly or indirectly, any
ownership interest or any additional ownership interest of any kind in any
nuclear-powered electric generating plant.
(j) Subsidiaries. Create or suffer to exist any active subsidiaries other
than Properties, Inc., a New Hampshire corporation; or permit any material
assets or business to be maintained at or conducted by any subsidiary except
for the assets owned by Properties, Inc. not exceeding $20,000,000.
(k) Prepayment or Alteration of Debt. (i) Prepay, redeem, reduce or
voluntarily retire, or make or agree to make any change in the terms of, any
Debt of the Account Party, other than repayments and prepayments of advances
under, and modifications of, the Revolving Credit Agreement, in each case to
the extent permitted by Section 7.04; (ii) without limitation of the
foregoing, amend, modify or supplement the Indenture or the First Mortgage
Indenture or (iii) issue any First Mortgage Bonds as collateral security for
any existing or future debt, or grant any other security to any holder of
existing Debt of the Account Party, except to the extent permitted by Section
7.04.
(l) Loans and Investments. Make any loans to or investments in any Person,
other than investments in Permitted Investments.
(m) Affiliate Receivables. Permit the aggregate balance of accounts
receivable from Affiliates (other than such receivables constituting
receivables for wholesale sales of power) to equal or exceed $12,500,000 as
of the end of any calendar month.
SECTION VII.3. Reporting Obligations. So long as any amount shall remain
available to be drawn under the Letter of Credit or any Advance or other
amounts shall remain unpaid hereunder or any Participating Bank shall have
any Commitment, the Account Party will, unless the Majority Lenders shall
otherwise consent in writing, furnish to the Agent in sufficient copies for
the Issuing Bank and each Participating Bank, the following:
(i) as soon as possible and in any event within five (5) days after the
occurrence of each Event of Default or Unmatured Default continuing on the
date of such statement, a statement of the Chief Financial Officer, Treasurer
or Assistant Treasurer of the Account Party setting forth details of such
Event of Default or Unmatured Default and the action which the Account Party
proposes to take with respect thereto;
(ii) as soon as available and in any event within fifty (50) days after the
end of each of the first three quarters of each fiscal year of the Account
Party, (A) if and so long as the Account Party is required to submit to the
Securities and Exchange Commission a report on Form 10-Q, a copy of the
Account Party's report on Form 10-Q submitted to the Securities and Exchange
Commission with respect to such quarter and (B) if the Account Party ceases
to be required to submit such report, a balance sheet of the Account Party as
of the end of such quarter and statements of income and retained earnings and
of cash flows of the Account Party for the period commencing at the end of
the previous fiscal year and ending with the end of such quarter, all in
reasonable detail and duly certified (subject to year-end audit adjustments)
by the Chief Financial Officer, Treasurer or Assistant Treasurer of the
Account Party as having been prepared in accordance with generally accepted
accounting principles consistent with those applied in the preparation of the
financial statements referred to in Section 6.01(e) hereof, in each such
case, delivered together with a certificate of said officer (x) stating that
no Event of Default or Unmatured Default has occurred and is continuing or,
if an Event of Default or Unmatured Default has occurred and is continuing, a
statement as to the nature thereof and the action which the Account Party
proposes to take with respect thereto, (y) demonstrating compliance with
Section 7.01(j) hereof for and as of the end of such fiscal quarter and
compliance with Sections 7.02(b) and (e) hereof, as of the dates on which any
Debt was created, incurred or assumed (using the Account Party's most recent
annual actuarial determinations in the computation of Debt referred to in
clause (ix) in the definition of "Debt") or any Restricted Payment or NUG
Settlement Payment was made during such quarter, and (z) demonstrating, after
giving effect to the incurrence of any Debt created, incurred or assumed
during such fiscal quarter (using the Account Party's most recent annual
actuarial determinations in the computation of Debt referred to in clause
(ix) in the definition of "Debt") and after giving effect to any Restricted
Payments or NUG Settlement Payments made during such fiscal quarter,
compliance with Section 7.01(j) hereof for the remainder of the fiscal year
of the Account Party based on the operating budget/forecast of operations
delivered pursuant to Section 7.03 (iv) hereof for such fiscal year, such
demonstrations to be in a schedule (in form satisfactory to the Majority
Lenders) which sets forth the computations used by the Account Party in
determining such compliance;
(iii) as soon as available and in any event within 105 days after the end
of each fiscal year of the Account Party, (A) if and so long as the Account
Party is required to submit to the Securities and Exchange Commission a
report on Form 10-K, a copy of the Account Party's report on Form 10-K
submitted to the Securities and Exchange Commission with respect to such year
and (B) if the Account Party ceases to be required to submit such report, a
copy of the annual audit report for such year for the Account Party including
therein a balance sheet of the Account Party as of the end of such fiscal
year and statements of income and retained earnings and of cash flows of the
Account Party for such fiscal year, in each case certified by a nationally-
recognized independent public accountant, in each such case delivered
together with a certificate of the Chief Financial Officer, Treasurer or
Assistant Treasurer (x) stating that the financial statements were prepared
in accordance with generally accepted accounting principles consistent with
those applied in the preparation of financial statements referred to in
Section 6.01(e) hereof, and that no Event of Default or Unmatured Default has
occurred and is continuing, or if an Event of Default or Unmatured Default
has occurred and is continuing, stating the nature thereof and the action
which the Account Party proposes to take with respect thereto and (y)
demonstrating compliance with Section 7.01(j) hereof for and as of the end of
such fiscal year and compliance with Sections 7.02(b) and (e) hereof, as of
the dates on which any Debt was created, incurred or assumed (using the
Account Party's most recent annual actuarial determinations in the
computation of Debt referred to in clause (ix) in the definition of "Debt")
or any Restricted Payment or NUG Settlement Payment was made during the last
fiscal quarter of the Account Party, such demonstrations to be in a schedule
(in form satisfactory to the Majority Lenders) which sets forth the
computations used by the Account Party in determining such compliance.
(iv) as soon as available and in any event before March 31 of each fiscal
year, a copy of an operating budget/forecast of operations of the Account
Party as approved by the Board of Directors of the Account Party in form
satisfactory to the Participating Banks for such fiscal year of the Account
Party, together with a certificate of the Chief Financial Officer, Treasurer
or Assistant Treasurer of the Account Party stating that such budget/forecast
was prepared in good faith and on reasonable assumptions;
(v) not later than ten days following the end of each fiscal quarter of the
Account Party, a report on the progress of and developments in the Rate
Proceeding, the Final Plan and any negotiations concerning the foregoing;
(vi) as soon as available and in any event no later than the New Hampshire
Public Utilities Commission shall have received the Account Party's annual
submission, if any, relating to the "return on equity collar" referred to in
the Rate Agreement, a copy of such annual submission of the Account Party;
(vii) as soon as possible and in any event (A) within 30 days after the
Account Party knows or has reason to know that any ERISA Plan Termination
Event described in clause (i) of the definition of ERISA Plan Termination
Event with respect to any ERISA Plan or ERISA Multiemployer Plan has occurred
and (B) within 10 days after the Account Party knows or has reason to know
that any other ERISA Plan Termination Event with respect to any ERISA Plan or
ERISA Multiemployer Plan has occurred, a statement of the Chief Financial
Officer, Treasurer or Assistant Treasurer of the Account Party describing
such ERISA Plan Termination Event and the action, if any, which the Account
Party proposes to take with respect thereto;
(viii) promptly after receipt thereof by the Account Party or any of its
ERISA Affiliates from the PBGC, copies of each notice received by the Account
Party or any such ERISA Affiliate of the PBGC's intention to terminate any
ERISA Plan or ERISA Multiemployer Plan or to have a trustee appointed to
administer any ERISA Plan or ERISA Multiemployer Plan;
(ix) promptly and in any event within 30 days after the filing thereof with
the Internal Revenue Service, copies of each Schedule B (Actuarial
Information) to the annual report (Form 5500 Series) with respect to each
ERISA Plan (if any) to which the Account Party is a contributing employer;
(x) promptly after receipt thereof by the Account Party or any of its ERISA
Affiliates from an ERISA Multiemployer Plan sponsor, a copy of each notice
received by the Account Party or any of its ERISA Affiliates concerning the
imposition or amount of withdrawal liability in an aggregate principal amount
of at least $10,000,000 pursuant to Section 4202 of ERISA in respect of which
the Account Party may be liable;
(xi) promptly after the Account Party becomes aware of the occurrence
thereof, notice of all actions, suits, proceedings or other events (A) of the
type described in Section 6.01(f), or (B) which purport to affect the
legality, validity or enforceability of the Rate Agreement, or any
Transaction Document, Loan Document, Related Document or Significant
Contract;
(xii) promptly after the sending or filing thereof, copies of all such
proxy statements, financial statements, and reports which the Account Party
sends to its public security holders (if any) or files with, and copies of
all regular, periodic and special reports and all registration statements and
periodic or special reports, if any, which the Account Party files with, the
Securities and Exchange Commission or any governmental authority which may be
substituted therefor, or with any national securities exchange;
(xiii) promptly after receipt thereof, any assertion of the character
described in Section 8.01(h) hereof and the action the Account Party proposes
to take with respect thereto;
(xiv) promptly after knowledge of any material default under the Rate
Agreement or any Significant Contract, notice of such default and the action
the Account Party proposes to take with respect thereto;
(xv) promptly after knowledge of any amendment, modification, or other change
to the Rate Agreement or any Significant Contract or to any Governmental
Approval affecting the Rate Agreement, notice of such amendment, modification
or other change, it being understood that for purposes of this clause (xiv)
any filing by the Account Party in the ordinary course of the Account Party's
business with, or order issued or action taken by, a governmental authority
or regulatory body after May 16, 1991 to implement the terms of the Rate
Agreement shall not be considered an amendment, modification or change to a
Governmental Approval affecting the Rate Agreement; and
(xvi) promptly after requested, such other information respecting the
financial condition, operations, properties, prospects or otherwise, of the
Account Party as the Issuing Bank or Majority Lenders may from time to time
reasonably request in writing.
SECTION VII.4. Most Favored Lender Covenants. So long as any amount shall
remain available to be drawn under the Letter of Credit or any Advance or
other amounts shall remain unpaid hereunder or any Participating Bank shall
have any Commitment:
(a) The Account Party will not amend, modify or supplement, or consent to
any amendment, modification or supplement to, the Other Reimbursement
Agreement or the Revolving Credit Agreement (whether the same relates to
pricing, tenor, reduction, prepayment, covenants, other credit terms or
otherwise), unless the Account Party shall first have offered to amend,
modify or supplement the Loan Documents in a like manner, subject however, to
the provisions of subsection (b), to the extent applicable.
(b) If at any time the Account Party shall be unable to borrow under the
Revolving Credit Agreement (or any successor revolving facility) because the
Account Party is unable to satisfy any "material adverse change" or other
condition precedent to borrowing (a "Funding Suspension"), and (x) the
failure to satisfy such condition does not itself constitute an Event of
Default hereunder and (y) no Event of Default or Unmatured Default shall
have occurred and be continuing hereunder, the provisions of subsection (a)
shall be subject to the following:
(i) The Account Party will be free to negotiate with the lenders under the
Revolving Credit Agreement (or the lenders under such successor facility)
(the"Non-Funding Lenders") and may resolve or not resolve such Funding
Suspension in such manner as it may see fit, without any requirement that the
Agent, the Issuing Bank or the Participating Banks consent thereto;
(ii) Any improvement in pricing, covenants or other credit terms
afforded to the Non-Funding Lenders to resolve the Funding Suspension shall
be offered to the Agent, the Issuing Bank and the Participating Banks in the
manner prescribed by subsection (a). Any additional security granted to the
Non-Funding Lenders to resolve the Funding Suspension shall be afforded
equally and ratably to the Agent, the Issuing Bank and the Participating
Banks, subject to the provisions of Section 7.05; and
(iii) If in connection with the resolution of a Funding Suspension, the
Non-Funding Lenders' facility shall be permanently reduced such that any
amounts repaid or prepaid as part of such resolution are not available to be
re-borrowed, the Account Party will pay to the Agent, for the benefit of the
Issuing Bank and the Participating Banks an amount equal to such repayment or
prepayment, dollar-for-dollar, to be applied to the reduction of the
Available Amount or to be held as cash collateral for the obligations of the
Account Party under the Loan Documents. For the avoidance of doubt:
(A) a reduction in the unfunded portion of the Non-Funding Lenders'
commitments will not, by itself, entitle the Agent, the Issuing Bank and the
Participating Banks to any such payment or to any reduction in the Available
Amount; and
(B) the Agent, the Issuing Bank and the Participating Banks will not be
entitled to any payment or reduction in the Available Amount solely as a
result of repayments and prepayments of advances under such facility, if
such repayment or prepayment results in the Non-Funding Lenders' commitments
becoming again available to the Account Party in at least the amount of the
repayment or prepayment.
(c) The provisions of subsection (b) shall not apply during the continuance
of an Event of Default.
SECTION VII.5. Covenants Concerning Certain Collateral.
(a) Cash Account. Subject to the provisions of subsection (b), below, upon
the occurrence and during the continuance of any Event of Default, the Agent
shall at the request, or may with the consent, of the Majority Lenders,
direct the Account Party to, and if so directed, the Account Party shall,
deposit with the Agent an amount in the cash account (the "Cash Account")
described below equal to the Available Amount of the Letter of Credit. Such
Cash Account shall at all times be free and clear of all rights or claims of
third parties. The Cash Account shall be maintained with the Agent in the
name of, and under the sole dominion and control of, the Agent, and amounts
deposited in the Cash Account shall bear interest at a rate equal to the rate
generally offered by Swiss Bank for deposits equal to the balance in the Cash
Account, for a term to be agreed to between the Account Party and the Agent.
If any Letter of Credit drawings then outstanding or thereafter made are not
reimbursed in full immediately after being made and upon demand, then, in any
such event, the Agent may apply the amounts then on deposit in the Cash
Account, in such priority as the Agent shall elect, toward the payment in
full of any or all of the Account Party's obligations hereunder as and when
such obligations shall become due and payable. Upon payment in full, after
the termination of the Letters of Credit, of all such obligations, the Agent
will repay to the Account Party any cash then on deposit in the Cash Account.
The Issuing Bank hereby confirms its obligation as set forth in the Letter of
Credit to make all payments under the Letter of Credit with its own funds and
not with any funds of the Account Party or the Issuer, and nothing in this
subsection (a) or otherwise shall in any way limit such obligation.
(b) Waiver and Surrender of Rights to Certain Collateral. Without in any
way modifying the payment provisions of Article III, and subject in all
respects to the provisions of subsection (c), below, the Agent, the Issuing
Bank and the Participating Banks hereby waive and surrender, effective upon
the commencement of any case by or against the Account Party seeking relief
in respect of the Account Party under the Bankruptcy Code, any and all right,
title and interest of the Agent, the Issuing Bank and the Participating Banks
in and to the Cash Account, the Collateral described in the Security
Agreement and all other collateral security, if any, granted to the Agent,
the Issuing Bank or the Participating Banks on or after April 23, 1998 (all
of the foregoing being hereinafter referred to as the "Extension Collateral",
which term shall exclude absolutely the Account Party's Series G First
Mortgage Bonds), and agree that upon any such commencement, the rights of
the Agent, the Issuing Bank and the Banks in and to the Extension Collateral
shall be null and void and the Agent, the Issuing Bank and the Banks shall
not thereafter seek or accept any benefits they may have in and to the
Extension Collateral; provided that the foregoing shall not apply to any
benefit to Agent, the Issuing Bank or any Participating Bank of any Extension
Collateral, if and only if: (i) a valid and perfected lien on or security
interest in such Extension Collateral was granted to one or more other
Secured Parties under the Intercreditor Agreement, (ii) such benefit to the
Agent, the Issuing Bank or any Participating Bank is no greater than such as
derives from its rights under the Intercreditor Agreement to share in the
benefits of all Collateral referred to therein on the terms and subject to
the conditions thereof, and (iii) after giving effect to such sharing, the
aggregate amount of secured claims against the bankruptcy estate of the
Account Party would not be increased.
(c) The waiver, surrender and agreement set forth in subsection (b), above,
shall terminate and be of no force and effect (i) if and to the extent that
such termination and the retention and enjoyment by the Agent, the Issuing
Bank and the Participating Banks of such right, title and interest would not
result in the grant of the Extension Collateral to the Agent, the Issuing
Bank and the Participating Banks being deemed to (X) constitute a transfer of
property of the Account Party avoidable under Section 547(b) of the
Bankruptcy Code or (Y) otherwise constitute a basis for the recovery of any
amounts realized with respect to the Collateral or the value thereof from the
Trustee or any holder of the Bonds as an avoidable transfer under Section
547(b) of the Bankruptcy Code and (ii) in any case, as to any item of
Extension Collateral, on the 91st day following the date on which a lien on
or security interest in such Extension Collateral in favor of the Agent, the
Issuing Bank or the Participating Banks was first perfected under applicable
law, so long as no such case has been commenced and is pending.
(d) Acknowledgment. The Agent, the Issuing Bank and the Participating
Banks, each by its execution and delivery of this Agreement, acknowledge and
agree to the provisions of this Section 7.05.
ARTICLE VIII
DEFAULTS
SECTION VIII.1. Events of Default. The following events shall each
constitute an "Event of Default" if the same shall occur and be continuing
after the grace period and notice requirement (if any) applicable thereto:
(a) The Account Party shall fail to pay any interest on any Advance or
pursuant to Section 4.02 hereof within two days after the same becomes due;
the Account Party shall fail to reimburse the Issuing Bank for any Interest
Drawing (as defined in the Letter of Credit) within two days after such
reimbursement becomes due; or the Account Party shall fail to make any other
payment required to be made pursuant to Article II or Article III hereof when
due; or
(b) Any representation or warranty made by the Account Party (or any of its
officers or agents) in any Loan Document or Transaction Document or in any
certificate or other writing delivered pursuant to any Loan Document or
Transaction Document shall prove to have been incorrect in any material
respect when made or deemed made; or
(c) The Account Party shall fail to perform or observe any term or covenant
on its part to be performed or observed contained in Sections 7.01(a), (d) or
(j), Section 7.02 or Section 7.03(i) hereof; or
(d) The Account Party shall fail to perform or observe any other term or
covenant on its part to be performed or observed contained in any Loan
Document or Transaction Document and such failure shall remain unremedied,
after written notice thereof shall have been given to the Account Party by
the Agent, the Issuing Bank or any Participating Bank, for a period of 30
days; or
(e) The Account Party shall fail to pay any of its Debt when due (including
any interest or premium thereon but excluding Debt arising hereunder and
excluding other Debt aggregating in no event more than $10,000,000 in
principal amount at any one time) whether by scheduled maturity, required
prepayment, acceleration, demand or otherwise, and such failure shall
continue after the applicable grace period, if any, specified in any
agreement or instrument relating to such Debt; or any other default under any
agreement or instrument relating to any such Debt, or any other event, shall
occur and shall continue after the applicable grace period, if any, specified
in such agreement or instrument, if the effect of such default or event is to
accelerate, or to permit the acceleration of, the maturity of such Debt; or
any such Debt shall be declared to be due and payable, or required to be
prepaid (other than by a regularly scheduled required prepayment or as a
result of the Account Party's exercise of a prepayment option) prior to the
stated maturity thereof; unless in each such case the obligee under or holder
of such Debt or the trustee with respect to such Debt shall have waived in
writing such circumstance without consideration having been paid by the
Account Party so that such circumstance is no longer continuing; or
(f) The Account Party shall generally not pay its debts as such debts become
due, or shall admit in writing its inability to pay its debts generally, or
shall make an assignment for the benefit of creditors; or any proceeding
shall be instituted by or against the Account Party seeking to adjudicate it
a bankrupt or insolvent, or seeking liquidation, winding up, reorganization,
arrangement, adjustment, protection, relief, or composition of its debts
under any law relating to bankruptcy, insolvency, or reorganization or relief
of debtors, or seeking the entry of an order for relief or the appointment of
a receiver, trustee, or other similar official for it or for any substantial
part of its property and, in the case of a proceeding instituted against the
Account Party, either the Account Party shall consent thereto or such
proceeding shall remain undismissed or unstayed for a period of 90 days or
any of the actions sought in such proceeding (including without limitation
the entry of an order for relief against the Account Party or the appointment
of a receiver, trustee, custodian or other similar official for the Account
Party or any of its property) shall occur; or the Account Party shall take
any corporate or other action to authorize any of the actions set forth above
in this subsection (f); or
(g) Any judgment or order for the payment of money in excess of $10,000,000
shall be rendered against the Account Party or its properties and either
enforcement proceedings shall have been commenced by any creditor upon such
judgment or order and shall not have been stayed or there shall be any period
of 15 consecutive days during which a stay of enforcement of such judgment or
order, by reason of a pending appeal or otherwise, shall not be in effect; or
(h) Any material provision of any Loan Document, the Rate Agreement, any
Significant Contract or any Related Document shall for any reason other than
the express terms thereof or the exercise of any right or option expressly
contained therein cease to be valid and binding on any party thereto except
as otherwise expressly permitted by the exceptions and provisions contained
in Section 7.02(g) hereof; or any party thereto other than the Participating
Banks shall so assert in writing, provided that in the case of any party
other than the Account Party making such assertion in respect of the Rate
Agreement, any Significant Contract or any Related Document, such assertion
shall not in and of itself constitute an Event of Default hereunder until (i)
such asserting party shall cease to perform under and in compliance with the
Rate Agreement, such Significant Contract or such Related Document, (ii) the
Account Party shall fail to diligently prosecute, by appropriate action or
proceedings, a rescission of such assertion or a binding determination as to
the merits thereof or (iii) such a binding determination shall have been made
in favor of such asserting party's position; or
(i) The Security Documents shall for any reason, except to the extent
permitted by the terms thereof, fail or cease to create valid and perfected
Liens (to the extent purported to be granted by such documents and subject to
the exceptions permitted thereunder) in any of the applicable Collateral
(other than Liens in favor of the Trustee with respect to the interests of
the Issuer under the Indenture), provided, that such failure or cessation
relating to any non-material portion of such Collateral shall not constitute
an Event of Default hereunder unless the same shall not have been corrected
within 30 days after the Account Party becomes aware thereof; or
(j) The Account Party shall not have in full force and effect any or all
insurance required under Section 7.01(c) hereof or there shall be incurred
any uninsured damage, loss or destruction of or to the Account Party's
properties in an amount not covered by insurance (including fully-funded
self-insurance programs) which the Majority Lenders consider to be material;
or
(k) A default by the Account Party shall have occurred under the Rate
Agreement and shall not have been effectively cured within the time period
specified therein for such cure (or, if no such time period is specified
therein, 10 days); or a default by any party shall have occurred under any
Significant Contract and such default shall not have been effectively cured
within 30 days after notice from the Agent to the Account Party stating that,
in the opinion of the Majority Lenders, such default may have a material
adverse effect upon the financial condition, operations, properties or
prospects of the Account Party as a whole; or
(l) Any Governmental Approval (whether federal, state or local) required to
give effect to the Rate Agreement (including, without limitation, Chapter
362-C of the New Hampshire Revised Statutes and the enabling order of the
NHPUC issued pursuant thereto) shall be amended, modified or supplemented, or
any other regulatory or legislative action or change (whether federal, state
or local) having the effect, directly or indirectly, of modifying the
benefits or entitlements of the Account Party under the Rate Agreement shall
occur, and in any such case such amendment, modification, supplement, action
or change may have, in the opinion of the Majority Lenders, a material
adverse effect upon the financial condition, operations, properties or
prospects of the Account Party as a whole; or
(m) NU shall cease to own all of the outstanding common stock of the Account
Party, free and clear of any Liens; or
(n) An event of default (as defined therein) shall have occurred and be
continuing under the Indenture or the First Mortgage Indenture; or
(o) An event of default (as defined therein) shall have occurred and be
continuing under the Revolving Credit Agreement or the Other Reimbursement
Agreement; or
(p) The Fixed-Rate Conversion shall fail to be consummated on May 1,1998.
SECTION VIII.2. Remedies Upon Events of Default. Upon the occurrence and
during the continuance of any Event of Default, then, and in any such event
the Agent with the concurrence of the Issuing Bank may, and upon the
direction of the Majority Lenders the Agent shall (i) if the Letter of Credit
Amendment shall not have been issued, instruct the Issuing Bank to (whereupon
the Issuing Bank shall) by notice to the Account Party declare its commitment
to issue the Letter of Credit Amendment to be terminated, whereupon the same
shall forthwith terminate, (ii) instruct the Issuing Bank to (whereupon the
Issuing Bank shall) furnish to the Trustee and the Paying Agent written
notice of such Event of Default in accordance with Section 6.01(a)(iv) of the
Indenture and of the Issuing Bank's determination to terminate the Letter of
Credit on the fifth business day (as defined in the Indenture) following the
Trustee's and Paying Agent's receipt of such notice, (iii) instruct the
Issuing Bank to (whereupon the Issuing Bank shall) furnish to the Trustee and
the Paying Agent written notice that the Interest Component will not be
reinstated in the amount of one or more Interest Drawings, all as provided in
the Letter of Credit; (iv) direct the Account party to pay cash into the Cash
Account in accordance with Section 7.05(a); (v) declare the Advances and all
other principal amounts outstanding hereunder, all interest thereon and all
other amounts payable hereunder to be forthwith due and payable, whereupon
the Advances and all other principal amounts outstanding hereunder, all such
interest and all such other amounts shall become and be forthwith due and
payable, without presentment, demand, protest or further notice of any kind,
all of which are hereby expressly waived by the Account Party, and (vi)
instruct the Issuing Bank to (whereupon the Issuing Bank shall) exercise all
the rights and remedies provided herein and under and in respect of the
Security Documents; provided, however, that in the event of an actual or
deemed entry of an order for relief with respect to the Account Party under
the Federal Bankruptcy Code, (A) the commitment of the Issuing Bank to issue
the Letter of Credit, the Commitments and the obligations of the
Participating Banks to make Advances shall automatically be terminated, and
(B) the Advances and all other principal amounts outstanding hereunder, all
interest accrued and unpaid thereon and all other amounts payable hereunder
shall automatically become due and payable, without presentment, demand,
protest or any notice of any kind, all of which are hereby expressly waived
by the Account Party.
SECTION VIII.3. Issuing Bank to Notify First Mortgage Trustee, Others. The
Issuing Bank shall, if so directed by the Majority Lenders, promptly notify
the First Mortgage Trustee by telephone, confirmed in writing, of the
occurrence of any Event of Default. In addition, the Issuing Bank shall
furnish to the Agent, the Account Party, the Paying Agent and the Issuer a
copy of (a) any notice furnished to the First Mortgage Trustee pursuant to
the preceding sentence and (b) any notice delivered to the Trustee pursuant
to clause (ii) or clause (iii) of Section 8.02. Notwithstanding the
foregoing, no failure of the Issuing Bank to give any notice (or copy of a
notice) as contemplated by this Section 8.03 shall limit or impair any rights
of the Issuing Bank, the Agent or any Participating Bank or the exercise of
any remedy hereunder, nor shall the Issuing Bank, the Agent or any
Participating Bank incur any liability as a result of any such failure.
ARTICLE IX
THE AGENT, THE PARTICIPATING BANKS AND THE ISSUING BANK
SECTION IX.1. Authorization of Agent; Actions of Agent and Issuing Bank. The
Issuing Bank and each Participating Bank hereby appoint and authorize the
Agent to take such action as agent on their behalf and to exercise such
powers under this Agreement as are delegated to the Agent by the terms
hereof, together with such powers as are reasonably incidental thereto;
provided, however, that neither the Agent nor the Issuing Bank shall be
required to take any action which exposes the Agent or the Issuing Bank to
personal liability or which is contrary to this Agreement or applicable law.
As to any matters not expressly provided for by any Related Document
(including, without limitation, enforcement or collection thereof), neither
the Agent nor the Issuing Bank shall be required to exercise any discretion
or take any action. The Agent agrees to deliver promptly (i) to the Issuing
Bank and each Participating Bank copies of each notice delivered to it by the
Account Party and (ii) to each Participating Bank copies of each notice
delivered to it by the Issuing Bank, in each case pursuant to the terms of
this Agreement.
SECTION IX.2. Reliance, Etc. Neither the Agent, the Issuing Bank, nor any
of their directors, officers, agents or employees shall be liable for any
action taken or omitted to be taken by it or them under or in connection with
this Agreement or any Related Document, except for its or their own gross
negligence or willful misconduct as determined by a court of competent
jurisdiction. Without limitation of the generality of the foregoing, each of
the Agent and the Issuing Bank (i) may consult with legal counsel (including
counsel for the Account Party), independent public accountants and other
experts selected by it and shall not be liable for any action taken or
omitted to be taken in good faith by it in accordance with the advice of such
counsel, accountants or experts; (ii) makes no warranty or representation to
any Participating Bank and shall not be responsible to any Participating Bank
for any statements, warranties or representations made in or in connection
with this Agreement or any Related Document; (iii) shall not have any duty to
ascertain or to inquire as to the performance or observance of any of the
terms, covenants or conditions of this Agreement or any Related Document on
the part of the Account Party to be performed or observed, or to inspect any
property (including the books and records) of the Account Party; (iv) shall
not be responsible to any Participating Bank for the due execution, legality,
validity, enforceability, genuineness, sufficiency or value of this Agreement
or any Related Document or any other instrument or document furnished
pursuant hereto and thereto; and (v) shall incur no liability under or in
respect of this Agreement or any Related Document by acting upon any notice,
consent certificate or other instrument or writing (which may be by telegram,
cable or telex), including, without limitation, any thereof from time to time
purporting to be from the Trustee, believed by it to be genuine and signed or
sent by the proper party or parties.
SECTION IX.3. The Agent, the Issuing Bank and Affiliates. The Agent and the
Issuing Bank shall have the same rights and powers under this Agreement as
any other Participating Bank and may exercise (or omit from exercising) the
same as though they were not the Agent and the Issuing Bank, respectively,
and the term "Participating Bank" shall, unless otherwise expressly
indicated, include Swiss Bank in its individual capacity. The Agent, the
Issuing Bank and their respective Affiliates may accept deposits from, lend
money to, act as trustee under indentures of, and generally engage in any
kind of business with, the Account Party, any of its subsidiaries and any
Person who may do business with or own securities of the Account Party or any
such subsidiary, all as if Swiss Bank was not the Agent or the Issuing Bank,
and without any duty to account therefor to the Participating Banks.
SECTION IX.4. Participating Bank Credit Decision. Each of the Issuing Bank
and each Participating Bank acknowledges that it has, independently and
without reliance upon the Arrangers, the Agent, the Issuing Bank or any other
Participating Bank and based on the financial information referred to in
Section 6.01(e) hereof and such other documents and information as it has
deemed appropriate, made its own credit analysis and decision to enter into
this Agreement. Each of the Issuing Bank and each Participating Bank also
acknowledges that it will, independently and without reliance upon the
Arrangers, the Agent, the Issuing Bank or any other Participating Bank and
based on such documents and information as it shall deem appropriate at the
time, continue to make its own credit decisions in taking or not taking
action under this Agreement.
SECTION IX.5. Indemnification. The Participating Banks agree to indemnity
the Arrangers, the Agent and the Issuing Bank (to the extent not reimbursed
by the Account Party), ratably according to their respective Participation
Percentages, from and against any and all liabilities, obligations, losses,
damages, penalties, actions, judgments, suits, costs, expenses or
disbursements of any kind or nature whatsoever which may be imposed on,
incurred by, or asserted against the Arrangers, the Agent or the Issuing Bank
in any way relating to or arising out of this Agreement or any action taken
or omitted by the Arrangers, the Agent or the Issuing Bank under or in
connection with this Agreement, provided that no Participating Bank shall be
liable for any portion of such liabilities, obligations, losses, damages,
penalties, actions, judgments, suits, costs, expenses or disbursements
resulting from the Arrangers', the Agent's or the Issuing Bank's (as the case
may be) gross negligence or willful misconduct. Without limitation of the
foregoing, each Participating Bank agrees to reimburse the Arrangers, the
Agent and the Issuing Bank promptly upon demand for its ratable share of any
out-of-pocket expenses (including counsel fees) incurred by the Arrangers,
the Agent and the Issuing Bank in connection with the preparation, execution,
delivery, administration, modification, amendment, waiver or enforcement
(whether through negotiations, legal proceedings or otherwise) of, or legal
advice in respect of rights or responsibilities under, this Agreement to the
extent that the Arrangers, the Agent and the Issuing Bank (as the case may
be) are entitled to reimbursement for such expenses pursuant to Section 10.04
hereof but are not reimbursed for such expenses by the Account Party.
SECTION IX.6. Successor Agent. The Agent may resign at any time by giving
written notice thereof to the Issuing Bank, the Participating Banks and the
Account Party, with any such resignation to become effective only upon the
appointment of a successor Agent pursuant to this Section 9.06. Upon any
such resignation, the Issuing Bank shall have the right to appoint a
successor Agent, which shall be another commercial bank or trust company
reasonably acceptable to the Account Party, organized or licensed under the
laws of the United States, or of any State thereof. Upon the acceptance of
any appointment as Agent hereunder by a successor Agent and the execution and
delivery by the Account Party and the successor Agent of an agreement
relating to the fees, if any, to be paid to the successor Agent in connection
with its acting as Agent hereunder, such successor Agent shall thereupon
succeed to and become vested with all the rights, powers, privileges and
duties of the retiring Agent, and the retiring Agent shall be discharged from
its duties and obligations under this Agreement. After any retiring Agent's
resignation hereunder as Agent, the provisions of this Article IX shall inure
to its benefit as to any actions taken or omitted to be taken by it while it
was Agent under this Agreement.
SECTION IX.7. Issuing Bank. (a) All notices received by the Issuing Bank
pursuant to this Agreement or any Related Document (other than the Letter of
Credit) shall be promptly delivered to the Agent for distribution to the
Participating Banks.
(b) Except to the extent permitted by Section 2.06, the Issuing Bank shall
not amend or waive any provision or consent to the amendment or waiver of any
Related Document without the written consent of the Majority Lenders.
Notwithstanding the foregoing, each Participating Bank, by its execution and
delivery of this Agreement, authorizes and directs the Issuing Bank to
execute and deliver the Second Supplement, dated as of May 1, 1995, to the
Original Indenture.
(c) Upon receipt by the Issuing Bank from time to time of any amount
pursuant to the terms of any Related Document (other than pursuant to the
terms of this Agreement), the Issuing Bank shall promptly deliver to the
Agent such amount.
SECTION IX.8. Certain Authorizations and Consent. The Issuing Bank and each
Participating Bank, by its acceptance hereof, and each other Participating
Bank by its execution and delivery of the Participant Assignment pursuant to
which it became a Participating Bank, consents to, authorizes, ratifies and
confirms in all respects:
(i) the execution, delivery, acceptance and performance by the Agent and by
the Collateral Agent of the Intercreditor Agreement, as the same may be from
time to time amended in accordance with the terms thereof and Section 10.01
hereof;
(ii) the execution, delivery and acceptance by the Collateral Agent of, and
the taking by the Collateral Agent of all actions under, the Security
Agreement, as the same may be from time to time amended in accordance with
the terms thereof and Section 10.01 hereof;
the execution and delivery of this Agreement by the Issuing Bank or such
Participating Bank, or the execution and delivery of such Participant
Assignment by such Participating Bank, as the case may be, constituting
(without further act or deed) the Issuing Bank or such Participating Bank's
acceptance and approval of, and agreement to the terms of, the Intercreditor
Agreement and the Security Agreement with the same effect as if the Issuing
Bank or such Participating Bank were itself a party thereto.
ARTICLE X
MISCELLANEOUS
SECTION X.1. Amendments, Etc. No amendment or waiver of any provision of
this Agreement or the Pledge Agreement, nor consent to any departure by the
Account Party therefrom, shall in any event be effective unless the same
shall be in writing and signed by the Majority Lenders, and then such waiver
or consent shall be effective only in the specific instance and for the
specific purpose for which given; provided, however, that no amendment,
waiver or consent shall, unless in writing and signed by the Issuing Bank and
all the Participating Banks, do any of the following: (a) waive, modify or
eliminate any of the conditions specified in Article V of this Agreement or
Article III of the Amendment, (b) increase the Commitments of the
Participating Banks that may be maintained hereunder or subject the
Participating Banks to any additional obligations, (c) reduce the principal
of, or interest on, the Advances, any amount reimbursable on demand pursuant
to Section 3.01, or any fees or other amounts payable hereunder, (d) postpone
any date fixed for any payment of principal of, or interest on, the Advances,
such reimbursable amounts or any fees or other amounts payable hereunder
(other than fees payable to the Issuing Bank or the Agent pursuant to Section
2.03 hereof), (e) change the percentage of the Commitments or of the
aggregate unpaid principal amount of the Advances, or the number of
Participating Banks which shall be required for the Participating Banks or
any of them to take any action hereunder, (f) amend this Agreement or the
Pledge Agreement in a manner intended to prefer one or more Participating
Banks over any other Participating Banks, (g) amend this Section 10.01, or
(h) release any of the Collateral otherwise than in accordance with any
provisions for such release contained in the Security Documents, or change
any provision of any Security Document providing for the release of all or
substantially all of the Collateral; and provided, further, that (i) no
amendment, waiver or consent shall, unless in writing and signed by the
Issuing Bank or the Agent in addition to the Participating Banks required
above to take such action, affect the rights or duties of the Issuing Bank or
the Agent, as the case may be, under this Agreement or the Pledge Agreement
and (ii) no amendment, waiver or consent shall, unless in writing and signed
by the "Majority Lenders" under the Other Reimbursement Agreement and the
"Majority Lenders" under the Revolving Credit Agreement, shall change the
percentage of the Commitments or of the aggregate unpaid principal amount of
the Advances, or the number of Participating Banks which shall be required
for the Participating Banks or any of them to take, or to direct the
Collateral Agent to take, any action under the Intercreditor Agreement and
the Security Agreement.
SECTION X.2. Notices, Etc. All notices and other communications provided for
hereunder and under the other Loan Documents shall be in writing (including
telegraphic, telex, telecopy or cable communication) and mailed, telegraphed,
telexed, telecopied, cabled or delivered:
(i) if to the Account Party, to it in care of NUSCO at NUSCO's address at
107 Selden Street, Berlin, Connecticut 06037 (telecopy: (860) 665-5457),
Attention: Assistant Treasurer - Finance;
(ii) if to the Issuing Bank or the Agent, to it at its address at 222
Broadway, 12th Floor, New York, New York 10038, Attention: Customer Service
Unit, (telephone: (212) 412-3363, telecopy: (212) 412-3080, Telex: 12-6946),
with a copy to: Utilities Finance Group, (telephone (212) 412-2551, telecopy:
(212) 412-7575) and with a further copy to Credit Enhancement Unit (telephone
(212) 412-3578, telecopy (212) 412-6969);
(iii) if to any Participating Bank, to it at its address set forth on the
signature pages to the Amendment or in the Participation Assignment pursuant
to which it became a Participating Bank; or
as to each party other than any Participating Bank, at such other address as
shall be designated by such party in a written notice to the other parties,
and, as to any Participating Bank, at such other address as shall be
designated by such Participating Bank in a written notice to the Account
Party and the Agent. All such notices and communications shall, when mailed,
telegraphed, telexed, telecopied or cabled, be effective five days after when
deposited in the mails, or when delivered to the telegraph company, confirmed
by telex answerback, telecopied or delivered to the cable company,
respectively, except that notices and communications to the Agent or the
Issuing Bank pursuant to Article II, III or IV shall not be effective until
received by the Agent or the Issuing Bank, as the case may be.
SECTION X.3. No Waiver of Remedies. No failure on the part of any
Participating Bank or the Issuing Bank to exercise, and no delay in
exercising, any right hereunder or under any Loan Document shall operate as a
waiver thereof; nor shall any single or partial exercise of any such right
preclude any other or further exercise thereof or the exercise of any other
right. The remedies herein provided are cumulative and not exclusive of any
remedies provided by law.
SECTION X.4. Cost; Expenses and Indemnification. (a) The Account Party
agrees to pay on demand all costs and expenses, if any (including, without
limitation, reasonable counsel fees and expenses), of (i) the Arrangers, the
Agent and the Issuing Bank in connection with the preparation, negotiation,
execution and delivery of the Loan Documents and Transaction Documents and
the administration of the Loan Documents and Transaction Documents, the care
and custody of any and all collateral, and any proposed modification,
amendment, or consent relating thereto; and (ii) the Arrangers, the Agent,
the Issuing Bank and each Participating Bank in connection with the
enforcement (whether through negotiations, legal proceedings or otherwise) of
this Agreement or any other Loan Document or Transaction Document.
(b) The Account Party hereby agrees to indemnify and hold the Arrangers, the
Agent, the Issuing Bank and each Participating Bank and their respective
officers, directors, employees, professional advisors and affiliates (each,
an "Indemnified Person") harmless from and against any and all claims,
damages, losses, liabilities, costs or expenses (including reasonable
attorney's fees and expenses, whether or not such Indemnified Person is named
as a party to any proceeding or investigation or is otherwise subjected to
judicial or legal process arising from any such proceeding or investigation)
which any of them may incur or which may be claimed against any of them by
any person or entity (except to the extent such claims, damages, losses,
liabilities, costs or expenses arise from the gross negligence or willful
misconduct of the Indemnified Person):
(i) by reason of or in connection with the execution, delivery or
performance of any of the Loan Documents, the Transaction Documents or the
Related Documents or any transaction contemplated thereby, or the use by the
Account Party of the proceeds of any Advance or the use by the Paying Agent
or the Trustee of the proceeds of any drawing under the Letter of Credit;
(ii) in connection with or resulting from the utilization, storage, disposal,
treatment, generation, transportation, release or ownership of any Hazardous
Substance (A) at, upon or under any property of the Account Party or any of
its Affiliates or (B) by or on behalf of the Account Party or any of its
Affiliates at any time and in any place;
(iii) in connection with any documentary taxes, assessments or charges
made by any governmental authority by reason of the execution and delivery of
any of the Loan Documents;
(iv) by reason of or in connection with the execution and delivery or
transfer of, or payment or failure to make payment under, the Letter of
Credit; provided, however, that the Account Party shall not be required to
indemnity the Arrangers, the Agent, the Issuing Bank or any Participating
Bank pursuant to this Section for any claims, damages, losses, liabilities,
costs or expenses to the extent caused by (A) the Issuing Bank's willful
misconduct or gross negligence, as determined by a court of competent
jurisdiction, in determining whether documents presented under the Letter of
Credit are genuine or comply with the terms of the Letter of Credit or (B)
the Issuing Bank's willful or grossly negligent failure, as determined by a
court of competent jurisdiction, to make lawful payment under the Letter of
Credit after the presentation to it by the Paying Agent of a draft and
certificate strictly complying with the terms and conditions of the Letter of
Credit; or
(v) by reason of any inaccuracy or alleged inaccuracy in any material
respect, or any untrue statement or alleged untrue statement of any material
fact, contained in any Official Statement, except to the extent contained in
or arising from information in such Official Statement supplied in writing by
and describing the Issuing Bank or any previous issuer of a letter of credit
relating to the Bonds.
(c) Nothing contained in this Section 10.04 is intended to limit the Account
Party's obligations set forth in Articles II, III and IV. The Account
Party's obligations under this Section 10.04 shall survive the creation and
sale of any participation interest pursuant to Section 10.06 hereof and shall
survive as well the repayment of all amounts owing to the Agent, the Issuing
Bank and the Participating Banks under the Loan Documents and the termination
of the Commitments. If and to the extent that the obligations of the Account
Party under this Section 10.04 are unenforceable for any reason, the Account
Party agrees to make the maximum contribution to the payment and satisfaction
thereof which is permissible under applicable law.
SECTION X.5. Right of Set-off. (a) Upon (i) the occurrence and during the
continuance of any Event of Default and (ii) the taking of any action or the
giving of any instruction by the Agent as specified by Section 8.02 hereof,
the Issuing Bank and each Participating Bank are hereby authorized at any
time and from time to time, to the fullest extent permitted by law, to set
off and apply any and all deposits (general or special, time or demand,
provisional or final) at any time held and other indebtedness at any time
owing by the Issuing Bank or such Participating Bank to or for the credit or
the account of the Account Party against any and all of the obligations of
the Account Party now or hereafter existing under this Agreement in favor of
the Issuing Bank or such Participating Bank, irrespective of whether or not
the Issuing Bank or such Participating Bank shall have made any demand under
this Agreement and although such obligations may be unmatured. The Issuing
Bank and each Participating Bank agrees promptly to notify the Account Party
after any such set-off and application provided that the failure to give such
notice shall not affect the validity of such set-off and application. The
rights of the Issuing Bank and each Participating Bank under this Section are
in addition to other rights and remedies (including, without limitation,
other rights of set-off) which the Issuing Bank and/or such Participating
Bank may have.
(b) The Account Party agrees that it shall have no right of off-set,
deduction or counterclaim in respect of its obligations hereunder, and that
the obligations of the Issuing Bank and of the several Participating Banks
hereunder are several and not joint. Nothing contained herein shall
constitute a relinquishment or waiver of the Account Party's rights to any
independent claim that the Account Party may have against the Issuing Bank or
any Participating Bank, but no Participating Bank shall be liable for the
conduct of the Issuing Bank or any other Participating Bank, and the Issuing
Bank shall not be liable for the conduct of any Participating Bank.
SECTION X.6. Binding Effect; Assignments and Participants. (a) This
Agreement shall become effective when it shall have been executed and
delivered by the Account Party, the Agent, the Issuing Bank and each
Participating Bank named on the signature pages to the Amendment and
thereafter shall be binding upon and inure to the benefit of the Account
Party, the Agent, the Issuing Bank and each Participating Bank and their
respective successors and assigns, except that the Account Party shall not
have the right to assign its rights hereunder or any interest herein without
the prior written consent of the Issuing Bank and each Participating Bank,
and the Issuing Bank may not assign its commitment to issue the Letter of
Credit or its obligations under or in respect of the Letter of Credit.
(b) Each Participating Bank may assign all or any portion of its rights
under this Agreement, under the Letter of Credit or in any security
hereunder, including, without limitation, any instruments securing the
Account Party's obligations hereunder; provided that (i) no assignment by any
Participating Bank may be made to any Person, other than to another
Participating Bank, except with the prior written consent of the Issuing Bank
and the Account Party (which consent in the case of the Account Party, (A)
shall not be unreasonably withheld and (B) shall not be required if an Event
of Default shall have occurred and be continuing and the Agent or the Issuing
Bank shall have exercised any remedy described in clause (ii), (iii) or (v)
of Section 8.02), (ii) any assignment shall be of a constant and not a
varying percentage of all of the assignor's rights and obligations hereunder
and (iii) the parties to each such assignment shall execute and deliver to
the Agent a Participation Assignment, together with a processing fee of
$2,500. Upon receipt of a completed Participation Assignment and the
processing fee, the Agent will record in a register maintained for such
purpose the name of the assignee and the percentage participation interest
assigned by the assignor and assumed by the assignee for purposes of the
determination of such assignor's and assignee's respective Participation
Percentages. Upon such execution, delivery, acceptance and recording, from
and after the effective date specified in each Participation Assignment,
which effective date shall be at least five Business Days after the execution
thereof, the assignee shall, to the extent of such assignment, become a party
hereto and have all of the rights and obligations of a Participating Bank
hereunder and, to the extent of such assignment, such assigning Participating
Bank shall be released from its obligations hereunder (without relieving such
Participating Bank from any liability for damages, costs and expenses
suffered by the Issuing Bank or the Account Party as a result of the failure
by such Participating Bank to perform its obligations hereunder).
(c) Each Participating Bank may grant participations to one or more Persons
in all or any part of, or any interest (undivided or divided) in, such
Participating Bank's rights and obligations under this Agreement (any such
Person being referred to hereinafter as a "Participant" and such interests
are collectively, referred to hereinafter as the "Rights"); provided,
however, that (i) such Participating Bank's obligations under this Agreement
shall remain unchanged; (ii) any such Participant shall be entitled to the
benefits and cost protections provided for in Section 4.03 hereof on the same
basis as if it were a Participating Bank hereunder; (iii) the Account Party,
the Agent and the Issuing Bank shall continue to deal solely and directly
with such Participating Bank in connection with such Participating Bank's
rights and obligations under this Agreement; and (iv) no such Participant,
other than an Affiliate of such Participating Bank, shall be entitled to
require such Participating Bank to take or omit to take any action hereunder,
unless such action or omission would have an effect of the type described in
subsections (c), (d) or (h) of Section 10.01 hereof.
(d) Notwithstanding anything contained in this Section 10.06 to the
contrary, the Issuing Bank and any Participating Bank may assign and pledge
all or any portion of the Advances (or participating interests therein) owing
to the Issuing Bank or such Participating Bank to any Federal Reserve Bank
(and its transferees) as collateral security pursuant to Regulation A of the
Board of Governors of the Federal Reserve System and any Operating Circular
issued by such Federal Reserve Bank. No such assignment shall release the
Issuing Bank or such Participating Bank from its obligations hereunder.
SECTION X.7. Relation of the Parties; No Beneficiary. No term, provision or
requirement, whether express or implied, of any Loan Document, or actions
taken or to be taken by any party thereunder, shall be construed to create a
partnership, association, or joint venture between such parties or any of
them. No term or provision of the Loan Documents shall be construed to
confer a benefit upon, or grant a right or privilege to, any Person other
than the parties hereto.
SECTION X.8. Issuing Bank Not Liable. As between the Agent, the Issuing
Bank and the Participating Banks on the one hand, and the Account Party on
the other, the Account Party assumes all risks of the acts or omissions of
the Paying Agent, the Trustee and any other beneficiary or transferee of the
Letter of Credit with respect to its use of the Letter of Credit. Neither the
Agent, the Issuing Bank, any Participating Bank, nor any of their respective
officers or directors shall be liable or responsible for: (a) the use which
may be made of the Letter of Credit or any acts or omissions of the Paying
Agent, the Trustee and any other beneficiary or transferee in connection
therewith; (b) the validity, sufficiency or genuineness of documents, or of
any endorsement thereon, even if such documents should prove to be in any or
all respects invalid, insufficient, fraudulent or forged; (c) payment by the
Issuing Bank against presentation of documents which do not comply with the
terms of the Letter of Credit, including failure of any documents to bear any
reference or adequate reference to the Letter of Credit; or (d) any other
circumstances whatsoever in making or failing to make payment under the
Letter of Credit, except that the Account Party shall have a claim against
the Issuing Bank, and the Issuing Bank shall be liable to the Account Party,
to the extent of any direct, as opposed to consequential, damages suffered by
the Account Party which the Account Party proves were caused by (i) the
Issuing Bank's willful misconduct or gross negligence, as determined by a
court of competent jurisdiction, in determining whether documents presented
under the Letter of Credit are genuine or comply with the terms of the Letter
of Credit or (ii) the Issuing Bank's willful or grossly negligent failure, as
determined by a court of competent jurisdiction, to make lawful payment under
the Letter of Credit after the presentation to it by the Paying Agent of a
draft and certificate strictly complying with the terms and conditions of the
Letter of Credit. In furtherance and not in limitation of the foregoing, the
Issuing Bank may accept original or facsimile (including telecopy) sight
drafts and accompanying certificates presented under the Letter of Credit
that appear on their face to be in order, without responsibility for further
investigation, regardless of any notice or information to the contrary.
SECTION X.9. Confidentiality. In connection with the negotiation and
administration of this Agreement and the other Loan Documents, the Account
Party has furnished and will from time to time furnish to the Agent, the
Issuing Bank and the Participating Banks (each, a "Recipient") written
information which is identified to the Recipient when delivered as
confidential (such information, other than any such information which (i) was
publicly available, or otherwise known to the Recipient at the time of
disclosure, (ii) subsequently becomes publicly available other than through
any act or omission by the Recipient or (iii) otherwise subsequently becomes
known to the Recipient other than through a Person whom the Recipient knows
to be acting in violation of his or its obligations to the Account Party,
being hereinafter referred to as "Confidential Information"). The Recipient
will not knowingly disclose any such Confidential Information to any third
party (other than to those persons who have a confidential relationship with
the Recipient), and will take all reasonable steps to restrict access to such
information in a manner designed to maintain the confidential nature of such
information, in each case until such time as the same ceases to be
Confidential Information or as the Account Party may otherwise instruct. It
is understood, however, that the foregoing will not restrict the Recipient's
ability to freely exchange such Confidential Information with prospective
assignees of or participants in the Recipient's position herein, but the
Recipient's ability to so exchange Confidential Information shall be
conditioned upon any such prospective assignee's or participant's entering
into an understanding as to confidentiality similar to this provision. It is
further understood that the foregoing will not prohibit the disclosure of any
or all Confidential Information if and to the extent that such disclosure may
be required (i) by a regulatory agency or otherwise in connection with an
examination of the Recipient's records by appropriate authorities, (ii)
pursuant to court order, subpoena or other legal process or (iii) otherwise,
as required by law; in the event of any required disclosure under clause (ii)
or (iii) above, the Recipient agrees to use reasonable efforts to inform the
Account Party as promptly as practicable.
SECTION X.10. Waiver of Jury Trial. The Account Party, the Arrangers, the
Agent, the Issuing Bank, and the Participating Banks each hereby irrevocably
waives all right to trial by jury in any action, proceeding or counterclaim
arising out of or relating to this Agreement or any other Loan Document, any
Transaction Document or any other instrument or document delivered hereunder
or thereunder.
SECTION X.11. Governing Law. This Agreement, the Amendment and the Pledge
Agreement shall be governed by, and construed in accordance with, the laws of
the State of New York. The Account Party, the Arrangers, the Agent, the
Issuing Bank and each Participating Bank each (i) irrevocably submits to the
jurisdiction of any New York State Court or Federal court sitting in New York
City in any action arising out of any Loan Document, (ii) agrees that all
claims in such action may be decided in such court, (iii) waives, to the
fullest extent it may effectively do so, the defense of an inconvenient forum
and (iv) consents to the service of process by mail. A final judgment in any
such action shall be conclusive and may be enforced in other jurisdictions.
Nothing herein shall affect the right of any party to serve legal process in
any manner permitted by law or affect its right to bring any action in any
other court.
SECTION X.12. Execution in Counterparts. This Agreement may be executed in
any number of counterparts and by different parties hereto in separate
counterparts, each of which when so executed shall be deemed to be an
original and all of which taken together shall constitute one and the same
agreement.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed by their respective officers thereunto duly authorized, as of the
date first above written, such execution being conclusively evidenced by the
execution and delivery by such parties of the Amendment to which this Amended
and Restated Second Series E Letter of Credit and Reimbursement Agreement is
attached.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
executed by their respective officers thereunto duly authorized, as of the
date first above written.
THE ACCOUNT PARTY:
PUBLIC SERVICE COMPANY OF
NEW HAMPSHIRE
By: /S/David R. McHale
Title: Assistant Treasurer
THE AGENT AND ISSUING BANK:
SWISS BANK CORPORATION,
STAMFORD BRANCH,
as Agent and as Issuing Bank
By: /S/ PETER V. MATTON
Title: Executive Director
By: /S/ WILLIAM A. ROCHE
Title: Director
THE PARTICIPATING BANKS:
BARCLAYS BANK PLC,
NEW YORK BRANCH
By: /S/ SYDNEY DENNIS
Title: Managing Director
Address for Notices
Barclays Bank PLC
222 Broadway
New York, New York 10038
Attention: Sydney Dennis
Telephone: (212) 412-2570
Fax: (212) 412-6709
SWISS BANK CORPORATION,
STAMFORD BRANCH
By: /S/ WILLIAM A. ROCHE
Title: Director
By: /S/ DAVID C. HEMINGWAY
Title: Director
Address for Notices
Swiss Bank Corporation
677 Washington Boulevard
Stamford, Connecticut 06912
Attention: Darryl M. Monasebian
Telephone: (203) 819-8005
Fax: (203) 819-8610
BANK OF AMERICA NATIONAL
TRUST AND SAVINGS ASSOCIATION
By: /S/ VERN HOWARD
Title: Managing Director
Address for Notices
Bank of America NT & SA
555 California Street
San Francisco, California 94104
Attention: Vern Howard
Telephone: (415) 953-0590
Fax: (415) 622-0632
LTCB TRUST COMPANY
By: /S/ GREGORY L. HONG
Title: Senior Vice President
Address for Notices
LTCB Trust Company
165 Broadway, 49th Floor
New York, New York 10006
Attention: Gregory H. Hong
Telephone: (212) 335-4534
Fax: (212) 608-2371
TORONTO DOMINION (NEW YORK), INC.
By: /S/ DEBBIE A. GREENE
Title: Vice President
Address for Notices
The Toronto-Dominion Bank
909 Fannin Street, Suite 1700
Houston, Texas 77010
Attention: Debbie Greene
Telephone: (713) 653-8250
Fax: (713) 951-9921
UNION BANK OF CALIFORNIA
By: /S/ KARYSSA M. BRITTON
Title: Vice President
Address for Notices
Union Bank of California
445 S. Figueroa Street, 15th Floor
Los Angeles, CA 90071
Attention: John M. Edmonston
Telephone: (213) 236-5809
Fax: (213) 236-4096
THE BANK OF NOVA SCOTIA
By: /S/FRAN PITCHLEY
Title:
Address for Notices
The Bank of Nova Scotia
28 State Street, 17th Floor
Boston, Massachusetts 02109
Attention: Paula A. MacDonald
Telephone: (617) 624-7613
Fax: (617) 624-7607
THE CHASE MANHATTAN BANK
By: /S/ PAUL V. FARRELL
Title: Vice President
Address for Notices
The Chase Manhattan Bank
270 Park Avenue
New York, New York 10017
Attention: Paul V. Farrell
Telephone: (212) 270-7653
Fax: (212) 270-3089
CITIBANK, N.A.
By: /S/ ROBERT J. HARRITY, JR.
Title: Managing Director
Address for Notices
Citibank, N.A.
399 Park Avenue
4th Floor, Zone 20
New York, New York 10043
Attention: Robert J. Harrity, Jr.
Telephone: (212) 559-6482
Fax: (212) 793-6130
BANKBOSTON, N.A.
By: /S/ MICHAEL M. PARKER
Title: Managing Director
Address for Notices
BankBoston, N.A.
100 Federal Street, M/S 01-08-04
Boston, MA 02110
Attention: Michael M. Parker
Telephone: (617) 434-7829
Fax: (617) 434-3652
THE FIRST NATIONAL BANK OF CHICAGO
By: /S/ MADELEINE N. PEMBER
Title: Assistant Vice President
Address for Notices
The First National Bank of Chicago
One First National Plaza, Suite 0363
Chicago, Illinois 60670
Attention: Kenneth J. Bauer
Telephone: (312) 732-6282
Fax: (312) 732-3055
THE FUJI BANK, LIMITED
By: /S/ RAYMOND VENTURA
Title: Vice President & Manager
Address for Notices
The Fuji Bank, Limited
Two World Trade Center
New York, New York 10048
Attention: Michael Gebauer
Telephone: (212) 898-2064
Fax: (212) 321-9407
THE INDUSTRIAL BANK OF JAPAN
TRUST COMPANY
By: /S/ JOHN DIPPO
Title: Senior Vice President
Address for Notices
The Industrial Bank of Japan Trust Company
1251 Avenue of the Americas
New York, New York 10020-1104
Attention: John Cunningham
Telephone: (212) 282-3411
Fax: (212) 282-4988
THE NIPPON CREDIT BANK, LTD.
By: /S/ KOICHI SUNAGAWA
Title: Representative
Address for Notices
The Nippon Credit Bank, Ltd.
101 East 52nd Street, 14th Floor
New York, New York 10022
Attention: Koichi Sunagawa
Telephone: (212) 751-7330
Fax: (212) 751-0987
FLEET NATIONAL BANK
By: /S/ DANIEL D. BUTLER
Title: Vice President
Address for Notices
Fleet Bank
40 Westminster Street
Mail Stop: RI OP T05A
Providence, Rhode Island 02903-4963
Attention: Fred N. Manning
Telephone: (401) 459-4845
Fax: (401) 459-4963
SOCIETE GENERALE
By: /S/GORDON EADON
Title:
Address for Notices
Societe Generale
1221 Avenue of the Americas
New York, New York 10020
Attention: Gordon Eadon
Telephone: (212) 278-6880
Fax: (212) 278-7430
THE SUMITOMO BANK, LIMITED,
NEW YORK BRANCH
By: /S/ KAZUYOSHI OGAWA
Title: Joint General Manager
Address for Notices
The Sumitomo Bank, Limited,
New York Branch
277 Park Avenue
New York, New York 10172
Attention: J. Bruce Meredith
Telephone: (212) 244-4129
Fax: (212) 224-5188
MELLON BANK, N.A.
By: /S/ KURT HEWETT
Title: Vice President
Address for Notices
Mellon Bank, N.A.
One Mellon Bank Center, Room 4425
Pittsburgh, Pennsylvania 15258
Attention: Kurt Hewett
Telephone: (412) 234-7355
Fax: (412) 234-0286
CREDIT LYONNAIS (NEW YORK)
By: /S/ ALAN SIDRANE
Title: Senior Vice President
Address for Notices
Credit Lyonnais (New York)
1301 Avenue of the Americas
New York, New York 10019
Attention: David Bonington
Telephone: (212) 261-7861
Fax: (212) 261-3259
THE YASUDA TRUST AND BANKING
CO., LTD., NEW YORK BRANCH
By: /S/ ROHN LAUDENSCHLAGER
Title: Senior Vice President
Address for Notices
The Yasuda Trust and Banking Co., Ltd.,
New York Branch
666 Fifth Avenue, Suite 801
New York, New York 10103
Attention: Rohn Laudenschlager
Telephone: (212) 373-5713
Fax: (212) 373-5796
Exhibit 4.4.2
FIRST SUPPLEMENTAL INDENTURE dated as of the first day of October, 1954,
made and entered into by and between WESTERN MASSACHUSETTS ELECTRIC COMPANY,
a corporation organized under the laws of the Commonwealth of Massachusetts
having principal places of business at Greenfield and Turners Falls in the
Country of Franklin, Springfield in the County of Hampden, Pittsfield in the
County of Berkshire, and Boston in the County of Suffolk, all in said
Commonwealth, (hereinafter called the Company) and OLD COLONY TRUST COMPANY,
a corporation organized under the laws of the Commonwealth of Massachusetts,
and having its principal office and usual place of business in said Boston,
(hereinafter called the Trustee).
WITNESSETH that:
WHEREAS the Company has heretofore executed and delivered to the Trustee
its First Mortgage Indenture and Deed of Trust dated as of August 1, 1954,
(hereinafter singularly called the Original Indenture and with this and all
other indentures supplemental thereto collectively called the Indenture)
conveying certain property therein described in trust as security for the
Bonds of the Company to be issued thereunder as therein provided, and for
other purposes more particularly specified therein, and the Trustee has
accepted said Trust; and
WHEREAS the Company has issued and there are now outstanding under the
Indenture $11,000,000 aggregate principal amount of First Mortgage Bonds,
Series A, 2.95%, due October 1, 1973, (hereinafter called the 2.95% Bonds);
and
WHEREAS pursuant to the provisions of Section 3.03 of the Original
Indenture, the Company has authorized the issue of an additional series of
its First Mortgage Bonds under the Indenture to be designated "First Mortgage
Bonds, Series B, 3 1/8%, due October 1, 1984" (hereinafter called the Series
B Bonds) to be limited in aggregate principal amount to $6,000,000, being the
entire issue of the Series B Bonds but constituting only the initial issue of
the Bonds referred to for convenience in said Section 3.03 of the Original
Indenture as "Series B Bonds"; and
WHEREAS the Company, pursuant to votes or resolutions duly and legally
adopted by its Board of Directors, by its Executive Committee and by its
stockholder at meetings duly and regularly called and held for the purpose,
has been duly authorized the execution and delivery of this First
Supplemental Indenture, and the issue of Series B Bonds in the aggregate
principal amount of $6,000,000; and
WHEREAS the Department of Public Utilities of the Commonwealth of
Massachusetts has in due form of law authorized the issue of the Series B
Bonds in the aggregate principal amount of $6,000,000 by its Order dated
September 16, 1954; and
WHEREAS the permanent form of the Series B Bonds in coupon form, of the
coupons thereon, and of the registration as to principal thereof, and the
permanent form of the Series B Bonds in fully registered form without
coupons, and of the transfer thereof, and the form of the certificate of
authentication of and of the stamp tax legend to be affixed to the Series B
Bonds in either form shall be substantially as follows:
FORM OF BOND
No. BM $1,000
WESTERN MASSACHUSETTS ELECTRIC COMPANY
First Mortgage Bond, Series B, 3 1/8%, due October 1, 1984
FOR VALUE RECEIVED, WESTERN MASSACHUSETTS ELECTRIC COMPANY, a
corporation of the Commonwealth of Massachusetts, (hereinafter called the
Company) hereby promises to pay to the bearer or, if this Bond be registered
as to principal otherwise than to bearer, then to the registered owner
hereof, the sum of one thousand dollars ($1,000) on the first day of October,
1984, and semi-annually on the first days of April and October in each year
to pay interest on said sum at the rate of three and one-eighth percentum (3
1/8%) per annum from the date hereof until the Company's obligation in
respect of said sum shall be discharged, but until maturity, only upon
presentation and surrender of the annexed coupons as they severally mature.
Both principal and interest shall be payable at the principal office in
Boston in the County of Suffolk and said Commonwealth of Old Colony Trust
Company, a corporation organized under the laws of said Commonwealth,
(hereinafter with its successors, as defined in the Indenture mentioned
below, generally called the Trustee), or of such successors, or, at the
option of the bearer or registered owner, at the office or agency of the
Company in the Borough of Manhattan, The City of New York, New York, in such
coin or currency of the United States of America as at the time of payment is
legal tender for public and private debts.
This Bond is one of a series of Bonds known as the "First Mortgage
Bonds, Series B, 3 1/8%, due October 1, 1984" of the Company, limited to six
million dollars ($6,000,000) in aggregate principal amount (except as
provided by the terms of Section 2.13 of the Indenture mentioned below), and
issued under and secured by a First Mortgage Indenture and Deed of Trust
between the Company and the said Old Colony Trust Company, as Trustee, dated
as of August 1, 1954, (hereinafter, with all indentures stated to be
supplemental thereto to which the Trustee shall be a party, including the
First Supplemental Indenture mentioned below, generally called the Indenture)
and a First Supplemental Indenture dated as of October 1, 1954, an executed
counterpart of each of which is on file at the principal office of the
Trustee, to which Indenture reference is hereby made for a description of the
nature and extent of the security, the rights thereunder of the bearers or
registered owners of Bonds issued and to be issued thereunder and of the
coupons appertaining thereto, the rights, duties, and immunities thereunder
of the Trustee, the rights and obligations thereunder of the Company, and the
terms and conditions upon which said Bonds, and other and further Bonds of
other series, are issued and are to be issued; but neither the foregoing
reference to the Indenture nor any provision of this Bond or of the Indenture
shall affect or impair the obligation of the Company, which is absolute,
unconditional and unalterable, to pay at the maturities herein provided the
principal of and interest on this Bond as herein provided.
The coupon Bonds of this series in permanent form are issuable in the
denomination of one thousand dollars ($1,000). The fully registered Bonds of
this series in permanent form are issuable in denominations of one thousand
dollars ($1,000) and any multiple thereof.
This Bond, singly or together with other coupon Bonds of this series,
may be exchanged at the option of the bearer or registered owner for fully
registered bonds of this series of an equal principal amount, in the manner
and on the terms provided in said Indenture.
This Bond, except while registered as to principal, and the coupons
annexed hereto shall be transferable by delivery. The bearer hereof may have
the ownership of the principal of this Bond registered upon presentation
hereof for that purpose at the principal office of the Trustee, such
registration to be noted hereon. After such registration no transfer hereof
shall be valid unless made on the registration books at said office by the
registered owner in person or by his duly authorized attorney and similarly
noted hereon; but this Bond may be discharged from registry by like transfer
to bearer similarly registered and noted hereon, and thereupon
transferability by delivery shall be restored and this Bond may again and
from time to time be registered or transferred as before. The coupons
annexed hereto, whether or not this Bond be registered as to principal, shall
remain payable to bearer and shall continue to be transferable by delivery.
The Company and the Trustee may deem and treat the bearer of this Bond, if it
be not then registered as to principal, or if this Bond be registered as to
principal as herein authorized, the person in whose name the same is
registered, as the absolute owner hereof and the bearer of any coupon hereto
appertaining as the absolute owner thereof, whether or not this Bond or such
coupon shall be overdue, for the purpose of receiving payment and for all
other purposes, and neither the Company nor the Trustee shall be affected by
any notice to the contrary.
The Bonds of this series are subject to redemption prior to maturity
upon not less than thirty (30) days' prior notice, as a whole at any time, or
in part from time to time, at the option of the Company or for the purposes
of the Improvement Fund for Bonds of this series or of any other provision of
the Indenture, in the manner and with the effect provided in said Indenture,
(i) if from Improvement Fund moneys pursuant to Article IV of said First
Supplemental Indenture or moneys to be applied by the Trustee as provided in
Section 8.05 of the original Indenture, at the applicable percentages
specified under the column headed Special Redemption Price, below, of the
principal amount thereof, and (ii) if at the option of the Company or
pursuant to any provisions of the Indenture other than those in respect of
said Improvement Fund or said Section 8.05 of the original Indenture, at the
applicable percentages specified under the column headed Optional Redemption
Price, below, of the principal amount thereof, together in each chase with
accrued and unpaid interest to the date fixed for redemption:
12 Months' 12 Months'
Period Optional Special Period Optional Special
Starting Redemption Redemption Starting Redemption Redemption
October 1 Price Price October 1 Price Price
1954 104.47% 101.47% 1969 102.16% 100.90%
1955 104.32 101.44 1970 102.01 100.85
1956 104.16 101.41 1971 101.85 100.80
1957 104.01 101.38 1972 101.70 100.75
1958 103.86 101.34 1973 101.55 100.70
1959 103.70 101.31 1974 101.39 100.65
1960 103.55 101.27 1975 101.24 100.59
1961 103.39 101.24 1976 101.08 100.53
1962 103.24 101.20 1977 100.93 100.47
1963 103.09 101.16 1978 100.78 100.41
1964 102.93 101.12 1979 100.62 100.35
1965 102.78 101.08 1980 100.47 100.29
1966 102.62 101.04 1981 100.31 100.22
1967 102.47 100.99 1982 100.16 100.15
1968 102.32 100.95 1983 100.00 100.00
Notice of redemption as aforesaid shall be given by publication at least
once in each of three (3) successive weeks, the first publication to be at
least thirty (30) days before the date set for redemption, in at least two
daily newspapers of general circulation printed in the English language one
of which shall be published in said Boston, and by mailing, at least thirty
(30) days prior to the date set for redemption, by registered mail, to the
registered owners of all fully registered Bonds and to the registered owners
of all coupon Bonds registered as to principal, which have been called for
redemption, a copy of said notice.
If this Bond shall be called for redemption, or provision for such call
shall have been made, as provided in said Indenture, and payment of the
redemption price shall have been duly provided for by the Company, interest
shall cease to accrue hereon from and after the redemption date, the coupons
appertaining hereto thereafter maturing shall be void, the Company shall from
the time provided in said Indenture be under no further liability in respect
of the principal of, or premium, if any, or interest on, this Bond and the
bearer or registered owner hereof shall from and after such time look for
payment hereof solely to the money so provided.
The said Indenture contains provisions permitting the Company and the
Trustee with the consent of the bearers or registered owners of not less than
seventy percentum (70%) in principal amount of the Bonds at the time
outstanding (except Bonds held by or for the benefit of the Company),
including if more than one series of Bonds shall be at the time outstanding,
not less than seventy percentum (70%) in principal amount of the Bonds
(except Bonds held by or for the benefit of the Company) of each series
affected differently from those of other series, to effect by supplemental
indenture modifications or alterations of said Indenture and of the rights
and obligations of the Company and of the bearers and registered owners of
the Bonds and coupons; but no such modification or alteration shall be made
which, without the written approval or consent of the bearer or registered
owner hereof, will extend the maturity hereof or reduce the rate or extend
the time for payment of interest hereon or reduce the amount of the principal
hereof or of any premium payable on the redemption hereof, or which will
reduce the percentage of the principal amount of Bonds required for the
adoption of the modifications or alterations as aforesaid, or authorize the
creation by the Company, except as expressly authorized by the Indenture, of
any mortgage, pledge, or lien upon the property subjected thereto ranking
prior to or on an equality with the lien thereof.
If a default as defined in said Indenture shall occur, the principal of
this Bond may become or be declared due and payable before maturity, in the
manner and with the effect provided in the Indenture; but any default and the
consequences thereof may be waived by certain percentages of the bearers or
registered owners of Bonds, all as provided in said Indenture.
No recourse shall be had for the payment of the principal of or the
interest on this Bond or for any claim based hereon or otherwise in respect
hereof or of the said Indenture against any incorporator, stockholder,
director, or officer, past, present, or future, as such, of the Company or of
any predecessor or successor corporation under any constitution, statute, or
rule of law, or by the enforcement of any assessment, penalty, or otherwise,
all such liability being waived and released by the holder hereof by the
acceptance of this Bond.
This Bond shall take effect as a sealed instrument.
Neither this Bond nor any of the annexed coupons shall become or be
valid or obligatory until the certificate of authentication hereon shall have
been signed by the Trustee.
IN WITNESS WHEREOF, WESTERN MASSACHUSETTS ELECTRIC COMPANY has caused
this Bond to be executed in its name and on its behalf, by its President or a
Vice President and its Treasurer or an Assistant Treasurer, thereunto duly
authorized, and its corporate seal to be impressed or imprinted hereon, and
the coupons annexed thereto to bear the facsimile signature of its Treasurer,
as of the first day of October, 1954.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By
By
FORM OF COUPON
On , 19 , WESTERN MASSACHUSETTS ELECTRIC COMPANY
upon surrender hereof, unless the Bond hereinafter mentioned shall have been
called for previous redemption and payment duly provided therefor, will pay
to the bearer, at the principal office in Boston, Massachusetts, of Old
Colony Trust Company or of any successor as Trustee under the Indenture
securing said Bond, or, at the option of the bearer, at the office or agency
of the Company in the Borough of Manhattan, The City of New York, New York
fifteen and 63/100* dollars, in any coin or currency of the United States of
America which at the time of such payment is legal tender for public and
private debts, being six (6) months' interest on its First Mortgage Bond,
Series B, 3 1/8%, due October 1, 1984, Numbered .
Treasurer
*NOTE: April coupons will be in the amount of $15.63; October coupons will
be in the amount of $15.62.
FORM FOR REGISTRATION
NOTICE: No writing below except by a duly authorized office of the
Registrar.
Date of Registration
Name of Registered Owner
Signature of Registrar
FORM OF FULLY REGISTERED BOND
No. BR $
WESTERN MASSACHUSETTS ELECTRIC COMPANY
First Mortgage Bond, Series B, 3 1/8%, due October 1, 1984
FOR VALUE RECEIVED, WESTERN MASSACHUSETTS ELECTRIC COMPANY, a
corporation of the Commonwealth of Massachusetts, (hereinafter called the
Company) hereby promises to pay to , or registered
assigns, the sum of dollars ($ ), on
the first day of October, 1984, and semi-annually on the first days of April
and October in each year to pay interest on said sum at the rate of three and
one-eighth percentum (3 1/8%) per annum from the date hereof until the
Company's obligation with respect to said sum shall be discharged. Both
principal and interest shall be payable at the principal office in Boston in
the County of Suffolk and said Commonwealth of Old Colony Trust Company, a
corporation organized under the laws of said Commonwealth (hereinafter with
its successors, as defined in the Indenture mentioned below, generally called
the Trustee), or of such successors, or, at the option of the registered
owner or registered assigns, at the office or agency of the Company in the
Borough of Manhattan, The City of New York, New York, in such coin or
currency of the United States of America as at the time of payment is legal
tender for public and private debts.
This Bond is one of a series of Bonds known as the "First Mortgage
Bonds, Series B, 3 1/8%, due October 1, 1984" of the Company, limited to six
million ($6,000,000) in aggregate principal amount (except as provided by the
terms of Section 2.13 of the Indenture mentioned below), and issued under and
secured by a First Mortgage Indenture and Deed of Trust between the Company
and said Old Colony Trust Company, as Trustee, dated as of August 1, 1954,
(hereinafter with all indentures stated to be supplemental thereto to which
the Trustee shall be a party, including the First Supplemental Indenture
mentioned below, generally called the Indenture) and a First Supplemental
Indenture dated as of October 1, 1954, an executed counterpart of each of
which is on file at the principal office of the Trustee, to which Indenture
reference is hereby made for a description of the nature and extent of the
security, the rights thereunder of the bearers or registered owners of Bonds
issued and to be issued thereunder, the rights, duties, and immunities
thereunder of the Trustee, the rights and obligations thereunder of the
Company, and the terms and conditions upon which said Bonds, and other and
further Bonds of other series are issued and are to be issued; but neither
the foregoing reference to the Indenture nor any provision of this Bond or of
the Indenture shall affect or impair the obligation of the Company, which is
absolute, unconditional and unalterable, to pay at the maturities herein
provided the principal of and interest on this Bond as herein provided.
The fully registered Bonds of this series in permanent form are issuable
in denominations of one thousand dollars ($1,000) and any multiple thereof.
The coupon Bonds of this series in permanent form are issuable in the
denomination of one thousand dollars ($1,000).
This Bond is transferable by the registered owner hereof in person or by
his duly authorized attorney at the principal office of the Trustee upon
surrender and cancellation hereof, and thereupon a new Bond or Bonds of this
series for a like principal amount will be issued in exchange, all as
provided in said Indenture. The Company and the Trustee may deem and treat
the registered owner hereof as the absolute owner hereof, whether or not this
Bond be overdue, for the purpose of receiving payment and for all other
purposes, and neither the Company nor the Trustee shall be affected by any
notice to the contrary.
This Bond is exchangeable at the option of the registered owner hereof
at the principal office of the Trustee for coupon Bonds of this series of an
equal principal amount, upon transfer and surrender hereof to the Trustee as
hereinbefore provided, in the manner and on the terms provided in said
Indenture, and upon such transfer and surrender, coupon Bonds of this series,
with all coupons for interest unpaid hereon and none others attached, will be
issued in lieu hereof.
This Bond is also exchangeable at the option of the registered owner
hereof at the principal office of the Trustee for an equal principal amount
of fully registered Bonds of this series of other denominations, in the
manner and on the terms provided in said Indenture.
The Bonds of this series are subject to redemption prior to maturity
upon not less than thirty (30) days' prior notice as a whole at any time, or
in part from time to time, at the option of the Company or for the purposes
of the Improvement Fund for Bonds of this series or of any other provision of
the Indenture, in the manner and with the effect provided in said Indenture,
(i) if from Improvement Fund moneys pursuant to Article IV of said First
Supplemental Indenture or moneys to be applied by the Trustee as provided in
Section 8.05 of the original Indenture, at the applicable percentages
specified under the column headed Special Redemption Price, below, of the
principal amount thereof, and (ii) if at the option of the Company or
pursuant to any provisions of the Indenture other than those in respect of
said Improvement Fund or said Section 8.05 of the original Indenture, at the
applicable percentages specified under the column headed Optional Redemption
Price, below, of the principal amount thereof, together in each case with
accrued and unpaid interest to the date fixed for redemption:
12 Months' 12 Months'
Period Optional Special Period Optional Special
Starting Redemption Redemption Starting Redemption Redemption
October 1 Price Price October 1 Price Price
1954 104.47% 101.47% 1969 102.16% 100.90%
1955 104.32 101.44 1970 102.01 100.85
1956 104.16 101.41 1971 101.85 100.80
1957 104.01 101.38 1972 101.70 100.75
1958 103.86 101.34 1973 101.55 100.70
1959 103.70 101.31 1974 101.39 100.65
1960 103.55 101.27 1975 101.24 100.59
1961 103.39 101.24 1976 101.08 100.53
1962 103.24 101.20 1977 100.93 100.47
1963 103.09 101.16 1978 100.78 100.41
1964 102.93 101.12 1979 100.62 100.35
1965 102.78 101.08 1980 100.47 100.29
1966 102.62 101.04 1981 100.31 100.22
1967 102.47 100.99 1982 100.16 100.15
1968 102.32 100.95 1983 100.00 100.00
Notice of redemption as aforesaid shall be given by publication at least
once in each of three (3) successive weeks, the first publication to be at
least thirty (30) days before the date set for redemption, in at least two
daily newspapers of general circulation printed in the English language one
of which shall be published in said Boston, and by mailing, at least thirty
(30) days prior to the date set for redemption, by registered mail, to the
registered owners of all coupon Bonds registered as to principal, which have
been called for redemption, a copy of said notice.
If this Bond, or a part hereof, shall be called for redemption, or
provision for such call shall have been made, as provided in said Indenture,
and payment of the redemption price shall have been duly provided for by the
Company, interest shall cease to accrue hereon, or on such called part, from
and after the redemption date, the Company shall from the time provided in
said Indenture be under no further liability in respect of the principal of,
or premium, if any, or interest on, this Bond, or such called part, and the
registered owner hereof shall from and after such time look for payment
hereof solely to the money so provided.
The said Indenture contains provisions permitting the Company and the
Trustee with the consent of the bearers of registered owners of not less than
seventy percentum (70%) in principal amount of the Bonds at the time
outstanding (except Bonds held by or for the benefit of the Company),
including, if more than one series of Bonds shall be at the time outstanding,
not less than seventy percentum (70%) in principal amount of the Bonds
(except Bonds held by or for the benefit of the Company) of each series
affected differently from those of other series, to effect by supplemental
indenture modifications or alterations of said Indenture and of the rights
and obligations of the Company and of the bearers and registered owners of
the Bonds; but no such modification or alteration shall be made which,
without the written approval or consent of the registered owner hereof, will
extend the maturity hereof or reduce the rate or extend the time for payment
of interest hereon or reduce the amount of the principal hereof or of any
premium payable on the redemption hereof, or which will reduce the percentage
of the principal amount of Bonds required for the adoption of the
modifications or alterations as aforesaid, or authorize the creation by the
Company, except as expressly authorized by the Indenture, of any mortgage,
pledge, or lien upon the property subjected thereto ranking prior to or on an
equality with the lien thereof.
If a default as defined in said Indenture shall occur, the principal of
this Bond may become or be declared due and payable before maturity, in the
manner and with the effect provided in the Indenture; but any default and the
consequences thereof may be waived by certain percentages of the bearers or
registered owners of Bonds, all as provided in said Indenture.
No recourse shall be had for the payment of the principal of or the
interest on this Bond or for any claim based hereon or otherwise in respect
hereof or of the said Indenture against any incorporator, stockholder,
director, or officer, past, present, or future, as such, of the Company or of
any predecessor or successor corporation under any constitution, statute, or
rule of law, or by the enforcement of any assessment, penalty, or otherwise,
all such liability being waived and released by the holder hereof by the
acceptance of this Bond.
This Bond shall take effect as a sealed instrument.
This Bond shall not become or be valid or obligatory until the
certificate of authentication hereon shall have been signed by the Trustee.
IN WITNESS WHEREOF, WESTERN MASSACHUSETTS ELECTRIC COMPANY has caused
this Bond to be executed in its name and on its behalf by its President or a
Vice President and its Treasurer or an Assistant Treasurer thereunto duly
authorized, and its corporate seal to be impressed or imprinted hereon, as of
the day of , 19 .
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By
By
FORM FOR TRANSFER
FOR VALUE RECEIVED
hereby sell, assign, and transfer the within Bond to
and hereby irrevocably constitute and appoint
attorney to transfer said Bond on the books of
the Company with full power of substitution in the premises.
Dated this day of , 19 .
In presence of:
CERTIFICATE OF AUTHENTICATION
This Bond is one of the First Mortgage Bonds, Series B, 3 1/8%, due
October 1, 1984, described and provided for in the within mentioned
Indenture.
OLD COLONY TRUST COMPANY, TRUSTEE
By
Authorized Officer
FORM OF STAMP TAX LEGEND
Any Federal Revenue Tax on the issue of this Bond has been paid by
affixing to an original counterpart of the Indenture under which it is
issued, and duly canceling, the required stamps.
AND WHEREAS all requirements of law and of the Certificate of
Incorporation as amended, and of the By-Laws of the Company, including all
requisite action on the part of directors and officers, and all things
necessary to make the Series B Bonds, when duly executed by the Company and
delivered, the valid, binding, and legal obligations of the Company, and the
covenants and stipulations herein contained valid and binding obligations of
the Company, have been done and performed, and the execution and delivery
hereof have been in all respects duly authorized;
NOW, THEREFORE, THIS FIRST SUPPLEMENTAL INDENTURE WITNESSETH: In
consideration of the premises and of the mutual covenants herein contained
and of the purchase and acceptance by the bearers and registered owners
thereof of the Series B Bonds at any time issued hereunder, and of one dollar
($1) duly paid to the Company by the Trustee and for other good and valuable
consideration, the receipt whereof at or before the ensealing and delivery of
these presents is hereby acknowledged, and in confirmation of and
supplementing the Indenture, and in the performance and observance of the
provisions thereof, and in order to establish the forms and characteristics
of the Series B Bonds, and to secure the payment of the payment of the
principal of and premium, if any, and interest on all Bonds from time to time
outstanding under the Indenture according to their tenor and effect, and to
secure the performance and observance of all the covenants and conditions
therein contained, the Company has executed and delivered this First
Supplemental Indenture, and does hereby confirm the conveyance, transfer,
assignment and mortgage of the franchises and properties as set forth in the
Original Indenture and has granted, bargained, sold, conveyed, assigned,
transferred, mortgaged, and confirmed, and by these presents does grant,
bargain, sell, convey, assign, transfer, mortgage, and confirm unto Old
Colony Trust Company, as Trustee, as provided in the Indenture, its
successors in the trusts thereof and hereof, and its and their assigns, all
and singular the franchises and properties of the character described and
defined in the Original Indenture as Mortgaged Property, acquired after the
execution of the Original Indenture, subject, however, to Permitted
Encumbrances and to any mortgages or other liens or encumbrances thereon of
the character described in Section 4.10 of the Original Indenture existing at
the time of the acquisition of such franchises and properties by the Company
or created contemporaneously to secure or to raise a part of the purchase
price thereof and to any renewals or extensions of such mortgages or other
liens or encumbrances.
There is furthermore expressly excepted and excluded from the lien and
operation of this First Supplemental Indenture, and from the definition of
Mortgaged Property, all the property of the Company described in clauses A to
J, both inclusive, of the granting clauses of the Original Indenture, whether
owned at the time of the execution of this First Supplemental Indenture or
hereafter acquired by it.
TO HAVE AND TO HOLD all and singular the above described franchises and
properties unto the said Old Colony Trust Company, as Trustee under the
Indenture, its successors in the trusts thereof and hereof, and its and their
assigns, to its and their own use forever.
BUT IN TRUST, NEVERTHELESS, upon the terms and trusts set forth in the
Indenture for the equal pro rata benefit, security, and protection of the
bearers or registered owners of the Bonds from time to time certified,
issued, and outstanding under the Indenture, without any discrimination,
preference, priority, or distinction of any Bond or coupon over any other
Bond or coupon by reason of series, priority in the time of issue, sale, or
negotiation thereof, or otherwise howsoever, except as otherwise provided in
the Indenture;
PROVIDED, HOWEVER, and these presents are upon the condition that if the
Company, its successors or assigns, shall pay or cause to be paid the
principal of and the premium, if any, and interest on the Bonds outstanding
under the Indenture at the times and in the manner stipulated therein and in
the Indenture and shall keep, perform and observe all and singular the
covenants and promises in said Bonds and in the Indenture expressed to be
kept, performed, and observed by or on the part of the Company, then this
First Supplemental Indenture, and the estate and rights hereby granted shall,
pursuant to the provisions of Article XV of the Original Indenture, cease,
determine and be void, but only if the Original Indenture shall have ceased,
determined and become void, as therein provided, otherwise to be and remain
in full force and effect.
ARTICLE I.
DESCRIPTION AND ISSUE OF SERIES B BONDS
Section 1.01 The permanent Series B Bonds shall be substantially in the
forms hereinbefore set forth, with such changes therein as shall be approved
by the Company and the Trustee, shall be designated as the First Mortgage
Bonds, Series B 3 1/8%, due October 1, 1984, of the Company, shall be
issuable in the aggregate principal amount of six million dollars
($6,000,000) and not more except as provided in Section 2.13 of the Original
Indenture, if in coupon form shall be dated as of October 1, 1954, and if in
fully registered form shall be dated as provided in the Original Indenture,
shall mature October 1, 1984, shall bear interest at the rate of three and
one-eighth percentum (3 1/8%) per annum from the date thereof until the
Company's obligation in respect of the principal thereof shall be discharged,
payable semi-annually on the first days of April and October in each year
(the principal, premium, if any, and interest thereon being payable at the
principal office of the Trustee in the City of Boston, Massachusetts, or, at
the option of the holder, at the office or agency of the Company in the
Borough of Manhattan, The City of New York, New York, in coin or currency of
the United States of America which at the time of payment is legal tender for
public and private debts), shall be issued in coupon form registerable as to
principal only, in the denomination of one thousand dollars ($1,000) each,
and in fully registered form in denominations of one thousand dollars
($1,000) and any multiple thereof shall be redeemable at the times and in the
manner provided in Article V of the Original Indenture and as hereinafter
provided in this First Supplemental Indenture and shall be entitled to the
benefit of the Improvement Fund described in Article IV of this First
Supplemental Indenture.
Section 1.02 The Series B Bonds in coupon form may be exchanged for
Series B Bonds in fully registered form of a like aggregate principal amount,
and upon surrender at the principal office of the Trustee of any such Bond or
Bonds with all unpaid coupons appertaining thereto, and if registered as to
principal, accompanied by a written instrument of transfer signed by the
registered owner thereof or by his duly authorized attorney, in form
satisfactory to the Trustee, the Company shall issue and the Trustee shall
certify and deliver in exchange therefor one or more fully registered Series
B Bonds in a like aggregate principal amount in the name or names designated
by the holder of the coupon Bond or Bonds so surrendered.
Series B Bonds in fully registered form may be exchanged at the
principal office of the Trustee for a like aggregate principal amount of
Series B Bonds in fully registered form of other denominations and, upon
surrender to the Trustee for exchange of one more of such Series B Bonds, the
Company shall execute and the Trustee shall certify and shall deliver in
exchange therefor a like aggregate principal amount of such Series B Bonds of
other denominations.
The Series B Bonds in fully registered form may also be exchanged for
Series B Bonds in coupon form of a like aggregate principal amount, and upon
surrender at the principal office of the Trustee of any such Bond or Bonds
accompanied by a written instrument of transfer signed by the registered
owner thereof or by his duly authorized attorney, in form satisfactory to the
Trustee, the Company shall issue and the Trustee shall certify (unless coupon
Bonds previously certified shall be available) and deliver in exchange
therefor Series B Bonds in coupon form in a like aggregate principal amount,
with such coupons annexed thereto as may be necessary in order that no gain
or less of interest shall result from such exchange.
ARTICLE II
DIVIDEND COVENANT
Section 2.01 The Company hereby covenants and agrees with the Trustee
and with the respective bearers and owners of Series B Bonds that so long as
any of the Series B Bonds shall be outstanding, the Company will not on or
after October 1, 1954, declare or pay a dividend upon its capital stock
(other than a dividend payable in shares of its capital stock) or make any
other distribution on any shares of its capital stock, or purchase any shares
of its capital stock in an amount or amounts exceeding the Dividend Fund
hereinafter described, as constituted at the time of the declaration or
payment of such dividend or distribution or at the time of such purchase.
The Dividend Fund shall be computed by adding to
(a) the sum of $2,639,760.58
(b) the net earnings of the Company, determined as hereinafter
defined, for the period, considered as a unit, from January 1, 1954, to the
close of that quarter which last precedes the date of the declaration of any
such proposed dividend or distribution, or date of such purchase;
and by subtracting from the total thereof
(c) the aggregate amounts theretofore paid out or declared or
agreed to be paid out during said period in respect of such dividends,
distributions, or purchases.
For the purposes of this Covenant, the net earnings of the Company for
any such period shall be computed on an accrual basis in accordance with
sound accounting practice then current by deducting from the total revenues
for such period the total operating expenses and other proper charges to
income for such period, including (without in any respect limiting the
generality of the foregoing) all taxes, interest on all outstanding
indebtedness, amortization of debt discount and expense amortization of all
other deferred charges properly subject to amortization, all charges on the
Company's books to expense or income to provide for depreciation and all
charges for maintenance, but excluding any provision for any Improvement Fund
or any Sinking or similar fund for the retirement of debt and any profits and
losses from the sale or other disposition of capital assets made in said
period; provided however that
(1) the charge to earnings and credit to depreciation reserve for said
period shall comply with the provisions of Section 4.12 of the Original
Indenture, except that for any period less than a year the charge for such
period shall be apportioned, at a rate which shall not be less than the
annual rate required by Section 4.12 of the Original Indenture, on the
balance of the depreciable property as described in said Section 4.12 owned
by the Company at the beginning of said year; and
(2) net margins shall be adjusted by debits or credits thereto which
are offset by adjustments of the hydro-equalization reserve of the Company
and, except for said adjustments, net earnings shall not reflect as revenues
or as a deduction from revenues any adjustment made during such period
(whether made through surplus or income accounts) properly attributable to
operations prior to January 1, 1954.
In the event that the Company shall merge or consolidate with any other
corporation or corporations pursuant to Article XIV of the Original
Indenture, the Dividend Fund shall not be increased or diminished by the
surplus or deficit of such other corporation or corporations or by its or
their earnings, dividends, distributions, or purchases prior to the date of
such merger or consolidation.
ARTICLE III
REDEMPTION OF SERIES B BONDS
Section 3.01 The Series B Bonds shall be redeemable as a whole at any
time or in part from time to time, at the option of the Company or for the
purposes of the Improvement Fund provided for in Article IV hereof or of any
other provisions of the Indenture including this First Supplemental Indenture
(i) if from Improvement Fund moneys pursuant to said Article IV or moneys to
be applied by the Trustee as provided in Section 8.05 of the Original
Indenture, at the applicable percentages of the called principal amount
thereof specified under the column headed Special Redemption Price in the
forms of Series B Bonds hereinabove contained, and (ii) if at the option of
the Company or pursuant to any provisions of the Indenture including this
First Supplemental Indenture, other than those in respect of said Improvement
Fund or said Section 8.05 of the Original Indenture, at the applicable
percentages of the called principal amount thereof specified under the column
headed Optional Redemption Price in the forms of Series B Bonds hereinable
contained, together in each case with accrued and unpaid interest to the date
set for redemption, all in the manner provided in Article V of the Original
Indenture. Unless all the Series B Bonds then Outstanding shall be in fully
registered form, failure by the Company to give notice by mail, as therein
provided, shall not invalidate or affect the validity of the redemption
proceedings.
ARTICLE IV
IMPROVEMENT FUND
Section 4.01 The Company covenants that so long as any Series B Bonds
are Outstanding hereunder it will on the first day of November, 1955, and on
the first day of November in each calendar year thereafter pay to the Trustee
the sum of sixty thousand dollars ($60,000), as an Improvement Fund to be
held and applied by the Trustee pursuant to the terms of Section 4.03 of this
Article IV; provided however, that the Company may, at its option,
irrevocably allocate, upon filing the application and other documents
described in Section 4.02 of this Article IV, Net Property Additions towards
the satisfaction of the obligation aforesaid in an amount equal to sixty
percentum (60%) of the Available Net Property Additions as set forth in Item
G of the Certificate of Available Net Property Additions filed in connection
with said application.
Section 4.02 For the purpose of determining the amount of money if any,
to be paid to the Trustee pursuant to the provisions of Section 4.01, the
Company shall file with the Trustee on or before each said first day of
November the following:
(a) an application consisting of an Officers' Certificate conforming to
the requirements of Section 17.02 of the Original Indenture and otherwise
substantially in the following form:
WESTERN MASSACHUSETTS ELECTRIC COMPANY
To Old Colony Trust Company, Trustee
under Indenture dated as of August 1, 1954.
Improvement Fund Application
under First Supplemental Indenture
filed November , 19
In conformity with the provisions of Article IV of the First
Supplemental Indenture providing for an annual Improvement Fund in the amount
of $60,000 for the benefit of the holders or registered owners of the First
Mortgage Bonds, Series B, 3 1/8%, due October 1, 1984, of the aforesaid
Company issued under the aforesaid Indenture, we hereby certify that the sum
of $60,000 is due at this time from the Company to you as Trustee as
aforesaid on account of said Improvement Fund obligation now due and payable.
(If irrevocable allocation of Net Property Additions is in full
satisfaction of the Improvement Fund obligation then current, the following
should be used)
Application is hereby made irrevocably to allocate in the amount of
$100,000 the Available Net Property Additions set forth in Item G of the
accompanying Certificate of Available Net Property Additions in full
satisfaction of said obligation.
(If in partial satisfaction, the following should be used)
Application is hereby made irrevocably to allocate Net Property
Additions shown in the accompanying Certificate of Available Net Property
Additions, in partial satisfaction of said obligation, by application of an
amount equal to sixty percentum (60%) of the Available Net Property Additions
set forth in Item G of said Certificate, the balance of $ being
transmitted herewith in cash in full satisfaction of said obligation.
(If there is no allocation of Net Property Additions the following
should be used)
The sum of $60,000 is transmitted herewith in cash in full satisfaction
of said obligation.
Office held
Office held
(b) if irrevocable allocation of any Net Property Additions be made
(1) a Directors Resolution authorizing the execution of a
Supplemental Indenture in form satisfactory to the Trustee conveying,
transferring and/or assigning to the Trustee all Fundable Property not
previously so conveyed, transferred and/or assigned;
(2) said Supplemental Indenture duly executed by the Company, and
if necessary by the Trustee, in as many counterparts as the Trustee shall
require;
(3) a Certificate of Available Net Property Additions;
(4) an Accountant's Certificate similar, except for necessary
variations, to the Accountant's Certificate described in subparagraph (f) of
Section 3.08 of the Original Indenture;
(5) an Engineer's Certificate similar, except for necessary
variations, to the Engineer's Certificate described in subparagraph (g) of
Section 3.08 of the Original Indenture;
(6) an Opinion of Counsel to the effect that the amount of the
Improvement Fund obligation then due pursuant to this Section is correctly
stated in said application, and that the documents described in this Section
and/or the sum of money paid to the Trustee pursuant to this Section fully
satisfy the liability of the Company upon the Improvement Fund obligation
then due pursuant to this Section and if any Fundable Property be conveyed,
assigned, and/or transferred to the Trustee, that all corporate action
prerequisite or necessary for the execution and delivery of the Supplemental
Indenture has been taken; that the Property Additions described in Item B of
said Certificate are Fundable Property within the definition thereof
contained in the Original Indenture; and that all recording and filing in
respect of said Supplemental Indenture necessary for the security of any and
all Bonds has been or will be completed.
The Company shall also pay to the Trustee with the documents aforesaid
the sum of money, if any, set forth in the said application.
Section 4.08 If at the close of the first day of November, 1955, and of
the first day of November in any calendar year thereafter, there shall be in
the hands of the Trustee any cash paid to the Trustee pursuant to the
provisions of Section 4.02, in the aggregate amount of five thousand dollars
($5,000) or more, said cash shall be set aside by the Trustee for the call
and redemption of Series B Bonds then Outstanding and the Trustee, on behalf
of and in the name of the Company and at the Company's expense, shall call
for redemption on or prior to the next succeeding thirty-first day of
December, at a redemption price in respect of each Bond so called for
redemption consisting of the applicable percentage of the called principal
amount thereof specified under the column headed Special Redemption Price in
the forms of Series B Bonds hereinabove contained and interest accrued
thereon to the date fixed for redemption, Series B Bonds to a principal
amount sufficient (exclusive of accrued interest) to exhaust as nearly as may
be the cash so set aside. Notice to bearers or registered owners of the
Series B Bonds called for redemption under this Section shall be given in the
manner provided in Section 5.04 of the Original Indenture; the particular
Series B Bonds to be redeemed shall, unless they shall include all the Series
B Bonds then Outstanding, be chosen by lot as provided in Section 5.02 of the
Original Indenture; and the provisions of Section 5.05 of the Original
Indenture shall be applicable to the redemption of such Series B Bonds and
all matters related thereto.
The Company shall reimburse the Trustee, forthwith upon its request, for
all sums paid or to be paid out as interest upon Series B Bonds redeemed
pursuant to the provisions of this Section.
ARTICLE V
THE TRUSTEE
Section 5.01 The Trustee shall be entitled to, may exercise, and shall
be protected by, where and to the full extent that the same are applicable,
all the rights, powers, privileges, immunities and exemptions provided in the
Indenture, as if the provisions concerning the same were incorporated herein
at length. The remedies and provisions of the Indenture applicable in case
of any default by the Company thereunder are hereby adopted and made
applicable in case of any default with respect to the properties included
herein and, without limitation of the generality of the foregoing, there are
hereby conferred upon the Trustee the same powers of sale and other powers
over the properties described herein as are expressed to be conferred by the
Indenture.
ARTICLE VI
DEFEASANCE
This Supplemental Indenture shall become void when the Indenture shall
be void.
ARTICLE VII
AMENDMENTS OF ORIGINAL INDENTURE
Section 7.01 The Original Indenture is hereby amended pursuant to
subparagraph (f) of Section 16.01 of the Original Indenture, as follows:
(a) there are hereby added to the end of the last sentence of Section
4.14 of the Original Indenture the words "or consolidation"; and
(b) there are hereby inserted the words "in principal amount" between
the word "majority" and the word "of" in the first sentence of the last
paragraph of Section 9.01 of the Original Indenture.
Section 7.02 The Original Indenture is hereby amended pursuant to sub-
paragraph (j) of Section 16.01 of the Original Indenture, as follows:
(a) there are hereby inserted at the end of Section 4.06 of the
Original Indenture three additional paragraphs reading as follows:
"The Company will annually, within thirty (30) days after the thirty-
first day of July, 1955, and within thirty (30) days after the thirty-first
day of July in each calendar year thereafter, cause an examination of the
Mortgaged Property to be made by an Engineer qualified as to the operation
and maintenance of the Mortgaged Property, and will file with the Trustee an
Engineer's Certificate signed by such Engineer stating whether or not the
Mortgaged Property (exclusive of retired property and property which the
Company has disposed of or ceased to operate or is contemplating disposing of
or ceasing to operate in the near future, as permitted by Article VII hereof)
owned by the Company on May 31, 1954, or the date of the last preceding
similar Engineer's Certificate, if any, and Mortgaged Property subsequently
acquired, whether as replacements or renewals or as entirely new property,
has been since May 31, 1954, or the date of such preceding Engineer's
Certificate, if any, and Mortgaged Property subsequently acquired, whether as
replacements or renewals or as entirely new property, has been since May 31,
1954, or the date of such preceding Engineer's Certificate, if any,
maintained at a standard of efficiency approved by good engineering practice
and in compliance with the Company's covenants in this Section 4.06, and
whether or not all such Mortgaged Property that is no longer used or useful
in the Company's business has been duly recorded as retired on the books of
the Company. Such Engineer's Certificate shall also state whether or not any
deficiency previously reported in the performance by the Company of its
covenants in this Section 4.06 has been made good, and whether or not since
May 31, 1954, or the date of such preceding Engineer's Certificate, if any,
there has been charged to current operating expense accounts sufficient
amounts to cover that portion of the cost of all repairs, replacements, and
renewals necessary to maintain the Mortgaged Property at such standard which
is required to be so charged in accordance with sound accounting practice.
If such Engineer's Certificate shall indicate that the Mortgaged Property has
not been properly maintained pursuant to the Company's covenants in this
Section 4.06 or shall indicate that sufficient charges have not been made to
current operating expense accounts such Engineer's Certificate shall further
state the amount of the deficiency in such maintenance and/or charges from
May 31, 1954, or from the date of such last preceding Engineer's Certificate,
if any.
"If such Engineer's Certificate shall indicate that any such deficiency
exists, the Company will with all reasonable speed make such repairs and/or
do such other maintenance work and/or make such charges to current operating
expense accounts or to earned surplus as may be necessary to make good such
deficiency, whereupon such Engineer (or, in the case of his refusal or
inability to act, some other Engineer) shall file an Engineer's Certificate
with the Trustee that such deficiency has been made good; and if such
Engineer's Certificate shall state that there has not been recorded as
retired on the books of the Company Mortgaged Property which is no longer
used or useful in the Company's business, the Company will forthwith make
appropriate entries on its books recording the retirement of such property
and will file with the Trustee a certificate signed by its Treasurer stating
that such entrees have been made.
"Any such Engineer's Certificate filed with the Trustee shall be open to
inspection by any Bondholder at any reasonable time. Subject to the
provisions of Sections 13.02 and 13.03, the Trustee may treat any such
Engineer's Certificate as sufficient evidence of compliance or non-compliance
with the covenants in this Section 4.06 and of the extent of such non-
compliance, if any, or may make, or cause to be made, with respect thereto
such further investigations and reports or may obtain such further evidence
with respect thereto as it may deem advisable."
(b) there are hereby inserted the words "or any other Obligor upon the
Bonds" between the word "Company" and the words "for the whole amount" in the
first sentence of Section 9.11 of the Original Indenture;
(c) there is hereby inserted at the beginning of Section 17.02 of the
Original Indenture an additional paragraph reading as follows:
"The Company shall furnish to the Trustee evidence of compliance with
conditions precedent, if any, provided for in the Indenture (including any
covenants compliance with which constitutes a condition precedent) which
relate to the authentication and delivery of the Bonds, to the release or the
release and substitution of property subject to the lien of the Indenture, to
the satisfaction and discharge of the Indenture, or to any other action to be
taken by the Trustee at the request or upon the application of the Company.
Such evidence shall consist of the following:
(1) An Officers' Certificate stating that such conditions precedent
have been complied with;
(2) An Opinion of Counsel stating that in his opinion such conditions
precedent have been complied with; and
(3) In the case of conditions precedent compliance with which is
subject to verification by accountants, an Accountant's Certificate, which,
in the case of any such conditions precedent to the authentication and
delivery of the Bonds, and not otherwise, shall be an Independent
Accountant's Certificate, if the aggregate principal amount of such Bonds and
of other Bonds authenticated and delivered since the commencement of the then
current calendar year (other than those with respect to which a certificate
or opinion of an independent public accountant is not required, or with
respect to which a certificate or opinion of an independent public accountant
has previously been furnished) is ten per centum (10%) or more of the
aggregate amount of Bonds at the time Outstanding, but no certificate or
opinion need be made by any person other than an officer or employee of the
Company who is specified in this Indenture as to (A) dates or periods not
covered by annual reports required to be filed by the Company in the case of
conditions precedent which depend on a state of facts as of a date or dates
or for a period or periods different from that required to be covered by such
annual reports, or (B) the amount and value of Property Additions, except as
provided in the last paragraph of Section 3.08, or (C) the adequacy of
depreciation, maintenance or repairs."
Section 7.03 The Original Indenture is hereby amended pursuant to
Section 16.02 of the Original Indenture, as follows:
(a) Section 9.17 off the Original Indenture is hereby amended to read as
follows:
"Section 9.17 In case more than one series of Bonds be Outstanding
hereunder and an event of default shall have happened because of any default
in the payment of the principal of, or of the interest on, or of any Sinking
Fund, Maintenance and Renewal Fund, Improvement Fund, or analogous fund
installment in respect of, the Bonds of any one or more of such series and
not in respect of the Bonds of one or more of the other series, and such
event of default shall be subsisting, then whatever action in this Article it
is provided may or shall be taken upon the happening of such an event of
default (continuing or subsisting as in this Indenture provided) by or upon
the request of the holders of a specified percentage in principal amount of
Bonds then Outstanding (excluding Company-owned Bonds), may or shall be taken
only if such holders of a majority in principal amount of the Bonds then
Outstanding (excluding Company-owned Bonds) of the series as to which such
default shall have been made."
such amendment having been approved by resolution of the Board of Directors
of the Company and by the written consent, filed with the Trustee, of the
holders of one hundred per centum (100%) in principal amount of the Bonds at
the time Outstanding (there being no Company-owned Bonds).
ARTICLE VIII
MISCELLANEOUS PROVISIONS
Section 8.01 The recitals in this First Supplemental Indenture shall be
taken as recitals by the Company alone, and shall not be considered as made
by or as imposing any obligation or liability upon the Trustee, nor shall the
Trustee be held responsible for the legality or validity of this First
Supplemental Indenture, and the Trustee makes no covenants or
representations, and shall not be responsible, as to or for the effect,
authorization, execution, delivery, or recording of this First Supplemental
Indenture, except as expressly set forth in the Original Indenture. The
Trustee shall not be taken impliedly to waive by this First Supplemental
Indenture any right it would otherwise have. As provided in the Original
Indenture, this First Supplemental Indenture shall hereafter form a part of
the Indenture.
Section 8.02 If and to the extent that any provision of this First
Supplemental Indenture limits, qualifies, or conflicts with another provision
of the Indenture required by any of Sections 310 to 317, inclusive, of the
Trust Indenture Act of 1939 to be included in an indenture to be qualified
under said Act, such required provision shall control.
Section 8.03 This First Supplemental Indenture may be simultaneously
executed in any number of counterparts, each of which shall be deemed an
original; and all said counterparts executed and delivered, each as an
original, shall constitute but one and the same instrument, which shall for
all purposes be sufficiently evidenced by any such original counterpart.
IN WITNESS WHEREOF, said Western Massachusetts Electric Company has
caused this instrument to be executed in its corporate name by its President
or one of its Vice-Presidents, thereunto duly authorized, and its corporate
seal to be hereto affixed, attested by its Clerk or an Assistant Clerk, and
said Old Colony Trust Company has caused this instrument to be executed in
its corporate name by one of its Vice-Presidents, thereunto duly authorized,
and its corporate seal to be hereto affixed, all on and as of the day and
year first above written.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By ROBERT R. HABBERLEY
Vice-President
Attest: (CORPORATE SEAL)
JAMES GRAY
Clerk
Signed sealed and delivered by
Western Massachusetts Electric
Company in our presence:
R. D. FISHER
A. W. WILKINSON
OLD COLONY TRUST COMPANY
By J. J. WALSH
Vice-President
Signed sealed and delivered by
Old Colony Trust Company
in our presence:
R. D. FISHER
A. W. WILKINSON (CORPORATE SEAL)
COMMONWEALTH OF MASSACHUSETTS
SUFFOLK, SS.
On this first day of October in the year 1954 before me personally came
Robert R. Habberley and James Gray, both to me personally known, who being by
me duly sworn did depose and say that they reside in Greenfield,
Massachusetts and in Springfield, Massachusetts, respectively; that they are
respectively a vice-president and clerk of Western Massachusetts Electric
Company, one of the corporations described in and which executed the
foregoing instrument; that they know the seal of said corporation; that the
seal affixed to said instrument opposite the execution was affixed thereto
pursuant to the authority of its Board of Directors; that they signed their
respective names thereto by like authority; and each of them acknowledged
said instrument to be his free act and deed in his said capacity and the free
act and deed of Western Massachusetts Electric Company.
IN WITNESS WHEREOF I hereunto set my hand and affixed my official seal,
at Boston in said Commonwealth, the day and year first above written.
Elliot G. Kelley
(NOTARIAL Notary Public for
SEAL) the Commonwealth of Massachusetts
My commission expires:
November 14, 1958
COMMONWEALTH OF MASSACHUSETTS
SUFFOLK, SS.
On this first day of October in the year 1954 before me personally came
J. J. Walsh to me personally known, who being by me duly sworn did depose and
say that he resides in Dorchester, Massachusetts; that he is a vice-president
of Old Colony Trust Company, one of the corporations described in and which
executed the foregoing instrument; that he knows the seal of said
corporation; that the seal affixed to said instrument opposite the execution
was affixed thereto pursuant to the authority of its Board of Directors; that
he signed his name thereto by like authority; and he acknowledged said
instrument to be his free act and deed in his said capacity and the free act
and deed of Old Colony Trust Company.
IN WITNESS WHEREOF, I have hereunto set may hand and affixed my official
seal, at Boston in said Commonwealth, the day and year first above written.
Elliot G. Kelley (NOTARIAL
Notary Public for Seal)
the Commonwealth of Massachusetts
My commission expires:
November 14, 1958
I, the undersigned, Clerk of WESTERN MASSACHUSETTS ELECTRIC COMPANY,
hereby CERTIFY that at a special meeting of the stockholders of said Company,
duly called and held at Boston, Massachusetts, on September 28, 1954, the
following vote was duly adopted by the affirmative vote of all the
outstanding stock of said Company; and I, the undersigned, FURTHER CERTIFY
that a meeting of the Board of Directors of said Company, duly called and
held on September 28, 1954, at which a quorum was present and voting, the
same identical vote was unanimously passed by said Board of Directors:
Further
Voted: That the form, as presented to this meeting, of the proposed
First Supplemental Indenture to be dated as of October 1, 1954, between the
Company and Old Colony Trust Company, as Trustee, is hereby approved; that
the President or any Vice President of the Company is each hereby authorized
to execute the same for and on behalf of the Company and under its corporate
seal, which the Clerk or an Assistant Clerk of the Company is hereby
authorized to affix and attest; that the President or any Vice President of
the Company is each hereby authorized to deliver the same in as many
counterparts as may be deemed desirable by the said Trustee; and that the
execution as aforesaid of the First Supplemental Indenture shall be
conclusive evidence that it is the First Supplemental Indenture approved at
this meeting and the execution of which is hereby authorized.
And I FURTHER CERTIFY that Robert R. Habberley is a Vice President of
said Company, duly authorized to execute in the name and on behalf of said
Company, the foregoing First Supplemental Indenture dated as of October 1,
1954; that I am the Clerk of said Company, duly authorized to attest the
ensealing of said First Supplemental Indenture; that the First Supplemental
Indenture to which this certificate is attached is substantially in the form
presented to and approved at each of said meetings held September 28, 1954;
that the foregoing is a correct copy of the vote adopted at each of said
meetings; and that the foregoing vote remains in full force and effect
without alteration.
IN WITNESS WHEREOF, I have hereunto subscribed my name as Clerk and have
caused the corporate seal of the Company to be hereunto affixed on October 1,
1954.
JAMES GRAY
JAMES GRAY, Clerk
(Corporate Seal)
RECORDING NOTE
The First Supplemental Indenture dated as of October 1, 1954, from
Western Massachusetts Electric Company to Old Colony Trust Company as
Trustee, has been duly filed for record as follows:
in the following Registries of Deeds:
County of Franklin
County of Hampden
County of Hampshire
County of Berkshire - Middle District
County of Berkshire - Northern District
County of Berkshire - Southern District
all in the Commonwealth of Massachusetts
County of Cheshire
in the State of New Hampshire
Vernon Land Records
in the State of Vermont
and in the following Land Court Registration Districts:
County of Hampden
County of Hampshire
County of Berkshire - Middle District
all in the Commonwealth of Massachusetts
A Second Confirmatory Indenture of Mortgage dated October 1, 1954, from
said Company to Old Colony Trust Company as Trustee, incorporating by
reference the terms and provisions of said First Supplemental Indenture, was
duly filed for record in the offices of the clerks of the following cities
and towns:
City of Boston
City of Springfield
City of Chicopee
City of Pittsfield
Town of West Springfield
City of Westfield
Town of Lee
Town of Greenfield
Town of Easthampton
Town of Dalton
Town of Montague
all in the Commonwealth of Massachusetts.
Exhibit 4.4.10
SUPPLEMENTAL INDENTURE
Dated as of May 1, 1998
To
First Mortgage Indenture and Deed of Trust
Dated as of August 1, 1954
WESTERN MASSACHUSETTS ELECTRIC COMPANY
TO
STATE STREET BANK AND TRUST COMPANY, Trustee
1998 Series A Bonds, Due June 1, 1999
WESTERN MASSACHUSETTS ELECTRIC COMPANY
Supplemental Indenture, Dated as of May 1, 1998
EIGHTY-SECOND SUPPLEMENTAL INDENTURE dated as of the first day of May,
1998, made and entered into by and between WESTERN MASSACHUSETTS ELECTRIC
COMPANY, a corporation organized under the laws of the Commonwealth of
Massachusetts, with its principal place of business at 174 Brush Hill Avenue,
West Springfield, Massachusetts 01089 (hereinafter generally called the
"Company" or "WMECO"), and STATE STREET BANK AND TRUST COMPANY, a trust
company organized under the laws of the Commonwealth of Massachusetts, as
successor to The First National Bank of Boston, as TRUSTEE under the Mortgage
Indenture described below, with its principal corporate trust office at Two
International Place, 4th Floor, Boston, MA 02110 (said State Street Bank and
Trust Company or, as applied to action antedating the effective date of said
succession, said The First National Bank of Boston, or its predecessor by
merger, Old Colony Trust Company, being hereinafter generally called the
Trustee).
WITNESSETH that:
WHEREAS, the Company has heretofore executed and delivered to the
Trustee its First Mortgage Indenture and Deed of Trust [1] dated as of
August 1, 1954 (hereinafter as amended by a First Supplemental Indenture
dated as of October 1, 1954, called the Original Indenture, the Original
Indenture with all indentures supplemental thereto being hereinafter
generally called the Indenture), conveying certain property therein described
in trust as security for the Bonds of the Company to be issued thereunder as
therein provided and for other purposes more particularly specified therein,
and the Trustee has accepted said Trust; and
[1] For details as to the filing and recording of this instrument in
Massachusetts, see Schedule C.
WHEREAS, there are outstanding $385,000,000 aggregate principal amount
of First Mortgage Bonds which have been issued at various times and in
various amounts and with various dates of maturity and rates of interest and
have been denominated Series V, Series W, Series X, Series Y, 1997 Series A
and 1997 Series B; and
WHEREAS, in order to provide a single, comprehensive, efficient
framework for the financing of nuclear fuel for Millstone 1 and Millstone 2,
as well as The Connecticut Light and Power Company's ("CL&P") and WMECO's
(together with CL&P, the "Companies") approximately 65.172% ownership
interest in the nuclear fuel for Millstone 3, the Companies entered into
arrangements with Bankers Trust Company, not in its individual capacity but
solely as trustee (the "NBFT Trustee") of the Niantic Bay Fuel Trust
(the "Trust") which was specially created for the purpose of such financing
pursuant to a Trust Agreement dated as of January 4, 1982 as amended and
restated as of February 11, 1992 (the "Trust Agreement") among Bankers Trust
Company, as trustee, State Street Bank and Trust Company of Connecticut,
National Association, (which is the successor trustor to the New Connecticut
Bank and Trust Company, National Association, as assignee of the Federal
Deposit Insurance Corporation, as receiver of The Connecticut Bank and Trust
Company, National Association), as Trustor (the "Trustor"), and CL&P, WMECO
and The Hartford Electric Light Company (which merged with and into CL&P on
June 30, 1982), as beneficiaries;
WHEREAS, pursuant to a Nuclear Fuel Lease Agreement (the "Lease
Agreement) dated as of January 4, 1982, as amended and restated as of
February 11, 1992, between CL&P and WMECO, The Hartford Electric Light
Company, and the NBFT Trustee, the Companies have assigned to the NBFT
Trustee all of their right, title, and interest in and to all or part of
certain nuclear fuel contracts and nuclear fuel and the NBFT Trustee, in
turn, has agreed to either reimburse the Companies for payments made to
contractors under the assigned nuclear fuel contracts or to make such
payments directly to the contractors;
WHEREAS, as part of the nuclear fuel financing arrangements for the
Millstone Units, the NBFT Trustee entered into a revolving credit facility
(the "Facility") with a syndicate of banks which, pursuant to its terms, was
scheduled to expire on February 19, 1998 and, in connection therewith, a
credit agreement dated as of February 11, 1992, as amended pursuant to a
First Amendment dated as of April 30, 1993 and a Second Amendment dated as of
May 12, 1995, with each of the financial institutions party thereto, and
The First National Bank of Chicago (the "Bank Agent"), as agent for such
financial institutions (as so named and as it may have been otherwise
supplemented, amended or modified through the date hereof the "Current Credit
Agreement", and together with any replacement thereof, the "Credit
Agreement");
WHEREAS, in order to induce the banks to extend the Facility through
July 31, 1998, the Companies were required to agree to provide additional
collateral, equal to 50 percent of the banks' commitment under the Facility,
by May 1, 1998 in the form of first mortgage bonds, as set forth in a Third
Amendment and Waiver to Credit Agreement dated as of February 19, 1998
(the "Amendment");
WHEREAS, to satisfy the requirements under the Amendment and to meet a
contractual requirement that the holders of the Trust's Intermediate Term
Notes (the "IT Notes") are entitled to equal treatment with the banks, WMECO
agreed, by appropriate and sufficient corporate action in conformity with the
provisions of the Indenture to create a further series of bonds (hereinafter
generally referred to as the "1998 Series A Bonds" or the "bonds of 1998
Series A"), limited in principal amount to $17,300,000 to be issued to secure
WMECO's obligations under the Lease Agreement and to be assigned by the
NBFT Trustee to The First National Bank of Chicago as Collateral Agent and
Pledgee (the "Collateral Agent") under a certain Security Agreement and
Assignment of Contracts dated as of January 4, 1982, as amended and restated
February 11, 1992, (the "Security Agreement") between the NBFT Trustee and
the Collateral Agent for the ratable benefit of the Secured Parties referred
to therein (the "Secured Parties"). The 1998 Series A Bonds shall consist of
fully registered bonds containing terms and provisions duly fixed and
determined by the Board of Directors of WMECO and expressed in this
Supplemental Indenture, including terms and provisions with respect to
maturity, interest payment, interest rate and repayment as provided herein.
Such fully registered bonds and the Trustee's certificate of authentication
thereof to be substantially in the forms thereof respectively set forth in
Schedule A appended hereto and made a part hereof;
WHEREAS, WMECO proposes to execute and deliver this Supplemental
Indenture to provide for the issue of the bonds of 1998 Series A and to
confirm the lien of the Indenture on the property referred to below, all as
permitted by Section 3.04 of the Indenture; and
WHEREAS, the Company, pursuant to resolutions duly and legally adopted
by its Board of Directors at a meeting duly called and held for the purpose,
has duly authorized the execution and delivery of this Eighty-Second
Supplemental Indenture and the issue of the 1998 Series A Bonds in the
aggregate principal amount not exceeding $17,300,000; and
WHEREAS, the issue of the 1998 Series A Bonds in said aggregate
principal amount not exceeding $17,300,000 and the execution and delivery of
this Eighty-Second Supplemental Indenture have been duly approved to the
extent required by law by the Department of Telecommunications and Energy of
said Commonwealth and by the Department of Public Utility Control of the
State of Connecticut; and
WHEREAS, all requirements of law and of the articles of organization, as
amended, and of the by-laws of WMECO, including all requisite action on the
part of directors and officers, and all things necessary to make the 1998
Series A Bonds, when duly executed by WMECO and delivered, the valid,
binding, and legal obligations of WMECO, and the covenants and stipulations
herein contained valid and binding obligations of WMECO, have been done and
performed, and the execution and delivery hereof have been in all respects
duly authorized; and
NOW, THEREFORE, THIS EIGHTY-SECOND SUPPLEMENTAL INDENTURE WITNESSETH:
In consideration of the premises and of the mutual covenants herein contained
and of the purchase and acceptance by the registered owners thereof of the
1998 Series A Bonds at any time issued hereunder, and of one dollar ($1) duly
paid to the Company by the Trustee and for other good and valuable
considerations, the receipt whereof at or before the ensealing and delivery
of these presents is hereby acknowledged, and in confirmation of and
supplementing the Indenture, and in the performance and observance of the
provisions thereof, and in order to establish the form and characteristics of
the 1998 Series A Bonds, and to secure the payment of the principal of and
premium, if any, and interest, if any, on all Bonds from time to time
outstanding under the Indenture according to their tenor and effect, and to
secure the performance and observance of all the covenants and conditions
contained therein and in this Eighty-Second Supplemental Indenture, the
Company has executed and delivered this Eighty-Second Supplemental Indenture,
and does hereby confirm the conveyance, transfer, assignment, and mortgage of
the franchises and properties as set forth in the Original Indenture and in
all supplemental indentures prior hereto, excepting only such as have been
released in accordance with Article VII of the Indenture and has granted,
bargained, sold, conveyed, assigned, transferred, mortgaged, and confirmed,
and by these presents does grant, bargain, sell, convey, assign, transfer,
mortgage, and confirm unto State Street Bank and Trust Company, as Trustee,
as provided in the Indenture, its successors in the trusts thereof and
hereof, and its and their assigns, all and singular the franchises and
properties of the Company of the character described and defined in the
Original Indenture as Mortgaged Property (including all and singular such
franchises and properties which may hereafter be acquired by the
Company) acquired after the execution of the Original Indenture including all
real property conveyed to the Company prior to the date hereof, including,
but not limited to, the property set forth in Schedule B appended hereto,
subject, however, to Permitted Encumbrances and to any mortgages or other
liens or encumbrances thereon of the character described in Section 4.10 of
the Indenture existing at the time of the acquisition of such franchises and
properties by the Company or created contemporaneously to secure or to raise
a part of the purchase price thereof and to any renewals or extensions of
such Permitted Encumbrances, mortgages or other liens or encumbrances.
There is furthermore expressly excepted and excluded from the lien and
operation of this Eighty-Second Supplemental Indenture, and from the
definition of the Mortgaged Property, all the property of the Company
described in clauses A to J, both inclusive, of the granting clauses of the
Original Indenture, whether owned at the time of the execution of this
Eighty-Second Supplemental Indenture or thereafter acquired by it.
TO HAVE AND TO HOLD all and singular the above described franchises and
properties unto the said State Street Bank and Trust Company, as Trustee
under the Indenture, its successors in the trusts thereof and hereof, and
its and their assigns, to its and their own use forever.
BUT IN TRUST, NEVERTHELESS, upon the terms and trusts set forth in the
Indenture for the equal pro rata benefit, security, and protection of the
bearers or registered owners of the Bonds from time to time certified,
issued, and outstanding under the Indenture, without any discrimination,
preference, priority, or distinction of any Bond or coupon over any other
Bond or coupon by reason of series, priority in the time of issue, sale, or
negotiation thereof, or otherwise howsoever, except as otherwise provided in
the Indenture;
PROVIDED, HOWEVER, and these presents are upon the condition that if the
Company, its successors or assigns, shall pay or cause to be paid the
principal of and the premium, if any, and interest, if any, on the Bonds
outstanding under the Indenture at the times and in the manner stipulated
therein and in the Indenture and shall keep, perform, and observe all and
singular the covenants and promises in said Bonds and in the Indenture
expressed to be kept, performed, and observed by or on the part of the
Company, then this Eighty-Second Supplemental Indenture and the estate and
rights hereby granted shall, pursuant to the provisions of Article XV of the
Original Indenture, cease, determine and be void, but only if the Indenture
shall have ceased, determined and become void, as therein provided, otherwise
to be and remain in full force and effect.
ARTICLE I
DESCRIPTION AND ISSUE OF THE 1998 SERIES A BONDS
Section 1.01. Designation; Amount; Form of Bonds of 1998 Series A.
The 1998 Series A Bonds and the certificate of authentication of the Trustee
upon said Bonds shall be substantially in the forms thereof respectively set
forth in Schedule A appended hereto, with such changes therein as shall be
approved by the Company and the Trustee. The 1998 Series A Bonds shall be
designated as the First Mortgage Bonds, 1998 Series A, due June 1, 1999 of
the Company, shall be issuable in the aggregate principal amount not
exceeding seventeen million three hundred thousand dollars ($17,300,000) and
no more except as provided in Section 2.13 of the Original Indenture.
The Bonds shall be issued in fully registered form in denominations of one
thousand dollars ($1,000) and any multiple thereof, and shall be redeemable
in the manner provided in Section 1.05 of this Eighty-Second Supplemental
Indenture. Notwithstanding the provisions of Section 2.11 of the Original
Indenture, no charge, except for taxes or governmental charges, shall be made
by the Company upon any registration of transfer or exchange of the 1998
Series A Bonds.
Section 1.02. Provisions of Bonds of 1998 Series A; Interest Accrual.
The bonds of 1998 Series A shall mature on June 1, 1999 and shall
bear interest at the Lease Rate (as defined below), as applicable from time
to time, but such interest shall accrue only upon and following the
occurrence and during the continuance of an Accelerating Event (as defined
below); provided, however, that in no event shall the interest rate payable
on the 1998 Series A Bonds exceed 6.89% per annum; and shall be payable both
as to principal and interest at the office or agency of WMECO in the Borough
of Manhattan, New York, New York, in any coin or currency of the United
States of America which at the time of payment is legal tender for the
payment of public and private debts. After a responsible officer of the
Trustee shall have received written notice from the Collateral Agent of the
occurrence of an Accelerating Event, specifying in reasonable detail the
events giving rise to the Accelerating Event and the date of its occurrence,
interest on the outstanding 1998 Series A Bonds shall be due and payable on
demand, provided, however, that upon the occurrence of an Accelerating Event
which is an Insolvency Event, interest shall be immediately due and payable
on demand whether or not the Trustee has received notice of the occurrence of
such Accelerating Event. Interest shall accrue from and including the date
of occurrence of an Accelerating Event and shall continue to accrue during
the continuance of such Accelerating Event. Interest on the outstanding 1998
Series A Bonds shall cease to accrue following the discontinuance of any such
Accelerating Event as evidenced by a written notice from an officer of the
Collateral Agent to a responsible officer of the Trustee, and any interest on
the outstanding 1998 Series A Bonds that has accrued but has not yet become
due and payable at the time such notice is given shall be extinguished and
shall not be required to be paid at any time thereafter.
Except as specified in the preceding paragraph, no interest shall accrue
or be payable on the 1998 Series A Bonds.
An "Accelerating Event" shall be deemed to have occurred on any date on
which the Event of Default (as defined in the Security Agreement) shall have
occurred and be continuing.
An "Insolvency Event" shall be deemed to have occurred on any date
an Event of Default described in Section 7.1.1 or 7.1.2 of the Current Credit
Agreement or an Event of Default of the same nature described in any Credit
Agreement or any IT Note Agreement (as defined in the Lease Agreement) shall
have occurred and be continuing.
The term "Lease Rate" shall mean for any day, that rate sufficient to
generate interest due on the outstanding 1998 Series A Bonds for such day in
an aggregate amount equal to that portion of the Daily Lease Charge (as
defined in the Lease Agreement) for such day which is the obligation of WMECO
under the Lease Agreement, but in no event shall such rate exceed 6.89% per
annum. From time to time following the occurrence of an Accelerating Event,
WMECO at the request of the Collateral Agent, shall certify to the Collateral
Agent, the Trustee and the NBFT Trustee the applicable Lease Rate for each
day of the period covered by such certificate.
If any amounts due under the Credit Agreement or any IT Note Agreement
(as defined in the Lease Agreement) shall become, or any bank acting as agent
on behalf of the financial institutions party to the Credit Agreement or the
holder or holders of any IT Notes shall so declare amounts due under such
Credit Agreement or IT Note Agreement, as the case may be, to be forthwith
due and payable pursuant to the terms of such Credit Agreement or IT Note
Agreement, as the case may be, the entire principal of the bonds of 1998
Series A, together with interest accrued but unpaid thereon, shall without
notice or demand of any kind, become immediately due and payable.
Anything in the Indenture, this Supplemental Indenture or any bond of
1998 Series A to the contrary notwithstanding, the bonds of 1998 Series A
shall be deemed paid, and all obligations of WMECO to pay at the times
provided herein the principal of, premium, if any, and interest on the bonds
of 1998 Series A shall be satisfied and discharged, if and to the extent,
that (A) the Current Credit Agreement is terminated in its entirety and all
obligations thereunder shall have been paid in full and WMECO shall not have
given notice to the Trustee that such 1998 Series A Bonds shall remain
outstanding, (B) each of the financial institutions party to the Credit
Agreement has agreed in writing that the 1998 Series A Bonds shall be deemed
paid, or (C) on June 1, 1999, no Event of Default (as defined in the Security
Agreement) shall have occurred and be continuing; it being understood that
the actual indebtedness evidenced by the 1998 Series A Bonds as of any time
shall be limited to 19% of the Secured Obligations (as defined in the
Security Agreement) as determined at such time, that at no time shall any
claim be made for principal and interest on the 1998 Series A Bonds in excess
of 19% of the Secured Obligations as determined at such time, and that, to
the extent that the outstanding principal amount of the 1998 Series A Bonds
exceeds such amount, neither the Secured Parties nor the Collateral Agent
shall have any right under, or right to exercise any right granted to the
holders of such excess 1998 Series A Bonds under, the Indenture. The Trustee
shall be entitled to rely on written notice from the Collateral Agent that no
Event of Default has occurred and is continuing under the Security Agreement.
Notwithstanding the provisions of Section 2.01 and Section 2.12 of the
Original Indenture, each bond of 1998 Series A shall be dated as of May 1,
1998 and shall bear interest on the principal amount thereof as provided
herein.
Notwithstanding the provisions of Section 2.12 of the Original
Indenture, the person in whose name any bond of 1998 Series A is registered
at the close of business on any record date (as hereinafter defined) with
respect to any interest payment date shall be entitled to receive the
interest payable on such interest payment date notwithstanding the
cancellation of such bond upon any registration of transfer or exchange
thereof subsequent to the record date and prior to such interest payment
date, except that if and to the extent the Company shall default in the
payment of the interest due on such interest payment date, then such
defaulted interest shall be paid to the person in whose name such bond is
registered on a subsequent record date for the payment of defaulted interest
if one shall have been established as hereinafter provided and otherwise on
the date of payment of such defaulted interest. A subsequent record date may
be established by the Company by notice mailed to the owners of the bonds of
1998 Series A not less than ten (10) days preceding such record date, which
record date shall not be more than five (5) days prior to the subsequent
interest payment date. The term "record date" as used in this Section with
respect to any regular interest payment date shall mean the day next
preceding such interest payment date, or if such day shall not be a Business
Day, the next preceding day which shall be a Business Day.
Section 1.03. Transfer and Exchange of the 1998 Series A Bonds; Agent
as Registered Holder; Restriction on Transfer of 1998 Series A Bonds.
The bonds of 1998 Series A may be surrendered for registration of transfer as
provided in the Indenture at the office or agency of the Company in the
Borough of Manhattan, New York, New York, and may be surrendered at said
office for exchange for a like aggregate principal amount of bonds of 1998
Series A of other authorized denominations. Pursuant to provisions of Section
2.07 of the Original Indenture, the Company appoints State Street Bank and
Trust Company, N.A. and its successors as the agency of the Company in the
Borough of Manhattan, City of New York, New York, for the registration of
transfer and exchange of the 1998 Series A Bonds.
The bonds of 1998 Series A shall be issued to and registered in the name
of THE FIRST NATIONAL BANK OF CHICAGO, as Pledgee and Collateral Agent under
the Security Agreement for the ratable benefit of the Secured Parties named
in the Security Agreement and, anything in the Indenture, this Supplemental
Indenture or any bond of 1998 Series A to the contrary notwithstanding, the
bonds of 1998 Series A shall not be sold, assigned, pledged or transferred,
except to effect the transfer to any successor Collateral Agent under the
Security Agreement.
Section 1.04. Conditions under which the 1998 Series A Bonds Not
Entitled to Benefits of Indenture. Anything in the Indenture, this
Supplemental Indenture or any bond of 1998 Series A to the
contrary notwithstanding, (i) the actual indebtedness evidenced by the 1998
Series A Bonds as of any time shall be limited to 19% of the amount of the
Secured Obligations (as defined in the Security Agreement) as determined at
such time; (ii) at no time shall any claim be made for principal and interest
on the 1998 Series A Bonds in excess of 19% of the amount of such Secured
Obligations as determined at such time; and (iii) to the extent that the
outstanding principal amount of the 1998 Series A Bonds exceeds such amount,
neither the Collateral Agent nor the Secured Parties (as defined in the
Security Agreement) shall have any right under, or right to exercise any
right granted to the holders of such excess 1998 Series A Bonds under, the
Indenture.
Section 1.05. No Redemption. The bonds of 1998 Series A shall not be
redeemable.
Section 1.06.Issuance of Bonds Against Bonds to be Retired or Redeemed.
Each initial and successive holder of any bond of the 1998 Series A,
solely by virtue of its acquisition thereof, shall have and be deemed to have
given written consent, without the need for any further action or consent by
such holder, to the following amendment to the Original Indenture, and each
said holder hereby authorizes the Trustee, on behalf of the holder, to waive
any notice contemplated by the Indenture and to give written consent to such
amendment. The amendment modifies Section 3.04(h) of the Original Indenture
to read as follows:
(h) in the event that (i) the total annual interest requirements of
the Bonds then to be issued under this Section exceed the total annual
interest requirements of the Bonds in respect of the payment,
retirement, redemption, Cancellation or surrender to the Trustee for
Cancellation of which said Bonds are then to be issued and (ii) such
Bonds in respect of the payment, retirement, redemption, Cancellation or
surrender to the Trustee for Cancellation of which said Bonds are then
to be issued are then Outstanding and mature more than two years from
the date of the Officers' Certificate contemplated by paragraph (d) of
this Section, an Earnings Certificate.
ARTICLE II
DIVIDEND COVENANT
Section 2.01 Dividend Covenant. This Eighty-Second Supplemental
Indenture imposes no additional restrictions on the Company's right to
declare or pay any dividends or make any other distributions on or in respect
of its common stock or to purchase or otherwise acquire for a consideration
any shares of its common stock beyond those created by prior supplemental
indentures and those in the Company's preferred stock provisions, by-laws and
those otherwise required by law.
ARTICLE III
REPAYMENT OF THE 1998 SERIES A BONDS
Section 3.01. Repayment Upon Reduction of Aggregate Commitment Under the
Facility. Upon written notice by the Collateral Agent to the Trustee (i) that
the Current Credit Agreement has been amended to reduce or cancel the
Aggregate Commitment (as defined in the Current Credit Agreement) of the
banks thereunder, and (ii) that upon the making of
any repayment of outstanding advances, if any, required pursuant to the terms
of the Current Credit Agreement as a result of such reduction or
cancellation, the sum of the then outstanding principal amount of the
IT Notes and the greater of the Aggregate Commitment under the Current Credit
Agreement and the aggregate principal amount of all loans outstanding under
the Current Credit Agreement equals less than $90,000,000, bonds of the 1998
Series A, in a principal amount equal to 19% of the amount by which the
principal amount of the then outstanding 1998 Series A Bonds held by the
Collateral Agent exceeds the sum of the then outstanding principal amount of
the IT Notes and the greater of the Aggregate Commitment under the Current
Credit Agreement and the aggregate principal amount of all loans outstanding
under the Current Credit Agreement shall be deemed paid and all obligations
of WMECO hereunder and thereunder with respect to such principal amount of
1998 Series A Bonds shall be deemed satisfied and discharged.
ARTICLE IV
THE TRUSTEE
Section 4.01. Trustee. The Trustee shall be entitled to, may exercise,
and shall be protected by, where and to the full extent that the same are
applicable, all the rights, powers, privileges, immunities and exemptions
provided in the Indenture, as if the provisions concerning the same were
incorporated herein at length. The remedies and provisions of the Indenture
applicable in case of any default by the Company thereunder are hereby
adopted and made applicable in case of any default with
respect to the properties included herein and, without limitation of the
generality of the foregoing, there are hereby conferred upon the Trustee the
same powers of sale and other powers over the properties described herein as
are expressed to be conferred by the Indenture.
ARTICLE V
DEFEASANCE
Section 5.01. Defeasance. This Eighty-Second Supplemental Indenture
shall become void when the Indenture shall be void.
ARTICLE VI
MISCELLANEOUS PROVISIONS
Section 6.01. Effect of Recitals
The recitals in this Eighty-Second Supplemental Indenture shall be taken
as recitals by the Company alone, and shall not be considered as made by or
as imposing any obligation or liability upon the Trustee, nor shall the
Trustee be held responsible for the legality or validity of this
Eighty-Second Supplemental Indenture, and the Trustee makes no covenants or
representations, and shall not be responsible, as to or for the effect,
authorization, execution, delivery, or recording of this Supplemental
Indenture, except as expressly set forth in the Original Indenture.
The Trustee shall not be taken impliedly to waive by this Eighty-Second
Supplemental Indenture any right it would otherwise have as provided in the
Original Indenture, this Eighty-Second Supplemental Indenture shall hereafter
form a part of the Indenture.
Section 6.02. Counterparts. This Eighty-Second Supplemental Indenture
may be simultaneously executed in any number of counterparts, each of which
shall be deemed an original; and all said counterparts executed and
delivered, each as an original, shall constitute but one and the same
instrument, which shall for all purposes be sufficiently evidenced by any
such original counterpart.
Section 6.03. Benefits of Supplemental Indenture and 1998 Series A
Bonds. Nothing in this Supplemental Indenture, or in the bonds of 1998
Series A, expressed or implied, is intended or shall be construed to give to
any person or corporation other than WMECO, the Trustee and the holders of
the bonds and interest obligations secured by the Indenture and this
Supplemental Indenture, any legal or equitable right, remedy or claim under
or in respect of this Supplemental Indenture or of any covenant, condition or
provision herein contained. All the covenants, conditions and provisions
hereof are and shall be for the sole and exclusive benefit of WMECO, the
Trustee and the holders of the bonds and interest obligations secured by the
Indenture and this Supplemental Indenture.
Section 6.04. Effect of Table of Contents and Headings.
The table of contents and the descriptive headings of the several Articles
and Sections of this Supplemental Indenture are inserted for convenience of
reference only and are not to be taken to be any part of this Supplemental
Indenture or to control or affect the meaning, construction or effect of the
same.
Section 6.05. Payment Due on Holidays. If the date for making any
payment or the last date for performance of any act or the exercise of any
right, as provided in this Supplemental Indenture, is not a Business Day,
such payment may be made or act performed or right exercised on the next
succeeding Business Day unless otherwise provided herein, with the same force
and effect as if done on the nominal date provided in this Supplemental
Indenture.
IN WITNESS WHEREOF, said Western Massachusetts Electric Company has
caused this instrument to be executed in its corporate name by its President
or one of its Vice Presidents and by its Treasurer or an Assistant Treasurer,
thereunto duly authorized, and its corporate seal to be hereto affixed and
attested by its Clerk or an Assistant Clerk, and said State Street Bank and
Trust Company has caused this instrument to be executed in its corporate name
by one of its Vice Presidents or Assistant Vice Presidents, thereunto duly
authorized, and its corporate seal to be hereto affixed, all as of the day
and year first above written.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By:
/s/John B. Keane
Vice President and Treasurer
and by
/s/David R. McHale
Assistant Treasurer
Attest:
/s/O. Kay Comendul
Clerk or Assistant Clerk
Signed, sealed and delivered by
Western Massachusetts Electric
Company in our presence:
/s/Tracy A. DeCredico
STATE OF CONNECTICUT
COUNTY OF HARTFORD BERLIN
On this 27 th day of April in the year 1998 before me personally came
John B. Keane and David R. McHale, to me personally known, who being by me
duly sworn did depose and say that they are respectively a Vice President and
an Assistant Treasurer of Western Massachusetts Electric Company, one of the
corporations described in and which executed the foregoing instrument; that
they know the seal of said corporation; that the seal affixed to said
instrument opposite the execution was affixed thereto pursuant to the
authority of its Board of Directors; that they signed their names thereto by
like authority; and they acknowledged said instrument to be their free act
and deed in their said respective capacities and the free act and deed of
Western Massachusetts Electric Company.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official
seal, at Berlin, in said State, the day and year first above written.
/s/Carole J. Kobrzycki
Notary Public for the
State of Connecticut
My commission expires 1/31/2003
(NOTARIAL SEAL)
STATE STREET BANK AND TRUST COMPANY, Trustee
By/s/Ruth A. Smith
Authorized Officer
Signed, sealed and delivered by (CORPORATE SEAL)
State Street Bank and Trust
Company in our presence:
/s/witness
/s/witness
COMMONWEALTH OF MASSACHUSETTS
BOSTON
COUNTY OF SUFFOLK
On this 20 th day of April in the year 1998 before me personally came
Ruth A. Smith to me personally known, who being by me duly
sworn did depose and say that he is an Vice President of State
Street Bank and Trust Company one of the corporations described in and which
executed the foregoing instrument; that he knows the seal of said
corporation; that the seal affixed to said instrument opposite the execution
was affixed thereto pursuant to the authority of its Board of Directors; that
he signed his name thereto by like authority; and he acknowledged said
instrument to be his free act and deed in his said capacity and the free act
and deed of State Street Bank and Trust Company.
IN WITNESS WHEREOF, I have hereunto set my hand and my official seal, at
Boston in said Commonwealth, the day and year first above written.
/s/Rose Marie Mogauro
Notary Public for the
Commonwealth of Massachusetts
My commission expires: 1/14/2005
(NOTARIAL SEAL)
Schedule A
(FORM OF BOND)
No. R-1 $17,300,000
WESTERN MASSACHUSETTS ELECTRIC COMPANY
First Mortgage Bond, 1998 Series A, due June 1, 1999
FOR VALUE RECEIVED, WESTERN MASSACHUSETTS ELECTRIC COMPANY, a
corporation of the Commonwealth of Massachusetts (hereinafter called the
Company) hereby promises to pay to THE FIRST NATIONAL BANK OF CHICAGO, or
registered assigns, in each case as Pledgee and Collateral Agent for the
benefit of the Secured Parties (as such term is defined in the Security
Agreement referred to on the reverse hereof), the principal sum of
$17,300,000 or, if less, 19% of the aggregate Secured Obligations (as defined
in the Security Agreement referred to on the reverse hereof) outstanding on
June 1, 1999 or any date on or before June 1, 1999 on which the principal
hereof becomes due and payable. The Company further agrees to pay interest
on said sum at the Lease Rate (as such term and all other capitalized terms
used but not otherwise defined herein are defined in the Indenture referred
to on the reverse hereof) as applicable from time to time, but such interest
shall accrue only upon and following the occurrence and during the
continuance of an Accelerating Event; provided, however, that in no event
shall the interest rate payable on the 1998 Series A Bonds exceed 6.89% per
annum. After a responsible officer of the Trustee shall have received
written notice from the Collateral Agent of the occurrence of an Accelerating
Event specifying in reasonable detail the events giving rise to the
Accelerating Event and the date of its occurrence, interest hereon shall be
due and payable on demand; provided, however, that upon the occurrence of
an Accelerating Event which is an Insolvency Event, interest shall be
immediately due and payable on demand whether or not the Trustee has received
notice of the occurrence of such Accelerating Event. Interest shall accrue
from and including the date of occurrence of an Accelerating Event and shall
continue to accrue during the continuance of an Accelerating Event. Interest
hereon shall cease to accrue following the discontinuance of the Accelerating
Event as evidenced by written notice from an officer of the Collateral Agent
to a responsible officer of the Trustee, and any interest hereon that has
accrued but has not yet become due and payable at the time such notice is
given shall be extinguished and shall not be required to be paid at any time
thereafter. The bonds of 1998 Series A shall be payable both as to principal
and interest at the office or agency of the Company in the Borough of
Manhattan, New York, New York, in any coin or currency of the United States
of America which at the time of payment is legal tender for the payment of
public and private debts. The interest on the bonds of 1998 Series A,
whether in temporary or definitive form, shall be payable without
presentation of such bonds; and only to or upon the written order of the
registered holders thereof of record at the applicable record date. If any
amounts due under the Credit Agreement or any IT Note Agreement (as defined
in the Lease Agreement) shall become, or any bank acting as agent on behalf
of the financial institutions party to the Credit Agreement or the holder or
holders of any IT Notes shall so declare amounts due under such Credit
Agreement or IT Note Agreement, as the case may be, to be forthwith due and
payable pursuant to the terms of such Credit Agreement or IT Note Agreement,
as the case may be, the entire principal of the bonds of 1998 Series A,
together with interest accrued but unpaid thereon, shall without notice or
demand of any kind, become immediately due and payable.
Anything in the Indenture referred to on the reverse hereof, the
supplemental indenture establishing the terms and conditions of bonds of this
Series (the "Supplemental Indenture") or any bond of 1998 Series A to the
contrary notwithstanding, the bonds of 1998 Series A shall be deemed paid,
and all obligations of the Company to pay at the times provided herein the
principal of, premium, if any, and interest on the bonds of 1998 Series A
shall be satisfied and discharged, if and to the extent, that (A) the Current
Credit Agreement is terminated in its entirety and all obligations thereunder
shall have been paid in full and the Company shall not have given notice to
the Trustee that such 1998 Series A Bonds shall remain outstanding, (B) each
of the financial institutions party to the Credit Agreement has agreed in
writing that the 1998 Series A Bonds shall be deemed paid, or (C) on June 1,
1999, no Event of Default (as defined in the Security Agreement) shall have
occurred and be continuing; it being understood that the actual indebtedness
evidenced by the 1998 Series A Bonds as of any time shall be limited to 19%
of the amount of the Secured Obligations (as defined in the Security
Agreement) as determined at such time, that at no time shall any claim be
made for principal and interest on the 1998 Series A Bonds in excess of 19%
of such Secured Obligations as determined at such time, and that, to the
extent that the outstanding principal amount of the 1998 Series A Bonds
exceeds such amount, neither the Secured Parties nor the Collateral Agent
shall have any right under, or right to exercise any right granted to the
holders of such excess 1998 Series A Bonds under, the Indenture. The Trustee
shall be entitled to rely on written notice from the Collateral Agent that no
Event of Default has occurred and is continuing under such Security
Agreement. By its acceptance of this Bond, the Collateral Agent agrees upon
request of the Company to provide such notice to the Trustee so long as no
Event of Default has occurred and is continuing.
Each installment of interest hereon shall be payable to the person who
shall be the registered owner of this Bond at the close of business on the
record date, which shall be the day next preceding such interest payment
date, or if such date shall not be a Business Day (as defined on the reverse
hereof), the next preceding day which is a Business Day.
Reference is hereby made to the further provisions of this Bond set
forth on the reverse hereof, and the registration of transfer and
exchangeability of this Bond, and such further provisions shall for all
purposes have the same effect as though fully set forth in this place.
This Bond shall not become or be valid or obligatory until the
certificate of authentication hereon shall have been signed by State Street
Bank and Trust Company (hereinafter with its successors as defined in the
Indenture, generally called the Trustee), or by such a successor.
IN WITNESS WHEREOF, Western Massachusetts Electric Company has caused
this Bond to be executed in its name and on its behalf by its President or a
Vice President and its Treasurer or an Assistant Treasurer thereunto duly
authorized, and its corporate seal to be impressed or imprinted hereon.
Dated as of , 1998.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By
By
CERTIFICATE OF AUTHENTICATION
This Bond is one of the First Mortgage Bonds, 1998 Series A, due June 1,
1999, described and provided for in the within mentioned Indenture.
STATE STREET BANK AND TRUST COMPANY
By:
Authorized Signatory
[FORM OF BOND]
[REVERSE]
WESTERN MASSACHUSETTS ELECTRIC COMPANY
First Mortgage Bond, 1998 Series A
The Bond is one of a series of Bonds in fully registered form known as
the "First Mortgage Bonds, 1998 Series A, due June 1, 1999" of the Company,
limited to seventeen million three hundred thousand dollars ($17,300,000) in
aggregate principal amount (except as provided by the terms of Section2.13 of
the Original Indenture mentioned below), and issued under and secured by a
First Mortgage Indenture and Deed of Trust between the Company and Old Colony
Trust Company (now State Street Bank and Trust Company, successor Trustee) as
Trustee, dated as of August 1, 1954 (herein as amended by a First
Supplemental Indenture dated as of October 1, 1954, called the Original
Indenture, the Original Indenture with all indentures supplemental thereto,
including specifically the Eighty-Second Supplemental Indenture dated as of
May 1, 1998, being herein generally called the Indenture) and said
Eighty-Second Supplemental Indenture, an executed counterpart of each of
which is on file at the principal corporate trust office of the Trustee, to
which Indenture reference is hereby made for a description of the nature and
extent of the security, the rights thereunder of the bearers or registered
owners of Bonds issued and to be issued thereunder, the rights, duties, and
immunities thereunder of the Trustee, the rights and obligations thereunder
of the Company, and the terms and conditions upon which said Bonds, and other
and further Bonds of other series, are issued and are to be issued; but
neither the foregoing reference to the Indenture nor any provision of this
Bond or of the Indenture establishing the terms and conditions of the bonds
of this Series shall affect or impair the obligation of the Company, which is
absolute, unconditional and unalterable, to pay the principal of and interest
on this Bond as herein provided. The principal of this bond may be declared
or may become due on the conditions, in the manner and at the time set forth
in the Indenture, upon the happening of an event of default as in the
Indenture provided or if any amounts due under the Credit Agreement (as such
term is defined in the Security Agreement) or any IT Note Agreement (as such
term is defined in the Security Agreement referred to below) shall become, or
the Bank Agent or the holder or holders of any IT Note shall so declare
amounts due under such Credit Agreement or such IT Note Agreement, to be
forthwith due and payable pursuant to the terms of such Credit Agreement or
IT Note Agreement, as the case may be.
This Bond, together with all other Bonds of this series, if any, is
issued to evidence and secure the Company's obligations pursuant to the Lease
Agreement, it being understood that the actual indebtedness evidenced by the
1998 Series A Bonds as of any time shall be limited to 19% of the amount of
the Secured Obligations (as defined in the Security Agreement referred to
below) as determined at such time, that at no time shall any claim be made
for principal and interest on the 1998 Series A Bonds in excess of 19% of the
amount of the Secured Obligations as determined at such time, and that, to
the extent that the outstanding principal amount of the 1998 Series A Bonds
exceeds such amount, neither the Secured Parties nor the Collateral Agent
shall have any right under, or right to exercise any right granted to the
holders of such excess 1998 Series A Bonds under, the Indenture.
The bonds of 1998 Series A shall be issued to and registered in the name
of THE FIRST NATIONAL BANK OF CHICAGO, as Pledgee and Collateral Agent
(the "Collateral Agent") under the Security Agreement and Assignment of
Contracts dated as of January 4, 1982, as amended and restated February 11,
1992 between Bankers Trust Company, not in its individual capacity but solely
as trustee of the Niantic Bay Fuel Trust which was created pursuant to a
Trust Agreement dated as of January 4, 1982, as amended and restated as of
February 11, 1992 among Bankers Trust Company, as trustee, State Street Bank
and Trust Company of Connecticut, National Association (which is the
successor trustor to the New Connecticut Bank and Trust Company, National
Association, as assignee of the Federal Deposit Insurance Corporation, as
receiver of the Connecticut Bank and Trust Company, National Association), as
Trustor and the Company, The Connecticut Light & Power Company ("CL&P") and
The Hartford Electric Light Company (which merged with and into CL&P on June
30, 1982), as beneficiaries, and the Collateral Agent for the ratable benefit
of the Secured Parties referred to therein (the "Security Agreement").
Anything in the Indenture, the Supplemental Indenture or any bond of 1998
Series A to the contrary notwithstanding, the bonds of 1998 Series A shall
not be sold, assigned, pledged or transferred, except to effect the transfer
to any successor Collateral Agent under the Security Agreement. Prior to due
presentment for registration of transfer of this Bond, the Company and the
Trustee may deem and treat the registered owner hereof as the absolute owner
hereof, whether or not this Bond be overdue, for the purpose of receiving
payment and for all other purposes, and neither the Company nor the Trustee
shall be affected by any notice to the contrary.
Upon written notice by the Collateral Agent to the Trustee (i) that the
Current Credit Agreement has been amended to reduce or cancel the Aggregate
Commitment (as defined in the Current Credit Agreement) of the banks
thereunder, and (ii) that upon the making of any repayment of outstanding
advances, required pursuant to the terms of the Current Credit Agreement as a
result of such reduction or cancellation, the sum of the then outstanding
principal amount of the IT Notes and the greater of the Aggregate Commitment
under the Current Credit Agreement and the aggregate principal amount of all
loans outstanding under the Current Credit Agreement equals less than
$90,000,000, bonds of the 1998 Series A, in a principal amount equal to 19%
of the amount by which the principal amount of the then outstanding 1998
Series A Bonds held by the Collateral Agent exceeds the sum of the then
outstanding principal amount of the IT Notes and the greater of the Aggregate
Commitment under the Current Credit Agreement and the aggregate principal
amount of all loans outstanding under the Current Credit Agreement, shall be
deemed paid and all obligations of WMECO hereunder and thereunder with
respect to such principal amount of 1998 Series A Bonds shall be deemed
satisfied and discharged.
This Bond is exchangeable at the option of the registered owner hereof
at the office or agency of the Company in the Borough of Manhattan, New York,
New York, for an equal principal amount of fully registered bonds of this
series of other authorized denominations, in the manner and on the terms
provided in the Indenture.
The 1998 Series A Bonds shall not be redeemable.
The Indenture contains provisions permitting the Company and the Trustee
with the consent of the bearers or registered owners of not less than seventy
percentum (70%) in principal amount of the Bonds at the time outstanding
(except Bonds held by or for the benefit of the Company), including, if more
than one Series of Bonds shall be at the time outstanding, not less than
seventy percentum (70%) in principal amount of the Bonds (except Bonds held
by or for the benefit of the Company) of each series affected differently
from those of other series, to effect by supplemental indenture modifications
or alterations of the Indenture and of the rights and obligations of the
Company and of the bearers and registered owners of the Bonds; but no such
modification or alteration shall be made which, without the written approval
or consent of the registered owner hereof, will extend the maturity hereof or
reduce the rate or extend the time for payment of interest hereon or change
the amount of the principal hereof or of any premium payable on the
redemption hereof, or which will reduce the percentage of the principal
amount of Bonds or the percentage of the principal amount of Bonds of any one
series required for the adoption of the modifications or alterations as
aforesaid, or authorize the creation by the Company, except as expressly
authorized by the Indenture, of any mortgage, pledge, or lien upon the
property subjected thereto ranking prior to or on an equality with the lien
thereof.
Each initial and successive holder of any bond of the 1998 Series A,
solely by virtue of its acquisition thereof, shall have and be deemed to have
given written consent, without the need for any further action or consent by
such holder, to the following amendment to the Original Indenture, and each
said holder hereby authorizes the Trustee, on behalf of the holder, to waive
any notice contemplated by the Indenture and to give written consent to such
amendment. The amendment modifies Section 3.04(h) of the Original Indenture
to read as follows:
(h) in the event that (i) the total annual interest requirements of
the Bonds then to be issued under this Section exceed the total annual
interest requirements of the Bonds in respect of the payment,
retirement, redemption, Cancellation or surrender to the Trustee for
Cancellation of which said Bonds are then to be issued and (ii) such
Bonds in respect of the payment, retirement, redemption, Cancellation or
surrender to the Trustee for Cancellation of which said Bonds are then
to be issued are then Outstanding and mature more than two years from
the date of the Officers' Certificate contemplated by paragraph (d) of
this Section, an Earnings Certificate.
If a default as defined in the Indenture shall occur, the principal of
this Bond may become or be declared due and payable before maturity, in the
manner and with the effect provided in the Indenture; but any default and the
consequences thereof may be waived by certain percentages of the bearers or
registered owners of Bonds, all as provided in the Indenture.
If the date for making any payment or the last date for performance of
any act or the exercise of any right, as provided in the Supplemental
Indenture establishing the terms and series of the bonds of this 1998 Series
A, is not a Business Day, such payment may be made or act performed or right
exercised on the next succeeding Business Day, unless otherwise provided
herein, with the same force and effect as if done on the nominal date
provided in the Supplemental Indenture establishing the terms and series of
the bonds of this 1998 Series A.
No recourse shall be had for the payment of the principal of or the
interest on this Bond, or for any claim based hereon or otherwise in respect
hereof, or of the Indenture against any incorporator, stockholder, director,
or officer, past, present, or future, as such, of the Company or of any
predecessor or successor corporation under any constitution, statute, or rule
of law, or by the enforcement of any assessment, penalty, or otherwise, all
such liability being waived and released by the holder hereof by the
acceptance of this Bond.
Schedule B
All of the following real estate and rights in real estate, the titles
to the various sites being those acquired by the Company by the respective
deeds below mentioned.
NONE
Schedule C
(NOT INCLUDED)
Detail of Filing and Recording of First Mortgage Indenture and Deed
Trust dated as of August 1, 1954 in Massachusetts.
Exhibit 4.4.11
SUPPLEMENTAL INDENTURE
Dated as of May 1, 1998
To
First Mortgage Indenture and Deed of Trust
Dated as of August 1, 1954
WESTERN MASSACHUSETTS ELECTRIC COMPANY
TO
STATE STREET BANK AND TRUST COMPANY, Trustee
1998 Series A Bonds, Due June 1, 1999
Amending the Eighty-Second Supplemental Indenture
dated as of May 1, 1998
WESTERN MASSACHUSETTS ELECTRIC COMPANY
Supplemental Indenture, Dated as of May 1, 1998
TABLE OF CONTENTS
Parties
Recitals
ARTICLE I
AMENDMENT OF INDENTURE
Section 1.01. Amendment of Section 3.01 of the Eighty-Second Supplemental
Indenture
Section 1.02. Amendment of Schedule A to the Eighty-Second Supplemental
Indenture
ARTICLE II
THE TRUSTEE
Section 2.01. Trustee
ARTICLE III
DEFEASANCE
Section 3.01. Defeasance
ARTICLE IV
MISCELLANEOUS PROVISIONS
Section 4.01. Effect of Recitals
Section 4.02. Counterparts
Section 4.03. Benefits of Supplemental Indenture and the 1998 Series A Bonds
Section 4.04. Effect of Table of Contents and Headings
TESTIMONIUM
SIGNATURES
ACKNOWLEDGMENTS
SCHEDULE A - Form of Bond for the 1998 Series A; Form of Trustee's
Certificate
SCHEDULE C - Detail of Filing and Recording of First Mortgage Indenture and
Deed of Trust
EIGHTY-THIRD SUPPLEMENTAL INDENTURE dated as of the first day of May,
1998, made and entered into by and between WESTERN MASSACHUSETTS ELECTRIC
COMPANY, a corporation organized under the laws of the Commonwealth of
Massachusetts, with its principal place of business at 174 Brush Hill Avenue,
West Springfield, Massachusetts 01089 (hereinafter generally called the
"Company" or "WMECO"), and STATE STREET BANK AND TRUST COMPANY, a trust
company organized under the laws of the Commonwealth of Massachusetts, as
successor to The First National Bank of Boston, as TRUSTEE under the Mortgage
Indenture described below, with its principal corporate trust office at Two
International Place, 4th Floor, Boston, MA 02110 (said State Street Bank and
Trust Company or, as applied to action antedating the effective date of said
succession, said The First National Bank of Boston, or its predecessor by
merger, Old Colony Trust Company, being hereinafter generally called the
Trustee).
WITNESSETH that:
WHEREAS, the Company has heretofore executed and delivered to the
Trustee its First Mortgage Indenture and Deed of Trust1 dated as of August 1,
1954 (hereinafter as amended by a First Supplemental Indenture dated as of
October 1, 1954, called the Original Indenture, the Original Indenture with
all indentures supplemental thereto being hereinafter generally called the
Indenture), conveying certain property therein described in trust as security
for the Bonds of the Company to be issued thereunder as therein provided and
for other purposes more particularly specified therein, and the Trustee has
accepted said Trust; and
WHEREAS, there are outstanding $385,000,000 aggregate principal amount
of First Mortgage Bonds which have been issued at various times and in
various amounts and with various dates of maturity and rates of interest and
have been denominated Series V, Series W, Series X, Series Y, 1997 Series A
and 1997 Series B; and
WHEREAS, WMECO executed and delivered an Eighty-Second Supplemental
Indenture dated as of May 1, 1998 to provide for the issue of the bonds of
1998 Series A; and
WHEREAS, WMECO proposes to execute and deliver this Eighty-Third
Supplemental Indenture to correct a typographical error appearing in Section
3.01 and Schedule A of the Eighty-Second Supplemental Indenture, all as
permitted by Section 16.01(f) of the Indenture; and
WHEREAS, all acts and things necessary to constitute this Eighty-Third
Supplemental Indenture as a valid, binding and legal instrument have been
authorized and performed.
NOW, THEREFORE, THIS EIGHTY-THIRD SUPPLEMENTAL INDENTURE WITNESSETH:
ARTICLE I
AMENDMENT OF INDENTURE
Section 1.01. Amendment of Section 3.01 of the Eighty-Second
Supplemental Indenture. The Indenture shall be, and hereby is, amended to
correct a typographical error by deleting Section 3.01 of the Eighty-Second
Supplemental Indenture in its entirety and substituting in lieu thereof the
following:
Section 3.01. Repayment Upon Reduction of Aggregate Commitment Under the
Facility. Upon written notice by the Collateral Agent to the Trustee (i)
that the Current Credit Agreement has been amended to reduce or cancel the
Aggregate Commitment (as defined in the Current Credit Agreement) of the
banks thereunder, and (ii) that upon the making of any repayment of
outstanding advances, if any, required pursuant to the terms of the Current
Credit Agreement as a result of such reduction or cancellation, the sum of
the then outstanding principal amount of the IT Notes and the greater of the
Aggregate Commitment under the Current Credit Agreement and the aggregate
principal amount of all loans outstanding under the Current Credit Agreement
equals less than $90,000,000, bonds of the 1998 Series A, in a principal
amount equal to the amount by which the principal amount of the then
outstanding 1998 Series A Bonds held by the Collateral Agent exceeds 19% of
the sum of the then outstanding principal amount of the IT Notes and the
greater of the Aggregate Commitment under the Current Credit Agreement and
the aggregate principal amount of all loans outstanding under the Current
Credit Agreement, shall be deemed paid and all obligations of WMECO hereunder
and thereunder with respect to such principal amount of 1998 Series A Bonds
shall be deemed satisfied and discharged.
Section 1.02. Amendment of Schedule A to the Eighty-Second Supplemental
Indenture. The Indenture shall be, and hereby is, amended to correct a
typographical error by deleting Schedule A to the Eighty-Second Supplemental
Indenture in its entirety and substituting in lieu thereof Schedule A
appended hereto.
ARTICLE II
THE TRUSTEE
Section 2.01. Trustee. The Trustee shall be entitled to, may exercise,
and shall be protected by, where and to the full extent that the same are
applicable, all the rights, powers, privileges, immunities and exemptions
provided in the Indenture, as if the provisions concerning the same were
incorporated herein at length. The remedies and provisions of the Indenture
applicable in case of any default by the Company thereunder are hereby
adopted and made applicable in case of any default with respect to the
properties included herein and, without limitation of the generality of the
foregoing, there are hereby conferred upon the Trustee the same powers of
sale and other powers over the properties described herein as are expressed
to be conferred by the Indenture.
ARTICLE III
DEFEASANCE
Section 3.01. Defeasance. This Eighty-Third Supplemental Indenture
shall become void when the Indenture shall be void.
ARTICLE IV
MISCELLANEOUS PROVISIONS
Section 4.01. Effect of Recitals. The recitals in this Eighty-Third
Supplemental Indenture shall be taken as recitals by the Company alone, and
shall not be considered as made by or as imposing any obligation or liability
upon the Trustee, nor shall the Trustee be held responsible for the legality
or validity of this Eighty-Third Supplemental Indenture, and the Trustee
makes no covenants or representations, and shall not be responsible, as to or
for the effect, authorization, execution, delivery, or recording of this
Supplemental Indenture, except as expressly set forth in the Original
Indenture. The Trustee shall not be taken impliedly to waive by this Eighty-
Third Supplemental Indenture any right it would otherwise have as provided in
the Original Indenture, this Eighty-Third Supplemental Indenture shall
hereafter form a part of the Indenture.
Section 4.02. Counterparts. This Eighty-Third Supplemental Indenture
may be simultaneously executed in any number of counterparts, each of which
shall be deemed an original; and all said counterparts executed and
delivered, each as an original, shall constitute but one and the same
instrument, which shall for all purposes be sufficiently evidenced by any
such original counterpart.
Section 4.03. Benefits of Supplemental Indenture and 1998 Series A
Bonds. Nothing in this Supplemental Indenture, or in the bonds of 1998
Series A, expressed or implied, is intended or shall be construed to give to
any person or corporation other than WMECO, the Trustee and the holders of
the bonds and interest obligations secured by the Indenture and this
Supplemental Indenture, any legal or equitable right, remedy or claim under
or in respect of this Supplemental Indenture or of any covenant, condition or
provision herein contained. All the covenants, conditions and provisions
hereof are and shall be for the sole and exclusive benefit of WMECO, the
Trustee and the holders of the bonds and interest obligations secured by the
Indenture and this Supplemental Indenture.
Section 4.04. Effect of Table of Contents and Headings. The table of
contents and the descriptive headings of the several Articles and Sections of
this Supplemental Indenture are inserted for convenience of reference only
and are not to be taken to be any part of this Supplemental Indenture or to
control or affect the meaning, construction or effect of the same.
IN WITNESS WHEREOF, said Western Massachusetts Electric Company has caused
this instrument to be executed in its corporate name by its President or one
of its Vice Presidents and by its Treasurer or an Assistant Treasurer,
thereunto duly authorized, and its corporate seal to be hereto affixed and
attested by its Clerk or an Assistant Clerk, and said State Street Bank and
Trust Company has caused this instrument to be executed in its corporate name
by one of its Vice Presidents or Assistant Vice Presidents, thereunto duly
authorized, and its corporate seal to be hereto affixed, all as of the day
and year first above written.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By/s/John B. Keane
Vice President and Treasurer
and by/s/David R. McHale
Assistant Treasurer
Attest:/s/O. Kay Comendul
Clerk or Assistant Clerk
Signed, sealed and delivered by
Western Massachusetts Electric
Company in our presence:
/s/Tracy A. DeCredico
/s/Marion C. Bloomquist
STATE OF CONNECTICUT
COUNTY OF HARTFORD BERLIN
On this 4 th day of May in the year 1998 before me personally came John B.
Keane and David R. McHale, to me personally known, who being by me duly sworn
did depose and say that they are respectively a Vice President and an
Assistant Treasurer of Western Massachusetts Electric Company, one of the
corporations described in and which executed the foregoing instrument; that
they know the seal of said corporation; that the seal affixed to said
instrument opposite the execution was affixed thereto pursuant to the
authority of its Board of Directors; that they signed their names thereto by
like authority; and they acknowledged said instrument to be their free act
and deed in their said respective capacities and the free act and deed of
Western Massachusetts Electric Company.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal,
at Berlin, in said State, the day and year first above written.
/s/Susan L. Cifaldi
Notary Public for the
State of Connecticut
My commission expires May 31, 1999
(NOTARIAL SEAL)
STATE STREET BANK AND TRUST COMPANY, Trustee
By:/s/ Ruth A. Smith
Authorized Officer
Signed, sealed and delivered by (CORPORATE SEAL)
State Street Bank and Trust
Company in our presence:
/s/James E. Schultz
/s/Rene Regland
COMMONWEALTH OF MASSACHUSETTS
BOSTON
COUNTY OF SUFFOLK
On this 5 th day of May in the year 1998 before me personally came Ruth
A. Smith to me personally known, who being by me duly sworn did depose and
say that she is a Vice President of State Street Bank and Trust Company, one
of the corporations described in and which executed the foregoing instrument;
that she knows the seal of said corporation; that the seal affixed to said
instrument opposite the execution was affixed thereto pursuant to the
authority of its Board of Directors; that she signed his name thereto by like
authority; and he acknowledged said instrument to be his free act and deed in
she said capacity and the free act and deed of State Street Bank and Trust
Company.
IN WITNESS WHEREOF, I have hereunto set my hand and my official seal, at
Boston in said Commonwealth, the day and year first above written.
/s/James M. Coolidge
Notary Public for the
Commonwealth of Massachusetts
My commission expires: June 19, 2003
(NOTARIAL SEAL)
Schedule A
(FORM OF BOND)
No. R-1 $17,300,000
WESTERN MASSACHUSETTS ELECTRIC COMPANY
First Mortgage Bond, 1998 Series A, due June 1, 1999
FOR VALUE RECEIVED, WESTERN MASSACHUSETTS ELECTRIC COMPANY, a
corporation of the Commonwealth of Massachusetts (hereinafter called the
Company) hereby promises to pay to THE FIRST NATIONAL BANK OF CHICAGO, or
registered assigns, in each case as Pledgee and Collateral Agent for the
benefit of the Secured Parties (as such term is defined in the Security
Agreement referred to on the reverse hereof), the principal sum of
$17,300,000 or, if less, 19% of the aggregate Secured Obligations (as defined
in the Security Agreement referred to on the reverse hereof) outstanding on
June 1, 1999 or any date on or before June 1, 1999 on which the principal
hereof becomes due and payable. The Company further agrees to pay interest
on said sum at the Lease Rate (as such term and all other capitalized terms
used but not otherwise defined herein are defined in the Indenture referred
to on the reverse hereof) as applicable from time to time, but such interest
shall accrue only upon and following the occurrence and during the
continuance of an Accelerating Event; provided, however, that in no event
shall the interest rate payable on the 1998 Series A Bonds exceed 6.89% per
annum. After a responsible officer of the Trustee shall have received
written notice from the Collateral Agent of the occurrence of an Accelerating
Event specifying in reasonable detail the events giving rise to the
Accelerating Event and the date of its occurrence, interest hereon shall be
due and payable on demand; provided, however, that upon the occurrence of an
Accelerating Event which is an Insolvency Event, interest shall be
immediately due and payable on demand whether or not the Trustee has received
notice of the occurrence of such Accelerating Event. Interest shall accrue
from and including the date of occurrence of an Accelerating Event and shall
continue to accrue during the continuance of an Accelerating Event. Interest
hereon shall cease to accrue following the discontinuance of the Accelerating
Event as evidenced by written notice from an officer of the Collateral Agent
to a responsible officer of the Trustee, and any interest hereon that has
accrued but has not yet become due and payable at the time such notice is
given shall be extinguished and shall not be required to be paid at any time
thereafter. The bonds of 1998 Series A shall be payable both as to principal
and interest at the office or agency of the Company in the Borough of
Manhattan, New York, New York, in any coin or currency of the United States
of America which at the time of payment is legal tender for the payment of
public and private debts. The interest on the bonds of 1998 Series A,
whether in temporary or definitive form, shall be payable without
presentation of such bonds; and only to or upon the written order of the
registered holders thereof of record at the applicable record date. If any
amounts due under the Credit Agreement or any IT Note Agreement (as defined
in the Lease Agreement) shall become, or any bank acting as agent on behalf
of the financial institutions party to the Credit Agreement or the holder or
holders of any IT Notes shall so declare amounts due under such Credit
Agreement or IT Note Agreement, as the case may be, to be forthwith due and
payable pursuant to the terms of such Credit Agreement or IT Note Agreement,
as the case may be, the entire principal of the bonds of 1998 Series A,
together with interest accrued but unpaid thereon, shall without notice or
demand of any kind, become immediately due and payable.
Anything in the Indenture referred to on the reverse hereof, the eighty-
second supplemental indenture establishing the terms and conditions of bonds
of this Series (the "Supplemental Indenture"), the eighty-third supplemental
indenture amending the Supplemental Indenture or any bond of 1998 Series A to
the contrary notwithstanding, the bonds of 1998 Series A shall be deemed
paid, and all obligations of the Company to pay at the times provided herein
the principal of, premium, if any, and interest on the bonds of 1998 Series A
shall be satisfied and discharged, if and to the extent, that (A) the Current
Credit Agreement is terminated in its entirety and all obligations thereunder
shall have been paid in full and the Company shall not have given notice to
the Trustee that such 1998 Series A Bonds shall remain outstanding, (B) each
of the financial institutions party to the Credit Agreement has agreed in
writing that the 1998 Series A Bonds shall be deemed paid, or (C) on June 1,
1999, no Event of Default (as defined in the Security Agreement) shall have
occurred and be continuing; it being understood that the actual indebtedness
evidenced by the 1998 Series A Bonds as of any time shall be limited to 19%
of the amount of the Secured Obligations (as defined in the Security
Agreement) as determined at such time, that at no time shall any claim be
made for principal and interest on the 1998 Series A Bonds in excess of 19%
of such Secured Obligations as determined at such time, and that, to the
extent that the outstanding principal amount of the 1998 Series A Bonds
exceeds such amount, neither the Secured Parties nor the Collateral Agent
shall have any right under, or right to exercise any right granted to the
holders of such excess 1998 Series A Bonds under, the Indenture. The Trustee
shall be entitled to rely on written notice from the Collateral Agent that no
Event of Default has occurred and is continuing under such Security
Agreement. By its acceptance of this Bond, the Collateral Agent agrees upon
request of the Company to provide such notice to the Trustee so long as no
Event of Default has occurred and is continuing.
Each installment of interest hereon shall be payable to the person who
shall be the registered owner of this Bond at the close of business on the
record date, which shall be the day next preceding such interest payment
date, or if such date shall not be a Business Day (as defined on the reverse
hereof), the next preceding day which is a Business Day.
Reference is hereby made to the further provisions of this Bond set
forth on the reverse hereof, and the registration of transfer and
exchangeability of this Bond, and such further provisions shall for all
purposes have the same effect as though fully set forth in this place.
This Bond shall not become or be valid or obligatory until the
certificate of authentication hereon shall have been signed by State Street
Bank and Trust Company (hereinafter with its successors as defined in the
Indenture, generally called the Trustee), or by such a successor.
IN WITNESS WHEREOF, Western Massachusetts Electric Company has caused
this Bond to be executed in its name and on its behalf by its President or a
Vice President and its Treasurer or an Assistant Treasurer thereunto duly
authorized, and its corporate seal to be impressed or imprinted hereon.
Dated as of , 1998.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By:
By:
CERTIFICATE OF AUTHENTICATION
This Bond is one of the First Mortgage Bonds, 1998 Series A, due June 1,
1999, described and provided for in the within mentioned Indenture.
STATE STREET BANK AND TRUST COMPANY
By:
Authorized Signatory
[FORM OF BOND]
[REVERSE]
WESTERN MASSACHUSETTS ELECTRIC COMPANY
First Mortgage Bond, 1998 Series A
The Bond is one of a series of Bonds in fully registered form known as
the "First Mortgage Bonds, 1998 Series A, due June 1, 1999" of the Company,
limited to seventeen million three hundred thousand dollars ($17,300,000) in
aggregate principal amount (except as provided by the terms of Section 2.13
of the Original Indenture mentioned below), and issued under and secured by a
First Mortgage Indenture and Deed of Trust between the Company and Old Colony
Trust Company (now State Street Bank and Trust Company, successor Trustee) as
Trustee, dated as of August 1, 1954 (herein as amended by a First
Supplemental Indenture dated as of October 1, 1954, called the Original
Indenture, the Original Indenture with all indentures supplemental thereto,
including specifically the Eighty-Second Supplemental Indenture dated as of
May 1, 1998 and the Eighty-Third Supplemental Indenture dated as of May 1,
1998, being herein generally called the Indenture) and said Eighty-Second and
Eighty-Third Supplemental Indentures, executed counterparts of each of which
are on file at the principal corporate trust office of the Trustee, to which
Indenture reference is hereby made for a description of the nature and extent
of the security, the rights thereunder of the bearers or registered owners of
Bonds issued and to be issued thereunder, the rights, duties, and immunities
thereunder of the Trustee, the rights and obligations thereunder of the
Company, and the terms and conditions upon which said Bonds, and other and
further Bonds of other series, are issued and are to be issued; but neither
the foregoing reference to the Indenture nor any provision of this Bond or of
the Indenture establishing the terms and conditions of the bonds of this
Series shall affect or impair the obligation of the Company, which is
absolute, unconditional and unalterable, to pay the principal of and interest
on this Bond as herein provided. The principal of this bond may be declared
or may become due on the conditions, in the manner and at the time set forth
in the Indenture, upon the happening of an event of default as in the
Indenture provided or if any amounts due under the Credit Agreement (as such
term is defined in the Security Agreement) or any IT Note Agreement (as such
term is defined in the Security Agreement referred to below) shall become, or
the Bank Agent or the holder or holders of any IT Note shall so declare
amounts due under such Credit Agreement or such IT Note Agreement, to be
forthwith due and payable pursuant to the terms of such Credit Agreement or
IT Note Agreement, as the case may be.
This Bond, together with all other Bonds of this series, if any, is
issued to evidence and secure the Company's obligations pursuant to the Lease
Agreement, it being understood that the actual indebtedness evidenced by the
1998 Series A Bonds as of any time shall be limited to 19% of the amount of
the Secured Obligations (as defined in the Security Agreement referred to
below) as determined at such time, that at no time shall any claim be made
for principal and interest on the 1998 Series A Bonds in excess of 19% of the
amount of the Secured Obligations as determined at such time, and that, to
the extent that the outstanding principal amount of the 1998 Series A Bonds
exceeds such amount, neither the Secured Parties nor the Collateral Agent
shall have any right under, or right to exercise any right granted to the
holders of such excess 1998 Series A Bonds under, the Indenture.
The bonds of 1998 Series A shall be issued to and registered in the name
of THE FIRST NATIONAL BANK OF CHICAGO, as Pledgee and Collateral Agent (the
"Collateral Agent") under the Security Agreement and Assignment of Contracts
dated as of January 4, 1982, as amended and restated February 11, 1992
between Bankers Trust Company, not in its individual capacity but solely as
trustee of the Niantic Bay Fuel Trust which was created pursuant to a Trust
Agreement dated as of January 4, 1982, as amended and restated as of February
11, 1992 among Bankers Trust Company, as trustee, State Street Bank and Trust
Company of Connecticut, National Association (which is the successor trustor
to the New Connecticut Bank and Trust Company, National Association, as
assignee of the Federal Deposit Insurance Corporation, as receiver of the
Connecticut Bank and Trust Company, National Association), as Trustor and the
Company, The Connecticut Light & Power Company ("CL&P") and The Hartford
Electric Light Company (which merged with and into CL&P on June 30, 1982), as
beneficiaries, and the Collateral Agent for the ratable benefit of the
Secured Parties referred to therein (the "Security Agreement"). Anything in
the Indenture, the Supplemental Indenture, the Eight-Third Supplemental
Indenture dated as of May 1, 1998 amending the Supplemental Indenture or any
bond of 1998 Series A to the contrary notwithstanding, the bonds of 1998
Series A shall not be sold, assigned, pledged or transferred, except to
effect the transfer to any successor Collateral Agent under the Security
Agreement. Prior to due presentment for registration of transfer of this
Bond, the Company and the Trustee may deem and treat the registered owner
hereof as the absolute owner hereof, whether or not this Bond be overdue, for
the purpose of receiving payment and for all other purposes, and neither the
Company nor the Trustee shall be affected by any notice to the contrary.
Upon written notice by the Collateral Agent to the Trustee (i) that the
Current Credit Agreement has been amended to reduce or cancel the Aggregate
Commitment (as defined in the Current Credit Agreement) of the banks
thereunder, and (ii) that upon the making of any repayment of outstanding
advances, if any, required pursuant to the terms of the Current Credit
Agreement as a result of such reduction or cancellation, the sum of the then
outstanding principal amount of the IT Notes and the greater of the Aggregate
Commitment under the Current Credit Agreement and the aggregate principal
amount of all loans outstanding under the Current Credit Agreement equals
less than $90,000,000, bonds of the 1998 Series A, in a principal amount
equal to the amount by which the principal amount of the then outstanding
1998 Series A Bonds held by the Collateral Agent exceeds 19% of the sum of
the then outstanding principal amount of the IT Notes and the greater of the
Aggregate Commitment under the Current Credit Agreement and the aggregate
principal amount of all loans outstanding under the Current Credit Agreement,
shall be deemed paid and all obligations of WMECO hereunder and thereunder
with respect to such principal amount of 1998 Series A Bonds shall be deemed
satisfied and discharged.
This Bond is exchangeable at the option of the registered owner hereof
at the office or agency of the Company in the Borough of Manhattan, New York,
New York, for an equal principal amount of fully registered bonds of this
series of other authorized denominations, in the manner and on the terms
provided in the Indenture.
The 1998 Series A Bonds shall not be redeemable.
The Indenture contains provisions permitting the Company and the Trustee
with the consent of the bearers or registered owners of not less than seventy
percentum (70%) in principal amount of the Bonds at the time outstanding
(except Bonds held by or for the benefit of the Company), including, if more
than one Series of Bonds shall be at the time outstanding, not less than
seventy percentum (70%) in principal amount of the Bonds (except Bonds held
by or for the benefit of the Company) of each series affected differently
from those of other series, to effect by supplemental indenture modifications
or alterations of the Indenture and of the rights and obligations of the
Company and of the bearers and registered owners of the Bonds; but no such
modification or alteration shall be made which, without the written approval
or consent of the registered owner hereof, will extend the maturity hereof or
reduce the rate or extend the time for payment of interest hereon or change
the amount of the principal hereof or of any premium payable on the
redemption hereof, or which will reduce the percentage of the principal
amount of Bonds or the percentage of the principal amount of Bonds of any one
series required for the adoption of the modifications or alterations as
aforesaid, or authorize the creation by the Company, except as expressly
authorized by the Indenture, of any mortgage, pledge, or lien upon the
property subjected thereto ranking prior to or on an equality with the lien
thereof.
Each initial and successive holder of any bond of the 1998 Series A,
solely by virtue of its acquisition thereof, shall have and be deemed to have
given written consent, without the need for any further action or consent by
such holder, to the following amendment to the Original Indenture, and each
said holder hereby authorizes the Trustee, on behalf of the holder, to waive
any notice contemplated by the Indenture and to give written consent to such
amendment. The amendment modifies Section 3.04(h) of the Original Indenture
to read as follows:
(h) in the event that (i) the total annual interest requirements of
the Bonds then to be issued under this Section exceed the total annual
interest requirements of the Bonds in respect of the payment, retirement,
redemption, Cancellation or surrender to the Trustee for Cancellation of
which said Bonds are then to be issued and (ii) such Bonds in respect of the
payment, retirement, redemption, Cancellation or surrender to the Trustee for
Cancellation of which said Bonds are then to be issued are then Outstanding
and mature more than two years from the date of the Officers' Certificate
contemplated by paragraph (d) of this Section, an Earnings Certificate.
If a default as defined in the Indenture shall occur, the principal of
this Bond may become or be declared due and payable before maturity, in the
manner and with the effect provided in the Indenture; but any default and the
consequences thereof may be waived by certain percentages of the bearers or
registered owners of Bonds, all as provided in the Indenture.
If the date for making any payment or the last date for performance of
any act or the exercise of any right, as provided in the Supplemental
Indenture establishing the terms and series of the bonds of this 1998 Series
A, as amended by the Eighty-Third Supplemental Indenture dated as of May 1,
1998 amending the Supplemental Indenture, is not a Business Day, such payment
may be made or act performed or right exercised on the next succeeding
Business Day, unless otherwise provided herein, with the same force and
effect as if done on the nominal date provided in the Supplemental Indenture
establishing the terms and series of the bonds of this 1998 Series A, as
amended by the Eighty-Third Supplemental Indenture dated as of May 1, 1998
amending the Supplemental Indenture.
No recourse shall be had for the payment of the principal of or the
interest on this Bond, or for any claim based hereon or otherwise in respect
hereof, or of the Indenture against any incorporator, stockholder, director,
or officer, past, present, or future, as such, of the Company or of any
predecessor or successor corporation under any constitution, statute, or rule
of law, or by the enforcement of any assessment, penalty, or otherwise, all
such liability being waived and released by the holder hereof by the
acceptance of this Bond.
Schedule C
Detail of Filing and Recording of First Mortgage Indenture and Deed
Trust dated as of August 1, 1954 in Massachusetts.
Date
Page Recorded Doc. No. Book
Registry of Deeds
County of Berkshire
Middle District 8/18/54 22357 614 395
Northern District 8/18/54 2684 512 97
Southern District 8/18/54 None Assigned 310 379
County of Franklin 8/18/54 3501 1007 2
County of Hampshire 8/18/54 5070 1175 388
County of Hampden 8/15/54 20682 2331 1
Registry District of Land Court
County of Berkshire
Middle District 10/4/54 8407-A
Northern District 11/5/68 3115
County of Hampshire 8/18/54 822
County of Hampden 8/19/54 18800
Office of Town Clerk, 3/22/67 6917 None Assigned
West Springfield*
*Confirmatory Indenture 8/18/54 None Assigned 54 121
of Mortgage filed
Secretary of the 442315
Commonwealth
1For details as to the filing and recording of this instrument in
Massachusetts, see Schedule C.
Exhibit 10.23.2
RESTATED
NEW ENGLAND
POWER POOL AGREEMENT
(Restated to reflect changes effected by the Fifth Supplement to Thirty-
Third Agreement Amending New England Power Pool Agreement, and the Thirty-Sixth
Agreement Amending New England Power Pool Agreement, and all prior
amendments)
<PAGE>
TABLE OF CONTENTS
Page
PART ONE - INTRODUCTION. . . . . . . . . . . . . . . . . . . . .1
SECTION 1 - DEFINITIONS. . . . . . . . . . . . . . . . . . . . .1
1.1 Adjusted Load. . . . . . . . . . . . . . . . . . . . .2
1.2 Adjusted Monthly Peak. . . . . . . . . . . . . . . . .2
1.3 Adjusted Net Interchange . . . . . . . . . . . . . . .2
1.4 AGC Capability . . . . . . . . . . . . . . . . . . . .3
1.5 AGC Entitlement. . . . . . . . . . . . . . . . . . . .3
1.6 Agreement. . . . . . . . . . . . . . . . . . . . . . .4
1.7 Annual Transmission Revenue Requirements . . . . . . .4
1.8 Automatic Generation Control or AGC. . . . . . . . . .4
1.9 Bid Price. . . . . . . . . . . . . . . . . . . . . . .5
1.10 Commission . . . . . . . . . . . . . . . . . . . . . .5
1.11 Control Area . . . . . . . . . . . . . . . . . . . . .5
1.12 Curtailment. . . . . . . . . . . . . . . . . . . . . .6
1.13 Direct Assignment Facilities . . . . . . . . . . . . .7
1.14 Dispatch Price . . . . . . . . . . . . . . . . . . . .7
1.15 EHV PTF. . . . . . . . . . . . . . . . . . . . . . . .8
1.16 Electrical Load. . . . . . . . . . . . . . . . . . . .8
1.17 Eligible Customer. . . . . . . . . . . . . . . . . . .9
1.18 Energy . . . . . . . . . . . . . . . . . . . . . . . 10
1.19 Energy Entitlement . . . . . . . . . . . . . . . . . 10
1.20 Entitlement. . . . . . . . . . . . . . . . . . . . . 11
1.21 Entity . . . . . . . . . . . . . . . . . . . . . . . 11
1.22 Excepted Transaction . . . . . . . . . . . . . . . . 12
1.23 Executive Committee. . . . . . . . . . . . . . . . . 12
1.24 Facilities Study . . . . . . . . . . . . . . . . . . 13
1.25 Firm Contract. . . . . . . . . . . . . . . . . . . . 13
1.26 First Effective Date . . . . . . . . . . . . . . . . 13
1.27 Good Utility Practice. . . . . . . . . . . . . . . . 13
1.28 HQ Contracts . . . . . . . . . . . . . . . . . . . . 14
1.29 HQ Energy Banking Agreement. . . . . . . . . . . . . 14
1.30 HQ Interconnection . . . . . . . . . . . . . . . . . 14
1.31 HQ Interconnection Agreement . . . . . . . . . . . . 15
1.32 HQ Interconnection Capability Credit . . . . . . . . 15
1.33 HQ Interconnection Transfer Capability . . . . . . . 16
1.34 HQ Net Interconnection Capability Credit . . . . . . 17
1.35 HQ Phase I Energy Contract . . . . . . . . . . . . . 17
1.36 HQ Phase I Percentage. . . . . . . . . . . . . . . . 17
1.37 HQ Phase I Transfer Credit . . . . . . . . . . . . . 18
1.38 HQ Phase II Firm Energy Contract . . . . . . . . . . 18
1.39 HQ Phase II Gross Transfer Responsibility. . . . . . 18
1.40 HQ Phase II Net Transfer Responsibility. . . . . . . 19
1.41 HQ Phase II Percentage . . . . . . . . . . . . . . . 19
1.42 HQ Phase II Transfer Credit. . . . . . . . . . . . . 19
1.43 HQ Use Agreement . . . . . . . . . . . . . . . . . . 19
1.44 Installed Capability . . . . . . . . . . . . . . . . 20
1.45 Installed Capability Entitlement . . . . . . . . . . 20
1.46 Installed Capability Responsibility. . . . . . . . . 21
1.47 Installed System Capability. . . . . . . . . . . . . 21
1.48 Interchange Transactions . . . . . . . . . . . . . . 21
1.49 Internal Point-to-Point Service. . . . . . . . . . . 21
1.50 Interruption . . . . . . . . . . . . . . . . . . . . 21
1.51 ISO. . . . . . . . . . . . . . . . . . . . . . . . . 22
1.52 Kilowatt . . . . . . . . . . . . . . . . . . . . . . 22
1.53 Load . . . . . . . . . . . . . . . . . . . . . . . . 22
1.54 Local Network. . . . . . . . . . . . . . . . . . . . 24
1.56 Lower Voltage PTF. . . . . . . . . . . . . . . . . . 24
1.57 Management Committee . . . . . . . . . . . . . . . . 25
1.58 Market Reliability Planning Committee. . . . . . . . 25
1.59 Monthly Peak . . . . . . . . . . . . . . . . . . . . 25
1.60 NEPOOL . . . . . . . . . . . . . . . . . . . . . . . 25
1.61 NEPOOL Control Area. . . . . . . . . . . . . . . . . 25
1.62 NEPOOL Installed Capability. . . . . . . . . . . . . 26
1.63 NEPOOL Installed Capability Responsibility . . . . . 27
1.64 NEPOOL Objective Capability. . . . . . . . . . . . . 27
1.65 New Unit . . . . . . . . . . . . . . . . . . . . . . 27
1.66 Non-Participant. . . . . . . . . . . . . . . . . . . 27
1.67 Operable Capability. . . . . . . . . . . . . . . . . 28
1.68 Operable Capability Entitlement. . . . . . . . . . . 28
1.69 Operable Capability Requirement . . . . . . . . . . 29
1.70 Operable System Capability . . . . . . . . . . . . . 29
1.71 Operating Reserve. . . . . . . . . . . . . . . . . . 29
1.72 Operating Reserve Entitlement. . . . . . . . . . . . 29
1.73 Other HQ Energy. . . . . . . . . . . . . . . . . . . 30
1.74 Participant. . . . . . . . . . . . . . . . . . . . . 30
1.75 Pool-Planned Facility. . . . . . . . . . . . . . . . 31
1.76 Pool-Planned Unit. . . . . . . . . . . . . . . . . . 31
1.77 Power Year . . . . . . . . . . . . . . . . . . . . . 31
1.78 Prior NEPOOL Agreement . . . . . . . . . . . . . . . 31
1.79 Proxy Unit . . . . . . . . . . . . . . . . . . . . . 31
1.80 PTF. . . . . . . . . . . . . . . . . . . . . . . . . 32
1.81 Regional Market Operations Committee . . . . . . . . 32
1.82 Regional Network Service . . . . . . . . . . . . . . 32
1.83 Regional Transmission Operations Committee . . . . . 32
1.84 Regional Transmission Planning Committee . . . . . . 32
1.85 Related Person . . . . . . . . . . . . . . . . . . . 33
1.86 Scheduled Dispatch Period. . . . . . . . . . . . . . 33
1.87 Second Effective Date. . . . . . . . . . . . . . . . 33
1.88 Service Agreement. . . . . . . . . . . . . . . . . . 34
1.89 Summer Capability. . . . . . . . . . . . . . . . . . 34
1.90 Summer Period. . . . . . . . . . . . . . . . . . . . 34
1.91 System Contract. . . . . . . . . . . . . . . . . . . 34
1.92 System Impact Study. . . . . . . . . . . . . . . . . 35
1.93 System Operator. . . . . . . . . . . . . . . . . . . 35
1.94 Target Availability Rate . . . . . . . . . . . . . . 36
1.95 Tariff . . . . . . . . . . . . . . . . . . . . . . . 36
1.96 Third Effective Date . . . . . . . . . . . . . . . . 36
1.97 Through or Out Service . . . . . . . . . . . . . . . 36
1.99 Transmission Customer. . . . . . . . . . . . . . . . 37
1.100 Transmission Provider . . . . . . . . . . . . . 37
1.101 Unit Contract . . . . . . . . . . . . . . . . . 37
1.102 Voting Share. . . . . . . . . . . . . . . . . . 38
1.103 Winter Capability . . . . . . . . . . . . . . . 38
1.104 Winter Period . . . . . . . . . . . . . . . . . 38
1.105 10-Minute Spinning Reserve. . . . . . . . . . . 38
1.106 10-Minute Non-Spinning Reserve. . . . . . . . . 39
1.107 30-Minute Operating Reserve . . . . . . . . . . 40
1.108 33rd Amendment. . . . . . . . . . . . . . . . . 41
1.109 Modification of Certain Definitions When a
Participant Purchases a Portion of Its
Requirements from Another Participant Pursuant
to Firm Contract. . . . . . . . . . . . . . . . 42
SECTION 2 - PURPOSE; EFFECTIVE DATES . . . . . . . . . . . . . 45
2.1 Purpose. . . . . . . . . . . . . . . . . . . . . . . 45
2.2 Effective Dates; Transitional Provisions . . . . . . 45
SECTION 3 - MEMBERSHIP . . . . . . . . . . . . . . . . . . . . 46
3.1 Membership . . . . . . . . . . . . . . . . . . . . . 46
3.2 Operations Outside the Control Area. . . . . . . . . 48
3.3 Lack of Place of Business in New England . . . . . . 48
3.4 Obligation for Deferred Expenses . . . . . . . . . . 49
3.5 Financial Security . . . . . . . . . . . . . . . . . 49
SECTION 4 - STATUS OF PARTICIPANTS . . . . . . . . . . . . . . 50
4.1 Treatment of Certain Entities as Single Participant. 50
4.2 Participants to Retain Separate Identities . . . . . 51
SECTION 5 - NEPOOL OBJECTIVES AND COOPERATION BY
PARTICIPANTS . . . . . . . . . . . . . . . . . . . 52
5.1 NEPOOL Objectives. . . . . . . . . . . . . . . . . . 52
5.2 Cooperation by Participants. . . . . . . . . . . . . 53
PART TWO - GOVERNANCE. . . . . . . . . . . . . . . . . . . . . 54
SECTION 6 - MANAGEMENT COMMITTEE . . . . . . . . . . . . . . . 54
6.1 Membership . . . . . . . . . . . . . . . . . . . . . 54
6.2 Term of Members. . . . . . . . . . . . . . . . . . . 55
6.3 Votes. . . . . . . . . . . . . . . . . . . . . . . . 55
6.4 Number of Votes Necessary for Action . . . . . . . . 64
6.5 Proxies. . . . . . . . . . . . . . . . . . . . . . . 65
6.6 Alternates . . . . . . . . . . . . . . . . . . . . . 65
6.7 Officers . . . . . . . . . . . . . . . . . . . . . . 65
6.8 Meetings . . . . . . . . . . . . . . . . . . . . . . 66
6.9 Notice of Meetings . . . . . . . . . . . . . . . . . 66
6.10 Adoption of Budgets. . . . . . . . . . . . . . . . . 66
6.11 Adoption of Bylaws . . . . . . . . . . . . . . . . . 67
6.12 Establishing Reliability Standards . . . . . . . . . 67
6.13 Appointment and Compensation of NEPOOL Personnel . . 68
6.14 Duties and Authority . . . . . . . . . . . . . . . . 68
6.15 Attendance of Members of Management Committee at
Other Committee Meetings . . . . . . . . . . . . . . 74
SECTION 7 - EXECUTIVE COMMITTEE. . . . . . . . . . . . . . . . 74
7.1 Organization . . . . . . . . . . . . . . . . . . . . 74
7.2 Membership . . . . . . . . . . . . . . . . . . . . . 75
7.3 Term of Members. . . . . . . . . . . . . . . . . . . 77
7.4 Alternates . . . . . . . . . . . . . . . . . . . . . 78
7.5 Votes. . . . . . . . . . . . . . . . . . . . . . . . 78
7.6 Number of Votes Necessary for Action . . . . . . . . 79
7.7 Officers . . . . . . . . . . . . . . . . . . . . . . 79
7.8 Meetings . . . . . . . . . . . . . . . . . . . . . . 80
7.9 Notice of Meetings . . . . . . . . . . . . . . . . . 80
7.10 Notice to Members of Management Committee of
Actions by Executive Committee . . . . . . . . . . . 81
7.11 Appeal of Actions to Management Committee. . . . . . 81
SECTION 8 - MARKET RELIABILITY PLANNING COMMITTEE. . . . . . . 82
8.1 Organization . . . . . . . . . . . . . . . . . . . . 82
8.2 Membership . . . . . . . . . . . . . . . . . . . . . 82
8.3 Term of Members. . . . . . . . . . . . . . . . . . . 84
8.4 Voting . . . . . . . . . . . . . . . . . . . . . . . 85
8.5 Alternates . . . . . . . . . . . . . . . . . . . . . 86
8.6 Officers . . . . . . . . . . . . . . . . . . . . . . 87
8.7 Meetings . . . . . . . . . . . . . . . . . . . . . . 87
8.8 Notice of Meetings . . . . . . . . . . . . . . . . . 87
8.9 Notice to Members of Management Committee. . . . . . 88
8.10 Appeal of Actions to Management Committee. . . . . . 88
8.11 Responsibilities . . . . . . . . . . . . . . . . . . 89
8.12 Functional Planning Committees . . . . . . . . . . . 91
8.13 Appointment of Task Forces . . . . . . . . . . . . . 92
8.14 Consultants, Computer Time and Expenses. . . . . . . 93
8.15 Further Powers and Duties. . . . . . . . . . . . . . 93
8.16 Reports to Management Committee. . . . . . . . . . . 93
8.17 Joint Meetings With Regional Transmission Planning
Committee. . . . . . . . . . . . . . . . . . . . . . 94
SECTION 9 - REGIONAL TRANSMISSION PLANNING COMMITTEE . . . . . 94
9.1 Organization . . . . . . . . . . . . . . . . . . . . 94
9.2 Membership . . . . . . . . . . . . . . . . . . . . . 95
9.3 Term of Members. . . . . . . . . . . . . . . . . . . 97
9.4 Voting . . . . . . . . . . . . . . . . . . . . . . . 97
9.5 Alternates . . . . . . . . . . . . . . . . . . . . . 99
9.6 Officers . . . . . . . . . . . . . . . . . . . . . . 99
9.7 Meetings . . . . . . . . . . . . . . . . . . . . . . 99
9.8 Notice of Meetings . . . . . . . . . . . . . . . . .100
9.9 Notice to Members of Management Committee. . . . . .100
9.10 Appeal of Actions to Management Committee. . . . . .101
9.11 Responsibilities . . . . . . . . . . . . . . . . . .101
9.12 Functional Planning Committees . . . . . . . . . . .103
9.13 Appointment of Task Forces . . . . . . . . . . . . .105
9.14 Consultants, Computer Time and Expenses. . . . . . .105
9.15 Further Powers and Duties. . . . . . . . . . . . . .105
9.16 Reports to Management Committee. . . . . . . . . . .106
9.17 Joint Meetings With Market Reliability Planning
Committee. . . . . . . . . . . . . . . . . . . . . .106
SECTION 10 - REGIONAL MARKET OPERATIONS COMMITTEE. . . . . . .106
10.1 Organization . . . . . . . . . . . . . . . . . . . .106
10.2 Membership . . . . . . . . . . . . . . . . . . . . .107
10.3 Terms of Members . . . . . . . . . . . . . . . . . .109
10.4 Voting . . . . . . . . . . . . . . . . . . . . . . .109
10.5 Alternates . . . . . . . . . . . . . . . . . . . . .111
10.6 Officers . . . . . . . . . . . . . . . . . . . . . .111
10.7 Meetings . . . . . . . . . . . . . . . . . . . . . .111
10.8 Notice of Meetings . . . . . . . . . . . . . . . . .112
10.9 Notice to Members of Management Committee. . . . . .112
10.10 Appeal of Actions to Management Committee . . .113
10.11 Appointment of Task Forces. . . . . . . . . . .113
10.12 Consultants, Computer Time and Expenses . . . .114
10.13 Responsibilities. . . . . . . . . . . . . . . .114
10.14 Further Powers and Duties . . . . . . . . . . .117
10.15 Development of Rules Relating to Non-
Participant Supply and Demand-side Resources. .117
10.16 Joint Meetings with Regional Transmission
Operations Committee. . . . . . . . . . . . . .118
SECTION 11 - REGIONAL TRANSMISSION OPERATIONS COMMITTEE. . . .118
11.1 Organization . . . . . . . . . . . . . . . . . . . .118
11.2 Membership . . . . . . . . . . . . . . . . . . . . .118
11.3 Terms of Members . . . . . . . . . . . . . . . . . .121
11.4 Voting . . . . . . . . . . . . . . . . . . . . . . .121
11.5 Alternates . . . . . . . . . . . . . . . . . . . . .123
11.6 Officers . . . . . . . . . . . . . . . . . . . . . .123
11.7 Meetings . . . . . . . . . . . . . . . . . . . . . .123
11.8 Notice of Meetings . . . . . . . . . . . . . . . . .124
11.9 Notice to Members of Management Committee. . . . . .124
11.10 Appeal of Actions to Management Committee . . .125
11.11 Appointment of Task Forces. . . . . . . . . . .125
11.12 Consultants, Computer Time and Expenses . . . .126
11.13 Responsibilities. . . . . . . . . . . . . . . .126
11.14 Further Powers and Duties . . . . . . . . . . .127
11.15 Joint Meetings with Regional Market Operations
Committee . . . . . . . . . . . . . . . . . . .128
PART THREE - MARKET PROVISIONS . . . . . . . . . . . . . . . .128
SECTION 12 - INSTALLED CAPABILITY AND OPERABLE CAPABILITY
OBLIGATIONS AND PAYMENTS. . . . . . . . . . . . .128
12.1 Obligations to Provide Installed Capability and
Operable Capability. . . . . . . . . . . . . . . . .128
12.2 Computation of Installed Capability
Responsibilities . . . . . . . . . . . . . . . . . .129
12.3 Computation of Operable Capability Requirements. . .147
12.4 Bids to Furnish Installed Capability or Operable
Capability . . . . . . . . . . . . . . . . . . . . .148
12.5 Consequences of Deficiencies in Installed
Capability Responsibility. . . . . . . . . . . . . .148
12.6 Consequences of Deficiencies in Operable Capability
Requirements . . . . . . . . . . . . . . . . . . . .151
12.7 Payments to Participants Furnishing Installed
Capability and Operable Capability . . . . . . . . .153
SECTION 13 - OPERATION, GENERATION, OTHER RESOURCES,
AND INTERRUPTIBLE CONTRACTS . . . . . . . . . . .155
13.1 Maintenance and Operation in Accordance with Good
Utility Practice . . . . . . . . . . . . . . . . . .155
13.2 Central Dispatch . . . . . . . . . . . . . . . . . .155
13.3 Maintenance and Repair . . . . . . . . . . . . . . .156
13.4 Objectives of Day-to-Day System Operation. . . . . .157
13.5 Satellite Membership . . . . . . . . . . . . . . . .158
SECTION 14 - INTERCHANGE TRANSACTIONS. . . . . . . . . . . . .158
14.1 Obligation for Energy, Operating Reserve and
Automatic Generation Control . . . . . . . . . . . .158
14.2 Obligation to Bid or Schedule, and Right to
Receive Energy, Operating Reserve and Automatic
Generation Control . . . . . . . . . . . . . . . . .162
14.3 Amount of Energy, Operating Reserve and Automatic
Generation Control Received or Furnished . . . . . .168
14.4 Payments by Participants Receiving Energy Service,
Operating Reserve and Automatic Generation Control. 171
14.5 Payments to Participants Furnishing Energy Service,
Operating Reserve, and Automatic Generation Control.173
14.6 Energy Transactions with Non-Participants. . . . . .176
14.7 Participant Purchases Pursuant to Firm Contracts
and System Contracts . . . . . . . . . . . . . . . .178
14.8 Determination of Energy Clearing Price . . . . . . .180
14.9 Determination of Operating Reserve Selling Price
and Clearing Price . . . . . . . . . . . . . . . . .181
14.10 Determination of AGC Clearing Price . . . . . .185
14.11 Funds to or from which Payments are to be Made.186
14.12 Development of Rules Relating to Nuclear and
Hydroelectric Generating Facilities, Limited-
Fuel Generating Facilities, and Interruptible
Loads . . . . . . . . . . . . . . . . . . . . .196
14.13 Dispatch and Billing Rules During Energy
Shortages . . . . . . . . . . . . . . . . . . .197
14.14 Congestion Uplift.. . . . . . . . . . . . . . .197
14.15 Additional Uplift Charges. . . . . . . . . . .202
PART FOUR - TRANSMISSION PROVISIONS. . . . . . . . . . . . . .203
SECTION 15 - OPERATION OF TRANSMISSION FACILITIES. . . . . . .203
15.1 Definition of PTF. . . . . . . . . . . . . . . . . .203
15.2 Maintenance and Operation in Accordance with Good
Utility Practice . . . . . . . . . . . . . . . . . .207
15.3 Central Dispatch . . . . . . . . . . . . . . . . . .207
15.4 Maintenance and Repair . . . . . . . . . . . . . . .207
15.5 Additions to or Upgrades of PTF. . . . . . . . . . .208
SECTION 16 - SERVICE UNDER TARIFF. . . . . . . . . . . . . . .211
16.1 Effect of Tariff . . . . . . . . . . . . . . . . . .211
16.2 Obligation to Provide Regional Service . . . . . . .211
16.3 Obligation to Provide Local Network Service. . . . .212
16.4 Transmission Service Availability. . . . . . . . . .215
16.5 Transmission Information . . . . . . . . . . . . . .215
16.6 Distribution of Transmission Revenues. . . . . . . .216
16.7 Changes to Tariff. . . . . . . . . . . . . . . . . .219
SECTION 17 - POOL-PLANNED UNIT SERVICE . . . . . . . . . . . .220
17.1 Effective Period . . . . . . . . . . . . . . . . . .220
17.2 Obligation to Provide Service. . . . . . . . . . . .220
17.3 Rules for Determination of Facilities Covered by
Particular Transactions. . . . . . . . . . . . . . .221
17.4 Payments for Uses of EHV PTF During the
Transition Period. . . . . . . . . . . . . . . . . .223
17.5 Payments for Uses of Lower Voltage PTF . . . . . . .228
17.6 Use of Other Transmission Facilities by
Participants . . . . . . . . . . . . . . . . . . . .228
17.7 Limits on Individual Transmission Charges. . . . . .229
PART FIVE - GENERAL. . . . . . . . . . . . . . . . . . . . . .230
SECTION 18 - GENERATION AND TRANSMISSION FACILITIES. . . . . .230
18.1 Designation of Pool-Planned Facilities . . . . . . .230
18.2 Construction of Facilities . . . . . . . . . . . . .231
18.3 Protective Devices for Transmission Facilities and
Automatic Generation Control Equipment . . . . . . .231
18.4 Review of Participant's Proposed Plans . . . . . . .232
18.5 Participant to Avoid Adverse Effect. . . . . . . . .233
SECTION 19 - EXPENSES. . . . . . . . . . . . . . . . . . . . .235
19.1 Annual Fee . . . . . . . . . . . . . . . . . . . . .235
19.2 NEPOOL Expenses. . . . . . . . . . . . . . . . . . .235
SECTION 20 - INDEPENDENT SYSTEM OPERATOR . . . . . . . . . . .236
SECTION 21 - MISCELLANEOUS PROVISIONS. . . . . . . . . . . . .242
21.1 Alternative Dispute Resolution . . . . . . . . . . .242
21.2 Payment of Pool Charges; Termination of Status as
Participant. . . . . . . . . . . . . . . . . . . . .255
21.3 Assignment . . . . . . . . . . . . . . . . . . . . .259
21.4 Force Majeure. . . . . . . . . . . . . . . . . . . .260
21.5 Waiver of Defaults . . . . . . . . . . . . . . . . .261
21.6 Other Contracts. . . . . . . . . . . . . . . . . . .261
21.7 Liability and Insurance. . . . . . . . . . . . . . .262
21.8 Records and Information. . . . . . . . . . . . . . .263
21.9 Consistency with NPCC and NERC Standards . . . . . .264
21.10 Construction. . . . . . . . . . . . . . . . . .264
21.11 Amendment . . . . . . . . . . . . . . . . . . .264
21.12 Termination . . . . . . . . . . . . . . . . . .267
21.13 Notices to Participants . . . . . . . . . . . .267
21.14 Severability and Renegotiation. . . . . . . . .269
21.15 No Third-Party Beneficiaries. . . . . . . . . .270
21.16 Counterparts. . . . . . . . . . . . . . . . . .270
<PAGE>
RESTATED NEPOOL POWER POOL AGREEMENT
THIS AGREEMENT dated as of the first day of September, 1971, as amended,
was entered into by the signatories thereto for the establishment by them
of a bulk power pool to be known as NEPOOL and is restated by an amendment
dated as of July 20, 1998.
In consideration of the mutual agreements and undertakings herein, the
signatories hereby agree as follows:
PART ONE
INTRODUCTION
SECTION 1
DEFINITIONS
Whenever used in this Agreement, in either the singular or plural number,
the following terms shall have the following respective meanings (an
asterisk (*) indicates that the definition may be modified in certain cases
pursuant to Section 1.109):
1.1 ADJUSTED LOAD * (not less than zero) of a Participant during any
particular hour is the Participant's Load during such hour less any
Kilowatts received (or Kilowatts which would have been received except
for the application of Section 14.7(b)) by such Participant pursuant
to a Firm Contract.
1.2 ADJUSTED MONTHLY PEAK of a Participant for a month is its Monthly
Peak, provided that if there has been a transfer between Participants,
in whole or part, of the responsibilities under this Agreement during
such month pursuant to a Firm Contract, the Adjusted Monthly Peak of
each such Participant shall reflect the effect of such transaction,
but the Adjusted Monthly Peak of a Participant shall not be changed
from the Monthly Peak to reflect the effect of any other transaction.
1.3 ADJUSTED NET INTERCHANGE of a Participant for an hour is (a) the
Kilowatts produced by or delivered to the Participant from its Energy
Entitlements or pursuant to arrangements entered into under Section
14.6, as adjusted in accordance with uniform market operation rules
approved by the Regional Market Operations Committee to take account
of associated electrical losses, as appropriate, MINUS (b) the sum of
(i) the Electrical Load of the Participant for the hour, and (ii) the
kilowatthours delivered by such Participant to other Participants
pursuant to Firm Contracts or System Contracts, in accordance with the
treatment agreed to pursuant to Section 14.7(a), together with any
associated electrical losses.
1.4 AGC CAPABILITY of an electric generating unit or combination of
units is the maximum dependable ability of the unit or units to
increase or decrease the level of output within a time frame specified
by market operation rules approved by the Regional Market Operations
Committee, in response to a remote direction from the System Operator
in order to maintain currently proper power flows into and out of the
NEPOOL Control Area and to control frequency.
1.5 AGC ENTITLEMENT is (a) the right to all or a portion of the AGC
Capability of a generating unit or combination of units to which an
Entity is entitled as an owner (either sole or in common) or as a
purchaser, REDUCED BY (b) any portion thereof which such Entity is
selling pursuant to a Unit Contract, and (c) further REDUCED OR
INCREASED, as appropriate, to recognize rights to receive or
obligations to supply AGC pursuant to Firm Contracts or System
Contracts in accordance with Section 14.7(a). An AGC Entitlement in a
generating unit or units may, but need not, be combined with any other
Entitlements relating to such generating unit or units and may be
transferred separately from the related Installed Capability
Entitlement, Operable Capability Entitlement, Energy Entitlement, or
Operating Reserve Entitlements.
1.6 AGREEMENT is this restated contract and attachments, including the
Tariff, as amended and restated from time to time.
1.7 ANNUAL TRANSMISSION REVENUE REQUIREMENTS of a Participant's PTF or
of all Participants' PTF for purposes of this Agreement are the
amounts determined in accordance with Attachment F to the Tariff.
1.8 AUTOMATIC GENERATION CONTROL OR AGC is a measure of the ability of a
generating unit or portion thereof to respond automatically within a
specified time to a remote direction from the System Operator to
increase or decrease the level of output in order to control frequency
and to maintain currently proper power flows into and out of the
NEPOOL Control Area.
1.9 BID PRICE is the amount which a Participant offers to accept, in a
notice furnished to the System Operator by it or on its behalf in
accordance with the market operation rules approved by the Regional
Market Operations Committee, as compensation for (i) furnishing
Installed Capability or Operable Capability to other Participants
pursuant to this Agreement, or (ii) preparing the start up or starting
up or increasing the level of operation of, and thereafter operating,
a generating unit or units to provide Energy to other Participants
pursuant to this Agreement, or (iii) having a unit or units available
to provide Operating Reserve to other Participants pursuant to this
Agreement, or (iv) having a unit or units available to provide AGC to
other Participants pursuant to this Agreement, or (v) providing to
other Participants Installed Capability, Operable Capability, Energy,
Operating Reserve and/or AGC pursuant to a Firm Contract or System
Contract in accordance with Section 14.7.
1.10 COMMISSION is the Federal Energy Regulatory Commission.
1.11 CONTROL AREA is an electric power system or combination of electric
power systems to which a common automatic generation control scheme is
applied in order to:
(l) match, at all times, the power output of the generators
within the electric power system(s) and capacity and energy
purchased from entities outside the electric power
system(s), with the load within the electric power
system(s);
(2) maintain scheduled interchange with other Control Areas,
within the limits of Good Utility Practice;
(3) maintain the frequency of the electric power system(s)
within reasonable limits in accordance with Good Utility
Practice and the criteria of the applicable regional
reliability council or the North American Electric
Reliability Council; and
(4) provide sufficient generating capacity to maintain operating
reserves in accordance with Good Utility Practice.
1.12 CURTAILMENT is a reduction in firm or non-firm transmission service
in response to a transmission capacity shortage as a result of system
reliability conditions.
1.13 DIRECT ASSIGNMENT FACILITIES are facilities or portions of
facilities that are Non-PTF and are constructed for the sole
use/benefit of a particular Transmission Customer requesting service
under the Tariff or Generator Owner or Interconnection Requester
requesting an interconnection. Direct Assignment Facilities shall be
specified in a separate agreement with the Transmission Provider whose
transmission system is to be modified to include and/or interconnect
with said Facilities, shall be subject to applicable Commission
requirements and shall be paid for by the Transmission Customer or a
Generator Owner or Interconnection Requester in accordance with the
separate agreement and not under the Tariff.
1.14 DISPATCH PRICE of a generating unit or combination of units, or a
Firm Contract or System Contract permitted to be bid to supply Energy
in accordance with Section 14.7(b), is the price to provide Energy
from the unit or units or Contract, as determined pursuant to market
operation rules approved by the Regional Market Operations Committee
to incorporate the Bid Price for such Energy and any loss adjustments,
if and as appropriate under such market operation rules.
1.15 EHV PTF are PTF transmission lines which are operated at 230 kV or
above and related PTF facilities, including transformers which link
other EHV PTF facilities, but do not include transformers which step
down from 230 kV or a higher voltage to a voltage below 230 kV.
1.16 ELECTRICAL LOAD (in Kilowatts) of a Participant during any
particular hour is the total during such hour (eliminating any
distortion arising out of (i) Interchange Transactions, or (ii)
transactions across the system of such Participant, or (iii)
deliveries between Entities constituting a single Participant, or (iv)
other electrical losses, if and as appropriate), of
(a) kilowatthours provided by such Participant to its retail
customers for consumption, PLUS
(b) kilowatthours of use by such Participant, PLUS
(c) kilowatthours of electrical losses and unaccounted for use
by the Participant on its system, PLUS
(d) kilowatthours used by such Participant for pumping Energy
for its Entitlements in pumped storage hydroelectric
generating facilities, PLUS
(e) kilowatthours delivered by such Participant to Non-
Participants.
The Electrical Load of a Participant may be calculated in any
reasonable manner which substantially complies with this definition.
1.17 ELIGIBLE CUSTOMER is the following: (i) Any Participant that is
engaged, or proposes to engage, in the wholesale or retail electric
power business is an Eligible Customer under the Tariff. (ii) Any
electric utility (including any power marketer), Federal power
marketing agency, or any person generating electric energy for sale or
for resale is an Eligible Customer under the Tariff. Electric energy
sold or produced by such entity may be electric energy produced in the
United States, Canada or Mexico. However, with respect to
transmission service that the Commission is prohibited from ordering
by Section 212(h) of the Federal Power Act, such entity is eligible
only if the service is provided pursuant to a state requirement that
the Transmission Provider with which that entity is directly
interconnected offer the unbundled transmission service, or pursuant
to a voluntary offer of such service by the Transmission Provider with
which that entity is directly interconnected. (iii) Any end user
taking or eligible to take unbundled transmission service pursuant to
a state requirement that the Transmission Provider with which that end
user is directly interconnected offer the transmission service, or
pursuant to a voluntary offer of such service by the Transmission
Provider, is an Eligible Customer under the Tariff.
1.18 ENERGY is power produced in the form of electricity, measured in
kilowatthours or megawatthours.
1.19 ENERGY ENTITLEMENT is (i) a right to receive Energy under a System
Contract or a Firm Contract in accordance with Section 14.7(a), or
(ii) a right to receive all or a portion of the electric output of a
generating unit or units to which an Entity is entitled as an owner
(either sole or in common) or as a purchaser pursuant to a Unit
Contract, REDUCED BY (iii) any portion thereof which such Entity is
selling pursuant to a Unit Contract. An Energy Entitlement in a
generating unit or units may, but need not, be combined with any other
Entitlements relating to such generating unit or units and may be
transferred separately from the related Installed Capability
Entitlement, Operable Capability Entitlement, Operating Reserve
Entitlements, or AGC Entitlement.
1.20 ENTITLEMENT is an Installed Capability Entitlement, Operable
Capability Entitlement, Energy Entitlement, Operating Reserve
Entitlement, or AGC Entitlement. When used in the plural form, it may
be any or all such Entitlements or combinations thereof, as the
context requires.
1.21 ENTITY is any person or organization whether the United States of
America or Canada or a state or province or a political subdivision
thereof or a duly established agency of any of them, a private
corporation, a partnership, an individual, an electric cooperative or
any other person or organization recognized in law as capable of
owning property and contracting with respect thereto that is either:
(a) engaged in the electric power business (the
generation and/or transmission and/or distribution
of electricity for consumption by the public or
the purchase, as a principal or broker, of
Installed Capability, Operable Capability, Energy,
Operating Reserve, and/or AGC for resale); or
(b) an end user of electricity that is taking or eligible to
take unbundled transmission service pursuant to an effective
state requirement that the Participant that is the
Transmission Provider with which that end user is directly
interconnected offer the transmission service, or pursuant
to a voluntary offer of unbundled transmission service to
that end user by the Participant that is the Transmission
Provider with which that end user is directly
interconnected.
1.22 EXCEPTED TRANSACTION is a transaction specified in Section 25 of
the Tariff for the applicable period specified in that Section.
1.23 EXECUTIVE COMMITTEE is the committee established pursuant to
Section 7.
1.24 FACILITIES STUDY is an engineering study conducted pursuant to this
Agreement or the Tariff by the System Operator and/or one or more
affected Participants to determine the required modifications to the
NEPOOL Transmission System, including the cost and scheduled
completion date for such modifications, that will be required to
provide a requested transmission service or interconnection.
1.25 FIRM CONTRACT is any contract, other than a Unit Contract, for the
purchase of Installed Capability, Operable Capability, Energy,
Operating Reserves, and/or AGC, pursuant to which the purchaser's
right to receive such Installed Capability, Operable Capability,
Energy, Operating Reserves, and/or AGC is subject only to the
supplier's inability to make deliveries thereunder as the result of
events beyond the supplier's reasonable control.
1.26 FIRST EFFECTIVE DATE is March 1, 1997.
1.27 GOOD UTILITY PRACTICE shall mean any of the practices, methods, and
acts engaged in or approved by a significant portion of the electric
utility industry during the relevant time period, or any of the
practices, methods, and acts which, in the exercise of reasonable
judgement in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired result at a
reasonable cost consistent with good business practices, reliability,
safety and expedition. Good Utility Practice is not limited to a
single, optimum practice, method or act to the exclusion of others,
but rather is intended to include acceptable practices, methods, or
acts generally accepted in the region.
1.28 HQ CONTRACTS are the HQ Interconnection Agreement, the HQ Phase I
Energy Contract, and the HQ Phase II Firm Energy Contract.
1.29 HQ ENERGY BANKING AGREEMENT is the Energy Banking Agreement entered
into on March 21, 1983 by Hydro-Quebec, the Participants, New England
Electric Transmission Corporation and Vermont Electric Transmission
Company, Inc., as it may be amended from time to time.
1.30 HQ INTERCONNECTION is the United States segment of the transmission
interconnection which connects the systems of Hydro-Quebec and the
Participants. "Phase I" is the United States portion of the 450 kV
HVDC transmission line from a terminal at the Des Cantons Substation
on the Hydro-Quebec system near Sherbrooke, Quebec to a terminal
having an approximate rating of 690 MW at a substation at the
Comerford Generating Station on the Connecticut River. "Phase II" is
the United States portion of the facilities required to increase to
approximately 2000 MW the transfer capacity of the HQ Interconnection,
including an extension of the HVDC transmission line from the terminus
of Phase I at the Comerford Station through New Hampshire to a
terminal at the Sandy Pond Substation in Massachusetts. The HQ
Interconnection does not include any PTF facilities installed or
modified to effect reinforcements of the New England AC transmission
system required in connection with the HVDC transmission line and
terminals.
1.31 HQ INTERCONNECTION AGREEMENT is the Interconnection Agreement
entered into on March 21, 1983 by Hydro-Quebec and the Participants,
as it may be amended from time to time.
1.32 HQ INTERCONNECTION CAPABILITY CREDIT of a Participant for a month
during the Base Term (as defined in Section 1.38) of the HQ Phase II
Firm Energy Contract is the sum in Kilowatts of (1)(a) the
Participant's percentage share, if any, of the HQ Phase I Transfer
Capability TIMES (b) the HQ Phase I Transfer Credit, PLUS (2)(a) the
Participant's percentage share, if any, of the HQ Phase II Transfer
Capability, TIMES (b) the HQ Phase II Transfer Credit. The Management
Committee shall establish appropriate HQ Interconnection Capability
Credits to apply for a Participant which has such a percentage share
(i) during an extension of the HQ Phase II Firm Energy Contract, and
(ii) following the expiration of the HQ Phase II Firm Energy Contract.
1.33 HQ INTERCONNECTION TRANSFER CAPABILITY is the transfer capacity of
the HQ Interconnection under normal operating conditions, as
determined in accordance with Good Utility Practice. The "HQ Phase I
Transfer Capability" is the transfer capacity under normal operating
conditions, as determined in accordance with Good Utility Practice, of
the Phase I terminal facilities as determined initially as of the time
immediately prior to Phase II of the Interconnection first being
placed in service, and as adjusted thereafter only to take into
account changes in the transfer capacity which are independent of any
effect of Phase II on the operation of Phase I. The "HQ Phase II
Transfer Capability" is the difference between the HQ Interconnection
Transfer Capability and the HQ Phase I Transfer Capability.
Determinations of, and any adjustment in, transfer capacity shall be
made by the Regional Market Operations Committee in accordance with a
schedule consistent with that followed by it in its determination of
the Winter Capability and Summer Capability of generating units.
1.34 HQ NET INTERCONNECTION CAPABILITY CREDIT of a Participant at a
particular time is its HQ Interconnection Capability Credit at the
time in Kilowatts, MINUS a number of Kilowatts EQUAL TO (1) the
percentage of its share of the HQ Interconnection Transfer Capability
committed or used by it for an "Entitlement Transaction" at the time
under the HQ Use Agreement, TIMES (2) its HQ Interconnection
Capability Credit for the current month.
1.35 HQ PHASE I ENERGY CONTRACT is the Energy Contract entered into on
March 21, 1983 by Hydro-Quebec and the Participants, as it may be
amended from time to time.
1.36 HQ PHASE I PERCENTAGE is the percentage of the total HQ
Interconnection Transfer Capability represented by the HQ Phase I
Transfer Capability.
1.37 HQ PHASE I TRANSFER CREDIT is 60/69 of the HQ Phase I Transfer
Capability, or such other fraction of the HQ Phase I Transfer
Capability as the Management Committee may establish.
1.38 HQ PHASE II FIRM ENERGY CONTRACT is the Firm Energy Contract dated
as of October 14, 1985 between Hydro-Quebec and certain of the
Participants, as it may be amended from time to time. The "Base Term"
of the HQ Phase II Firm Energy Contract is the period commencing on
the date deliveries were first made under the Contract and ending on
August 31, 2000.
1.39 HQ PHASE II GROSS TRANSFER RESPONSIBILITY of a Participant for any
month during the Base Term of the HQ Phase II Firm Energy Contract (as
defined in Section 1.38) is the number in Kilowatts of (a) the
Participant's percentage share, if any, of the HQ Phase II Transfer
Capability for the month TIMES (b) the HQ Phase II Transfer Credit.
Following the Base Term of the HQ Phase II Firm Energy Contract, and
again following the expiration of the HQ Phase II Firm Energy
Contract, the Management Committee shall establish an appropriate HQ
Phase II Gross Transfer Responsibility that shall remain in effect
concurrently with the HQ Interconnection Capability Credit.
1.40 HQ PHASE II NET TRANSFER RESPONSIBILITY of a Participant for any
month is its HQ Phase II Gross Transfer Responsibility for the month
minus a number of Kilowatts EQUAL TO (1) the highest percentage of its
share of the HQ Interconnection Transfer Capability committed or used
by it on any day of the month for an "Entitlement Transaction" under
the HQ Use Agreement, TIMES (2) its HQ Phase II Gross Transfer
Responsibility for the month.
1.41 HQ PHASE II PERCENTAGE is the percentage of the total HQ
Interconnection Transfer Capability represented by the HQ Phase II
Transfer Capability.
1.42 HQ PHASE II TRANSFER CREDIT is 90/131 of the HQ Phase II Transfer
Capability, or such other fraction of the HQ Phase II Transfer
Capability as the Management Committee may establish.
1.43 HQ USE AGREEMENT is the Agreement with Respect to Use of Quebec
Interconnection dated as of December 1, 1981 among certain of the
Participants, as amended and restated as of September 1, 1985 and as
it may be further amended from time to time.
1.44 INSTALLED CAPABILITY of an electric generating unit or combination
of units during the Winter Period is the Winter Capability of such
unit or units and during the Summer Period is the Summer Capability of
such unit or units.
1.45 INSTALLED CAPABILITY ENTITLEMENT is (a) the right to all or a
portion of the Installed Capability of a generating unit or units to
which an Entity is entitled as an owner (either sole or in common) or
as a purchaser pursuant to a Unit Contract, (b) REDUCED BY any portion
thereof which such Entity is selling pursuant to a Unit Contract, and
(c) further REDUCED OR INCREASED, as appropriate, to recognize rights
to receive or obligations to supply Installed Capability pursuant to
Firm Contracts or System Contracts in accordance with Section 14.7(a).
An Installed Capability Entitlement relating to a unit or units may,
but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the
related Operable Capability Entitlement, Energy Entitlement, Operating
Reserve Entitlements, or AGC Entitlement.
1.46 INSTALLED CAPABILITY RESPONSIBILITY * of a Participant for any
month is the number of Kilowatts determined in accordance with Section
12.2.
1.47 INSTALLED SYSTEM CAPABILITY of a Participant at a particular time
is (1) the sum of such Participant's Installed Capability Entitlements
PLUS (2) its HQ Net Interconnection Capability Credit at the time.
1.48 INTERCHANGE TRANSACTIONS are transactions deemed to be effected
under Section 12 of the Prior NEPOOL Agreement prior to the Second
Effective Date, and transactions deemed to be effected under Section
14 of this Agreement on and after the Second Effective Date.
1.49 INTERNAL POINT-TO-POINT SERVICE is the transmission service by that
name provided pursuant to Section 19 of the Tariff.
1.50 INTERRUPTION is a reduction in non-firm transmission service due to
economic reasons pursuant to Section 28.7 of the Tariff, other than a
reduction which results from a failure to dispatch a generating
resource, including a contract, used in a transaction requiring In
Service or Through or Out Service which is out of merit order.
1.51 ISO is the Independent System Operator which is responsible for the
continued operation of the NEPOOL Control Area from the NEPOOL control
center and the administration of the Tariff, subject to regulation by
the Commission.
1.52 KILOWATT is a kilowatthour per hour.
1.53 LOAD * (in Kilowatts) of a Participant during any particular hour
is the total during such hour (eliminating any distortion arising out
of (i) Interchange Transactions, or (ii) transactions across the
system of such Participant, or (iii) deliveries between Entities
constituting a single Participant, or (iv) other electrical losses, if
and as appropriate) of
(a) kilowatthours provided by such Participant to its retail
customers for consumption (excluding any kilowatthours which
may be classified as interruptible under market operation
rules approved by the Regional Market Operations Committee),
PLUS
(b) kilowatthours delivered by such Participant pursuant to Firm
Contracts to its wholesale customers for resale, PLUS
(c) kilowatthours of use by such Participant, exclusive of use
by such Participant for the operation and maintenance of its
generating unit or units, PLUS
(d) kilowatthours of electrical losses and unaccounted for use
by the Participant on its system.
The Load of a Participant may be calculated in any reasonable manner
which substantially complies with this definition.
For the purposes of calculating a Participant's Annual Peak, Adjusted
Monthly Peak, Adjusted Annual Peak and Monthly Peak, the Load of a
Participant shall be adjusted to eliminate any distortions resulting
from voltage reductions. In addition, upon the request of any
Participant, the Regional Market Operations Committee shall make, or
supervise the making of, appropriate adjustments in the computation of
Load for the purposes of calculating any Participant's Annual Peak,
Adjusted Monthly Peak, Adjusted Annual Peak and Monthly Peak to
eliminate any distortions resulting from emergency load curtailments
which would significantly affect the Load of any Participant.
1.54 LOCAL NETWORK is the transmission facilities constituting a local
network identified on Attachment E to the Tariff, and any other local
network or change in the designation of a Local Network as a Local
Network which the Management Committee may designate or approve from
time to time. The Management Committee may not unreasonably withhold
approval of a request by a Participant that it effect such a change or
designation.
1.55 LOCAL NETWORK SERVICE is the service provided, under a separate
tariff or contract, by a Participant that is a Transmission Provider
to another Participant, or other entity connected to the Transmission
Provider's Local Network to permit the other Participant or entity to
efficiently and economically utilize its resources to serve its load.
1.56 LOWER VOLTAGE PTF are all PTF facilities other than EHV PTF.
1.57 MANAGEMENT COMMITTEE is the committee established pursuant to
Section 6.
1.58 MARKET RELIABILITY PLANNING COMMITTEE is the committee established
pursuant to Section 8.
1.59 MONTHLY PEAK of a Participant for a month is the maximum Adjusted
Load of the Participant during any hour in the month.
1.60 NEPOOL is the New England Power Pool, the power pool created under
and governed by this Agreement, and the Entities collectively
participating in the New England Power Pool as Participants.
1.61 NEPOOL CONTROL AREA is the integrated electric power system to
which a common Automatic Generation Control scheme and various
operating procedures are applied by or under the supervision of the
System Operator in order to:
(i) match, at all times, the power output of the generators
within the electric power system and capacity and Energy
purchased from entities outside the electric power system,
with the load within the electric power system;
(ii) maintain scheduled interchange with other interconnected
systems, within the limits of Good Utility Practice;
(iii)maintain the frequency of the electric power system within
reasonable limits in accordance with Good Utility Practice
and the criteria of the Northeast Power Coordinating Council
and the North American Electric Reliability Council; and
(iv) provide sufficient generating capacity to maintain operating
reserves in accordance with Good Utility Practice.
1.62 NEPOOL INSTALLED CAPABILITY at any particular time is the sum of
the Installed System Capabilities of all Participants at such time.
1.63 NEPOOL INSTALLED CAPABILITY RESPONSIBILITY for any month is the sum
of the Installed Capability Responsibilities of all Participants
during that month.
1.64 NEPOOL OBJECTIVE CAPABILITY for any year or period during a year is
the minimum NEPOOL Installed Capability, treating the reliability
benefits of the HQ Interconnection as Installed Capability, as
established by the Management Committee, required to be provided by
the Participants in aggregate for the period to meet the reliability
standards established by the Management Committee pursuant to Section
6.12.
1.65 NEW UNIT is an electric generating unit (including a unit or units
owned by a Non-Participant in which a Participant has an Entitlement
under a Unit Contract) first placed into commercial operation after
May 1, 1987 (or, in the case of a unit or units owned by a
Non-Participant, in which a Participant's Unit Contract Entitlement
became effective after May 1, 1987) and not listed on Exhibit B to the
Prior NEPOOL Agreement.
1.66 NON-PARTICIPANT is any entity which is not a Participant.
1.67 OPERABLE CAPABILITY of an electric generating unit or units in any
hour is the portion of the Installed Capability of the unit or units
which is operating or available to respond within an appropriate
period (as identified in market operation rules approved by the
Regional Market Operations Committee) to the System Operator's call to
meet the Energy and/or Operating Reserve and/or AGC requirements of
the NEPOOL Control Area during a Scheduled Dispatch Period or is
available to respond within an appropriate period to a schedule
submitted by a Participant for the hour in accordance with market
operation rules approved by the Regional Market Operations Committee.
1.68 OPERABLE CAPABILITY ENTITLEMENT is (a) the right to all or a
portion of the Operable Capability of a generating unit or units to
which an Entity is entitled as an owner (either sole or in common) or
as a purchaser pursuant to a Unit Contract, (b) REDUCED BY any portion
thereof which such Entity is selling pursuant to a Unit Contract, and
(c) further REDUCED OR INCREASED, as appropriate, to recognize rights
to receive or obligations to supply Operable Capability pursuant to
Firm Contracts or System Contracts in accordance with Section 14.7(a).
An Operable Capability Entitlement relating to a unit or units may,
but need not, be combined with any other Entitlements relating to such
generating unit or units, and may be transferred separately from the
related Installed Capability Entitlement, Energy Entitlement,
Operating Reserve Entitlements, or AGC Entitlement.
1.69 OPERABLE CAPABILITY REQUIREMENT of a Participant for any hour is
the number of Kilowatts determined in accordance with Section 12.3.
1.70 OPERABLE SYSTEM CAPABILITY of a Participant in any hour is the sum
of such Participant's Operable Capability Entitlements.
1.71 OPERATING RESERVE is any or a combination of 10-Minute Spinning
Reserve, 10-Minute Non-Spinning Reserve, and 30-Minute Operating
Reserve, as the context requires.
1.72 OPERATING RESERVE ENTITLEMENT is (a) the right to all or a portion
of the Operating Reserve of any category which can be provided by a
generating unit or units to which an Entity is entitled as an owner
(either sole or in common) or as a purchaser pursuant to a Unit
Contract, (b) REDUCED BY any portion thereof which such Entity is
selling pursuant to a Unit Contract, and (c) further REDUCED OR
INCREASED, as appropriate, to recognize rights to receive or
obligations to supply Operating Reserve of that category pursuant to
Firm Contracts or System Contracts in accordance with Section 14.7(a).
An Operating Reserve Entitlement in any category relating to a
generating unit or units may, but need not, be combined with any other
Entitlements relating to such generating unit or units and may be
transferred separately from the other categories of Operating Reserve
Entitlements related to such unit or units and from the related
Installed Capability Entitlement, Operable Capability Entitlement,
Energy Entitlement, or AGC Entitlement.
1.73 OTHER HQ ENERGY is Energy purchased under the HQ Phase I Energy
Contract which is classified as "Other Energy" under that contract.
1.74 PARTICIPANT is an eligible Entity (or group of Entities which has
elected to be treated as a single Participant pursuant to Section 4.1)
which is a signatory to this Agreement and has become a Participant in
accordance with Section 3.1 until such time as such Entity's status as
a Participant terminates pursuant to Section 21.2.
1.75 POOL-PLANNED FACILITY is a generation or transmission facility
designated as "pool-planned" pursuant to Section 18.1.
1.76 POOL-PLANNED UNIT is one of the following units: New Haven Harbor
Unit 1 (Coke Works), Mystic Unit 7, Canal Unit 2, Potter Unit 2, Wyman
Unit 4, Stony Brook Units 1, 1A, 1B, 1C, 2A and 2B, Millstone Unit 3,
Seabrook Unit 1 and Waters River Unit 2 (to the extent of 7 megawatts
of its Summer Capability and 12 megawatts of its Winter Capability).
1.77 POWER YEAR is the period of twelve months commencing on November 1.
1.78 PRIOR NEPOOL AGREEMENT is the NEPOOL Agreement as in effect on
December 1, 1996.
1.79 PROXY UNIT is a hypothetical electric generating unit which
possesses a Winter Capability, equivalent forced outage rate, annual
maintenance outage requirement, and seasonal derating determined in
accordance with Section 12.2(a)(2).
1.80 PTF are the pool transmission facilities defined in Section 15.1,
and any other new transmission facilities which the Regional
Transmission Planning Committee determines, in accordance with
criteria approved by the Management Committee and subject to review by
the System Operator, should be included in PTF.
1.81 REGIONAL MARKET OPERATIONS COMMITTEE is the committee established
pursuant to Section 10.
1.82 REGIONAL NETWORK SERVICE is the transmission service by that name
provided pursuant to Section 14 of the Tariff.
1.83 REGIONAL TRANSMISSION OPERATIONS COMMITTEE is the committee
established pursuant to Section 11.
1.84 REGIONAL TRANSMISSION PLANNING COMMITTEE is the committee
established pursuant to Section 9.
1.85 RELATED PERSON of a Participant is either (i) a corporation,
partnership, business trust or other business organization 10% or more
of the stock or equity interest in which is owned directly or
indirectly by, or is under common control with, the Participant, or
(ii) a corporation, partnership, business trust or other business
organization which owns directly or indirectly 10% or more of the
stock or other equity interest in the Participant, or (iii) a
corporation, partnership, business trust or other business
organization 10% or more of the stock or other equity interest in
which is owned directly or indirectly by a corporation, partnership,
business trust or other business organization which also owns 10% or
more of the stock or other equity interest in the Participant.
1.86 SCHEDULED DISPATCH PERIOD is the shortest period for which the
System Operator performs and publishes a projected dispatch schedule
based on projected Electrical Loads and actual Bid Prices and
Participant-directed schedules for resources submitted in accordance
with Section 14.2(d).
1.87 SECOND EFFECTIVE DATE is the date on which the provisions of Part
Three of the Agreement (other than the Installed Capability
Responsibility provisions of Section 12) shall become effective and
shall be such date as the Commission may fix on its own or pursuant to
a request of the Management Committee.
1.88 SERVICE AGREEMENT is the initial agreement and any amendments or
supplements thereto entered into by the Transmission Customer and the
System Operator for service under the Tariff.
1.89 SUMMER CAPABILITY of an electric generating unit or combination of
units is the maximum dependable load carrying ability in Kilowatts of
such unit or units (exclusive of capacity required for station use)
during the Summer Period, as determined by the Regional Market
Operations Committee in accordance with Section 10.13(f).
1.90 SUMMER PERIOD in each Power Year is the four-month period from June
through September.
1.91 SYSTEM CONTRACT is any contract for the purchase of Installed
Capability, Operable Capability, Energy, Operating Reserves and/or
AGC, other than a Unit Contract or Firm Contract, pursuant to which
the purchaser is entitled to a specifically determined or determinable
amount of such Installed Capability, Operable Capability, Energy,
Operating Reserves and/or AGC.
1.92 SYSTEM IMPACT STUDY is an assessment pursuant to Part V, VI or VII
of the Tariff of (i) the adequacy of the NEPOOL Transmission System to
accommodate a request for the interconnection of a new or materially
changed generating unit or a new or materially changed interconnection
to another Control Area or new Regional Network Service, Internal
Point-to-Point Service or Through or Out Service, and (ii) whether any
additional costs may be required to be incurred in order to provide
the interconnection or transmission service.
1.93 SYSTEM OPERATOR is the central dispatching agency provided for in
this Agreement which has responsibility for the operation of the
NEPOOL Control Area from the NEPOOL control center and the
administration of the Tariff. The System Operator is the ISO.
1.94 TARGET AVAILABILITY RATE is the assumed availability of a type of
generating unit utilized by the Management Committee in its
determination pursuant to Section 6.14(e) of NEPOOL Objective
Capability.
1.95 TARIFF is the NEPOOL Open Access Transmission Tariff set out in
Attachment B to the Agreement, as modified and amended from time to
time.
1.96 THIRD EFFECTIVE DATE is the date on which all Interchange
Transactions shall begin to be effected on the basis of separate Bid
Prices for each type of Entitlement. The Third Effective Date shall
be fixed at the discretion of the Management Committee to occur within
six months to one year after the Second Effective Date, or at such
later date as the Commission may fix on its own or pursuant to a
request by the Management Committee.
1.97 THROUGH OR OUT SERVICE is the transmission service by that name
provided pursuant to Section 18 of the Tariff.
1.98 TRANSITION PERIOD is the five-year period commencing on March 1,
1997.
1.99 TRANSMISSION CUSTOMER is any Eligible Customer that (i) is a
Participant which is not required to sign a Service Agreement with
respect to a service to be furnished to it in accordance with Section
48 of the Tariff or (ii) executes, on its own behalf or through its
Designated Agent, a Service Agreement, or (iii) requests in writing,
on its own behalf or through its Designated Agent, that NEPOOL file
with the Commission a proposed unexecuted Service Agreement in order
that the Eligible Customer may receive transmission service under the
Tariff.
1.100TRANSMISSION PROVIDER is the Participants, collectively, which own
PTF and are in the business of providing transmission service or
provide service under a local open access transmission tariff, or in
the case of a municipal Participant, would be required to do so if
requested pursuant to the reciprocity requirements specified in the
Tariff, or an individual such Participant, whichever is appropriate.
1.101UNIT CONTRACT is a purchase contract pursuant to which the
purchaser is in effect currently entitled either (i) to a specifically
determined or determinable portion of the Installed Capability of a
specific electric generating unit or units, or (ii) to a specifically
determined or determinable amount of Operable Capability, Energy,
Operating Reserves and/or AGC if, or to the extent that, a specific
electric generating unit or units is or can be operated.
1.102VOTING SHARE has the meaning specified in Section 6.3.
1.103WINTER CAPABILITY of an electric generating unit or combination of
units is the maximum dependable load carrying ability in Kilowatts of
such unit or units (exclusive of capacity required for station use)
during the Winter Period, as determined by the Regional Market
Operations Committee in accordance with Section 10.13(f).
1.104WINTER PERIOD in each Power Year is the seven-month period from
November through May and the month of October.
1.10510-MINUTE SPINNING RESERVE in an hour are the following resources
that are designated by the System Operator in accordance with market
operation rules, as approved by the Regional Market Operations
Committee, to be available to provide contingency protection for the
system: (1) the Kilowatts of Operable Capability of an electric
generating unit or units that are synchronized to the system, unloaded
during all or part of the hour, and capable of providing contingency
protection by loading to supply Energy immediately on demand,
increasing the Energy output over no more than ten minutes to the full
amount of generating capacity so designated, and sustaining such
Energy output for so long as the System Operator determines in
accordance with market operation rules approved by the Regional Market
Operations Committee is necessary; and (2) any portion of the
Electrical Load of a Participant that the System Operator is able to
verify as capable of providing contingency protection by immediately
on demand reducing Energy requirements within ten minutes and
maintaining such reduced Energy requirements for so long as the System
Operator determines in accordance with market operation rules approved
by the Regional Market Operations Committee is necessary.
1.10610-MINUTE NON-SPINNING RESERVE in an hour are the following
resources that are designated by the System Operator in accordance
with market operation rules, as approved by the Regional Market
Operations Committee, to be available to provide contingency
protection for the system: (1) the Kilowatts of Operable Capability of
an electric generating unit or units that are not synchronized to the
system, during all or part of the hour, and capable of providing
contingency protection by loading to supply Energy within ten minutes
to the full amount of generating capacity so designated, and
sustaining such Energy output for so long as the System Operator
determines in accordance with market operation rules approved by the
Regional Market Operations Committee is necessary; (2) any portion of
a Participant's Electrical Load that the System Operator is able to
verify as capable of providing contingency protection by reducing
Energy requirements within ten minutes and maintaining such reduced
Energy requirements for so long as the System Operator determines in
accordance with market operations rules approved by the Regional
Market Operations Committee is necessary; and (3) any other resources
and requirements that were able to be designated for the hour as 10-
Minute Spinning Reserve but were not designated by the System Operator
for such purpose in the hour.
1.10730-MINUTE OPERATING RESERVE in an hour are the following resources
that are designated by the System Operator in accordance with market
operation rules, as approved by the Regional Market Operations
Committee, to be available to provide contingency protection for the
system: (1) the Kilowatts of Operable Capability of an electric
generating unit or units that are capable of providing contingency
protection by loading to supply Energy within thirty minutes of demand
at an output EQUAL TO its full amount of generating capacity so
designated and sustaining such Energy output for so long as the System
Operator determines in accordance with market operation rules approved
by the Regional Market Operations Committee is necessary; (2) any
portion of the Electrical Load of a Participant that the System
Operator is able to verify as capable of providing contingency
protection by reducing Energy requirements within thirty minutes and
maintaining such reduced Energy requirements for so long as the System
Operator determines in accordance with market operation rules approved
by the Regional Market Operations Committee is necessary; and (3) any
other resources and requirements that were able to be designated for
the hour as 10-Minute Spinning Reserve or 10-Minute Non-Spinning
Reserve but were not designated by the System Operator for such
purposes in the hour.
1.10833RD AMENDMENT is the Thirty-Third Agreement Amending New England
Power Pool Agreement dated as of December 1, 1996.
1.109MODIFICATION OF CERTAIN DEFINITIONS WHEN A PARTICIPANT PURCHASES A
PORTION OF ITS REQUIREMENTS FROM ANOTHER PARTICIPANT PURSUANT TO FIRM
CONTRACT
Definitions marked by an asterisk (*) are modified as follows
when a Participant purchases a portion of its requirements of
electricity from another Participant pursuant to a Firm Contract:
(a) If the Firm Contract limits deliveries to a specifically
stated number of Kilowatts and requires payment of a demand
charge thereon (thus placing the responsibility for meeting
additional demands on the purchasing Participant):
(1) in computing the ADJUSTED LOAD of the purchasing
Participant, the Kilowatts received pursuant to such
Firm Contract shall be deemed to be the number of
Kilowatts specified in the Firm Contract; and
(2) in computing the LOAD of the supplying Participant, the
Kilowatts delivered pursuant to such Firm Contract
shall be deemed to be the number of Kilowatts specified
in the Firm Contract.
(b) If the Firm Contract does not limit deliveries to a
specifically stated number of Kilowatts, but entitles the
Participant to receive such amounts of electricity as it may
require to supply its electric needs (thus placing the
responsibility for meeting additional demands on the
supplying Participant):
(1) the INSTALLED CAPABILITY RESPONSIBILITY of the
purchasing Participant shall be EQUAL TO the amount of
its Installed Capability Entitlements;
(2) in computing the ADJUSTED LOAD of the purchasing
Participant, the Kilowatts received pursuant to such
Firm Contract shall be deemed to be a quantity R{l};
and
(3) in computing the LOAD of the supplying Participant, the
Kilowatts delivered pursuant to such Firm Contract
shall be deemed to be a quantity R{l}.
The quantity R{l} equals (i) the Load of the purchasing
Participant less (ii) the amount of the purchasing
Participant's Installed Capability Entitlements multiplied
by a fraction X wherein:
-
Y
X is the maximum Load of the purchasing Participant
in the month, and
Y is the NEPOOL Installed Capability Responsibility
multiplied by the purchasing Participant's
fraction P determined pursuant to Section
12.2(a)(1), computed as if the Firm Contract did
not exist.
Terms used in this Agreement that are not defined above, or in the
sections in which such terms are used, shall have the meanings
customarily attributed to such terms in the electric power industry in
New England.
SECTION 2
PURPOSE; EFFECTIVE DATES
2.1 PURPOSE. This Restated NEPOOL Agreement is intended to provide for
a restructuring of the New England Power Pool by modifying the pool's
governance and market provisions to take account of a changed
competitive environment, by modifying the transmission
responsibilities of the Participants so that the pool will perform the
functions of a regional transmission group and provide service to
Participants and Non-Participants under a regional open access
transmission tariff, and by providing for the activation of the ISO
and the execution of a contract between the ISO and NEPOOL to define
the ISO's responsibilities.
2.2 EFFECTIVE DATES; TRANSITIONAL PROVISIONS. The provisions of Parts
One, Two, Four and Five of this Agreement and the Tariff became
effective on the First Effective Date and replaced on the First
Effective Date the provisions of Sections 1-8, inclusive, 10, 11, 13,
14.2, 14.3, 14.4 and 16 of the Prior NEPOOL Agreement. The provisions
of Sections 12.1(a), 12.2, 12.4 (as to Installed Capability only),
12.5 and 12.7(a) of this Agreement became effective on April 1, 1998
and replaced on such date the provisions of Section 9 of the Prior
NEPOOL Agreement.
The effectiveness of the remaining Sections of this Restated NEPOOL
Agreement shall be delayed pending the preparation of implementing
criteria, rules and standards and computer programs. These Sections
shall become effective on the Second Effective Date and shall replace
on the Second Effective Date the remaining provisions of the Prior
NEPOOL Agreement, which shall continue in effect until the Second
Effective Date.
As provided in Section 14, certain portions of Section 14 which will
become effective on the Second Effective Date will be superseded on
the Third Effective Date by other portions of Section 14.
SECTION 3
MEMBERSHIP
3.1 MEMBERSHIP. Those Entities which are Participants in NEPOOL on the
First Effective Date shall continue to be Participants.
Any other Entity may, upon compliance with such reasonable conditions
as the Management Committee may prescribe, become a Participant by
depositing a counterpart of this Agreement as theretofore amended,
duly executed by it, with the Secretary of the Management Committee,
accompanied by a certified copy of a vote of its board of directors,
or such other body or bodies as may be appropriate, duly authorizing
its execution and performance of this Agreement, and a check in
payment of the application fee described below.
Any such Entity which satisfies the requirements of this Section 3.1
shall become a Participant, and this Agreement shall become fully
binding and effective in accordance with its terms as to such Entity,
as of the first day of the second calendar month following its
satisfaction of such requirements; provided that an earlier or later
effective time may be fixed by the Management Committee with the
concurrence of such Entity or by the Commission.
The application fee to be paid by each Entity seeking to become a
Participant shall be in addition to the annual fee provided by Section
19.1 and shall be $500 or such other amount as may be fixed by the
Management Committee.
3.2 OPERATIONS OUTSIDE THE CONTROL AREA. Subject to the reciprocity
requirements of the Tariff, if a Participant serves a Load, or has
rights in supply or demand-side resources or owns transmission and/or
distribution facilities, located outside of the NEPOOL Control Area,
such Load and resources shall not be included for purposes of
determining the Participant's rights, responsibilities and obligations
under this Agreement, except that the Participant's Entitlements in
facilities or its rights in demand side-resources outside the NEPOOL
Control Area shall be included in such determinations if, to the
extent, and while such Entitlements are used for retail or wholesale
sales within the NEPOOL Control Area or such Entitlements or rights
are designated by a Participant for purposes of meeting its
obligations under Section 12 of this Agreement.
3.3 LACK OF PLACE OF BUSINESS IN NEW ENGLAND. If and for so long as a
Participant does not have a place of business located in one of the
New England states, the Participant shall be deemed to irrevocably (1)
submit to the jurisdiction of any Connecticut state court or United
States Federal court sitting in Connecticut (the state whose laws
govern this Agreement) over any action or proceeding arising out of or
relating to this Agreement that is not subject to the exclusive
jurisdiction of the Commission, (2) agree that all claims with respect
to such action or proceeding may be heard and determined in such
Connecticut state court or Federal court, (3) waive any objection to
venue or any action or proceeding in Connecticut on the basis of FORUM
NON CONVENIENS, and (4) agree that service of process may be made on
the Participant outside Connecticut by certified mail, postage
prepaid, mailed to the Participant at the address of its member on the
Management Committee as set out in the NEPOOL roster or at the address
of its principal place of business.
3.4 OBLIGATION FOR DEFERRED EXPENSES. NEPOOL may provide for the
deferral on the books of the Participants from time to time of capital
or other expenditures, and the recovery of the deferred expenses in
subsequent periods. Any Entity which becomes a Participant during the
recovery period for any such deferred expenses shall be obligated,
together with the continuing Participants, for its share of the
current and deferred expenses pursuant to Section 19.2.
3.5 FINANCIAL SECURITY. For an Entity applying to become a Participant
or any continuing Participant that the Management Committee reasonably
determines may fail to meet its financial obligations under the
Agreement, the Management Committee may require reasonable credit
review procedures which shall be made in accordance with standard
commercial practices. In addition, the Management Committee may
prescribe for such Entity or Participant a requirement that the Entity
or Participant provide and maintain in effect an irrevocable letter of
credit as security to meet its responsibilities and obligations under
the Agreement, or an alternative form of security proposed by the
Entity or Participant and acceptable to the Management Committee and
consistent with commercial practices established by the Uniform
Commercial Code that protects the Participants against the risk of
non-payment.
SECTION 4
STATUS OF PARTICIPANTS
4.1 TREATMENT OF CERTAIN ENTITIES AS SINGLE PARTICIPANT. All Entities
which are controlled by a single person (such as a corporation or a
business trust) which owns at least seventy-five percent of the voting
shares of, or equity interest in, each of them shall be collectively
treated as a single Participant for purposes of this Agreement, if
they each elect such treatment. They are encouraged to do so. Such
an election shall be made in writing and shall continue in effect
until revoked in writing.
In view of the long-standing arrangements in Vermont, Vermont Electric
Power Company, Inc. and any other Vermont electric utilities which
elect in writing to be grouped with it shall be collectively treated
as a single Participant for purposes of this Agreement.
4.2 PARTICIPANTS TO RETAIN SEPARATE IDENTITIES. The signatories to this
Agreement shall not become partners by reason of this Agreement or
their activities hereunder, but as to each other and to third persons,
they shall be and remain independent contractors in all matters
relating to this Agreement. This Agreement shall not be construed to
create any liability on the part of any signatory to anyone not a
party to this Agreement. Each signatory shall retain its separate
identity and, to the extent not limited hereby, its individual freedom
in rendering service to its customers.
SECTION 5
NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS
5.1 NEPOOL OBJECTIVES. The objectives of NEPOOL are, through joint
planning, central dispatching, cooperation in environmental matters
and coordinated construction, central dispatch by the System Operator
of the operation and coordinated maintenance of electric supply and
demand-side resources and transmission facilities, the provision of an
open access regional transmission tariff and the provision of a means
for effective coordination with other power pools and utilities
situated in the United States and Canada,
(a) to assure that the bulk power supply of the NEPOOL Control
Area conforms to proper standards of reliability;
(b) to create and maintain open, non-discriminatory,
competitive, unbundled markets for Energy, capacity, and
ancillary services that function efficiently in a changing
electric power industry and have access to regional
transmission at rates that do not vary with distance;
(c) to attain maximum practicable economy, consistent with
proper standards of reliability and the maintenance of
competitive markets, in such bulk power supply; and
(d) to provide access to competitive markets within the NEPOOL
Control Area and to neighboring regions;
and to provide for equitable sharing of the resulting
responsibilities, benefits and costs.
5.2 COOPERATION BY PARTICIPANTS. In order to attain the objectives of
NEPOOL set forth in Section 5.1, each Participant shall observe the
provisions of this Agreement in good faith, shall cooperate with all
other Participants and shall not either alone or in conjunction with
one or more other Entities take advantage of the provisions of this
Agreement so as to harm another Participant or to prejudice the
position of any Participant in the electric power business.
Until the Second Effective Date, in order to assure the equitable
sharing among the Participants of the benefits contemplated by this
Agreement, no Participant shall participate, except pursuant to this
Agreement, in any transaction with one or more other Participants or
other Entities if such transaction involves an economy interchange
arrangement. The foregoing restriction shall not, however, apply to
an economy interchange or other similar arrangement between or among a
Participant and one or more Entities which are not Participants if,
and to the extent that, such arrangement is consistent with attainment
of the objectives stated in Section 5.1 and with the Participant's
obligations under this Agreement.
PART TWO
GOVERNANCE
SECTION 6
MANAGEMENT COMMITTEE
6.1 MEMBERSHIP. There shall be a Management Committee which shall be
constituted as follows: each Participant shall appoint and be
represented by one member of the Management Committee.
6.2 TERM OF MEMBERS. Each member of the Management Committee shall hold
office until such member is replaced by the Participant which
appointed the member or until such Participant ceases to be a
Participant. Replacement of a member shall be effected by delivery by
a Participant of written notice of such replacement to the Secretary
of the Management Committee.
6.3 VOTES. Each member of the Management Committee shall have a Voting
Share in any month entitling the member to cast, on behalf of the
Participant which the member represents, votes representing the
percentage to which the member's Participant is entitled of the
aggregate Voting Shares of all Participants for the month. The
percentage of the aggregate Voting Shares of all Participants to which
a Participant is entitled in any month shall be determined in
accordance with the following formula:
V= .15833 ( P ) + .15833 ( E ) + .15833 ( C ) + .15833 ( X )
--- --- --- ---
P{1} E{1} C{1} X{1}
+ .15833 ( M ) + .15833 ( R ) + .05 ( Y )
--- --- ---
M{1} R{1} Y{1}
in which
V = the Participant's Voting Share as a percentage of the
aggregate Voting Shares of all Participants;
P = the average for each of the most recently completed twelve
months of the Participant's maximum Load during any clock
hour in a month;
P{1} = the average of the sums for each of the most recently
completed twelve months of the noncoincidental maximum Load
during any clock hour in a month of all Participants;
E = the average for the most recently completed twelve months of
the sum for each month of the Participant's Load for each
hour of the month PLUS any kilowatthours delivered during
the month to loads classified as interruptible under market
operation rules approved by the Regional Market Operations
Committee;
E{1} = the average for the most recently completed twelve months of
the sum for each month of the Loads of all Participants for
each hour of the month PLUS any kilowatthours delivered
during the month to loads classified as interruptible under
market operation rules approved by the Regional Market
Operations Committee.
C = the average in megawatts for the most recently completed
twelve months of the sum for each month of the Generation
Ownership Shares, as defined in this Section, of the
Participant;
C{1} = the average in megawatts for the most recently completed
twelve months of the sum for each month of the Generation
Ownership Shares of all Participants;
X = the average for the most recently completed twelve months of
the sum for each month of (i) a number of kilowatthours
EQUAL TO the Kilowatts of the Participant's Generation
Ownership Shares, TIMES the number of hours in the month,
PLUS (ii) the number of kilowatthours that the Participant
was entitled to receive in each hour with respect to its
Energy Entitlements under Unit Contracts or System Contracts
TIMES, in the case of each contract, the number of hours the
contract was in effect in the month, as computed without
giving effect to any resale in whole or part of any such
Energy Entitlement;
X{1} = the average for the most recently completed twelve months of the
sum for each month of (i) a number of kilowatthours EQUAL TO the
Kilowatts of the Generation Ownership Shares of all Participants,
TIMES the number of hours in the month, PLUS (ii) the number of
kilowatthours that all Participants were entitled to receive in
each hour with respect to their Energy Entitlements under Unit
Contracts or System Contracts TIMES, in the case of each
contract, the number of hours the contract was in effect in the
month, as computed without giving effect to any resale in whole
or part of any such Energy Entitlement;
M = the circuit miles of the Participant's Transmission
Ownership Shares, as defined in this Section, of PTF
transmission lines TIMES, in the case of each line, the
nominal operating voltage of the line;
M{1} = the aggregate of the circuit miles of the Transmission
Ownership Shares of PTF transmission lines of all
Participants TIMES, in the case of each line, the nominal
operating voltage of the line;
R = the Annual Transmission Revenue Requirements of the
Participant's PTF as of the beginning of the current
calendar year as determined in accordance with Attachment F
to the Tariff except that 1) such Revenue Requirements shall
not be reduced by the transmission support revenue received
as described in Section I of that Attachment and 2) such
Revenue Requirements shall not include transmission support
payments as described in Section J of that Attachment for
support arrangements which were entered into after December
31, 1996;
R{1} = the aggregate Annual Transmission Revenue Requirements of
the PTF of all Participants as of the beginning of the
current calendar year as determined in accordance with
Attachment F to the Tariff, except that 1) such Revenue
Requirements shall not be reduced by the transmission
support revenue received as described in Section I of that
Attachment and 2) such Revenue Requirements shall not
include transmission support payments as described in
Section J of that Attachment for support arrangements which
were entered into after December 31, 1996;
Y = 1; and
Y{1} = the number of NEPOOL Participants at the beginning of the
month;
PROVIDED, HOWEVER, that a Participant and its Related Persons may not have
aggregate Voting Shares exceeding 25% of the aggregate Voting Shares to
which all Participants are entitled. If the aggregate Voting Shares of a
Participant and its Related Persons would be in excess of 25% if it were
not for this limitation, the remaining Voting Shares to which such
Participant and its Related Persons would otherwise be entitled shall be
allocated to the other Participants on a pro rata basis.
For purposes of the preceding formula (i) if an Entity has been a
Participant for less than twelve months, the amounts to be taken into
account for purposes of "P", "E", "C" and "X" in the formula shall be for
the period during which the Entity has been a Participant; (ii) for
purposes of "X" and "X{1}" in the formula, the number of kilowatthours to
be taken into account with respect to the HQ Phase II Firm Energy Contract
for each Participant which has a share in the HQ Phase II Firm Energy
Contract shall be computed on the basis of the number of Kilowatts of its
HQ Interconnection Capability Credit, if any, for the month; and (iii) for
purposes of "X" and "X{1}" in the formula, the number of kilowatthours to
be taken into account with respect to an Energy Entitlement under a Unit
Contract or System Contract, other than the HQ Phase II Firm Energy
Contract, under which a Participant is entitled to receive Energy from
outside the NEPOOL Control Area shall be computed on the basis of the
number of Kilowatts of Installed Capability credit, or Monthly Peak
reduction, for which the Participant is given credit in determining whether
it has satisfied its Installed Capability Responsibility pursuant to
Section 12.
In the event a Participant both participates in the wholesale bulk power
market and owns PTF, the member appointed by the Participant shall be
entitled to divide the member's vote, as determined in accordance with this
Section, on any matter on the basis specified by it in a notice given to
the Secretary of the Management Committee at or prior to the meeting at
which the vote is to be cast, to reflect its market and transmission
interests. In such case the portion of the member's vote reflecting its
transmission interest may be cast by the member's alternate.
For purposes of this Section, the Generation Ownership Shares of a
Participant means and includes:
(A) the direct ownership interest which the Participant has as a sole
or joint owner in the Installed Capability of a generating unit
which is subject to NEPOOL central dispatch in accordance with
Section 13.2;
(B) the indirect ownership interest which the Participant has, as a
shareholder in Vermont Yankee Nuclear Power Corporation or a
similar corporation, or as a general or limited partner in Ocean
State Power or a similar partnership, in the Installed Capability
of a generating unit which is subject to NEPOOL central dispatch
in accordance with Section 13.2, provided the corporation or
partnership is itself not a Participant;
(C) any other interest which the Participant has in the Installed
Capability of a generating unit which is subject to NEPOOL
central dispatch in accordance with Section 13.2, under a lease
or other contractual arrangement, provided the other party to the
arrangement is itself not a Participant and the Management
Committee determines, at the request of the affected Participant,
that the Participant has benefits and rights, and assumes risks,
under the arrangement with respect to the unit which are
substantially equivalent to the benefits, rights and risks of an
owner; and
(D) an interest which the Participant shall be deemed to have in the
direct ownership interest, or the indirect ownership interest as
a shareholder or general or limited partner, of a Related Person
of the Participant in the Installed Capability of a generating
unit which is subject to NEPOOL central dispatch in accordance
with Section 13.2, provided the Related Person is itself not a
Participant.
For purposes of this Section, the Transmission Ownership Shares of a
Participant means and includes:
(W) the direct ownership interest which the Participant has as a sole
or joint owner of PTF;
(X) the indirect ownership interest which the Participant has, as a
shareholder in a corporation, or as a general or limited partner
in a partnership, in PTF owned by such corporation or
partnership, provided the corporation or partnership is not
itself a Participant;
(Y) any other interest which the Participant has in PTF under a lease
or other contractual arrangement, provided the other party to the
arrangement is not itself a Participant and the Management
Committee determines, at the request of the affected Participant,
that the Participant has benefits and rights, and assumes risks,
under the arrangement with respect to the PTF which are
substantially equivalent to the benefits, rights and risks of an
owner; and
(Z) an interest which the Participant shall be deemed to have in the
direct ownership interest, or the indirect ownership interest as
a shareholder or general or limited partner, of a Related Person
of the Participant in PTF, provided the Related Person is itself
not a Participant.
6.4 NUMBER OF VOTES NECESSARY FOR ACTION. Actions of the Management
Committee shall be effected only upon an affirmative vote of members
having at least 66% of the aggregate Voting Shares to which all
members are entitled; PROVIDED, HOWEVER, that the negative votes of
any three or more members representing Participants which are not
Related Persons of each other and which have at least 20% of the
aggregate Voting Shares to which all members are entitled shall defeat
any proposed action. In determining whether the negative vote total
specified above has been reached, the following limitation shall be
applied: if the member or members representing any Participant and
its Related Persons would be entitled to cast against the proposed
action more than 18% of the aggregate Voting Shares to which all
members are entitled, such member or members shall be entitled to vote
negatively only 18% of such aggregate Voting Shares.
6.5 PROXIES. The vote of any member of the Management Committee or the
member's alternate may be cast by another person pursuant to a written
proxy dated not more than one year previous to the meeting and
delivered to the Secretary of the Management Committee at or prior to
the meeting at which the proxy vote is cast.
6.6 ALTERNATES. A Participant may designate, by a written notice
delivered to the Secretary of the Management Committee, an alternate
for a member of the Management Committee appointed by it. In the
absence of the member, the alternate shall have all the powers of the
member, including the power to vote.
6.7 OFFICERS. At its annual meeting, the Management Committee shall
elect from among its members a Chair and a Vice-Chair; it shall also
elect a Secretary who need not be a member. These officers shall have
the powers and duties usually incident to such offices.
6.8 MEETINGS. The Management Committee shall hold its annual meeting in
December at such time and place as the Chair shall designate and shall
hold other meetings in accordance with a schedule adopted by the
Management Committee or at the call of the Chair. One or more members
who represent Participants having in the aggregate at least 3% of the
aggregate Voting Shares of all Participants may call a special meeting
of the Management Committee in the event that the Chair shall fail to
call such a meeting within three business days following the Chair's
receipt from such member or members of a request specifying the
subject matters to be acted upon at the meeting.
6.9 NOTICE OF MEETINGS. Written notice of each meeting of the
Management Committee shall be given to each member not less than five
business days prior to the date of the meeting, which notice shall
specify the principal subject matter expected to be acted upon at the
meeting.
6.10 ADOPTION OF BUDGETS. At each annual meeting, the Management
Committee shall adopt a NEPOOL budget for the ensuing calendar year.
In adopting budgets the Management Committee shall give due
consideration to the budgetary requests of each committee and shall
include the budget of the ISO as determined in accordance with
NEPOOL's contract between NEPOOL and the ISO. The Management
Committee may modify any NEPOOL budget from time to time after its
adoption and shall modify the NEPOOL budget if and as required to
support changes to the ISO budget adopted in accordance with the
contract between NEPOOL and the ISO.
6.11 ADOPTION OF BYLAWS. The Management Committee may adopt bylaws,
consistent with this Agreement, governing procedural matters including
the conduct of its meetings and those of the other committees.
6.12 ESTABLISHING RELIABILITY STANDARDS. It shall be the duty of the
Management Committee, after review of reports or actions of the System
Operator and the Market Reliability Planning Committee and Regional
Transmission Planning Committee and such other matters as the
Management Committee deems pertinent, to establish or approve proper
standards of reliability for the bulk power supply of NEPOOL. Such
standards shall be consistent with the directives of the North
American Electric Reliability Council and the Northeast Power
Coordinating Council and shall be reviewed periodically by the
Management Committee and revised as the Management Committee deems
appropriate.
6.13 APPOINTMENT AND COMPENSATION OF NEPOOL PERSONNEL. The Management
Committee shall determine what personnel are desirable for the
effective operation and administration of NEPOOL and shall fix or
authorize the fixing of the compensation for such persons.
6.14 DUTIES AND AUTHORITY.
(a) The Management Committee shall have the duty and requisite
authority to administer, enforce and interpret the
provisions of this Agreement in order to accomplish the
objectives of NEPOOL including the making of any decision or
determination necessary under any provision of this
Agreement and not expressly specified to be decided or
determined by any other body.
(b) The Management Committee shall have the authority to provide
for such facilities, materials and supplies as the
Management Committee may determine are necessary or
desirable to carry out the provisions of this Agreement.
(c) The Management Committee shall have, in addition to the
authority provided in Section 6.12, the authority, after
consultation with other NEPOOL committees and the System
Operator, to establish or approve consistent standards with
respect to any aspect of arrangements between Participants
and Non-Participants which it determines may adversely
affect the reliability of NEPOOL, and to review such
arrangements to determine compliance with such standards.
(d) The Management Committee, or its designee, shall have the
authority to act on behalf of all Participants in carrying
out any action properly taken pursuant to the provisions of
this Agreement. Without limiting the foregoing general
authority, the Management Committee, or its designee, shall
have the authority on behalf of all Participants to execute
any contract, lease or other instrument which has been
properly authorized pursuant to this Agreement including,
but not limited to, one or more contracts with the ISO, and
to file with the Commission and other appropriate regulatory
bodies: (i) this Agreement and documents amending or
supplementing this Agreement, including the Tariff, (ii)
contracts with Non-Participants or the ISO, and (iii)
related tariffs, rate schedules and certificates of
concurrence. The Management Committee shall, in addition,
have the authority to represent NEPOOL in proceedings before
the Commission.
(e) The Management Committee shall have the duty and requisite
authority, after consultation with other NEPOOL committees
and the System Operator, to fix the NEPOOL Objective
Capability for each month of each Power Year prior to the
beginning of the Power Year and thereafter to review at
least annually the anticipated Load of the NEPOOL
Participants and NEPOOL Installed Capability for each month
of such Power Year and to make such adjustments in the
NEPOOL Objective Capability as the Management Committee may
determine on the basis of such review. Since changes in the
circumstances which must be assumed by the Management
Committee in fixing NEPOOL Objective Capability for a future
period can significantly affect the required level of NEPOOL
Objective Capability for that period, the Management
Committee shall, where appropriate, also determine the
effect on NEPOOL Objective Capability of significant changes
in circumstances from those assumed, either by fixing
alternative NEPOOL Objective Capabilities, or by adopting
adjustment factors or formulas.
(f) The Management Committee shall have the duty and requisite
authority to establish or approve schedules fixing the
amounts to be paid by Participants and Non-Participants to
permit the recovery of expenses incurred in furnishing some
or all of the services furnished by NEPOOL either directly
or through the System Operator.
(g) The Management Committee shall have the duty and requisite
authority to provide for the sharing by Participants, on
such basis as the Management Committee may deem appropriate,
of payments and costs which are not otherwise reimbursed
under this Agreement and which are incurred by Participants
or under arrangements with Non-Participants and approved or
authorized by the Committee as necessary in order to meet or
avoid short-term deficiencies in the amount of resources
available to meet the pool's reliability objectives.
(h) The Management Committee shall have the authority, at the
time that it acts on an Entity's application pursuant to
Section 3.1 to become a Participant, to waive, conditionally
or unconditionally, compliance by such Entity with one or
more of the obligations imposed by this Agreement if the
Management Committee determines that such compliance would
be unnecessary or inappropriate for such Entity and the
waiver for such Entity will not impose an additional burden
on other Participants.
(i) Until the Second Effective Date, the Management Committee
shall have the duty and requisite authority to determine
which generating facilities should be equipped for Automatic
Generation Control in order to maintain proper frequency for
the interconnected bulk power system of the Participants and
to control power flows on interconnections between
Participants and non-Participants. The Management Committee
shall establish a system for sharing by the Participants
until the Second Effective Date, on such basis as the
Committee may deem appropriate, of the costs, including loss
of generator efficiency, that are incurred by Participants
in installing, maintaining and operating Automatic
Generation Control equipment required by the Committee and
are not otherwise reimbursed under this Agreement.
(j) The Management Committee shall have the duty and requisite
authority to act on appeals to it from the actions of other
NEPOOL committees and to appoint a special committee to
administer NEPOOL's alternate dispute resolution procedures
or to take any other action if it determines that such
action is necessary or appropriate to achieve a prompt
resolution of disputes under the provisions of Section 21.1.
(k) The Management Committee shall have such further powers and
duties as are conferred or imposed upon it by other sections
of this Agreement.
6.15 ATTENDANCE OF MEMBERS OF MANAGEMENT COMMITTEE AT OTHER COMMITTEE
MEETINGS. Each member of the Management Committee or that member's
designee shall be entitled to attend any meeting of any other NEPOOL
committee, and shall have a reasonable opportunity to express views on
any matter to be acted upon at the meeting.
SECTION 7
EXECUTIVE COMMITTEE
7.1 ORGANIZATION. There shall be an Executive Committee which shall
have all the powers and duties of the Management Committee (except as
provided below), subject to appeal to the Management Committee
pursuant to the provisions of Section 7.11. Between meetings of the
Management Committee, the Executive Committee shall exercise the
powers and perform the duties of the Management Committee. The
Executive Committee shall not have any of the powers or duties of the
Management Committee under Sections 6.7 and 6.10, except that the
Executive Committee shall have the power of the Management Committee
to modify from time to time an overall NEPOOL annual budget adopted by
the Management Committee, subject to the limitation that the aggregate
amount of net increase in an overall budget which may be effected by
the Executive Committee for any year shall not exceed 10% of the
budget initially adopted by the Management Committee.
7.2 MEMBERSHIP. The Executive Committee shall be constituted as
follows: the ISO shall have the right to appoint a non-voting member
of the Committee; each Participant whose Voting Share equals or
exceeds 3% of the aggregate Voting Shares of all Participants shall
have the right to appoint a voting member of the Committee; the
remaining Participants whose Voting Shares are less than 3% of the
aggregate Voting Shares of all Participants shall be divided into the
following five groups, with each having the right to appoint one
voting member of the Committee:
(a) One group consisting of the remaining Participants
which are municipally-owned and cooperatively-owned
utilities;
(b) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL Control
Area principally in the business of owning or operating
generation facilities and selling the output of such
generation;
(c) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL Control
Area principally in a business other than the business
of owning or operating generation or PTF facilities and
selling the output of such generation;
(d) One group consisting of the remaining Participants, if
any, which (i) own PTF, (ii) are not engaged in
electric generation or distribution and do not
participate in the wholesale bulk power market, and
(iii) are not Related Persons of any other Participant;
and
(e) One group consisting of the remaining Participants
which are investor-owned utilities subject to
traditional rate regulation or other Entities which do
not qualify to be included in any of the other four
groups.
Notwithstanding the foregoing, any such Participant may elect to join
a different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any Participant is a Related Person
of another Participant which has the individual right to appoint a
member of the Committee on the basis of its individual Voting Share,
the Participant shall be represented on the Committee by the member
appointed by the Participant which is its Related Person and shall not
be assigned to any of the five groups.
7.3 TERM OF MEMBERS. The member of the Executive Committee appointed by
the ISO shall serve until replaced by the ISO. Members of the
Executive Committee appointed by a Participant or group of
Participants shall serve until replaced by the Participant or
Participants which appointed them or until such Participant or
Participants shall lose their status as Participants or otherwise lose
their right to appoint the member. Appointment or replacement of a
member shall be effected by the ISO or a Participant or group of
Participants by giving written notice of such appointment or
replacement to the Secretary of the Executive Committee.
7.4 ALTERNATES. The ISO or a Participant or group of Participants may
designate, by a written notice given to the Secretary of the Executive
Committee, an alternate for any member of the Executive Committee
appointed by the ISO or such Participant or group of Participants. In
the absence of the member, the alternate shall have all the powers of
the member, including the power to vote.
7.5 VOTES. Each voting member of the Executive Committee shall have one
vote, which may be cast in person by the member or the member's
alternate or by another person pursuant to a written proxy dated not
more than one year previous to the meeting and delivered to the
Secretary of the Executive Committee at or prior to the meeting at
which the proxy vote is cast. If a Participant which has the
individual right to appoint a member of the Executive Committee both
participates in the wholesale bulk power market and owns PTF, the
member appointed by the Participant shall be entitled to divide the
member's vote on the basis specified in a notice given by it to the
Secretary of the Committee at or prior to the meeting at which the
vote is to be cast, to reflect the Participant's market and
transmission interests. In such case the portion of the Participant
member's vote reflecting its transmission interest may be cast by the
member's alternate.
A voting member appointed by a group may divide the member's vote on
the basis specified in a notice given by it to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect the different positions of the members of the group.
7.6 NUMBER OF VOTES NECESSARY FOR ACTION. The adoption of actions by
the Executive Committee shall require affirmative votes by voting
members aggregating at least 60% of the number of votes which the
voting members in attendance at a meeting at which a quorum is present
are entitled to cast. A majority of the voting members at any time
shall constitute a quorum.
7.7 OFFICERS. At its annual meeting, the Executive Committee shall
elect from its voting members a Chair and a Vice-Chair; it shall also
elect a Secretary who need not be a member. These officers shall have
the powers and duties usually incident to such offices.
7.8 MEETINGS. The Executive Committee shall hold its annual meeting in
December or January at such time and place as the Chair shall
designate and shall hold other meetings in accordance with a schedule
adopted by the Executive Committee or at the call of the Chair. Any
two members may call a special meeting of the Executive Committee in
the event that the Chair shall fail to call such a meeting within
three business days following the Chair's receipt from such members of
a request specifying the subject matters to be acted upon at the
meeting. Any regular or special meeting of the Executive Committee
may be conducted by means of conference telephone or other
communications equipment by means of which all persons participating
in the meeting can hear each other.
7.9 NOTICE OF MEETINGS. Written notice of each meeting of the Executive
Committee shall be given to each member of the Committee and each
member of the Management Committee not less than three business days
prior to the date of the meeting. The notice shall specify the
principal subject matter expected to be acted upon at the meeting.
7.10 NOTICE TO MEMBERS OF MANAGEMENT COMMITTEE OF ACTIONS BY EXECUTIVE
COMMITTEE. Prior to the end of the fifth business day following a
meeting of the Executive Committee, the Secretary of the Executive
Committee shall give written notice to the ISO and each member of the
Management Committee of any action taken by the Executive Committee at
such meeting.
7.11 APPEAL OF ACTIONS TO MANAGEMENT COMMITTEE. The ISO or any
Participant may appeal to the Management Committee any action taken by
the Executive Committee. Such an appeal shall be taken prior to the
end of the tenth business day following the meeting of the Executive
Committee to which the appeal relates by giving to the Secretary of
the Management Committee a signed and written notice of appeal and by
mailing a copy of the notice to the ISO and each member of the
Management Committee. Pending action on the appeal by the Management
Committee, the giving of a notice of appeal as aforesaid shall suspend
the action appealed from.
SECTION 8
MARKET RELIABILITY PLANNING COMMITTEE
8.1 ORGANIZATION. There shall be a Market Reliability Planning
Committee which shall have the responsibilities specified in Section
8.11. It may provide from time to time for the creation of one or
more Functional Planning Committees to act in particular functional
planning areas and to exercise such of the Market Reliability Planning
Committee's responsibilities as it may delegate to them.
8.2 MEMBERSHIP. The Market Reliability Planning Committee shall be
constituted as follows: the ISO shall have the right to appoint a
non-voting member of the Committee; each Participant whose Voting
Share equals or exceeds 3% of the aggregate Voting Shares of all
Participants shall have the right to appoint a voting member of the
Committee; the remaining Participants shall be divided into the
following five groups, with each having the right to appoint one
voting member of the Committee:
(a) One group consisting of the remaining Participants which are
municipally-owned and cooperatively-owned utilities;
(b) One group consisting of the remaining Participants which are
not subject to traditional utility rate regulation and which
are engaged in the NEPOOL Control Area principally in the
business of owning or operating generation facilities and
selling the output of such generation;
(c) One group consisting of the remaining Participants which are
not subject to traditional utility rate regulation and which
are engaged in the NEPOOL Control Area principally in a
business other than the business of owning or operating
generation or PTF facilities and selling the output of such
generation;
(d) One group consisting of the remaining Participants, if any,
which (i) own PTF, (ii) are not engaged in electric
generation or distribution and do not participate in the
wholesale bulk power market, and (iii) are not Related
Persons of any other Participant; and
(e) One group consisting of the remaining Participants which are
investor-owned utilities subject to traditional rate
regulation or other Entities which do not qualify to be
included in any of the other four groups.
Notwithstanding the foregoing, any such Participant may elect to join
a different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any Participant is a Related Person
of another Participant which has the individual right to appoint a
member of the Committee, the Participant shall be represented in the
Committee by the member appointed by the Participant which is its
Related Person and shall not be assigned to any of the five groups.
8.3 TERM OF MEMBERS. The member of the Market Reliability Planning
Committee appointed by the ISO shall serve until replaced by the ISO.
Members of the Market Reliability Planning Committee appointed by a
Participant or group of Participants shall serve until replaced by the
Participant or Participants which appointed them or until such
Participant or Participants cease to be Participants or otherwise lose
their right to appoint the member. Appointment or replacement of a
member shall be effected by the ISO or a Participant or group of
Participants by giving written notice of such appointment or
replacement to the Secretary of the Market Reliability Planning
Committee.
8.4 VOTING. Each voting member of the Market Reliability Planning
Committee shall have one vote which may be cast in person by the
member or the member's alternate or by another person pursuant to a
written proxy dated not more than one year previous to the meeting and
delivered to the Secretary of the Market Reliability Planning
Committee at or prior to the meeting at which the proxy vote is cast.
If a Participant which has the individual right to appoint a voting
member of the Market Reliability Planning Committee both participates
in the wholesale bulk power market and owns PTF, the member appointed
by the Participant shall be entitled to divide the member's vote on
the basis specified in a notice given by it to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect the Participant's market and transmission interests. In
such case the portion of the member's vote reflecting its transmission
interest may be cast by the member's alternate.
The voting member appointed by a group may divide the member's vote on
the basis specified in a notice given by it to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect the different positions of the members of the group.
The adoption of actions by the Market Reliability Planning Committee
shall require affirmative votes by voting members aggregating at least
60% of the number of votes which the members in attendance at a
meeting at which a quorum is present are entitled to cast. A majority
of the voting members at any time shall constitute a quorum.
8.5 ALTERNATES. The ISO or a Participant or group of Participants may
designate, by a written notice given to the Secretary of the Market
Reliability Planning Committee, an alternate for the member of the
Market Reliability Planning Committee appointed by the ISO or such
Participant or group of Participants. In the absence of the member,
the alternate shall have all the powers of the member, including the
power to vote.
8.6 OFFICERS. At its annual meeting, the Market Reliability Planning
Committee shall elect from its voting members a Chair and a Vice-
Chair; it shall also elect a Secretary who need not be a member of the
Committee. These officers shall have the powers and duties usually
incident to such offices.
8.7 MEETINGS. The Market Reliability Planning Committee shall hold its
annual meeting in December or January at such time and place as the
Chair shall designate and shall hold other meetings in accordance with
a schedule adopted by the Committee or at the call of the Chair. Any
two members may call a special meeting of the Market Reliability
Planning Committee in the event that the Chair shall fail to call such
a meeting within three business days following the Chair's receipt
from such members of a request specifying the subject matters to be
considered at the meeting. Any regular or special meeting of the
Market Reliability Planning Committee may be conducted by means of
conference telephone or other communications equipment by means of
which all persons participating in the meeting can hear each other.
8.8 NOTICE OF MEETINGS. Written notice of each meeting of the Market
Reliability Planning Committee shall be given to each member not less
than five business days prior to the date of the meeting. The
principal subject matter expected to be acted upon at a meeting shall
be specified in the notice of the meeting whenever the meeting is not
held in accordance with the schedule adopted by the Committee.
8.9 NOTICE TO MEMBERS OF MANAGEMENT COMMITTEE. Prior to the end of the
fifth business day following a meeting of the Market Reliability
Planning Committee, the Secretary of the Market Reliability Planning
Committee shall give written notice to the ISO and each member of the
Management Committee of any action taken by the Market Reliability
Planning Committee at such meeting.
8.10 APPEAL OF ACTIONS TO MANAGEMENT COMMITTEE. The ISO or any
Participant may appeal to the Management Committee any action taken by
the Market Reliability Planning Committee. Such an appeal shall be
taken prior to the end of the tenth business day following the meeting
of the Market Reliability Planning Committee to which the appeal
relates by giving to the Secretary of the Management Committee a
signed and written notice of appeal and by mailing a copy of the
notice to the ISO and each member of the Management Committee.
Pending action on the appeal by the Management Committee, the giving
of a notice of appeal as aforesaid shall suspend the action appealed
from.
8.11 RESPONSIBILITIES. The Market Reliability Planning Committee shall
be responsible, either directly or through its Functional Planning
Committees, and in conjunction with the ISO and the Regional
Transmission Planning Committee, as appropriate, for the following:
(a) providing overall direction to, and coordination of, joint
studies of supply and demand-side resources and
environmental considerations in order to achieve the
objectives of NEPOOL;
(b) recommending to the Management Committee the NEPOOL
Objective Capability for each Power Year;
(c) periodically reviewing the procedures used to calculate
NEPOOL Installed Capability, NEPOOL Objective Capability and
NEPOOL Capability Responsibility;
(d) causing to be prepared periodic short and long term load
forecasts for use in NEPOOL studies and operations and to
meet requirements of regulatory agencies;
(e) overseeing communications and liaison between NEPOOL and
governmental authorities on power supply, environmental and
load forecasting issues;
(f) coordinating the collection and exchange of necessary system
data and future plans for use in NEPOOL planning and to meet
requirements of regulatory agencies;
(g) following appropriate studies, recommending to the
Management Committee reliability standards for the bulk
power system of NEPOOL; and
(h) coordinating the review of proposed supply and demand-side
resource plans of Participants pursuant to Section 18.4 and
the submission of recommendations to the Management
Committee regarding such proposed plans.
8.12 FUNCTIONAL PLANNING COMMITTEES. The Market Reliability Planning
Committee's Functional Planning Committees shall remain subject to
policy-level direction and control by the Market Reliability Planning
Committee. Functional Planning Committees may participate in joint
studies with each other and with other NEPOOL committees or task
forces, but shall submit reports and recommendations directly to the
Management Committee only pursuant to the request of the Market
Reliability Planning Committee.
The members of each Functional Planning Committee shall be appointed
in the same manner as the members of the Market Reliability Planning
Committee, and, if requested by the ISO, shall include a non-voting
member appointed by the ISO. The Chair, Vice-Chair and Secretary of
each Functional Planning Committee shall be appointed in accordance
with procedures specified by the Market Reliability Planning
Committee.
Except as expressly directed by the Market Reliability Planning
Committee, its Functional Planning Committees shall be study, research
and deliberative bodies and shall not resolve by vote differences of
opinion as to proposed plans or other matters on which they may make
reports or recommendations. Functional Planning Committees shall
regularly report the results of their work to the Market Reliability
Planning Committee, and whenever a Functional Planning Committee is
unable to reach a consensus resolution of a policy issue, that issue
shall be reported to the Market Reliability Planning Committee.
Functional Planning Committee reports shall contain such personal
opinions and conclusions as any member may request. Where a vote of a
Functional Planning Committee is required for election of officers or
other organizational matters, the action shall be effective only upon
an affirmative vote of 60% of the voting members present at the
meeting.
8.13 APPOINTMENT OF TASK FORCES. The Market Reliability Planning
Committee and its Functional Planning Committees shall have the
authority, within the Market Reliability Planning Committee's budget
or with the approval of the Management Committee if beyond its budget,
to appoint task forces for particular studies and to name thereto
available employees of Participants.
8.14 CONSULTANTS, COMPUTER TIME AND EXPENSES. The Market Reliability
Planning Committee and its Functional Planning Committees shall have
the authority, within the Market Reliability Planning Committee's
budget or with the approval of the Management Committee if beyond its
budget, to retain the services of the ISO, to hire other consultants,
to procure computer time and to incur such expenses as may be required
to enable the Market Reliability Planning Committee, its Functional
Planning Committees and their task forces properly to perform their
duties.
8.15 FURTHER POWERS AND DUTIES. The Market Reliability Planning
Committee shall have such further powers and duties as may be
prescribed by the Management Committee or as set forth in this
Agreement.
8.16 REPORTS TO MANAGEMENT COMMITTEE. The Market Reliability Planning
Committee shall report to the Management Committee periodically the
results of its work and such reports shall contain such alternative
programs as the Market Reliability Planning Committee may consider
appropriate. Market Reliability Planning Committee reports shall also
contain such minority opinions and conclusions as any member shall
request.
8.17 JOINT MEETINGS WITH REGIONAL TRANSMISSION PLANNING COMMITTEE. The
Market Reliability Planning Committee is authorized and encouraged to
hold its meetings, and to conduct studies and exercise its
responsibilities, jointly with the Regional Transmission Planning
Committee to the extent appropriate.
SECTION 9
REGIONAL TRANSMISSION PLANNING COMMITTEE
9.1 ORGANIZATION. There shall be a Regional Transmission Planning
Committee which shall have the responsibilities specified in Section
9.11. It may provide from time to time for the creation of one or
more Functional Planning Committees to act in particular functional
transmission planning areas and to exercise such of the Regional
Transmission Planning Committee's responsibilities as it may delegate
to them.
9.2 MEMBERSHIP. The Regional Transmission Planning Committee shall be
constituted as follows: the ISO shall have the right to appoint a
non-voting member of the Committee; each Participant whose Voting
Share equals or exceeds 3% of the aggregate Voting Shares of all
Participants shall have the right to appoint a voting member of the
Committee; the remaining Participants whose Voting Shares are less
than 3% of the aggregate Voting Shares of all Participants shall be
divided into the following five groups, with each having the right to
appoint one voting member of the Committee:
(a) One group consisting of the remaining Participants which are
municipally-owned and cooperatively-owned utilities;
(b) One group consisting of the remaining Participants which are
not subject to traditional utility rate regulation and which
are engaged in the NEPOOL Control Area principally in the
business of owning or operating generation facilities and
selling the output of such generation;
(c) One group consisting of the remaining Participants which are
not subject to traditional utility rate regulation and which
are engaged in the NEPOOL Control Area principally in a
business other than the business of owning or operating
generation or PTF facilities and selling the output of such
generation;
(d) One group consisting of the remaining Participants, if any,
which (i) own PTF, (ii) are not engaged in electric
generation or distribution and do not participate in the
wholesale bulk power market, and (iii) are not Related
Persons of any other Participant; and
(e) One group consisting of the remaining Participants which are
investor-owned utilities subject to traditional utility rate
regulation or other Entities which do not qualify to be
included in any of the other four groups.
Notwithstanding the foregoing, any such Participant may elect to join
a different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any Participant is a Related Person
of another Participant which has the individual right to appoint a
member of the Committee on the basis of its individual Voting Share,
the Participant shall be represented in the Committee by the member
appointed by the Participant which is its Related Person and shall not
be assigned to any of the five groups.
9.3 TERM OF MEMBERS. The member of the Regional Transmission Planning
Committee appointed by the ISO shall serve until replaced by the ISO.
Other members of the Regional Transmission Planning Committee shall
serve until replaced by the Participant or Participants which
appointed them or until such Participant or Participants shall lose
their status as Participants or otherwise lose their right to appoint
the member. Appointment or replacement of a member shall be effected
by the ISO or a Participant or group of Participants by giving written
notice of such appointment or replacement to the Secretary of the
Regional Transmission Planning Committee.
9.4 VOTING. Each voting member of the Regional Transmission Planning
Committee shall have one vote which may be cast in person by the
member or the member's alternate or by another person pursuant to a
written proxy dated not more than one year previous to the meeting and
delivered to the Secretary of the Regional Transmission Planning
Committee at or prior to the meeting at which the proxy vote is cast.
If a Participant which has the individual right to appoint a member of
the Regional Transmission Planning Committee both participates in the
wholesale bulk power market and owns PTF, the member appointed by the
Participant shall be entitled to divide the member's vote on the basis
specified in a notice given to the Secretary of the Committee at or
prior to the meeting at which the vote is to be cast, to reflect the
Participant's market and transmission interests. In such case the
portion of the member's vote reflecting its transmission interest may
be cast by the member's alternate.
The voting member appointed by a group may divide the member's vote on
the basis specified in a notice given to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect the different positions of the members of the group.
The adoption of actions by the Regional Transmission Planning
Committee shall require affirmative votes by voting members
aggregating at least 60% of the number of votes which the members in
attendance at a meeting at which a quorum is present are entitled to
cast. A majority of the voting members at any time shall constitute a
quorum.
9.5 ALTERNATES. The ISO, or a Participant or group of Participants may
designate, by a written notice given to the Secretary of the Regional
Transmission Planning Committee, an alternate for any member of the
Regional Transmission Planning Committee appointed by the ISO or such
Participant or group of Participants. In the absence of the member,
the alternate shall have all the powers of the member, including the
power to vote.
9.6 OFFICERS. At its annual meeting, the Regional Transmission Planning
Committee shall elect from its voting members a Chair and a Vice-
Chair; it shall also elect a Secretary who need not be a member of the
Committee. These officers shall have the powers and duties usually
incident to such offices.
9.7 MEETINGS. The Regional Transmission Planning Committee shall hold
its annual meeting in December or January at such time and place as
the Chair shall designate and shall hold other meetings in accordance
with a schedule adopted by the Committee or at the call of the Chair.
Any two members may call a special meeting of the Regional
Transmission Planning Committee in the event that the Chair shall fail
to call such a meeting within three business days following the
Chair's receipt from such members of a request specifying the subject
matters to be considered at the meeting. Any regular or special
meeting of the Regional Transmission Planning Committee may be
conducted by means of conference telephone or other communications
equipment by means of which all persons participating in the meeting
can hear each other.
9.8 NOTICE OF MEETINGS. Written notice of each meeting of the Regional
Transmission Planning Committee shall be given to each member not less
than five business days prior to the date of the meeting. The
principal subject matter expected to be acted upon at a meeting shall
be specified in the notice of the meeting whenever the meeting is not
held in accordance with the schedule adopted by the Committee.
9.9 NOTICE TO MEMBERS OF MANAGEMENT COMMITTEE. Prior to the end of the
fifth business day following a meeting of the Regional Transmission
Planning Committee, the Secretary of the Regional Transmission
Planning Committee shall give written notice to the ISO and each
member of the Management Committee of any action taken by the Regional
Transmission Planning Committee at such meeting.
9.10 APPEAL OF ACTIONS TO MANAGEMENT COMMITTEE. The ISO or any
Participant may appeal to the Management Committee any action taken by
the Regional Transmission Planning Committee. Such an appeal shall be
taken prior to the end of the tenth business day following the meeting
of the Regional Transmission Planning Committee to which the appeal
relates by giving to the Secretary of the Management Committee a
signed and written notice of appeal and by mailing a copy of the
notice to the ISO and each member of the Management Committee.
Pending action on the appeal by the Management Committee, the delivery
of a notice of appeal as aforesaid shall suspend the action appealed
from.
9.11 RESPONSIBILITIES. The Regional Transmission Planning Committee
shall be responsible, either directly or through Functional Planning
Committees, and in conjunction with the ISO and the Market Reliability
Planning Committee, as appropriate, for the following:
(a) providing overall direction to, and coordination of, joint
studies of transmission facilities and the development of a
regional transmission plan in order to achieve the
objectives of NEPOOL;
(b) overseeing communications and liaison between NEPOOL and
governmental authorities on transmission issues;
(c) coordinating the collection and exchange of necessary system
data and future plans for use in NEPOOL planning and to meet
requirements of regulatory agencies;
(d) following appropriate studies, recommending to the
Management Committee proposed reliability standards for the
bulk power system of NEPOOL;
(e) coordinating the review of proposed transmission plans of
Participants pursuant to Section 18.4 and the submission of
recommendations to the Management Committee regarding such
proposed plans; and
(f) to the extent appropriate, establishing criteria, guidelines
and methodologies to assure consistency in monitoring and
assessing conformance of Participant and regional
transmission plans to accepted reliability criteria.
9.12 FUNCTIONAL PLANNING COMMITTEES. The Regional Transmission Planning
Committee's Functional Planning Committees shall remain subject to
policy-level direction and control by the Regional Transmission
Planning Committee. Functional Planning Committees may participate in
joint studies with each other and with other NEPOOL committees or task
forces, but shall submit reports and recommendations directly to the
Management Committee only pursuant to the request of the Regional
Transmission Planning Committee.
The members of each Functional Planning Committee shall be appointed
in the same manner as the members of the Regional Transmission
Planning Committee, and, if requested by the ISO, shall include a non-
voting member appointed by the ISO. The Chair, Vice-Chair and
Secretary of each Functional Planning Committee shall be appointed in
accordance with procedures specified by the Regional Transmission
Planning Committee.
Except as expressly directed by the Regional Transmission Planning
Committee, its Functional Planning Committees shall be study, research
and deliberative bodies and shall not resolve by vote differences of
opinion as to proposed plans or other matters on which they may make
reports or recommendations. Functional Planning Committees shall
regularly report the results of their work to the Regional
Transmission Planning Committee, and whenever a Functional Planning
Committee is unable to reach a consensus resolution of a policy issue,
that issue shall be reported to the Regional Transmission Planning
Committee. Functional Planning Committee reports shall contain such
personal opinions and conclusions as any member may request. Where a
vote of a Functional Planning Committee is required for election of
officers or other organizational matters, the action shall be
effective only upon an affirmative vote of 60% of the voting members
present at a meeting.
9.13 APPOINTMENT OF TASK FORCES. The Regional Transmission Planning
Committee and its Functional Planning Committees shall have the
authority, within the Regional Transmission Planning Committee's
budget or with the approval of the Management Committee if beyond its
budget, to appoint task forces for particular studies and to name
thereto available employees of Participants.
9.14 CONSULTANTS, COMPUTER TIME AND EXPENSES. The Regional Transmission
Planning Committee and its Functional Planning Committees shall have
the authority, within the Regional Transmission Planning Committee's
budget or with the approval of the Management Committee if beyond its
budget, to retain the services of the ISO, to hire other consultants,
to procure computer time and to incur such expenses as may be required
to enable the Regional Transmission Planning Committee, its Functional
Planning Committees and their task forces properly to perform their
duties.
9.15 FURTHER POWERS AND DUTIES. The Regional Transmission Planning
Committee shall have such further powers and duties as may be
prescribed by the Management Committee or as set forth in this
Agreement.
9.16 REPORTS TO MANAGEMENT COMMITTEE. The Regional Transmission
Planning Committee shall report to the Management Committee
periodically the results of its work and such reports shall contain
such alternative programs as the Regional Transmission Planning
Committee may consider appropriate. Regional Transmission Planning
Committee reports shall also contain such minority opinions and
conclusions as any member shall request.
9.17 JOINT MEETINGS WITH MARKET RELIABILITY PLANNING COMMITTEE. The
Regional Transmission Planning Committee is authorized and encouraged
to hold its meetings, and to conduct studies and exercise its
responsibilities, jointly with the Market Reliability Planning
Committee to the extent appropriate.
SECTION 10
REGIONAL MARKET OPERATIONS COMMITTEE
10.1 ORGANIZATION. There shall be a Regional Market Operations Committee
which shall be responsible for establishing or approving market
operation rules and for monitoring the operation of NEPOOL supply and
demand-side resources and the wholesale bulk power market.
10.2 MEMBERSHIP. The Regional Market Operations Committee shall be
constituted as follows: the ISO shall have the right to appoint a
non-voting member of the Committee; each Participant whose Voting
Share equals or exceeds 3% of the aggregate Voting Shares of all
Participants shall have the right to appoint a voting member of the
Committee; the remaining Participants shall be divided into the
following five groups, with each having the right to appoint one
voting member of the Regional Market Operations Committee:
(a) One group consisting of the remaining Participants which are
municipally-owned and cooperatively-owned traditional
utilities;
(b) One group consisting of the remaining Participants which are
not subject to traditional utility rate regulation and which
are engaged in the NEPOOL Control Area principally in the
business of owning or operating generation facilities and
selling the output of such generation;
(c) One group consisting of the remaining Participants which are
not subject to traditional utility rate regulation and which
are engaged in the NEPOOL Control Area principally in a
business other than the business of owning or operating
generation or PTF facilities and selling the output of such
generation;
(d) One group consisting of the remaining Participants, if any,
which (i) own PTF, (ii) are not engaged in electric
generation or distribution and do not participate in the
wholesale bulk power market, and (iii) are not Related
Persons of any other Participant; and
(e) One group consisting of the remaining Participants which are
investor-owned utilities subject to traditional utility rate
regulation or other Entities which do not qualify to be
included in any of the other four groups.
Notwithstanding the foregoing, any such Participant may elect to join
a different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any such Participant is a Related
Person of another Participant which has the individual right to
appoint a member of the Committee, the Participant shall be
represented in the Committee by the member appointed by the
Participant which is its Related Person and shall not be assigned to
any of the five groups.
10.3 TERMS OF MEMBERS. The member of the Regional Market Operations
Committee appointed by the ISO shall serve until replaced by the ISO.
Other members of the Regional Market Operations Committee shall serve
until replaced by the Participant or Participants which appointed them
or until such Participant or Participants shall lose their status as
Participants or otherwise lose the right to appoint the member.
Appointment or replacement of a member shall be effected by the ISO or
a Participant or group of Participants giving written notice of such
appointment or replacement to the Secretary of the Regional Market
Operations Committee.
10.4 VOTING. Each voting member of the Regional Market Operations
Committee shall have one vote, which may be cast in person by the
member or the member's alternate or by another person pursuant to a
written proxy dated not more than one year previous to the meeting and
delivered to the Secretary of the Regional Market Operations Committee
at or prior to the meeting at which the proxy vote is cast. If a
Participant which has the individual right to appoint a member of the
Regional Market Operations Committee both participates in the
wholesale bulk power market and owns PTF, the member appointed by the
Participant shall be entitled to divide its vote on the basis
specified in a notice given by it to the Secretary of the Committee at
or prior to the meeting at which the vote is to be cast, to reflect
the Participant's market and transmission interests. In such case the
portion of a member's vote reflecting its transmission interest may be
cast by the member's alternate.
The voting member appointed by a group may divide the member's vote on
the basis specified in a notice given by it to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect the different positions of the members of the group.
The adoption of actions by the Regional Market Operations Committee
shall require affirmative votes by voting members aggregating at least
60% of the number of votes which the members in attendance at a
meeting at which a quorum is present are entitled to cast. A majority
of the voting members at any time shall constitute a quorum.
10.5 ALTERNATES. The ISO or a Participant or group of Participants may
designate, by a written notice delivered to the Secretary of the
Regional Market Operations Committee, an alternate for any member of
the Regional Market Operations Committee appointed by the ISO or such
Participant or group of Participants. In the absence of the member,
the alternate shall have all of the powers of the member, including
the power to vote.
10.6 OFFICERS. At its annual meeting, the Regional Market Operations
Committee shall elect from its voting members a Chair and a Vice-
Chair; it shall also elect a Secretary who need not be a member.
These officers shall have the powers and duties usually incident to
such offices.
10.7 MEETINGS. The Regional Market Operations Committee shall hold its
annual meeting in December or January at such time and place as the
Chair shall designate and shall hold other meetings in accordance with
a schedule adopted by the Regional Market Operations Committee or at
the call of the Chair. Any two members may call a special meeting of
the Regional Market Operations Committee in the event that the Chair
shall fail to call such a meeting within three business days following
the Chair's receipt from such members of a request specifying the
subject matters to be acted upon at the meeting. In the event of
emergency, any member may call a special meeting of the Regional
Market Operations Committee to be held forthwith. Any annual, special
or other meeting of the Regional Market Operations Committee may be
conducted by means of conference telephone or other communications
equipment by means of which all persons participating in the meeting
can hear each other.
10.8 NOTICE OF MEETINGS. Written notice of each meeting of the Regional
Market Operations Committee shall be given to each member not less
than three business days prior to the date of the meeting. The notice
shall normally specify the principal subject matters expected to be
acted upon; provided, however, that no written notice shall be
required for a meeting called in the event of an emergency, although
the Secretary or the member calling the meeting shall use his or her
best efforts to notify every member of the meeting.
10.9 NOTICE TO MEMBERS OF MANAGEMENT COMMITTEE. Prior to the end of the
fifth business day following a meeting of the Regional Market
Operations Committee, the Secretary of the Regional Market Operations
Committee shall give written notice to the ISO and each member of the
Management Committee of any action taken by the Regional Market
Operations Committee at such meeting.
10.10APPEAL OF ACTIONS TO MANAGEMENT COMMITTEE. The ISO or any
Participant may appeal to the Management Committee any action taken by
the Regional Market Operations Committee. Such an appeal shall be
taken prior to the end of the tenth business day following the meeting
of the Regional Market Operations Committee to which the appeal
relates by giving to the Secretary of the Management Committee a
signed and written notice of appeal and by mailing a copy of the
notice to the ISO and each member of the Management Committee.
Pending action on the appeal by the Management Committee, the filing
of a notice of appeal as aforesaid shall suspend the action appealed
from.
10.11APPOINTMENT OF TASK FORCES. The Regional Market Operations
Committee shall have the authority, within its budget or with the
approval of the Management Committee if beyond its budget, to appoint
task forces for particular studies and may name thereto available
employees of Participants.
10.12CONSULTANTS, COMPUTER TIME AND EXPENSES. The Regional Market
Operations Committee shall have the authority, within its budget or
with the approval of the Management Committee if beyond its budget, to
retain the services of the ISO, to hire consultants, to procure
computer time, and to incur such expenses as may be required to enable
the Regional Market Operations Committee and its task forces properly
to perform their duties.
10.13RESPONSIBILITIES. The Regional Market Operations Committee, in
conjunction with the ISO and the Regional Transmission Operations
Committee, as appropriate, shall be responsible for the following:
(a) making or causing to be made, from time to time, necessary
studies and establishing or approving procedures based
thereon to assure the reliable operation and facilitate the
efficient operation of the NEPOOL Control Area bulk power
supply;
(b) performing the following: (i) coordinating studies of, and
providing information to Participants on, maintenance
schedules for the supply and demand-side resources and
transmission facilities of the Participants, and (ii)
adopting and implementing uniform rules or procedures, until
the Second Effective Date, for determining when a generating
unit's outages for maintenance shall be approved for
Scheduled Outage Service and for determining whether the
applicable Capability for a unit to be used in determining
the amount of a Participant's Scheduled Outage Service shall
be the unit's Reserve Capability or its Temporary Reserve
Capability;
(c) to the extent appropriate to assure the reliable operation
of the bulk power supply of NEPOOL, establishing or
approving reasonable standards, criteria and rules relating
to protective equipment, switching, voltage control, load
shedding, emergency and restoration procedures, and the
operation and maintenance of supply and demand-side
resources and transmission facilities of the Participants;
(d) determining the seasonal capabilities of each electric
generating unit or combination of units in which a
Participant has an Entitlement in a uniform manner applying
generally accepted engineering principles;
(e) determining as appropriate from time to time the current
Annual Peak, Adjusted Annual Peak, Monthly Peak, Adjusted
Monthly Peak, Installed Capability Responsibility, Operable
Capability Requirements, and obligations for Energy,
Operating Reserve and AGC of each Participant;
(f) until the Second Effective Date, determining the Incremental
Costs and Decremental Costs for each generating unit in
which a Participant has an Entitlement under the varying
circumstances affecting such costs;
(g) establishing or approving market operation rules governing
the submission of Bid Prices and the determination of prices
for Installed Capability, Operable Capability, Energy, each
category of Operating Reserve and AGC, and establishing or
approving appropriate billing procedures for transactions
pursuant to this Agreement; and
(h) calculating and equitably apportioning losses incurred in
connection with Interchange Transactions.
10.14FURTHER POWERS AND DUTIES. The Regional Market Operations
Committee shall have such further powers and duties as may be
prescribed by the Management Committee or as set forth in this
Agreement.
10.15DEVELOPMENT OF RULES RELATING TO NON-PARTICIPANT SUPPLY AND DEMAND-
SIDE RESOURCES. It is recognized that arrangements between
Participants and Non-Participants with respect to the Non-
Participants' supply and demand-side resources may create special
problems in the application of Sections 12 and 14. Accordingly, the
Regional Market Operations Committee shall analyze such special
problems and develop appropriate rules for reflecting such resources
in the Installed or Operable System Capability of a Participant which
enters into such an arrangement and for the treatment of such
arrangements for Energy, Operating Reserve and AGC purposes. Upon
approval by the Regional Market Operations Committee, such rules shall
supersede the provisions of Sections 12 and 14 (and the related
definitions in Section 1) to the extent of any conflict therewith.
10.16JOINT MEETINGS WITH REGIONAL TRANSMISSION OPERATIONS COMMITTEE.
The Regional Market Operations Committee is authorized and encouraged
to hold its meetings, and to conduct studies and exercise its
responsibilities, jointly with the Regional Transmission Operations
Committee to the extent appropriate.
SECTION 11
REGIONAL TRANSMISSION OPERATIONS COMMITTEE
11.1 ORGANIZATION. There shall be a Regional Transmission Operations
Committee which shall be responsible for monitoring the operation of
NEPOOL transmission and the administration of the Tariff.
11.2 MEMBERSHIP. The Regional Transmission Operations Committee shall be
constituted as follows: the ISO shall have the right to appoint a
non-voting member of the Committee; each Participant whose Voting
Share equals or exceeds 3% of the aggregate Voting Shares of all
Participants shall have the right to appoint one voting member of the
Committee; the remaining Participants whose Voting Shares are less
than 3% of the aggregate Voting Shares of all Participants shall be
divided into the following five groups, with each having the right to
appoint one voting member of the Committee:
(a) One group consisting of the remaining Participants which are
municipally-owned and cooperatively-owned traditional
utilities;
(b) One group consisting of the remaining Participants which are
not subject to traditional utility rate regulation and which
are engaged in the NEPOOL Control Area principally in the
business of owning or operating generation facilities and
selling the output of such generation;
(c) One group consisting of the remaining Participants which are
not subject to traditional utility rate regulation and which
are engaged in the NEPOOL Control Area principally in a
business other than the business of owning or operating PTF
or generation facilities and selling the output of such
generation;
(d) One group consisting of the remaining Participants, if any,
which (i) own PTF, (ii) are not engaged in electric
generation or distribution and do not participate in the
wholesale bulk power market, and (iii) are not Related
Persons of any other Participant; and
(e) One group consisting of the remaining Participants which are
investor-owned utilities subject to traditional utility rate
regulation or other Entities which do not qualify to be
included in any of the other four groups.
Notwithstanding the foregoing, any such Participant may elect to join
a different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any such Participant is a Related
Person of another Participant which has the individual right to
appoint a member of the Committee, the Participant shall be
represented in the Committee by the member appointed by the
Participant which is its Related Person and shall not be assigned to
any of the five groups.
11.3 TERMS OF MEMBERS. The member of the Regional Transmission
Operations Committee appointed by the ISO shall serve until replaced
by the ISO. Other members of the Regional Transmission Operations
Committee shall serve until replaced by the Participant or
Participants which appointed them or until such Participant or
Participants cease to be Participants or otherwise lose the right to
appoint the member. Appointment or replacement of a member shall be
effected by the ISO or a Participant or group of Participants by
giving written notice of such appointment or replacement to the
Secretary of the Regional Transmission Operations Committee.
11.4 VOTING. Each voting member of the Regional Transmission Operations
Committee shall have one vote, which may be cast in person by the
member or the member's alternate or by another person pursuant to a
written proxy dated not more than one year previous to the meeting and
delivered to the Secretary of the Regional Transmission Operations
Committee at or prior to the meeting at which the proxy vote is cast.
If a Participant which has the individual right to appoint a member of
the Regional Transmission Operations Committee both participates in
the wholesale bulk power market and owns PTF, the member appointed by
the Participant shall be entitled to divide the member's vote on the
basis specified in a notice given by it to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect its market and transmission interests. In such case the
portion of the member's vote reflecting its transmission interest may
be cast by the member's alternate.
The voting member appointed by a group may divide the member's vote on
the basis specified in a notice given by it to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect the different positions of the members of the group.
The adoption of actions by the Regional Transmission Operations
Committee shall require affirmative votes of voting members
aggregating at least 60% of the number of votes which the members in
attendance at a meeting at which a quorum is present are entitled to
cast. A majority of the voting members at any time shall constitute a
quorum.
11.5 ALTERNATES. The ISO or a Participant or group of Participants may
designate, by a written notice delivered to the Secretary of the
Regional Transmission Operations Committee, an alternate for any
member of the Regional Transmission Operations Committee appointed by
the ISO or such Participant or group of Participants. In the absence
of the member, the alternate shall have all of the powers of the
member, including the power to vote.
11.6 OFFICERS. At its annual meeting, the Regional Transmission
Operations Committee shall elect from its voting members a Chair and a
Vice-Chair; it shall also elect a Secretary who need not be a member.
These officers shall have the powers and duties usually incident to
such offices.
11.7 MEETINGS. The Regional Transmission Operations Committee shall hold
its annual meeting in December or January at such time and place as
the Chair shall designate and shall hold other meetings in accordance
with a schedule adopted by the Regional Transmission Operations
Committee or at the call of the Chair. Any two members may call a
special meeting of the Regional Transmission Operations Committee in
the event that the Chair shall fail to call such a meeting within
three business days following the Chair's receipt from such members of
a request specifying the subject matters to be acted upon at the
meeting. In the event of emergency, any member may call a special
meeting of the Regional Transmission Operations Committee to be held
forthwith. Any annual, special or other meeting of the Regional
Transmission Operations Committee may be conducted by means of
conference telephone or other communications equipment by means of
which all persons participating in the meeting can hear each other.
11.8 NOTICE OF MEETINGS. Written notice of each meeting of the Regional
Transmission Operations Committee shall be given to each member not
less than three business days prior to the date of the meeting. The
notice shall normally specify the principal subject matters expected
to be acted upon; provided, however, that no written notice shall be
required for a meeting called in the event of an emergency, although
the Secretary or the member calling the meeting shall use his or her
best efforts to notify every member of the meeting.
11.9 NOTICE TO MEMBERS OF MANAGEMENT COMMITTEE. Prior to the end of the
fifth business day following a meeting of the Regional Transmission
Operations Committee, the Secretary of the Regional Transmission
Operations Committee shall give written notice to the ISO and each
member of the Management Committee of any action taken by the Regional
Transmission Operations Committee at such meeting.
11.10APPEAL OF ACTIONS TO MANAGEMENT COMMITTEE. The ISO or any
Participant may appeal to the Management Committee any action taken by
the Regional Transmission Operations Committee. Such an appeal shall
be taken prior to the end of the tenth business day following the
meeting of the Regional Transmission Operations Committee to which the
appeal relates by giving to the Secretary of the Management Committee
a signed and written notice of appeal and by mailing a copy of the
notice to the ISO and each member of the Management Committee.
Pending action on the appeal by the Management Committee, the filing
of a notice of appeal as aforesaid shall suspend the action appealed
from.
11.11APPOINTMENT OF TASK FORCES. The Regional Transmission Operations
Committee shall have the authority, within its budget or with the
approval of the Management Committee if beyond its budget, to appoint
task forces for particular studies and may name thereto available
employees of Participants.
11.12CONSULTANTS, COMPUTER TIME AND EXPENSES. The Regional Transmission
Operations Committee shall have the authority, within its budget or
with the approval of the Management Committee if beyond its budget, to
retain the services of the ISO, to hire consultants, to procure
computer time, and to incur such expenses as may be required to enable
the Regional Transmission Operations Committee and its task forces
properly to perform their duties.
11.13RESPONSIBILITIES. The Regional Transmission Operations Committee,
in conjunction with the ISO and the Regional Market Operations
Committee, as appropriate, shall be responsible for the following:
(a) making or causing to be made, from time to time, necessary
studies and establishing or approving procedures based
thereon to assure the reliable operation and facilitate the
efficient operation of the NEPOOL Control Area bulk power
supply;
(b) coordinating studies of, and providing information to
Participants on, maintenance schedules for the supply and
demand-side resources and transmission facilities of the
Participants;
(c) to the extent appropriate to assure the reliable operation
of the bulk power supply of the NEPOOL Control Area,
establishing or approving reasonable standards, criteria and
rules relating to protective equipment, switching, voltage
control, load shedding, emergency and restoration
procedures, and the operation and maintenance of supply and
demand-side resources and transmission facilities of the
Participants; and
(d) establishing or approving appropriate billing procedures for
transmission service pursuant to this Agreement and the
Tariff.
11.14FURTHER POWERS AND DUTIES. The Regional Transmission Operations
Committee shall have such further powers and duties as may be
prescribed by the Management Committee or as set forth in this
Agreement.
11.15JOINT MEETINGS WITH REGIONAL MARKET OPERATIONS COMMITTEE. The
Regional Transmission Operations Committee is authorized and
encouraged to hold its meetings, and to conduct studies and exercise
its responsibilities, jointly with the Regional Market Operations
Committee to the extent appropriate.
PART THREE
MARKET PROVISIONS
SECTION 12
INSTALLED CAPABILITY AND OPERABLE CAPABILITY
OBLIGATIONS AND PAYMENTS
12.1 OBLIGATIONS TO PROVIDE INSTALLED CAPABILITY AND OPERABLE CAPABILITY.
(a) Each Participant shall have Installed System Capability during
each hour of each month at least sufficient to satisfy its
Installed Capability Responsibility for the month.
(b) Each Participant shall have Operable System Capability in each
hour at least sufficient to satisfy its Operable Capability
Requirement for such hour.
12.2 COMPUTATION OF INSTALLED CAPABILITY RESPONSIBILITIES.
(a) (1) At the conclusion of each month, the Regional Market
Operations Committee shall determine each Participant's
tentative Installed Capability Responsibility in Kilowatts
for such month in accordance with the following formula:
X = (P(A-N)+N{p})(1+T)
As used in this Section 12.2(a)(1), the symbols used in the
formula and the additional symbols defined below have the
following meanings:
X is the Participant's tentative Installed Capability
Responsibility for the month.
P is the value of the Participant's fraction for the
month as determined in accordance with the following
formula:
P = F{p}/F, wherein:
F{p} is the Participant's Adjusted Monthly Peak for
the month.
F is the aggregate for the month of the Adjusted
Monthly Peaks for all Participants.
A is the NEPOOL Objective Capability in megawatts for the
month as fixed by the Management Committee pursuant to
Section 6.14(e).
N is the aggregate of the New Unit Adjustments for all
Participants for the month as determined by the
Regional Market Operations Committee in accordance with
Section 12.2(a)(2).
N{p} is the aggregate of the Participant's New Unit
Adjustments for the month, as determined by the
Regional Market Operations Committee, and is EQUAL TO
the aggregate of the Participant's adjustments for each
New Unit included in its Installed System Capability
during the hour of the coincident peak load of the
Participants for the month. The Participant's
adjustment for each New Unit may be positive or
negative and shall be the product of (i) the
Participant's Installed Capability Entitlement in the
New Unit during the hour of the coincident peak load of
the Participants for the month, TIMES (ii) the New Unit
Adjustment Factor applicable to the New Unit as
determined in accordance with Section 12.2(a)(2).
T is the Participant's Unit Availability Adjustment
Factor for the month. T may be positive or negative
and shall be determined in accordance with the
following formula:
T = (I-H) x J x R, wherein:
-------------
100
I for the Participant for the month is the percentage
which represents the weighted average (using the
Installed Capability of each Installed Capability
Entitlement for such month for the weighting) of the
Four Year Installed Capability Target Availability
Rates of the Installed Capability Entitlements which
are included in the Participant's Installed System
Capability during the hour of the coincident peak load
of the Participants for the month. The Four Year
Target Availability Rate for an Installed Capability
Entitlement for any month is the average of the monthly
Target Availability Rates for the forty-eight months
which comprise the period of four consecutive calendar
years ending within the Power Year which includes such
month, as determined on the basis of the Target
Availability Rates for each of the forty-eight months,
and as applied on a basis which is consistent with the
fuel or maturity status of the unit for each of the
forty-eight months. The Target Availability Rates
shall be those utilized by the Management Committee in
its most recent determination of NEPOOL Objective
Capability pursuant to Section 6.14(e).
H for the Participant for the month is the percentage
which represents the weighted average (using the
Installed Capability of each Installed Capability
Entitlement for such month for the weighting) of the
Four Year Actual Availability Rates of the Installed
Capability Entitlements which are included in the
Participant's Installed System Capability during the
hour of the coincident peak load of the Participants
for the month. The Four Year Actual Availability Rate
for an Installed Capability Entitlement for any month
is the percentage which represents the average of the
amounts determined for H{1} for the four applicable
Twelve-Month Measurement Periods within the forty-eight
months which comprise the period of four consecutive
calendar years ending within the Power Year which
includes such month. A Twelve-Month Measurement Period
is a period of twelve sequential months. For purposes
of this sequence, the first month in the four years and
the immediately succeeding months shall be considered
to follow the forty-eighth month in the four-year
period. The four applicable Twelve-Month Measurement
Periods to be used in the determination of H{1} for an
Installed Capability Entitlement shall be the four
sequential Twelve-Month Measurement Periods out of the
twelve possible combinations which yield the highest
H{1}.
H{1} for an Installed Capability Entitlement in a unit or
combination of units for a Twelve-Month Measurement
Period is its Actual Availability Rate. The Actual
Availability Rate of an Installed Capability
Entitlement for a Twelve-Month Measurement Period is a
percentage and shall be the greater of:
(i) the percentage of (a) the amount of generation
which could have been received with respect to the
Installed Capability Entitlement if the unit or
combination of units had been fully available at
its full Installed Capability throughout the
Twelve-Month Measurement Period, which is
represented by (b) the amount of generation which
was actually available during such period, or
(ii) the average Target Availability Rate expressed as
a percentage for the Installed Capability
Entitlement for the Twelve-Month Measurement
Period less twenty percentage points. The average
Target Availability Rate of an Installed
Capability Entitlement for a Twelve-Month
Measurement Period is a percentage and is the
average of the monthly Target Availability Rates
for the months which comprise the Twelve-Month
Measurement Period, as determined on the basis of
the Target Availability Rates for each of the
twelve months, and as applied on a basis which is
consistent with the fuel or maturity status of the
unit or combination of units for each month in the
Twelve-Month Measurement Period. The Target
Availability Rates shall be those utilized by the
Management Committee in its most recent
determination of NEPOOL Objective Capability
pursuant to Section 6.14(e).
J for the month is the estimated percentage point change
in NEPOOL Objective Capability which would be required
as a result of a one percentage point change in the
weighted average equivalent availability rate of the
generating units in which the Participants have
Installed Capability Entitlements. The value for J
shall be adopted by the Management Committee each time
it fixes NEPOOL Objective Capability pursuant to
Section 6.14(e).
R for the month is the phase-out factor for the month,
which shall be as follows:
R=0.75 for the Power Year beginning November 1,
1997.
R=0.50 for the Power Year beginning November 1,
1998.
R=0.25 for the Power Year beginning November 1,
1999.
R=0 for the Power Year beginning November 1, 2000
and all subsequent Power Years.
(2) A New Unit Adjustment Factor for a New Unit shall be
determined to assign the effects of the New Unit on NEPOOL
Objective Capability to those Participants with Entitlements
in the New Unit. The New Unit Adjustment Factor for each
New Unit for each month shall be determined by the Regional
Market Operations Committee in accordance with the following
formula:
n = R(K{1}(c-C) + K{2}(f-F) + K{3}(m-M) + K{4}(d-D) +
K{5}(f-F)c{2})
As used in this Section 12.2(a)(2), the symbols used in the
formula have the following meanings:
R is the phase out factor as defined in Section
12.2(a)(1) above.
n is the New Unit Adjustment Factor, expressed as a
fraction, for the month for a New Unit.
c is the Winter Capability of the New Unit.
C is the Winter Capability of the Proxy Unit, which shall
be the number of Kilowatts, as determined by the
Management Committee, which would result in the NEPOOL
Objective Capability being approximately the same if
the generating units in which the Participants have
Installed Capability Entitlements were all units
possessing Proxy Unit characteristics.
f is the equivalent forced outage rate of the New Unit,
expressed as a fraction of a year, utilized in the
determination by the Management Committee of NEPOOL
Objective Capability for the month.
F is the equivalent forced outage rate of the Proxy Unit.
F, a fraction, shall be the weighted average equivalent
forced outage rate (using the Winter Capability of each
generating unit for such weighting) of the generating
units in which the Participants have Installed
Capability Entitlements, adjusted to compensate for the
rounding of the annual maintenance outage requirement
of the Proxy Unit.
m is the four-year average annual maintenance outage
requirement of the New Unit, expressed as a fraction of
a year. The data used to determine m shall include the
annual maintenance outage requirements for the current
Power Year and the next three Power Years, as utilized
for the New Unit in the most recent determination by
the Management Committee of NEPOOL Objective Capability
pursuant to Section 6.14(e).
M is the annual maintenance outage requirement of the
Proxy Unit. M shall be a fraction, the numerator of
which shall be the number of weeks (rounded to the
nearest full number) that most closely approximates the
weighted four-year average annual maintenance outage
requirement (using the Winter Capability of each
generating unit for such weighting) for the generating
units in which the Participants have Installed
Capability Entitlements, and the denominator of which
shall be 52 weeks.
d is the summer derating of the New Unit, expressed as a
fraction of the Winter Capability of the New Unit.
D is the summer derating of the Proxy Unit. D shall be a
fraction and shall be EQUAL TO the weighted average
fractional summer derating (using the Winter Capability
of each generating unit for such weighting) of the
generating units in which the Participants have
Installed Capability Entitlements.
K{1}, K{2}, K{3}, K{4}, and K{5}
are conversion coefficients for each of the Summer and
Winter Periods, determined by regression analysis such
that the product for the Installed Capability of a New
Unit TIMES its New Unit Adjustment Factor approximates
the effect on NEPOOL Objective Capability of the New
Unit.
Proxy Unit characteristics and conversion coefficients
contained in the formula shall be adopted by the Management
Committee and reviewed every five years (or more frequently
if the Management Committee determines that exceptional
circumstances require an earlier review) and revised as
necessary.
If a New Unit has unique characteristics affecting NEPOOL
Objective Capability which are not adequately reflected in
the New Unit Adjustment Factor formula, the Management
Committee shall determine for such New Unit a New Unit
Adjustment Factor which accounts for the New Unit's unique
characteristics.
The New Unit Adjustment Factor for any Restricted Unit (as
defined in Section 15.37B of the Prior NEPOOL Agreement) for
which proposed plans were submitted subsequent to November
1, 1990 for review pursuant to Section 18.4 or its
predecessor section in the Prior NEPOOL Agreement (or, in
the case of a unit with a rated capacity of less than 5MW,
for which notification was first given to NEPOOL subsequent
to November 1, 1990) and for the Peabody Municipal Light
Plant's Waters River #2 unit shall be determined in
accordance with the formula previously specified in Section
12.2(a)(2), modified as follows:
n = R(K{1}(c-C) + K{2}(f-F) + K{3}(m-M) + K{4}(d-D)
+K{5}(f-F)c{2}) + K{6}(2500-a)
The symbols used in the above formula, as modified, shall
have the meanings previously specified, except that the
symbols "K{6}" and "a" shall have the following meanings:
K{6} is a scaling factor of 0.0001.
a is as follows:
for units with more than 2500 annual hours available
for operation, "a" = 2500,
for units with annual hours available for operation
between 500 and 2500, inclusive, "a" = annual hours
available for operation, and
for units with annual hours available for operation
less than 500 hours, "a" = -7500;
PROVIDED, HOWEVER, that a Participant may elect to avoid, in
whole or part, the effect on its Installed Capability
Responsibility of a Restricted Unit's availability being
limited to 2500 hours or less a year by agreeing to leave
unfilled a portion of its dispatchable load allocation in
accordance with rules adopted by the Regional Market
Operations Committee.
(b) The tentative Installed Capability Responsibilities of the
Participants for any month, as determined in accordance with
Section 12.2(a), shall be adjusted in accordance with this
Section 12.2(b) in the event the value of H for any Participant
for any of the Twelve-Month Measurement Periods applicable to the
Participant for the month is increased in accordance with Section
12.2(a) because of the application of paragraph (ii) of the
definition of H{1}. In such event the Regional Market Operations
Committee shall determine each Participant's tentative Installed
Capability Responsibility for the month with and without the
application of said paragraph (ii). The difference between the
sum of all Participants' tentative Installed Capability
Responsibilities, with and without the application of said
paragraph (ii) for the month, shall be added to the tentative
Installed Capability Responsibilities of the Participants, as
determined in accordance with Section 12.2(a), in proportion to
said tentative Installed Capability Responsibilities, thereby
establishing each Participant's adjusted tentative Installed
Capability Responsibility for the month.
(c) For each month, the Regional Market Operations Committee shall
determine the sum of all Participants' adjusted tentative
Installed Capability Responsibilities, as initially determined in
accordance with Section 12.2(a) and as adjusted in accordance
with Section 12.2(b), if Section 12.2(b) is applicable for such
month. If the sum is less than, or equal to, the minimum NEPOOL
Installed Capability during the month, then the adjusted
tentative Installed Capability Responsibility as determined
pursuant to Section 12.2(a) or 12.2(b), whichever is applicable,
for each Participant is the final Installed Capability
Responsibility for each Participant. If the sum is greater than
such minimum NEPOOL Installed Capability, then each Participant's
final Installed Capability Responsibility shall be its adjusted
tentative Installed Capability Responsibility as determined
pursuant to Section 12.2(a) or 12.2(b), whichever is applicable,
multiplied by the ratio of the minimum NEPOOL Installed
Capability during the month to the sum of the adjusted tentative
Installed Capability Responsibilities for the month.
(d) It is recognized that the treatment of fuel conversions, dual
fuel units, immature units, new Installed Capability
Entitlements, cogeneration and small power-producing facilities,
Unit Contracts and other contract arrangements, units with
unusual maintenance cycles, and various other matters can result
in special problems in the determination of Unit Availability
Adjustment Factors and New Unit Adjustments. Accordingly, the
Regional Market Operations Committee shall analyze such special
problems and develop appropriate market operation rules to be
applied in taking such matters into account in the determination
of Unit Availability Adjustment Factors and New Unit Adjustments.
12.3 COMPUTATION OF OPERABLE CAPABILITY REQUIREMENTS.
For each hour, the Regional Market Operations Committee shall
determine each Participant's Operable Capability Requirement in
Kilowatts in accordance with the following formula:
OP{p} = EL{p} + OR{p}
As used in this Section 12.3, the symbols used in the formula have the
following meanings:
OP{p} is the Participant's Operable Capability Requirement for
the hour.
EL{p }is the Participant's Electrical Load during the hour.
OR{p }is the amount (in Kilowatts) of Operating Reserve which the
Participant was required to provide during the hour, as
determined in accordance with Section 14.1(b).
12.4 BIDS TO FURNISH INSTALLED CAPABILITY OR OPERABLE CAPABILITY. Each
Participant shall submit to or have on file with the System Operator,
in accordance with the market operation rules approved by the Regional
Market Operations Committee, one or more bids specifying the Bid Price
and Kilowatt amount at which it will furnish any and all surplus
Installed System Capability for a month or Operable System Capability
for an hour through NEPOOL to other Participants. If no bid is
submitted for a month for any surplus Installed System Capability or
for any hour for any surplus Operable System Capability, the Bid Price
for any such surplus for which there are no bids shall be deemed to be
zero.
12.5 CONSEQUENCES OF DEFICIENCIES IN INSTALLED CAPABILITY RESPONSIBILITY.
(a) At the conclusion of each month, the System Operator shall
determine whether each Participant has satisfied its Installed
Capability Responsibility obligation for the month. If the
minimum monthly Installed System Capability of a Participant
during the month was less than its Installed Capability
Responsibility, the number of Kilowatts of its deficiency shall
be computed and the Participant shall be deemed to purchase from
other Participants through NEPOOL Kilowatts of surplus Installed
System Capability equal to the amount of its deficiency and shall
pay to NEPOOL for the month any applicable fees for services
assessed pursuant to Section 19.2 PLUS the product of its total
Kilowatts of deficiency and the Installed Capability Clearing
Price for the month determined in accordance with Section
12.5(b). For purposes of this Section 12, the minimum monthly
Installed System Capability of a Participant for a month is the
Participant's lowest Installed System Capability for any hour
during the month. Retirements made on the last day of any month
shall not be deducted from Installed System Capability for that
month.
(b) At the end of each month, the System Operator shall determine the
Installed Capability Clearing Price for the month as follows:
(i) The System Operator shall determine the aggregate Kilowatt
shortage of Installed System Capability for the month for
all Participants that did not satisfy their Installed
Capability Responsibilities for that month.
(ii) The System Operator shall rank in the order of lowest to
highest Bid Price all Bid Prices received from Participants
having excess Installed System Capability for the month.
(iii)For each Participant, its Installed System Capability with
the lowest Bid Prices shall be deemed to have been furnished
first, to the extent required, to meet its Installed
Capability Responsibility. Any remainder starting with the
lowest Bid Prices shall be deemed to have been furnished, to
the extent required, to other Participants under this
Agreement to meet their shortages of Installed System
Capability for the month.
(iv) The Installed Capability Clearing Price for the month shall
equal the highest Bid Price for Installed System Capability
that is deemed in accordance with Section 12.5(b)(iii) to
have been furnished to another Participant for the month.
12.6 CONSEQUENCES OF DEFICIENCIES IN OPERABLE CAPABILITY REQUIREMENTS.
(a) For each hour, the System Operator shall determine whether each
Participant has satisfied its Operable Capability Requirement
obligation for that hour. If the minimum Operable System
Capability of a Participant during any hour was less than its
Operable Capability Requirement, the number of Kilowatts of its
deficiency shall be computed and the Participant shall be deemed
to purchase from other Participants through NEPOOL Kilowatts of
surplus Operable System Capability equal to the amount of its
deficiency and shall pay for the hour any applicable uplift
charge assessed under Section 14.15 and any applicable fees for
services assessed pursuant to Section 19.2 PLUS the product of
its Kilowatt deficiency for the hour and the Operable Capability
Clearing Price for the hour determined in accordance with Section
12.6(b). The minimum Operable System Capability of a Participant
for an hour is equal to the Participant's lowest Operable System
Capability at any time during the hour.
(b) For each hour, the System Operator shall determine the Operable
Capability Clearing Price as follows:
(i) The System Operator shall determine the aggregate Kilowatt
shortage of Operable System Capability for the hour for all
Participants that did not satisfy their Operable Capability
Requirements in that hour.
(ii) The System Operator shall rank in the order of lowest to
highest Bid Price all Bid Prices received from Participants
having excess Operable System Capability for the hour.
(iii)For each Participant, its Operable System Capability with
the lowest Bid Prices shall be deemed to have been furnished
first, to the extent required, to meet its Operable
Capability Requirement. Any remainder starting with the
lowest Bid Prices shall be deemed to have been furnished, to
the extent required, to other Participants under this
Agreement to meet their shortages of Operable System
Capability for that hour.
(iv) The Operable Capability Clearing Price for the hour shall be
equal to the highest Bid Price for Operable System
Capability that is deemed in accordance with Section
12.6(b)(iii) to have been furnished to another Participant
in the hour.
12.7 PAYMENTS TO PARTICIPANTS FURNISHING INSTALLED CAPABILITY AND
OPERABLE CAPABILITY.
(a) Participants that are deemed pursuant to Section 12.5 to furnish
any surplus in their Installed System Capability to other
Participants shall receive therefor their pro rata shares on a
Kilowatt basis of all payments made by Participants for the month
under Section 12.5, excluding any applicable fees for services
assessed pursuant to Section 19.2. If two or more Participants
with excess Installed System Capability have bid Kilowatts at the
Installed Capability Clearing Price, but not all the excess
Installed System Capability bid at such price is required to meet
shortages of Installed System Capability, then the excess
Installed System Capability bid at the Installed Capability
Clearing Price that each such Participant shall be deemed to have
furnished shall be the Kilowatts of excess Installed System
Capability bid by the Participant at that price MULTIPLIED by the
ratio of (i) the total Kilowatts of excess Installed System
Capability bid at the Installed Capability Clearing Price needed
to meet the shortages to (ii) the total Kilowatts of excess
Installed System Capability bid by all Participants at the
Installed Capability Clearing Price.
(b) Participants that are deemed pursuant to Section 12.6 to furnish
any surplus in their Operable System Capability to other
Participants shall receive therefor their pro rata shares on a
Kilowatt basis of all payments made by Participants for the hour
under Section 12.6, excluding any applicable uplift charges
assessed under Section 14.15 and any applicable fees for services
assessed pursuant to Section 19.2. If two or more Participants
with excess Operable System Capability in an hour have bid
Kilowatts at the Operable Capability Clearing Price, but not all
the excess Operable System Capability bid at such price is
required to meet shortages of Operable System Capability, then
the excess Operable System Capability bid at the Operable
Capability Clearing Price that each such Participant shall be
deemed to have furnished shall be the Kilowatts of excess
Operable System Capability bid by the Participant at that price
MULTIPLIED by the ratio of (i) the total Kilowatts of excess
Operable System Capability bid at the Operable Capability
Clearing Price needed to meet the shortages to (ii) the Kilowatts
of excess Operable System Capability bid by all Participants at
the Operable Capability Clearing Price.
SECTION 13
OPERATION, GENERATION, OTHER RESOURCES,
AND INTERRUPTIBLE CONTRACTS
13.1 MAINTENANCE AND OPERATION IN ACCORDANCE WITH GOOD UTILITY PRACTICE.
Each Participant shall, to the fullest extent practicable, cause all
generating facilities and other resources owned or controlled by it to
be designed, constructed, maintained and operated in accordance with
Good Utility Practice.
13.2 CENTRAL DISPATCH. Subject to the following sentence, each
Participant shall, to the fullest extent practicable, subject all
generating facilities and other resources owned or controlled by it to
central dispatch by the System Operator; provided, however, that each
Participant shall at all times be the sole judge as to whether or not
and to what extent safety requires that at any time any of such
facilities will be operated at less than full capacity or not at all.
Each Participant may remove from central dispatch a generating
facility or other resources owned or controlled by it if and to the
extent such removal is permitted by rules and standards approved by
the Management Committee.
13.3 MAINTENANCE AND REPAIR. Each Participant shall, to the fullest
extent practicable: (a) cause generating facilities and other
resources owned or controlled by it to be withdrawn from operation for
maintenance and repair only in accordance with maintenance schedules
reported to and published by the System Operator from time to time in
accordance with procedures established or approved by the Regional
Market Operations Committee, (b) restore such facilities to good
operating condition with reasonable promptness, and (c) accelerate or
delay maintenance and repair at the reasonable request of the System
Operator in accordance with market operation rules approved by the
Regional Market Operations Committee.
13.4 OBJECTIVES OF DAY-TO-DAY SYSTEM OPERATION. The day-to-day
scheduling and coordination through the System Operator of the
operation of generating units and other resources shall be designed to
assure the reliability of the bulk power system of the NEPOOL Control
Area. Such activity shall:
(a) satisfy the NEPOOL Control Area's Operating Reserve
requirements, including the proper distribution of those
Operating Reserves;
(b) satisfy the Automatic Generation Control requirements of the
NEPOOL Control Area; and
(c) satisfy the Energy requirements of all Electrical Loads of
the Participants.
all at the lowest practicable aggregate dispatch cost to the NEPOOL
Control Area in light of available Bid Prices and Participant-directed
schedules.
13.5 SATELLITE MEMBERSHIP. Each Participant which is responsible for the
operation of transmission facilities rated 69 kV or above in the
NEPOOL Control Area or generating units and other resources which are
subject to central dispatch by NEPOOL, or which is responsible for
implementing voltage reduction and load shedding procedures in the
NEPOOL Control Area, shall become a member of the appropriate
satellite dispatching center; provided that by mutual agreement among
the affected Participants and the appropriate satellite, a Participant
may be excused from joining the satellite if it has arranged with a
satellite member to assume responsibility to the satellite for its
facilities or obligations.
SECTION 14
INTERCHANGE TRANSACTIONS
14.1 OBLIGATION FOR ENERGY, OPERATING RESERVE AND AUTOMATIC GENERATION
CONTROL.
(a) Each Participant shall have for each hour an Energy obligation
equal to its Electrical Load PLUS the kilowatthours delivered by
such Participant to other Participants in the hour pursuant to
Firm Contracts or System Contracts, together with any associated
electrical losses.
(b) Each Participant shall have for each hour Operating Reserve
obligations equal to its share of the quantity of each category
of Operating Reserve required for the NEPOOL Control Area in the
hour.
Subject to adjustment pursuant to Section 14.6, a Participant's
share of each category of Operating Reserve required for any hour
shall be determined in accordance with the following formula:
OR{p}=SA{p} + [(OR-SA) (EL{p}/EL)], wherein
OR{p}is the Participant's share of that category of
Operating Reserve for the hour.
SA{p}is the number of Kilowatts, if any, of that category
of Operating Reserve for the hour that the Regional
Market Operations Committee determines should be
assigned specifically to such Participant and not be
shared by all Participants.
OR is the aggregate number of Kilowatts of that category
of Operating Reserve determined by the System Operator
in accordance with the directions of the Regional
Market Operations Committee to be required for the
NEPOOL Control Area for the hour that is not assigned
to Non-Participants.
SA is the aggregate number of Kilowatts of that category
of Operating Reserve for the hour that the Regional
Market Operations Committee determines should not be
shared by all Participants, but not including Operating
Reserve assigned to Non-Participants.
EL{p}is the Participant's Electrical Load for the hour.
EL is the sum of EL{p} for all Participants.
(c) Each Participant shall have for each hour an AGC obligation equal
to its share of AGC required for the NEPOOL Control Area in the
hour. Subject to adjustment pursuant to Section 14.6, a
Participant's share of AGC required for any hour shall be
determined in accordance with the following formula:
AGC{p}=AGC (EL{p}/EL), wherein
AGC{p}is the Participant's share of AGC for the hour.
AGC is the total amount of AGC determined by the System
Operator in accordance with market operation rules
approved by the Regional Market Operations Committee to
be required for the NEPOOL Control Area for the hour
that is not assigned to Non-Participants.
EL{p} and EL are as defined in Section 14.1(b).
14.2 OBLIGATION TO BID OR SCHEDULE, AND RIGHT TO RECEIVE ENERGY,
OPERATING RESERVE AND AUTOMATIC GENERATION CONTROL.
(a) A Participant which has Energy Entitlements shall submit to
or have on file with the System Operator, in accordance with
the market operation rules approved by the Regional Market
Operations Committee, one or more bids for the Energy
Entitlements for which the Participant is permitted to bid
specifying the Bid Price at which it will furnish Energy
through NEPOOL to other Participants under this Agreement or
to Non-Participants for ancillary services under the Tariff,
or pursuant to arrangements with Non-Participants entered
into under Section 14.6, except to the extent such
Entitlements are scheduled by the Participant consistent
with Section 14.2(d).
(b) A Participant which has Operating Reserve Entitlements or
AGC Entitlements shall also submit to or have on file with
the System Operator, in accordance with the market operation
rules approved by the Regional Market Operations Committee,
one or more bids for each such Entitlement for which the
Participant is permitted to bid specifying the Bid Prices at
which it will furnish 10-Minute Spinning Reserve, 10-Minute
Non-Spinning Reserve, 30-Minute Operating Reserve and/or AGC
through NEPOOL to other Participants under this Agreement or
to Non-Participants for ancillary services under the Tariff,
except to the extent such Entitlements are scheduled by the
Participant consistent with Section 14.2(d). Prior to the
Third Effective Date, Participants' rights and obligations
to submit bids for Operating Reserve Entitlements in
10-Minute Spinning Reserve shall be limited to Entitlements
in hydroelectric generating units and pumped storage
hydroelectric generating units.
(c) Except as emergency circumstances may result in the System
Operator requiring load curtailments by Participants, each
Participant shall be entitled to receive from the other
Participants (or from the service made available from Non-
Participants pursuant to arrangements entered into under
Section 14.6) such amounts, if any, of Energy, Operating
Reserve, and AGC as it requires and Non-Participants shall
be entitled to receive from Participants the amount of
ancillary services to which they are entitled pursuant to
the Tariff. If, for any hour, load curtailments are
required, the amount that Participants and Non-Participants
with shortages are entitled to receive shall be
proportionally reduced by the System Operator in a fair and
non-discriminatory manner in light of the circumstances.
(d) All Bid Prices for Entitlements shall be submitted in
accordance with market operation rules approved by the
Regional Market Operations Committee. If a Bid Price is not
submitted for any such Entitlement, the Bid Price shall be
deemed to be zero. For a generating unit in which there are
multiple Entitlement holders, only one Participant shall be
permitted to submit Bid Prices for Energy, Operating Reserve
and/or AGC Entitlements for such unit or to direct the
scheduling of the unit for any Scheduled Dispatch Period.
The Entitlement holders in each unit with multiple
Entitlement holders shall designate a single Participant
that will be permitted to submit Bid Prices and/or to direct
the scheduling of the unit. In the event that more than one
Participant is designated, or if the Entitlement holders do
not designate a single Participant, then Bid Prices for the
unit shall be based on its replacement cost of fuel, which
shall be furnished to the System Operator by the Participant
responsible for furnishing such information as of December
1, 1996. Further, any schedules for the unit will be
submitted to the System Operator by such Participant.
Nothing in this Agreement shall affect the rights of any
Entitlement holder under the contractual arrangements among
such Entitlement holders relating to the unit.
Prior to the Third Effective Date, Bid Prices must be
submitted for the next Scheduled Dispatch Period for all
Energy, Operating Reserve and AGC Entitlements in generating
unit or units and Energy Entitlements pursuant to Firm
Contracts or System Contracts which may be scheduled by the
buyer in accordance with Section 14.7(b) no later than noon
on the preceding day or such later time as is specified in
the market operation rules approved by the Regional Market
Operations Committee. On and after the Third Effective
Date, such Bid Prices shall be submitted for each hour of
the day and the notice period for such Bid Prices shall be
reduced to one hour or such shorter time as the System
Operator determines from time to time is practical while
maintaining reliability and meeting its other obligations to
the Participants, EXCEPT THAT such notice period shall be
longer than one hour if and to the extent that the System
Operator reasonably determines that such notice is the
shortest notice that is technically feasible at that time to
maintain reliability and meet its other obligations to the
Participants. The System Operator shall notify the
Participants following its receipt of all Bid Prices of the
expected dispatch schedule for the next Scheduled Dispatch
Period. The System Operator shall reduce the notice
required for Bid Prices and the applicable Scheduled
Dispatch Period to the minimum time technically and
practically feasible while maintaining reliability and
meeting its other obligations to the Participants.
Energy, Operating Reserve and/or AGC Entitlements in a
generating unit or units may also be scheduled directly by
the Participants permitted to submit Bid Prices for such
Entitlements, but only in accordance with this Section
14.2(d) and market operation rules approved by the Regional
Market Operations Committee consistent herewith. Subject to
the right of the System Operator to direct changes to
schedules in order to ensure reliability in the NEPOOL
Control Area or any neighboring control area, a Participant
permitted to bid its Energy, Operating Reserve, and/or AGC
Entitlements in a generating unit or units, or required to
make Energy deliveries, may submit an hour-to-hour schedule
for the operation or dispatch of such Entitlements during a
Scheduled Dispatch Period at or before the time that Bid
Prices are required to be submitted for such period. In
addition, prior to the Third Effective Date, a Participant
permitted to bid a unit or units may submit a short-notice
schedule for the operation or dispatch of any or all of the
Energy available from such unit or units during the current
or a subsequent Scheduled Dispatch Period following the time
that the System Operator notifies the appropriate
Participants of their expected Entitlement commitments for
that Scheduled Dispatch Period; PROVIDED THAT, for each such
short-notice schedule, the Participant has not been advised
by the System Operator that the Energy, Operating Reserve or
AGC Entitlements from the unit or units covered by the
Participant's schedule are expected to be used during the
Scheduled Dispatch Period to meet the region's Energy,
Operating Reserve and/or AGC requirements, and PROVIDED
FURTHER THAT the Participant short-notice schedule is only
to facilitate transactions during such period from resources
or to load located outside the NEPOOL Control Area; and
PROVIDED FURTHER THAT such schedule is furnished at least
one hour in advance of the start of the transaction. In
addition, a Participant may, on the same short notice,
schedule System Contracts with Non-Participants from
resources or to load located outside of the NEPOOL Control
Area.
14.3 AMOUNT OF ENERGY, OPERATING RESERVE AND AUTOMATIC GENERATION CONTROL
RECEIVED OR FURNISHED.
(a) For purposes of Sections 14.4, 14.5, and 14.8, the amount of
Energy which a Participant is deemed to receive or furnish in any
hour shall be the amount of its Adjusted Net Interchange. If the
Adjusted Net Interchange is negative, the Participant shall be
deemed to be receiving Energy in the hour. If the Adjusted Net
Interchange is positive, the Participant shall be deemed to be
furnishing Energy in the hour.
(b) For purposes of Sections 14.4, 14.5, and 14.9, prior to the Third
Effective Date: the amount of each category of Operating Reserve
which a Participant is deemed to receive in any hour is the
Kilowatts of such Operating Reserve assigned to the Participant
for the hour under Section 14.1(b) LESS any Kilowatts provided in
the hour by the Participant in accordance with the market
operation rules approved by the Regional Market Operations
Committee to meet any Operating Reserve requirements that were
specifically assigned to it and not shared by all Participants;
the amount of Operating Reserve of each category that the
Participant is deemed to have furnished under the Agreement in
the hour is the amount of such Operating Reserve designated by
the System Operator to be provided in the hour by the
Participant's applicable Operating Reserve Entitlements, MINUS
any Kilowatts used in the hour by the Participant in accordance
with the market operation rules to meet any Operating Reserve
requirements that were specifically assigned to it and not shared
by all Participants. For purposes of Sections 14.4, 14.5, and
14.9, on and after the Third Effective Date, the amount of each
category of Operating Reserve which a Participant is deemed to
have received or furnished in any hour is the difference between
the Kilowatts of such Operating Reserve assigned to the
Participant for the hour under Section 14.1(b) and the Kilowatts
of such Operating Reserve designated by the System Operator to be
provided in the hour by the Participant's applicable Operating
Reserve Entitlements.
(c) For purposes of Sections 14.4, 14.5, and 14.10, prior to the
Third Effective Date, the amount of AGC which a Participant is
deemed to have received in an hour is the AGC assigned to the
Participant for the hour under Section 14.1(c), and the amount a
Participant is deemed to have furnished in the hour is the AGC
designated by the System Operator to be provided in the hour by
the Participant's AGC Entitlements. For purposes of Sections
14.4, 14.5, and 14.10, on and after the Third Effective Date, the
amount of AGC which a Participant is deemed to have received or
furnished in an hour is the difference between the AGC assigned
to the Participant for the hour under Section 14.1(c) and the AGC
designated by the System Operator to be provided in the hour by
the Participant's AGC Entitlements.
14.4 PAYMENTS BY PARTICIPANTS RECEIVING ENERGY SERVICE, OPERATING RESERVE
AND AUTOMATIC GENERATION CONTROL.
(a) For every hour in which a Participant's Adjusted Net Interchange
is negative, the number of megawatthours of its Energy deficiency
shall be computed and the Participant shall pay for the hour the
product of its total megawatthours of deficiency and the Energy
Clearing Price applicable for the hour as determined in
accordance with Section 14.8, together with any applicable uplift
charges assessed to the Participant under Sections 14.14 and
14.15 of this Agreement and Section 24 of the Tariff and any
applicable fees for services assessed pursuant to Section 19.2.
(b) For every hour in which a Participant is deemed to receive
Operating Reserve of any category in accordance with Section
14.3(b), the number of Kilowatts it is deemed to receive for the
hour in each category shall be computed. The Participant shall
pay therefor for the hour any applicable uplift charge assessed
under Section 14.15 and any applicable fees for services assessed
pursuant to Section 19.2 PLUS the product of (i) the aggregate
amount paid to Participants for that category of Operating
Reserve for the hour pursuant to Section 14.5(b) and (ii) a
fraction of which the numerator is the Kilowatts of that category
of Operating Reserve deemed under Section 14.3(b) to have been
received by the Participant for the hour and the denominator is
the aggregate Kilowatts of that category of Operating Reserve
deemed under Section 14.3(b) to have been received by all
Participants for the hour.
(c) For every hour in which a Participant is deemed under Section
14.3(c) to have received AGC, the amount it is deemed to receive
shall be computed and the Participant shall pay therefor any
applicable uplift charge assessed under Section 14.15 and any
applicable fees for services assessed pursuant to Section 19.2
PLUS the product of (i) the aggregate amount paid to Participants
for AGC for the hour pursuant to Section 14.5(c) and (ii) a
fraction of which the numerator is the AGC the Participant is
deemed under Section 14.3(c) to have received for the hour and
the denominator is the aggregate amount of AGC all Participants
are deemed under Section 14.3(c) to have received for the hour.
14.5 PAYMENTS TO PARTICIPANTS FURNISHING ENERGY SERVICE, OPERATING RESERVE,
AND AUTOMATIC GENERATION CONTROL.
(a) Subject to the provisions of Section 14.12, a Participant that is
deemed in an hour to furnish Energy service to other Participants
pursuant to Section 14.3, or to Non-Participants for ancillary
services under the Tariff or pursuant to arrangements entered
into under Section 14.6, shall receive for each megawatthour
furnished by it the Energy Clearing Price for the hour determined
in accordance with Section 14.8 or the Bid Price for that
megawatthour, if higher than the Energy Clearing Price and the
unit is either within the Energy Clearing Price Block (as defined
in Section 14.8(c)) or is operated out of merit if such higher
Bid Price is appropriately paid pursuant to market operation
rules governing out-of-merit generation approved by the Regional
Market Operations Committee. In addition, to the extent that the
System Operator reduces Energy production from a generating unit
or units in order to provide VAR support, Participants with
Entitlements in such unit or units may receive their lost
opportunity costs if and to the extent provided for by market
operation rules approved by the Regional Market Operations
Committee.
(b) A Participant that is deemed in an hour to furnish Operating
Reserve under the Agreement shall receive for each Kilowatt of
each category of Operating Reserve furnished by it the applicable
Operating Reserve Selling Price as defined and determined in
accordance with Section 14.9 or the Bid Price to provide such
Kilowatt, if higher than the Operating Reserve Selling Price for
the hour.
(c) A Participant that is deemed in an hour to furnish AGC under the
Agreement shall receive therefor an amount calculated as follows:
(i) the AGC Clearing Price for the hour as defined and
determined in accordance with Section 14.10, TIMES the
change in AGC output of the Participant's AGC Entitlements
which the System Operator requested in the hour, TIMES an
appropriate unit conversion factor as determined in
accordance with market operation rules approved by the
Regional Market Operations Committee; PLUS
(ii) an AGC reservation payment for each AGC Entitlement that the
System Operator designated for AGC in the hour calculated as
(A) the AGC Clearing Price in effect for the hour, TIMES (B)
the level of AGC the System Operator determines to be
available in the hour from the Entitlement, TIMES (C) the
portion of the hour during which the System Operator had
designated the Entitlement for AGC; PLUS
(iii)a payment that compensates the Participant for its lost
opportunity cost, if any, for the operation of the
generating unit or combination of units designated for AGC
in the hour below the desired level of output in order to
provide AGC, as determined in accordance with market
operation rules approved by the Regional Market Operations
Committee.
14.6 ENERGY TRANSACTIONS WITH NON-PARTICIPANTS.
(a) The Management Committee is authorized to enter into contracts on
behalf of and in the names of all Participants (i) with power
pools or other entities in one or more other control areas to
purchase or furnish emergency Energy (and related services) that
is available for the System Operator to schedule in order to
ensure reliability in the NEPOOL Control Area or neighboring
control areas, and (ii) with Non-Participants pursuant to which
ancillary services will be provided by the Participants pursuant
to the Tariff. The terms of any such contractual arrangement
shall not require the furnishing of emergency service to any
other control area until the service needs of all Participants
have been provided for with the least expensive resources
practicable. Energy purchased in any hour from Non-Participants
under a contract entered into pursuant to this Section 14.6(a)
shall be deemed to be furnished to, and paid for by, Participants
entitled to or requiring such Energy in the hour pursuant to this
Section 14 at the higher of the Energy Clearing Price for the
hour or the price paid to the Non-Participant for the Energy.
(b) The Regional Market Operations Committee is authorized to provide
for the day-to-day scheduling through the System Operator of the
HQ Phase II Firm Energy Contract, in accordance with the HQ Use
Agreement, as if the Contract were a contract covering Energy
transactions with a Non-Participant entered into pursuant to
Section 14.6(a). The HQ Phase II Firm Energy Contract shall not
be deemed a Firm Contract for purposes of this Agreement. Energy
received in an hour from Hydro-Quebec pursuant to the HQ Energy
Banking Agreement, and Energy purchased in any hour from Hydro-
Quebec pursuant to the HQ Phase II Firm Energy Contract or any
other HQ Contract shall be deemed to be Energy furnished to each
Participant entitled to such Energy for the hour in the amount
reflected for the Participant in the System Operator's scheduling
of Energy deliveries in the hour from Hydro-Quebec; EXCEPT THAT
emergency Energy received from Hydro-Quebec under the HQ
Interconnection Agreement shall be deemed to be Energy provided
to (and shall be paid for by) Participants requiring such
emergency Energy in the hour. The System Operator shall schedule
such Energy deliveries to accommodate, to the maximum extent
possible, the schedule of Energy deliveries from Hydro-Quebec
requested by the Participant. The Participants deemed to have
received such Energy shall pay therefor the higher of the Energy
Clearing Price (together with any applicable uplift charges under
Sections 14.14 and/or 14.15 of this Agreement and/or Section 24
of the Tariff and any applicable fees for services assessed
pursuant to Section 19.2) or the price paid to Hydro-Quebec for
the Energy (or in the case of Energy received under the HQ Energy
Banking Agreement, the price paid for the related Energy
deliveries to Hydro-Quebec under the Agreement and any amount
payable to Hydro-Quebec with respect to the transaction).
14.7 PARTICIPANT PURCHASES PURSUANT TO FIRM CONTRACTS AND SYSTEM CONTRACTS.
(a) For Firm Contracts and System Contracts, the treatment of
Installed Capability, Operable Capability, Energy, Operating
Reserve and AGC between the seller and the purchaser in
determining their respective responsibilities and Entitlements
shall be as agreed between the parties and reported to the System
Operator in accordance with market operation rules approved by
the Regional Market Operations Committee. If and to the extent
necessary to implement the agreement between the parties, such
market operation rules, upon approval by the Management
Committee, shall supersede the provisions of the Agreement that
otherwise apply for determination of the respective
responsibilities and Entitlements of the parties.
(b) In the event a Participant has the right to receive Operable
Capability, Energy, Operating Reserve and/or AGC from a Non-
Participant under a System Contract or a Firm Contract, such
Contract shall be treated as nearly as possible as if it were a
Unit Contract for an Operable Capability Entitlement, Energy
Entitlement, Operating Reserve Entitlement and/or AGC
Entitlement, as applicable, PROVIDED THAT, in the case of Energy,
Operating Reserve, and/or AGC, the System Contract or Firm
Contract permits the scheduling of deliveries of such Energy,
Operating Reserve and/or AGC to be subject in whole or part to
central dispatch through the System Operator in accordance with
market operation rules approved by the Regional Market Operations
Committee.
14.8 DETERMINATION OF ENERGY CLEARING PRICE.
For each hour, the System Operator shall determine the Energy Clearing
Price as follows:
(a) The System Operator shall rank in the order of lowest to highest
(i) the Dispatch Prices derived from the Bid Prices to furnish
Energy in the hour and (ii) the cost to NEPOOL of any Energy
received from Non-Participants in the hour pursuant to contracts
referenced in Section 14.6.
(b) The Energy Clearing Price shall be the weighted average of the
Dispatch Prices (or NEPOOL cost) of the "Energy Clearing Price
Block" as defined in the next sentence. The Energy Clearing
Price Block shall be identified for each hour in accordance with
market operation rules approved by the Regional Market Operations
Committee to reflect those resources with the highest Dispatch
Prices or NEPOOL cost that were centrally dispatched by the
System Operator for Energy deemed to have been furnished to the
Participants, excluding resources that were dispatched out of
merit as determined in accordance with market operation rules
approved by the Regional Market Operations Committee.
14.9 DETERMINATION OF OPERATING RESERVE SELLING PRICE AND CLEARING PRICE.
(a) For each hour as necessary, the System Operator shall determine
the Operating Reserve Clearing Price for each category of
Operating Reserve as follows:
(i) The System Operator shall determine the aggregate Kilowatts
of the applicable category of Operating Reserve that are
deemed pursuant to Section 14.3(b) to have been received by
Participants for the hour.
(ii) For 10-Minute Non-Spinning Reserve and 30-Minute Operating
Reserve, the System Operator shall rank in the order of
lowest to highest the Bid Prices of the resources designated
by the System Operator for that category of Operating
Reserve for the hour. The applicable Operating Reserve
Clearing Price for 10-Minute Non-Spinning Reserve or 30-
Minute Operating Reserve shall be the weighted average of
the highest Bid Prices for the 1000 Kilowatts (or such other
number as may be specified by the Regional Market Operations
Committee) of that category of Operating Reserve that are
designated by the System Operator for use in the hour.
(iii)For 10-Minute Spinning Reserve the System Operator shall
rank in order of lowest to highest the sum for each
Operating Reserve Entitlement of (A) the Bid Price for such
Entitlement and (B) the lost opportunity costs (as defined
in Section 14.9(d)(ii)). The Operating Reserve Clearing
Price for 10-Minute Spinning Reserve shall be the weighted
average for the 1000 Kilowatts (or such other number as may
be specified by the Regional Market Operations Committee) of
the highest sums for the hour of the Entitlements that were
designated by the System Operator for use in the hour.
(b) The Operating Reserve Selling Price for any hour for each
Kilowatt of 10-Minute Non-Spinning Reserve and 30-Minute
Operating Reserve deemed to be furnished by a Participant in the
hour pursuant to Section 14.3(b) shall be the applicable
Operating Reserve Clearing Price determined in accordance with
Section 14.9(a).
(c) Prior to the Third Effective Date, the Operating Reserve Selling
Price for any hour for each Kilowatt of 10-Minute Spinning
Reserve deemed to be furnished by a Participant from one of its
generating units designated for the hour by the System Operator
for 10-Minute Spinning Reserve pursuant to Section 14.3(b) shall
be an amount equal to the sum of the "Lost Opportunity Clearing
Price" and the lost opportunity cost (as defined in Section
14.9(d)(ii)), if any, for the generating unit, both as determined
pursuant to Section 14.9(d) below. On and after the Third
Effective Date, the Operating Reserve Selling Price for an hour
for 10-Minute Spinning Reserve shall be the applicable Operating
Reserve Clearing Price for that hour.
(d) Prior to the Third Effective Date, for each hour, the System
Operator shall determine a Lost Opportunity Clearing Price for
use in determining the Operating Reserve Selling Price for 10-
Minute Spinning Reserve. A Lost Opportunity Clearing Price shall
be calculated for every hour as follows:
(i) The System Operator shall determine the Kilowatts of 10-
Minute Spinning Reserve that it designated and required for
the hour.
(ii) For that hour, the System Operator shall rank in order of
lowest to highest the lost opportunity costs for generating
units designated by the System Operator to provide 10-Minute
Spinning Reserve in the hour. For purposes of this Section
14.9, the lost opportunity cost for a Participant's
generating unit shall be the amount by which the Energy
Clearing Price for the hour exceeds the unit's Dispatch
Price (not less than zero), PLUS, in the case of
hydroelectric generating facilities and pumped storage
hydroelectric generating facilities, the Bid Price in the
hour for each facility to provide 10-Minute Spinning
Reserve.
(iii)The Lost Opportunity Clearing Price for an hour shall be the
weighted average of the highest 1000 Kilowatts (or such
other number as may be specified by the Regional Market
Operations Committee) of lost opportunity costs for
generating units that were designated by the System Operator
to provide 10-Minute Spinning Reserve in the hour.
14.10DETERMINATION OF AGC CLEARING PRICE.
For each hour, the System Operator shall determine the AGC Clearing
Price. The AGC Clearing Price shall be the weighted average "AGC
Capability Price" for the "AGC Clearing Price Block," as both terms
are defined below in this Section 14.10. The AGC Capability Price for
each hour for each AGC Entitlement designated by the System Operator
to provide AGC in the hour shall be a cost per unit of AGC capability
based on the Bid Price for the Entitlement for the hour divided by the
amount of AGC available in the hour from that Entitlement. The AGC
Clearing Price Block shall be identified by the System Operator for
each hour in accordance with market operation rules approved by the
Regional Market Operations Committee to reflect those AGC resources
with the highest Bid Prices that were designated by the System
Operator to provide AGC in the hour and were deemed pursuant to
Section 14.3(c) to have been received by Participants for the hour.
14.11FUNDS TO OR FROM WHICH PAYMENTS ARE TO BE MADE.
(a) All payments for Energy, Operating Reserves or AGC furnished
or received, all uplift charges paid pursuant to this
Section 14 of this Agreement and Section 24 of the Tariff,
and all fees for services paid pursuant to Section 19.2, and
any payments by Non-Participants for ancillary services
under Schedules 2-7 to the Tariff or pursuant to
arrangements referenced in Section 14.6, shall be allocated
each month through the Pool Interchange Fund as follows:
STEP ONE. For each week in which Energy is delivered or
received under the HQ Energy Banking Agreement, all payments
with respect to transactions under that Agreement shall be
made to or from the Energy Banking Fund provided for in
Section 14.11(b).
STEP TWO. (i) For each week in which Pre-Scheduled Energy
(as defined in the HQ Phase I Energy Contract) is purchased
pursuant to the HQ Phase I Energy Contract, the aggregate
amount which is paid pursuant to Section 14.6(b) for such
Energy by each Participant which is a participant in the
Phase I arrangements with Hydro-Quebec shall be determined
and paid on the Participant's account into the Phase I
Savings Fund.
(ii) For each week in which Energy is purchased pursuant to
the HQ Phase II Firm Energy Contract, the aggregate amount
which is paid pursuant to Section 14.6(b) for such Energy by
each Participant which is a participant in the Phase II
arrangements with Hydro-Quebec shall be determined and paid
on the Participant's account into the Phase II Savings Fund.
STEP THREE. For each week in which Other HQ Energy is
purchased pursuant to the HQ Phase I Energy Contract or
Energy is purchased pursuant to the HQ Interconnection
Agreement, the aggregate amount paid pursuant to Section
14.6(b) for such Energy shall be determined for each
Participant which is a participant in the Phase I or Phase
II arrangements with Hydro-Quebec. Such amount shall be
allocated between the Participant's share of the Phase I
Savings Fund and the Participant's share of the Phase II
Savings Fund created under the HQ Use Agreement in the same
ratio as (A) the sum of (x) the number of kilowatthours of
Other HQ Energy deemed to be purchased by the Participant
during the week and (y) the HQ Phase I Percentage of the
number of kilowatthours deemed to be purchased by the
Participant under the HQ Interconnection Agreement during
the week, bears to (B) the HQ Phase II Percentage of the
number of kilowatthours purchased under the HQ
Interconnection Agreement during the week.
STEP FOUR. The balance remaining in the Pool Interchange
Fund after Steps One through Three shall be retained in the
Pool Interchange Fund for the month and shall be used and
disbursed after each month in the following order:
(i) (A) amounts owed to Non-Participants (other than Hydro-
Quebec) for the month under contracts entered into with
them pursuant to Section 14.6(a) shall be paid, and (B)
amounts owed to Hydro-Quebec for the month for Energy
deemed to be furnished pursuant to Section 14.6(b) to
Participants which are not participants in the Phase I
or Phase II arrangements with Hydro-Quebec shall be
paid and, in the event the price paid by any such
Participant for such Energy is the Energy Clearing
Price, the excess, if any, of the Energy Clearing Price
over the amount owed to Hydro-Quebec shall be paid to
the Participant;
(ii) amounts paid by Participants for applicable fees for
services assessed pursuant to Section 19.2 shall be
used to reduce NEPOOL expenses; and
(iii)amounts owed to Participants for the month pursuant to
Section 14.5 shall then be paid.
(b) HQ ENERGY BANKING FUND. All amounts allocated to the HQ
Energy Banking Fund for each month shall be used and
disbursed as follows:
(i) Participants which furnish Energy for delivery to
Hydro-Quebec under the HQ Energy Banking Agreement
shall receive therefor from their share of the Energy
Banking Fund the amount to which they are entitled for
such service in accordance with Section 14.5.
(ii) amounts required to be paid to Hydro-Quebec under the
HQ Energy Banking Agreement shall be paid from the
shares of the Fund of the Participants engaging in
transactions under the HQ Energy Banking Agreement for
the month in accordance with their respective interests
in the transactions for the month. If there is not
enough in any such share, the Participants with the
deficient shares shall be billed and pay into their
shares of the Fund the amounts required for payments to
Hydro-Quebec.
(iii)subject to the remaining provisions of this Section, at
the end of each month any balance remaining in each
Participant's share of the HQ Energy Banking Fund shall
(I) in the case of any Participant which is not a
participant in the Phase I or Phase II arrangements
with Hydro-Quebec, be paid to such Participant, and
(II) in the case of any Participant which is a
participant in the Phase I or Phase II arrangements
with Hydro-Quebec, be paid to the Escrow Agent under
the HQ Use Agreement to be held and disbursed by it
through the Phase I Savings Fund and Phase II Savings
Fund created under the HQ Use Agreement, and shall be
allocated between the Participant's share of said Funds
as follows:
(A) the balance remaining in the Participant's share
of the HQ Energy Banking Fund for the month shall
be divided by the number of kilowatthours deemed
to be received by the Participant under the HQ
Energy Banking Agreement during the month to
determine an average savings amount per
kilowatthour;
(B) for any hour during the month in which the number
of kilowatthours received by NEPOOL under the HQ
Energy Banking Agreement exceeded the HQ Phase I
Transfer Capability, an amount EQUAL TO (A) the
Participant's share of the excess of (1) the
number of kilowatthours received over (2) the HQ
Phase I Transfer Capability TIMES (B) the average
savings amount per kilowatthour determined for
that Participant under (i) above shall be
allocated to the Phase II Savings Fund; and
(C) the remaining balance of the Participant's share
of the HQ Energy Banking Fund for the month shall
be allocated to the Phase I Savings Fund.
It is recognized that, in view of the time which may elapse
between the delivery of Energy to or by Hydro-Quebec in an
Energy Banking transaction under the HQ Energy Banking
Agreement and the return of the Energy, the amounts of
Energy delivered to and received from Hydro-Quebec, after
adjustment for losses, may not be in balance at the end of a
particular month.
Further, if as of the end of any month and after adjustment
for electrical losses, the cumulative amount of Energy so
received from Hydro-Quebec exceeds the amount so delivered,
the aggregate amount paid by Participants for the excess
Energy pursuant to Section 14.6(b) shall be paid to the
Energy Banking Fund. The Escrow Agent under the HQ Use
Agreement shall hold and invest these funds. On the return
of the excess Energy to Hydro-Quebec, the amount so held by
the Escrow Agent shall be repaid to Hydro-Quebec and
Participants in accordance with the Energy Banking
Agreement.
(c) PHASE I HQ SAVINGS FUND. The aggregate amount allocated to
each Participant's share of the Phase I HQ Savings Fund for
each month shall be used, first, to pay to Hydro-Quebec the
amount owed to it for the month for Energy furnished under
the Phase I HQ Energy Contract and the HQ Phase I Percentage
of the amount owed to it for the month for Energy furnished
to the Participants under the HQ Interconnection Agreement.
The balance of the amount allocated to the Fund for the
month shall be paid to the Escrow Agent under the HQ Use
Agreement to be held and disbursed by it through the Phase I
HQ Savings Fund created thereunder in accordance with each
Participant's contribution to such balance.
(d) PHASE II HQ SAVINGS FUND. The aggregate amount allocated to
the Phase II HQ Savings Fund for each month shall be used,
first, to pay to Hydro-Quebec the amount owed to it for the
month for Energy deemed to be furnished to the Participant
under the Phase II HQ Firm Energy Contract and the HQ Phase
II Percentage of the amount owed to it for the month for
Energy deemed to be furnished to the Participant under the
HQ Interconnection Agreement. The balance of the amount
allocated to the Fund for the month shall be paid to the
Escrow Agent under the HQ Use Agreement to be held and
disbursed by it through the Phase II HQ Savings Fund created
thereunder in accordance with each Participant's
contribution to such balance.
14.12DEVELOPMENT OF RULES RELATING TO NUCLEAR AND HYDROELECTRIC GENERATING
FACILITIES, LIMITED-FUEL GENERATING FACILITIES, AND INTERRUPTIBLE
LOADS.
It is recognized that the central dispatch of Energy available from
nuclear generating facilities and from pondage associated with
hydroelectric generating facilities and from interruptible loads and
of pumping Energy for pumped storage hydroelectric generating
facilities and other limited-fuel generating facilities involves
special problems which must be resolved to assure fair and non-
discriminatory treatment of Participants having Entitlements in such
generating facilities or having such interruptible loads or any other
Participants involved in such transactions. Accordingly, the Regional
Market Operations Committee shall analyze such special problems and
develop appropriate rules for dispatching such facilities (including,
but not limited to, bids for dispatchable pumping load at pumped
storage facilities), for handling such interruptible loads and for
paying for Operable Capability, Energy, Operating Reserve and AGC
involved in such transactions on a basis consistent with the
principles underlying this Section 14; and upon approval by the
Management Committee such rules shall supersede the provisions of
Sections 12 and 14 to the extent of any conflict.
14.13DISPATCH AND BILLING RULES DURING ENERGY SHORTAGES. It is recognized
that Energy shortages can result in special problems which must be
resolved to assure that dispatch and billing provisions do not prevent
achievement of the objectives specified in Section 13.4. Accordingly,
the Regional Market Operations Committee shall analyze such special
problems and develop appropriate dispatch and billing rules to be
applied during periods when the Management Committee determines that
there is, or is anticipated to be, an Energy shortage which adversely
affects the bulk power supply of the NEPOOL Control Area and any
adjoining areas served by Participants. Upon approval by the
Management Committee, such rules shall supersede the economic dispatch
and billing provisions of this Agreement to the extent of any conflict
therewith for the duration of such Energy shortage period.
14.14CONGESTION UPLIFT.
(a) It shall be the responsibility of the Management Committee
to review prior to January 1, 2000 the Congestion Costs
incurred with the new market arrangements contemplated by
Section 14 of this Agreement and with retail access, and to
determine whether subsection (b) of this Section, together
with an amendment specifying the rights of Participants and
Non-Participants across a constrained interface within the
NEPOOL Control Area and to make other necessary or
appropriate changes in subsection (b), all of the provisions
of which shall be considered for modification, or some other
modified or substitute provision dealing with the allocation
of Congestion Costs in a constrained transmission area,
should be made effective on January 1, 2000 and after the
preparation of necessary implementing rules and computer
software or on an earlier or later effective date. If the
Management Committee determines that such a provision should
be made effective, it shall recommend to the Participants
any required amendment to the Agreement and/or the Tariff
and a schedule for implementation which will permit
sufficient time for the development of necessary rules and
computer software. If the Management Committee is unable to
agree on such a determination prior to January 1, 2000 any
Participant or group of Participants may propose such an
amendment and schedule in a filing with the Commission.
(b) Commencing on January 1, 2000, but subject to the adoption
of an amendment specifying the rights of Participants and
Non-Participants across constrained interfaces within the
NEPOOL Control Area and making other necessary or
appropriate changes in the language of this subsection (b),
and the preparation of necessary implementing rules and
computer software, (or on such earlier or later date as is
fixed by the Management Committee in accordance with
subsection (a) of this Section), whenever limitations in
available transmission capacity in any hour require that the
System Operator dispatch out-of-merit resources that are bid
by the Participants in any area which is determined to be a
constrained transmission area in accordance with market
operation rules approved by the Regional Market Operations
Committee and the Regional Transmission Operations
Committee, the System Operator shall determine for the
constrained transmission area the aggregate Congestion Costs
for the hour.
Such Congestion Costs for each hour shall be allocated to
and paid by Participants and Non-Participants as a
congestion uplift as follows:
(i) In accordance with market operation rules approved by
the Regional Market Operations Committee and the
Regional Transmission Operations Committee, the System
Operator shall identify for each Participant and Non-
Participant the difference in megawatt hours, if any,
between (A) Electrical Load served by the Participant
or Non-Participant in the constrained area and
transactions by the Participant or Non-Participant
occurring in the hour which utilized the constrained
interface to move Energy through the constrained area
and (B) the Participant's or Non-Participant's in-merit
Energy Entitlements located in the constrained area
that were used in the hour to serve such Electrical
Load, taking into account Firm Contracts and System
Contracts between Participants and electrical losses,
if and as appropriate.
(ii) The System Operator shall identify for each Participant
and Non-Participant the megawatt hours, if any, of the
rights of that Participant or Non-Participant to use
the then effective transfer capability across the
constrained interface.
(iii)The System Operator shall identify for each Participant
and Non-Participant the megawatt hours, if any, by
which the amount determined pursuant to clause (i)
above for that Participant or Non-Participant exceeds
the amount determined for that Participant or Non-
Participant pursuant to clause (ii) above. If the
clause (i) amount exceeds the clause (ii) amount, the
Participant or Non-Participant shall be responsible for
paying a share of the aggregate Congestion Costs in
proportion to the Participant's or Non-Participant's
share of the aggregate amount of such excesses for all
Participants and Non-Participants, and such Congestion
Costs shall be included, as a transmission charge, in
the Regional Network Service, Internal Point-to-Point
Service or Through or Out Service charge, whichever is
applicable.
(c) As used in this Section 14.14, the "Congestion Cost" of an
out-of-merit resource for an hour means the product of (i)
the difference between its Dispatch Price and the Energy
Clearing Price for the hour, times (ii) the number of
megawatt hours of out-of-merit generation produced by the
resource for the hour.
14.15ADDITIONAL UPLIFT CHARGES. It is recognized that the System Operator
may be required from time to time to dispatch resources out of merit
for reasons other than those covered by Section 14.14 of this
Agreement and Section 24 of the Tariff. Accordingly, if and to the
extent appropriate, feasible and practical, dispatch and operational
costs shall be categorized and allocated as uplift costs to those
Participants and Non-Participants that are responsible for such costs.
Such allocations shall be determined in accordance with market
operation rules that are consistent with this Agreement and any
applicable regulatory requirements and approved by the Regional Market
Operations Committee.
PART FOUR
TRANSMISSION PROVISIONS
SECTION 15
OPERATION OF TRANSMISSION FACILITIES
15.1 DEFINITION OF PTF. PTF or pool transmission facilities are the
transmission facilities owned by Participants rated 69 kV or above
required to allow energy from significant power sources to move freely
on the New England transmission network, and include:
1. All transmission facilities owned by Participants classified as
PTF, but only so long as, in the case of each such facility, the
facility remains in service and continues to meet the definition
of PTF as in effect under this Agreement on April 1, 1998.
2. All other transmission lines and associated facilities owned by
Participants rated 69 kV and above, except for lines and
associated facilities that contribute little or no parallel
capability to the NEPOOL Transmission System (as defined in the
Tariff). The following do not constitute PTF:
(a) Those lines and associated facilities which are required to
serve local load only.
(b) Generator leads, which are defined as radial transmission
from a generation bus to the nearest point on the NEPOOL
Transmission System.
(c) Lines that are normally operated open.
(d) High voltage direct current lines and associated facilities
which serve to connect the PTF system to a system outside
the NEPOOL Control Area.
3. Parallel linkages in network stations owned by Participants
(including substation facilities such as transformers, circuit
breakers and associated equipment) interconnecting the lines
which constitute PTF.
4. Rights of way and land owned by Participants required for the
installation of facilities which constitute PTF under (1), (2) or
(3) above.
The Regional Transmission Planning Committee shall review at least
annually the status of transmission lines and related facilities and
determine whether such facilities constitute PTF and shall prepare and
keep current a schedule or catalogue of PTF facilities.
The following examples indicate the intent of the above definitions:
(i) Radial tap lines to local load are excluded.
(ii) Lines which loop, from two geographically separate points on
the NEPOOL Transmission System, the supply to a load bus
from the NEPOOL Transmission System are included.
(iii)Lines which loop, from two geographically separate points on
the NEPOOL Transmission System, the connections between a
generator bus and the NEPOOL Transmission System are
included.
(iv) Radial connections or connections from a generating station
to a single substation or switching station on the NEPOOL
Transmission System are excluded.
Transmission facilities owned by a Related Person of a Participant
which are rated 69 kV or above and are required to allow Energy from
significant power sources to move freely on the New England
transmission network shall also constitute PTF provided (i) such
Related Person files with the Secretary of the Management Committee
its consent to such treatment; and (ii) the Management Committee
determines that treatment of the facility as PTF will facilitate
accomplishment of NEPOOL's objectives. If a facility constitutes PTF
pursuant to this paragraph, it shall be treated as "owned" by a
Participant for purposes of the Tariff and the other provisions of
Part Four of the Agreement.
15.2 MAINTENANCE AND OPERATION IN ACCORDANCE WITH GOOD UTILITY PRACTICE.
Each Participant which owns or operates PTF or other transmission
facilities rated 69 kV or above shall, to the fullest extent
practicable, cause all such transmission facilities owned or operated
by it to be designed, constructed, maintained and operated in
accordance with Good Utility Practice.
15.3 CENTRAL DISPATCH. Each Participant which owns or operates PTF or
other transmission facilities rated 69 kV or above shall, to the
fullest extent practicable, subject all such transmission facilities
owned or operated by it to central dispatch by the System Operator;
provided, however, that each Participant shall at all times be the
sole judge as to whether or not and to what extent safety requires
that at any time any of such facilities will be operated at less than
their full capability or not at all.
15.4 MAINTENANCE AND REPAIR. Each Participant shall, to the fullest extent
practicable: (a) cause transmission facilities owned or operated by it
to be withdrawn from operation for maintenance and repair only in
accordance with maintenance schedules reported to and published by the
System Operator in accordance with procedures approved or established
by the Regional Transmission Operations Committee from time to time,
(b) restore such facilities to good operating condition with
reasonable promptness, and (c) in emergency situations, accelerate
maintenance and repair at the reasonable request of the System
Operator in accordance with rules approved by the Regional
Transmission Operations Committee.
15.5 ADDITIONS TO OR UPGRADES OF PTF. The possible need for an addition to
or upgrade of PTF may be identified in connection with an application
or request for service under the Tariff, or in connection with a
request for the installation of or material change to a generation or
transmission facility, or may be separately identified by a NEPOOL
committee, a Participant or the System Operator. In such cases, a
study, if necessary, to assess available transmission capacity and, if
necessary, a System Impact Study and a Facility Study shall be
performed by the affected Participant(s) in whose Local Network(s) the
addition or upgrade would or might be effected or their designee(s),
or the Regional Transmission Planning Committee and/or the System
Operator, in the case of a System Impact Study, or the Committee's or
the System Operator's designee(s) with review of the study by the
System Operator if it does not perform the study. Studies to assess
available transmission capacity and System Impact Studies and
Facilities Studies shall be conducted, as appropriate, in accordance
with the affected Participant's Local Network Service Tariff, or in
accordance with the applicable methodology specified in Attachments C
and D to the Tariff, and the provisions of the Local Network Service
Tariff or the applicable provisions of Attachments I and J to the
Tariff shall apply, as appropriate, with respect to the payment of the
costs of the study and the other matters covered thereby.
If any of the studies referred to above indicates that new PTF
facilities or a facility modification or other PTF upgrades are
necessary to provide the requested service, or in connection with a
new or modified generation or transmission facility, or otherwise in
order to ensure adequate, economic and reliable operation of the bulk
power supply systems of the Participants for regional purposes,
whether or not a particular customer is benefited, upon approval of
the studies by the Regional Transmission Planning Committee, subject
to review by the System Operator, one or more Transmission Providers
shall be designated by the Regional Transmission Planning Committee,
subject to review by the System Operator, to design and effect the
construction or modification.
Upon the designation of a Transmission Provider to design and effect a
PTF addition or upgrade and the fixing of the cost responsibilities of
the Participants and Non-Participants and agreement as to the security
and other provisions of said arrangement, the Transmission Provider
designated to perform the construction shall, in accordance with the
terms of such arrangement and subject to Sections 18.4 and 18.5, use
its best efforts to obtain any necessary public approvals or permits,
to acquire any required rights of way or other property, and to effect
the proposed construction or modification.
Responsibility for the costs of new PTF or any modification or other
upgrade of PTF required in connection with an application or request
for service under the Tariff and any related matter shall be
determined in accordance with Parts V and VI and Schedule 11 to the
Tariff, including without limitation the provisions relating to
responsibility for the costs of new PTF or modifications or other
upgrades to PTF exceeding regional system, regulatory or other public
requirements set forth in paragraph (ii) of Schedule 11 to the Tariff.
SECTION 16
SERVICE UNDER TARIFF
16.1 EFFECT OF TARIFF. The Tariff specifies the terms and conditions under
which the Participants will provide regional transmission service
through NEPOOL. This Section 16 specifies various rights and
obligations with respect to the revenues to be collected by NEPOOL for
the Participants under the Tariff and related matters.
16.2 OBLIGATION TO PROVIDE REGIONAL SERVICE. The Participants which own
PTF shall collectively provide through NEPOOL regional transmission
service over their PTF facilities, and the facilities of their Related
Persons which constitute PTF in accordance with Section 15.1, to other
Participants and other Eligible Customers pursuant to the Tariff. The
Tariff provides open access for all of the types of regional
transmission service required by Participants and other Eligible
Customers over PTF and it is intended to be the only source of such
service, except for service provided for Excepted Transactions.
16.3 OBLIGATION TO PROVIDE LOCAL NETWORK SERVICE. Each Participant which
owns transmission facilities other than PTF shall provide service over
such facilities to other Participants or other Eligible Customers
connected to the Transmission Provider's transmission system pursuant
to a tariff (a "Local Network Service Tariff") filed by the
Transmission Provider with the Commission. A Participant is also
obligated to provide service under its Local Network Service Tariff or
otherwise (i) to permit a Participant or other Entity with an
Entitlement in a generating unit in the Participant's local network to
deliver the output of the generating unit to an interconnection point
on PTF and (ii) to permit the delivery to an Eligible Customer taking
Internal Point-to-Point Service under the Tariff of the Energy and/or
capacity covered by its Completed Application for that Internal Point-
to-Point Service.
A Local Network Service Tariff shall provide:
(i) for a pro rata allocation of monthly revenue requirements not
otherwise paid for through charges to Eligible Customers for
Local Point-to-Point Service among the Transmission Provider's
Network Customers receiving service under the tariff on the basis
of their loads during the hour in the month in which the total
connected load to the Local Network is at its maximum, without
any adjustment for credits for generation;
(ii) for the recovery under the Local Network Service Tariff from
Network Customers and Eligible Customers taking Internal Point-
to-Point Service of that portion of the Transmission Provider's
annual transmission revenue requirements with respect to PTF
which is not recovered through the distribution of revenues from
Regional Network Service or Internal Point-to-Point Service
pursuant to Section 16.6;
(iii)that where all or a part of the load of a Participant or other
Eligible Customers taking service under the tariff is connected
directly to PTF, the Participant or other Eligible Customers
receiving the service shall pay each Year during the Transition
Period for such service with respect to the load directly
connected to PTF the percentage specified in the schedule below
of the applicable Local Network Service Tariff charge for service
across non-PTF transmission facilities and shall have no
obligation to pay charges for service across non-PTF transmission
facilities with respect to that portion of the connected load
after the Transition Period, but shall continue to pay its share
of any other Local Network Service costs directly associated with
the PTF-connected load; provided that in the event of any
inconsistency between the foregoing provisions and the terms of
any Excepted Transaction which is listed in Attachment G-1 to the
Tariff, the Excepted Transaction shall control:
<TABLE>
<CAPTION>
YEAR ONE YEAR TWO YEAR THREE YEAR FOUR YEAR FIVE
<S> <C> <C> <C> <C> <C>
% of charge
to be paid 100% 80% 60% 40% 20%
</TABLE>
(iv) that if the Transmission Provider receives a distribution
pursuant to Section 16.6 from NEPOOL out of revenues paid for
Through or Out Service, the amounts received shall reduce its
Local Network Service revenue requirements; and
(v) that if the Transmission Provider receives transmission revenues
from an Eligible Customer taking Local Network Service from that
Transmission Provider with respect to an Excepted Transaction,
the amounts received shall reduce the amount due from such
Eligible Customer connected to the Transmission Provider's
transmission system for Local Network Service provided thereto by
the Transmission Provider rather than reducing the Transmission
Provider's total cost of service.
16.4 TRANSMISSION SERVICE AVAILABILITY. The availability of transmission
capacity to provide transmission service under the Tariff shall be
determined in accordance with the Tariff. In determining the
availability of transmission capacity, existing committed uses of the
Participants' transmission facilities shall include uses for existing
firm loads and reasonably forecasted changes in such loads, and for
Excepted Transactions.
16.5 TRANSMISSION INFORMATION. Information concerning (i) available
transmission capacity, (ii) transmission rates and (iii) system
conditions that may give rise to Interruptions or Curtailments shall
be made available to all Participants and Non-Participants through the
OASIS on a timely and non-discriminatory basis. All Participants
owning PTF or other transmission facilities rated 69 kV or higher
shall make available to the System Operator the information required
to permit the maintenance of the OASIS in compliance with Commission
Order 889 and any other applicable Commission orders; provided that no
Participant shall be required to furnish information which is required
to be treated as confidential in accordance with NEPOOL policy without
appropriate arrangements to protect the confidentiality of such
information.
16.6 DISTRIBUTION OF TRANSMISSION REVENUES. Payments required by the
Tariff for the use of the NEPOOL Transmission System shall be made to
NEPOOL and shall be distributed by it in accordance with this Section
16.6.
A. REGIONAL NETWORK SERVICE REVENUES. Revenues received by NEPOOL
for providing Regional Network Service each month during the
Transition Period shall be distributed to the Participants owning
or supporting PTF in part on the basis of allocated flows for the
region as determined in accordance with the methodology specified
in Attachment A to this Agreement and in part in proportion to
the respective Annual Transmission Revenue Requirements for PTF
of the owners and supporters, in accordance with the following
Schedule:
<TABLE>
<CAPTION>
YEAR ONE YEAR TWO YEAR THREE YEAR FOUR YEAR FIVE
<S> <C> <C> <C> <C> <C>
Allocated
flows: 25% 20% 15% 10% 5%
Annual
Transmission
Revenue
Requirements 75% 80% 85% 90% 95%
</TABLE>
Revenues received by NEPOOL for providing Regional Network
Service each month after the Transition Period shall be
distributed to the Participants owning or supporting PTF in
proportion to their respective Annual Transmission Revenue
Requirements for PTF.
B. THROUGH OR OUT SERVICE REVENUES. The revenues received by NEPOOL
each month for providing Through or Out Service shall be
distributed among the Participants owning PTF on the basis of
allocated flows for the transaction determined in accordance with
the methodology specified in Attachment A to this Agreement;
provided that for service provided during the Transition Period
but not thereafter, for an "Out" transaction which originates on
the system of a Participant which owns the PTF interconnection
facilities on the New England side of the interface with the
other Control Area over which the transaction is delivered, 100%
of the megawatt mile flows with respect to the transaction shall
be deemed to occur on such Participant's system.
C. INTERNAL POINT-TO-POINT SERVICE REVENUES. The revenues received
by NEPOOL each month for providing Internal Point-to-Point
Service shall be distributed among the Transmission Providers
owning or supporting PTF and the Network Customers supporting PTF
on the basis of the respective Annual Transmission Revenue
Requirements for PTF under Attachment F to the Tariff.
D. ANCILLARY SERVICE PAYMENTS. The revenues received by NEPOOL
pursuant to Schedule 1 to the Tariff (scheduling, system control
and dispatch service) will be used to reimburse NEPOOL, the
System Operator (if the System Operator does not receive revenues
for that service under a separate tariff) and Participants for
the costs which are reflected in the charges for such service.
The revenues received by NEPOOL pursuant to Schedules 2-7 to the
Tariff shall be distributed prior to the Second Effective Date in
accordance with the continuing provisions of the Prior NEPOOL
Agreement and the rules adopted thereunder, and shall be
distributed on or after the Second Effective Date in accordance
with Section 14.
E. CONGESTION PAYMENTS. Any congestion uplift charge received as a
payment for transmission service pursuant to Section 24 of the
Tariff for any hour shall be applied in accordance with Section
14.5(a) in payment for Energy service.
16.7 CHANGES TO TARIFF. The Tariff constitutes part of the Agreement and
shall be subject to change either in accordance with Section 21.11 or
by an affirmative vote of members of the Management Committee having
at least 70% of the aggregate Voting Shares to which all members are
entitled; PROVIDED, HOWEVER, that the negative votes of any two or
more members representing Participants which are not Related Persons
of each other and which have at least 20% of the aggregate Voting
Shares to which all members are entitled shall defeat any proposed
change. In determining whether the negative vote total specified
above has been reached, the following limitation shall be applied: if
the member or members representing any Participant and its Related
Persons would be entitled to cast against the proposed action more
than 18% of the aggregate Voting Shares to which all members are
entitled, such member or members shall be entitled to vote negatively
only 18% of such aggregate Voting Shares. Nothing in this Agreement
shall be deemed to affect in any way the ability of any Participant or
Non-Participant to apply to the Commission under Section 205 or 206 of
the Federal Power Act for a change in any rate, charge, term,
condition or classification of service under the Tariff.
SECTION 17
POOL-PLANNED UNIT SERVICE
17.1 EFFECTIVE PERIOD. The provisions contained in this Section 17 shall
continue in effect until the fifth anniversary of the effective date
of the Tariff, and shall be of no effect after that date.
17.2 OBLIGATION TO PROVIDE SERVICE. Until the fifth anniversary of the
effective date of the Tariff, each Participant shall provide service
over its PTF facilities under this Section 17 rather than under the
Tariff, for the following purposes:
(a) the transfer to a Participant's system of its ownership
interest or its Unit Contract Entitlement under a contract
entered into by it before November 1, 1996 in a Pool-Planned
Unit which is off its system;
(b) the transfer to a Participant's system of its Entitlement in
a purchase under a contract entered into by it before
November 1, 1996 (including a purchase under the HQ Phase II
Firm Energy Contract) from Hydro-Quebec where the line over
which the transfer is made into New England is the HQ
Interconnection; and
(c) the transfer to a Non-Participant of its Entitlement in a
Pool-Planned Unit pursuant to an arrangement which has been
approved prior to November 1, 1996 by the Management
Committee.
17.3 RULES FOR DETERMINATION OF FACILITIES COVERED BY PARTICULAR
TRANSACTIONS. It is anticipated that it may be necessary with respect
to a particular transmission use under subsection (a), (b) or (c) of
Section 17.2 to determine whether the transaction is effected entirely
over PTF, entirely over facilities that are not PTF, or partially over
each.
The following rules shall be controlling in the determination of the
facilities required to effect the use:
(a) To the extent that EHV PTF is available to effect the
transaction, over all or part of the distance to be covered,
the use shall be deemed to be effected on such EHV PTF over
such portion of the distance to be covered.
(b) To the extent that EHV PTF is not available for the entire
distance to be covered by the use, but Lower Voltage PTF is
available to cover all or part of the distance not covered
by EHV PTF, the transaction shall be deemed to be effected
on such Lower Voltage PTF.
If a Participant has ownership or contractual rights with respect
to an Excepted Transaction which are independent of this
Agreement and the Tariff and are adequate to provide for a
transfer of the types specified in subsections 17.2(a), (b) or
(c), and such rights are not limited to the transfer in question,
the transfer shall be deemed to have been effected pursuant to
such rights and not pursuant to the provisions of this Agreement.
A copy of each instrument establishing such rights, or an opinion
of counsel describing and authenticating such rights, shall be
filed with the Secretary of the Management Committee.
17.4 PAYMENTS FOR USES OF EHV PTF DURING THE TRANSITION PERIOD.
(a) Each Participant shall pay each month for its uses of EHV PTF for
transfers of Entitlements pursuant to subsections (a) or (b) of
Section 17.2, one-twelfth of the NEPOOL EHV PTF Participant
Summer or Winter Wheeling Rate in effect for the calendar year
ending December 31, 1996, as determined in accordance with the
Prior NEPOOL Agreement, for each Kilowatt of its current
Entitlements which qualify for transfer pursuant to subsections
(a) or (b) of Section 17.2, except as otherwise provided in
Section 17.3; provided that such payment shall be required with
respect to only one-half the Kilowatts covered by a NEPOOL
Exchange Arrangement (as hereinafter defined).
Each Participant which is a party to the HQ Phase II Firm Energy
Contract (other than a Participant (i) whose system is directly
interconnected to the HQ Interconnection or (ii) which has
contractual rights independent of this Agreement and the Tariff
which give it direct access to the HQ Interconnection and which
are not limited to transfers of Energy delivered over the HQ
Interconnection) shall also pay each month for the use of EHV PTF
for deliveries under the Phase II Firm Energy Contract during the
Base Term of the HQ Phase II Firm Energy Contract, one-twelfth of
the NEPOOL EHV PTF Participant Summer or Winter Wheeling Rate in
effect for the calendar year ending December 31, 1996, as
determined in accordance with the Prior NEPOOL Agreement, for
each Kilowatt of its HQ Phase II Net Transfer Responsibility for
the month. If, and to the extent that, such Responsibility
continues for any period by which the term of said Contract
extends beyond the Base Term, each such Participant shall
continue to pay the above rate during the extension period with
respect to its continuing Responsibility. A Participant shall
not be deemed to be directly interconnected to the HQ
Interconnection for purposes of this paragraph solely because of
its participation in arrangements for the support and/or use of
PTF facilities installed or modified to effect reinforcements of
the New England AC transmission system required in connection
with the HQ Interconnection. A copy of each contract
establishing rights independent of this Agreement and the Tariff
which provides direct access to the HQ Interconnection, or an
opinion of counsel describing and authenticating such rights,
shall be filed with the Secretary of the Management Committee.
The NEPOOL EHV PTF Participant Summer Wheeling Rate for any
calendar year shall be applicable to the months in the Summer
Period.
The NEPOOL EHV PTF Participant Winter Wheeling Rate for any
calendar year shall be applicable to the months in the Winter
Period.
A NEPOOL Exchange Arrangement is one entered into by two
Participants each of which has an ownership interest in a Pool-
Planned Unit on its own system pursuant to which each sells out
of its ownership interest, a Unit Contract Entitlement to the
other for a period of time which is, in whole or part, the same
for both sales. Such an arrangement shall constitute a NEPOOL
Exchange Arrangement even though the beginning and ending dates
of the two Unit Contract sale periods are different, but only for
the period for which both sales are in effect. If for any period
the number of Kilowatts covered by the two Unit Contract
Entitlements of a NEPOOL Exchange Agreement are not the same, the
portion of the larger Entitlement which exceeds the amount of the
smaller Entitlement shall not be deemed to be covered by such
NEPOOL Exchange Arrangement for purposes of this Section 17.4.
(b) Each Participant shall pay each month for its use of EHV PTF for
a transfer of an Entitlement in a Pool-Planned Unit to a Non-
Participant pursuant to Section 17.2(c) such charge as is fixed
by the Management Committee at the time of its approval of the
sale, and filed with the Commission.
(c) Fifty percent of all amounts required to be paid with respect to
transfers by a Participant pursuant to subsection (a) or (b) of
Section 17.2 shall be paid to a pool transmission fund and
distributed monthly among the Participants in proportion to the
respective amounts of their costs with respect to EHV PTF for the
calendar year 1996 as determined in accordance with the Prior
NEPOOL Agreement.
(d) The remaining 50% of all amounts required to be paid with respect
to transfers by a Participant pursuant to subsections (a) or (b)
of Section 17.2 shall be paid to, and retained by, the
Participant on whose system the transfer originates, or in the
event the EHV PTF system of such Participant is supported in part
by other Participants, then to the Participant on whose system
the transfer originates and such other Participants in proportion
to the respective shares of the costs of such EHV PTF system
borne by each of them or in such other manner as the Participants
involved may jointly direct; provided that the Participant on
whose system the transfer originates shall have the right to
waive such 50% payment in whole or part as to a particular
transfer except that no such waiver may adversely affect the
payments to any other Participant which is supporting in part the
originating system's EHV PTF system.
17.5 PAYMENTS FOR USES OF LOWER VOLTAGE PTF. Each Participant which uses
another Participant's Lower Voltage PTF pursuant to this Section 17
shall pay each month to the owner of such Lower Voltage PTF (1) for
each Kilowatt of its use of such Lower Voltage PTF for transfer of
Entitlements pursuant to Subsections 17.2(a), (b) or (c) during the
month, and (2) during the Base Term of the HQ Phase II Firm Energy
Contract (and during any extension of the term of said Contract if and
to the extent its HQ Phase II Net Transfer Responsibility continues
during the extension period) for each Kilowatt of its HQ Phase II Net
Transfer Responsibility for the month, the owner's Lower Voltage PTF
Winter Wheeling Rate or Summer Wheeling Rate for the 1996 calendar
year, as determined in accordance with the Prior NEPOOL Agreement.
17.6 USE OF OTHER TRANSMISSION FACILITIES BY PARTICIPANTS. Each
Participant which has no direct connection between its system and PTF
shall be entitled to use the non-PTF transmission facilities of any
other Participant required to reach its system for any of the purposes
for which PTF may be used under Section 17.2. Such use shall be
effected, and payment made, in accordance with the other Participant's
filed open access tariff.
17.7 LIMITS ON INDIVIDUAL TRANSMISSION CHARGES.
Any charges for transmission service pursuant to this Section 17 by
any Participant to another Participant shall be just, reasonable and
not unduly discriminatory or preferential. No provision of this
Section 17 shall be construed to waive the right of any Participant to
seek review of any charge, term or condition applicable to such
transmission service by another Participant by the Commission or any
other regulatory authority having jurisdiction of the transaction.
PART FIVE
GENERAL
SECTION 18
GENERATION AND TRANSMISSION FACILITIES
18.1 DESIGNATION OF POOL-PLANNED FACILITIES.
At the request of a Participant, the Management Committee shall
designate as "pool-planned" a generating or transmission facility to
be constructed by the Participant or its Related Person if the
Management Committee determines that the facility is consistent with
NEPOOL planning. The Management Committee may not unreasonably
withhold designation as a Pool-Planned Facility of a generation unit
or other facility proposed by one or more Participants in order to
satisfy their anticipated Installed Capability Responsibilities with a
mix of generation and other resources reasonably comparable as to
economics and types to that being developed for New England.
18.2 CONSTRUCTION OF FACILITIES.
Subject to Sections 13.1, 15.2, 15.5, 18.3, 18.4 and 18.5, and to the
provisions of the Tariff, each Participant shall have the right to
determine whether, and to what extent, additions to and modifications
in its generating and transmission facilities shall be made. However,
each Participant shall give due consideration to recommendations made
to it by the Management Committee or the System Operator for any such
additions or modifications and shall follow such recommendations
unless it determines in good faith that the recommended actions would
not be in its best interest.
18.3 PROTECTIVE DEVICES FOR TRANSMISSION FACILITIES AND AUTOMATIC
GENERATION CONTROL EQUIPMENT.
Each Participant shall install, maintain and operate such protective
equipment and switching, voltage control, load shedding and emergency
facilities as the Management Committee may determine to be required in
order to assure continuity of service and the stability of the
interconnected transmission facilities of the Participants. Until the
Second Effective Date, each Participant shall also install, maintain
and operate such Automatic Generation Control equipment as the
Management Committee may determine to be required in order to maintain
proper frequency for the interconnected bulk power system of the
Participants and to maintain proper power flows into and out of the
NEPOOL Control Area.
18.4 REVIEW OF PARTICIPANT'S PROPOSED PLANS.
Each Participant shall submit to the System Operator, Management
Committee, the Market Reliability Planning Committee or the Regional
Transmission Planning Committee, as appropriate, and the Regional
Market Operations Committee or the Regional Transmission Operations
Committee, as appropriate, for review by them, in such form, manner
and detail as the Management Committee may reasonably prescribe, (i)
any new or materially changed plan for additions to, retirements of,
or changes in the capacity of any supply and demand-side resources or
transmission facilities rated 69 kV or above subject to control of
such Participant, and (ii) any new or materially changed plan for any
other action to be taken by the Participant which may have a
significant effect on the stability, reliability or operating
characteristics of its system or the system of any other Participant.
No significant action (other than preliminary engineering action)
leading toward implementation of any such new or changed plan shall be
taken earlier than sixty days (or ninety days, if the System Operator
or the Management Committee determines that it requires additional
time to consider the plan and so notifies the Participant in writing
within the sixty days) after the plan has been submitted to the
Committees. Unless prior to the expiration of the sixty or ninety
days, whichever is applicable, the Management Committee notifies the
Participant in writing that it has determined that implementation of
the plan will have a significant adverse effect upon the reliability
or operating characteristics of its system or of the systems of one or
more other Participants, the Participant shall be free to proceed.
The time limits provided by this Section 18.4 may be changed with
respect to any such submission by agreement between the Management
Committee and the Participant required to submit the plan.
18.5 PARTICIPANT TO AVOID ADVERSE EFFECT.
If the Management Committee notifies a Participant pursuant to Section
18.4 that implementation of the Participant's plan has been determined
to have a significant adverse effect upon the reliability or operating
characteristics of its system or the systems of one or more other
Participants, the Participant shall not proceed to implement such plan
unless the Participant takes such action or constructs at its expense
such facilities as the Management Committee determines to be
reasonably necessary to avoid such adverse effect; provided that if
the plan is for the retirement of a supply or demand-side resource,
the Participant may proceed with its plan only if, after engaging in
good faith negotiations with persons designated by the Management
Committee to address the adverse effects on reliability or operating
characteristics, the negotiations either address the adverse effects
to the satisfaction of the Management Committee, or no satisfactory
resolution can be achieved on terms acceptable to the parties within
90 days of the Participant's receipt of the Management Committee's
notice. Any agreement resulting from such negotiations shall be in
writing and shall be filed in accordance with the Commission's filing
requirements if it requires any payment.
SECTION 19
EXPENSES
19.1 ANNUAL FEE.
Each Participant shall pay to NEPOOL in January of each year an annual
fee of $500, which shall be applied toward NEPOOL expenses.
19.2 NEPOOL EXPENSES.
It is an objective of the Participants to work with the System
Operator to establish to the maximum extent possible fees for services
rendered that fairly allocate NEPOOL and System Operator costs
directly to the Participants and Non-Participants responsible for such
costs, rather than through the general expense allocation identified
below. Subject to the continued payment of a portion of NEPEX
Expenses from the Savings Fund until the Second Effective Date in
accordance with the Prior NEPOOL Agreement, the balance of NEPOOL
expenses remaining to be paid after the application of (i) the annual
fee to be paid pursuant to Section 19.1, and (ii) any fees or other
charges for services or other revenues received by NEPOOL, or
collected on its behalf by the System Operator, shall be allocated
among and paid monthly by the Participants in accordance with their
respective Voting Shares.
SECTION 20
INDEPENDENT SYSTEM OPERATOR
(a) The Management Committee is authorized and directed to approve
one or more agreements to be entered into with the ISO (the "ISO
Agreement") and any amendments to the ISO Agreement which the
Committee may deem necessary or appropriate from time to time.
The ISO Agreement shall specify the rights and responsibilities
of NEPOOL and the ISO, for the continued operation of the NEPOOL
control center by the ISO as the control center operator for the
NEPOOL Control Area and the administration of the Tariff. In
addition, the ISO shall be responsible for the furnishing of
billing and other services required by NEPOOL.
(b) The fees and charges of the ISO (other than fees and charges for
services which are separately billed), and any indemnification
payable under the ISO Agreement, shall be shared by the
Participants in accordance with Section 19.
(c) The Participants shall provide to the ISO the financial support,
information and other resources necessary to enable the ISO to
provide the services specified in the ISO Agreement, or in this
Agreement, in accordance with Good Utility Practice and subject
to the budgeting, approval and dispute resolution provisions of
the ISO Agreement and this Agreement.
(d) The Participants shall provide appropriate funding for the
acquisition of land, structures, fixtures, equipment and
facilities, and other capital expenditures for the ISO, which are
included in the annual budget for the ISO in accordance with the
provisions of the ISO Agreement, or otherwise specifically
approved by the Management Committee. All such land, structures,
fixtures, equipment and facilities, and other capital assets, and
all software or other intellectual property or rights to
intellectual property or other assets, acquired or developed by
the ISO in order to carry out its responsibilities under the ISO
Agreement shall be the property of the Participants or shall be
acquired by the Participants under lease in accordance with
arrangements approved by the Management Committee. Unless
otherwise agreed by the Participants, the funding of the
acquisition, or lease, of land, structures, fixtures, equipment
and facilities, and other capital expenditures, or the
acquisition of other assets, and the ownership thereof, or the
obligations of Participants as lessees, shall be in proportion to
the Voting Shares of each Participant in effect from time to
time. The Participants shall make all such assets (including the
assets of the existing NEPOOL headquarters and control center)
available for use by the ISO in carrying out its responsibilities
under the ISO Agreement. The ISO Agreement shall require the
ISO, on behalf of the Participants, to maintain and care for,
insure as appropriate, and pay any property taxes relating to,
assets made available for its use.
(e) The ISO Agreement shall require the ISO to refrain from any
action that would create any lien, security interest or
encumbrance of any kind upon the facilities, equipment or other
assets of any Participant, or upon anything that becomes affixed
to such facilities, equipment or other assets. The Participants
and the ISO shall include in the ISO Agreement a provision that,
upon the request of any Participant, the ISO shall (i) provide a
written statement that it has taken no action that would create
any such lien, security interest or encumbrance, and (ii) take
all actions within the control of the ISO, at the direction and
expense of the requesting Participant, required for compliance by
such Participant with the provisions of its mortgage relating to
such facilities, equipment or other assets.
(f) The ISO shall have the right to appoint a non-voting member and
an alternate to each NEPOOL committee other than the Management
Committee. The member appointed to each committee shall have all
of the rights of any other member of the committee except the
right to vote.
(g) The ISO shall have the same rights as a Participant to appeal to
the Management Committee any action taken by any other NEPOOL
committee, and shall be entitled to appear before the Management
Committee on any such appeal. Further, the ISO shall be entitled
to submit any dispute with respect to a vote of the Management
Committee to approve, modify, or reject a proposed action to
resolution in accordance with Section 21.1, whether or not the
action could have been submitted by a Participant in accordance
with Section 21.1A. In addition, the ISO shall be entitled to
submit any dispute with respect to a vote of the Management
Committee which denies an appeal to the Management Committee by
the ISO or which takes action on any rulemaking issue to the
Board of Directors of the ISO for determination, subject to the
right of the Management Committee to seek a review in accordance
with the Alternate Dispute Resolution procedures or by the
Commission. The ISO shall give notice of any such submission to
the Secretary of the Management Committee within ten days of the
action of the Management Committee and shall mail a copy of such
notice to each member of the Management Committee. Pending final
action on the submission in accordance with Section 21.1 or by
the Board of Directors of the ISO or the Commission, as
appropriate, the giving of notice of the submission shall suspend
the Management Committee's action. Unless the Board of Directors
of the ISO acts within 60 days of the ISO's notice to the
Management Committee, the Management Committee action will be
deemed to be approved.
(h) The ISO Agreement shall specify the ISO's independent authority
with respect to rulemaking.
(i) NEPOOL and its committees and the ISO shall consult and
coordinate from time to time with the relevant state regulatory,
siting and other authorities of the six New England states on
operating, planning and other issues of concern to the states.
The New England Conference of Public Utilities Commissioners,
Inc. (NECPUC) or its designee shall be furnished notices of
meetings of all NEPOOL committees and the Board of Directors of
the ISO, and minutes of their meetings. NECPUC and other state
authorities shall be provided an appropriate opportunity to
appear at meetings of the NEPOOL committees and the Board of
Directors of the ISO and to present their views. Representatives
of NEPOOL and the ISO shall be designated to attend meetings of
NECPUC or any committee or task force of NECPUC, to the extent
NECPUC or its committee or task force may deem such attendance
appropriate.
SECTION 21
MISCELLANEOUS PROVISIONS
21.1 ALTERNATIVE DISPUTE RESOLUTION.
A. GENERAL:
If the ISO is aggrieved by a vote of the Management Committee to
approve, modify or reject a proposed action under this Agreement,
including the Tariff, it may submit the matter for resolution
hereunder. If the Management Committee is aggrieved by an action
of the ISO Board of Directors ("ISO Board") under this Agreement,
including the Tariff or the ISO Agreement (as defined in Section
20(a)), the Management Committee may submit the matter for
resolution hereunder; provided, however, that if the action of
the ISO relates to rulemaking, the Management Committee may
submit the matters for resolution under this Section 21.1 only
with the concurrence of the ISO. Any Participant which is
aggrieved by a vote of the Management Committee to approve,
modify or reject a proposed action under this Agreement,
including the Tariff, may, as provided below, submit the matter
for resolution hereunder if the vote:
(1) requires such Participant to make a payment or to take any
action pursuant to this Agreement; or
(2) reduces the amount of any receipt or forbids, pursuant to
this Agreement, the taking of any action by the Participant;
or
(3) fails to afford it any right to which it is entitled under
the provisions of this Agreement or imposes on it a burden
to which it is not subject under the provisions of this
Agreement; or
(4) results in the termination of the Participant's status as a
Participant or imposes any penalty on the Participant; or
(5) results in an allocation of transmission or other facilities
support obligations; or
(6) fails to grant in full an application for transmission
service pursuant to the Tariff.
No legal or regulatory proceeding (except those reasonably
necessary to toll statutes of limitations, claims for laches or
other bars to later legal or regulatory action) shall be
initiated by any Participant with respect to any such matter
while proceedings are pending under this Section with respect to
the matter.
B. PROCEDURE:
(1) SUBMISSION OF A DISPUTE: The ISO or a Participant seeking
review of a vote of the Management Committee shall give
written notice to the Secretary of the Management Committee
within ten business days of the vote, and shall mail or
telecopy a copy of its notice to each member of the
Management Committee. Where the Management Committee is
seeking review of an action of the ISO Board, the Management
Committee shall give written notice to the Secretary of the
ISO Board. The provider of notice under this Section shall
be referred to herein as the "Aggrieved Party."
(2) SUSPENSION OF ACTION: If the ISO seeks review of a vote of
the Management Committee pursuant to this Section, the vote
to be reviewed shall be suspended pending resolution of such
review by the arbitrator or the Commission if raised in
regulatory proceedings. If a Participant seeks such a
review, the vote to be reviewed shall be suspended for up to
90 days following the giving of the Participant's notice
pending resolution of any arbitration proceeding unless the
Management Committee determines that the suspension will
imperil the stability or reliability of the NEPOOL Control
Area bulk power supply.
(3) AGGRIEVED PARTY OPTIONS: (i) If the notice is to seek review
of a vote of the Management Committee, the Aggrieved Party's
notice to the Management Committee shall invoke arbitration
as described herein in its notice pursuant to paragraph
B(1), and may also initiate mediation with the agreement of
the Management Committee, while reserving such Party's right
to proceed with the arbitration if mediation does not
resolve the matter within 20 days of the giving of the
Party's notice or such longer period as may be fixed by
mutual agreement of the Management Committee and the
Aggrieved Party. Notwithstanding the initiation of
mediation, the arbitration proceeding shall proceed
concurrently with the selection of the arbitrator pursuant
to paragraph C(1) of this Section 21.1.
(ii) If the notice is to seek review of an ISO action, the
Management Committee's notice to the ISO Board shall
(subject to the concurrence of the ISO for actions relating
to rulemaking as provided in Section 21.1A) invoke
arbitration as described herein in its notice pursuant to
paragraph B(1), and may also initiate mediation with the
agreement of the ISO Board, while reserving the Management
Committee's right to proceed with the arbitration if
mediation does not resolve the matter within 20 days of the
giving of the Management Committee's notice or such longer
period as may be fixed by mutual agreement of the ISO Board
and the Management Committee. Notwithstanding the initiation
of mediation, the arbitration proceeding shall proceed
concurrently with the selection of the arbitrator pursuant
to paragraph C(1) of this Section 21.1.
(4) MEDIATION POSITIONS NOT TO BE USED ELSEWHERE: All mediation
proceedings pursuant to this Section are confidential and
shall be treated as compromise and settlement negotiations
for purposes of applicable rules of evidence.
(5) TIME LIMITS; DURATION: Any other Participant that wishes to
participate in an arbitration proceeding hereunder shall
give signed written notice to the Secretary of the
Management Committee, and to the Secretary of the ISO Board
if the ISO is involved in such arbitration, no later than
ten calendar days after the giving of the notice of
arbitration. The arbitration procedure shall not exceed 90
calendar days from the date of the Aggrieved Party's notice
invoking arbitration to the arbitrator's decision unless the
parties agree upon a longer or shorter time. All agreements
by the ISO or the aggrieved Participant and the Management
Committee to use mediation shall establish a schedule which
will control unless later changed by mutual agreement.
C. ARBITRATION:
(1) SELECTION OF ARBITRATOR: The ISO or the aggrieved
Participant and the Management Committee shall attempt
to choose by mutual agreement a single neutral
arbitrator to hear the dispute. If the ISO or the
Participant and the Management Committee fail to agree
upon a single arbitrator within ten calendar days of
the giving of notice of arbitration to the Secretary of
the Management Committee or the Secretary of the ISO
Board, as the case may be, the American Arbitration
Association shall be asked to appoint an arbitrator.
In either case, the arbitrator shall be knowledgeable
in matters involving the electric power industry,
including the operation of control areas and bulk power
systems, and shall not have any substantial business or
financial relationships with the ISO, NEPOOL or its
Participants (other than previous experience as an
arbitrator) unless otherwise mutually agreed by the ISO
or the aggrieved Participant and the Management
Committee.
(2) COSTS: NEPOOL shall be responsible for all of the costs
of the proceeding if it is initiated by the ISO or by
the Management Committee. If a proceeding is initiated
by an aggrieved Participant, each party shall be
responsible for the following costs, if applicable:
(i) its own costs incurred during the arbitration
process (except that this does not preclude
billing the aggrieved Participant for its share of
NEPOOL Expenses that may include the Management
Committee's arbitration costs); PLUS
(ii) One half of the common costs of the arbitration
including, but not limited to, the arbitrator's
fee and expenses, the rental charge for a hearing
room and the cost of a court reporter and
transcript, if required.
(3) HEARING LOCATION: Unless otherwise mutually agreed,
the site for all arbitration hearings shall be NEPOOL
counsel's office.
D. RULES AND PROCEDURES:
(1) PROCEDURE AND DISCOVERY: The procedural rules (if
any), the conduct of the arbitration and the
availability, extent and duration of pre-hearing
discovery (if any), which shall be limited to the
minimum necessary to resolve the matters in dispute,
shall be determined by the arbitrator in his/her sole
discretion at or prior to the initial hearing.
(2) PRE-HEARING SUBMISSIONS: The Aggrieved Party shall
provide the arbitrator with a brief written statement
of its complaint and a statement of the remedy or
remedies it seeks, accompanied by copies of any
documents or other materials it wishes the arbitrator
to review. The Management Committee will provide the
arbitrator with a copy of this Agreement and all
relevant implementing documents, a brief description of
the action being arbitrated, copies of the minutes of
all NEPOOL committee meetings at which the matter was
discussed, a brief statement explaining why the
Management Committee believes its decision should be
upheld by the arbitrator, and copies of any documents
or other materials the Management Committee wishes the
arbitrator to review. If the Management Committee is
the Aggrieved Party, the ISO Board will provide copies
of minutes of the ISO Board meetings at which the
matter was discussed, a brief statement explaining why
the ISO Board believes its decision should be upheld by
the arbitrator, and copies of any documents or other
materials the ISO Board wishes the arbitrator to
review. These submissions shall be made within five
days after the selection of the arbitrator.
In addition, each party shall designate one or more
individuals to be available to answer questions the
arbitrator may have on the documents or other materials
submitted by that party. The answers to all such
questions shall be reduced to writing by the party
providing the answer and a copy shall be furnished to
the other party.
(3) INITIAL HEARING: An initial hearing will be held no
later than 10 days after the selection of the
arbitrator and shall be limited to issues raised in the
pre-hearing filings. The scheduling of further
hearings at the request of either party or on the
arbitrator's own motion shall be within the sole
discretion of the arbitrator.
(4) DECISION: The arbitrator's decision shall be due,
unless the deadline is extended by mutual agreement of
the ISO or the aggrieved Participant and the Management
Committee, within sixty days of the initial hearing or
within ninety days of the Aggrieved Party's initiation
of arbitration, whichever occurs first. The arbitrator
shall be authorized only to interpret and apply the
provisions of this Agreement and the arbitrator shall
have no power to modify or change the Agreement in any
manner.
(5) EFFECT OF ARBITRATION DECISION: The decision of the
arbitrator will be conclusive in a subsequent
regulatory or legal proceeding as to the facts
determined by the arbitrator but will not be conclusive
as to the law or constitute precedent on issues of law
in any subsequent regulatory or legal proceedings.
An aggrieved party may initiate a proceeding with a court or
with the Commission with respect to the arbitration or
arbitrator's decision only:
<circle>if the arbitration process does not result in a
decision within the time period specified and the
proceeding is initiated within thirty days after
the expiration of such time period; or
<circle>on the grounds specified in Sections 10 and 11
of Title 9 of the United States Code for judicial
vacation or modification of an arbitration award
and the proceeding is initiated within thirty days
of the issuance of the arbitrator's decision.
(6) OTHER DISPUTES: In the event a dispute arises with a
Non-Participant which receives or is eligible to
receive service under this Agreement or the Tariff with
respect to such service, the Non-Participant shall have
the right to have the dispute considered by the
Management Committee. In the event the Non-Participant
is aggrieved by the Management Committee's vote on the
dispute, and the vote has any of the effects specified
in paragraph A of this Section 21.1, the aggrieved Non-
Participant may require that the dispute be resolved in
accordance with this Section 21.1. To the extent that
NEPOOL provides services to Non-Participants under
separate agreements, the Management Committee shall
incorporate the provisions of this Section by reference
in any such agreement, in which case the term
"Participant" shall be deemed for purposes of the
dispute resolution provisions to include such Non-
Participant purchasers of NEPOOL services.
21.2 PAYMENT OF POOL CHARGES; TERMINATION OF STATUS AS PARTICIPANT.
(a) Any Participant shall have the right to terminate its status as a
Participant upon no less than six months' prior written notice
given to the Secretary of the Management Committee.
(b) If at any time during the term of this Agreement a receiver or
trustee of a Participant is appointed or a Participant is
adjudicated bankrupt or an order for relief is entered under the
Federal Bankruptcy Code against a Participant or if there shall
be filed against any Participant in any court (pursuant to the
Federal Bankruptcy Code or any statute of Canada or any state or
province) a petition in bankruptcy or insolvency or for
reorganization or for appointment of a receiver or trustee of all
or a portion of the Participant's property, and within ninety
days after the filing of such a petition against the Participant,
the Participant shall fail to secure a discharge thereof, or if
any Participant shall file a petition in voluntary bankruptcy or
seeking relief under any provision of any bankruptcy or
insolvency law or shall make an assignment for the benefit of
creditors, the Management Committee may terminate such
Participant's status as a Participant as of any time thereafter.
(c) Each Participant is obligated to pay when due in accordance with
NEPOOL procedures all amounts invoiced to it by NEPOOL, or by the
ISO on behalf of NEPOOL. If a Participant disputes a NEPOOL
invoice in whole or part, it shall be entitled to continue to
receive service under the Agreement and the Tariff, so long as
the Participant (i) continues to make all payments not in
dispute, and (ii) pays into an independent escrow account the
portion of the invoice in dispute, pending resolution of the
dispute. If the Participant fails to meet these two requirements
for continuation of service, NEPOOL may suspend service, in whole
or part, to the Participant sixty days after the giving of notice
to the Participant of NEPOOL's intention to suspend service, in
accordance with Commission policy.
(d) In the event a Participant fails, for any reason other than a
billing dispute as described in subsection (c) of this Section
21.2, to pay when due in accordance with NEPOOL procedures all
amounts invoiced to it by NEPOOL, or by the ISO on behalf of
NEPOOL, or the Participant fails to perform any other obligation
under the Agreement or the Tariff, and such failure continues for
at least ten days, NEPOOL may notify the Participant that it is
in default and may initiate a proceeding before the Commission to
terminate such Participant's status as a Participant. Pending
Commission action on such termination, NEPOOL may suspend
service, in whole or part, to the Participant on or after 50 days
after the giving of such notice and the initiation of such
proceeding, in accordance with Commission policy, unless the
Participant cures the default within such 50-day period.
(e) If the status of a Participant as a Participant is terminated
pursuant to this Section 21.2 or any other provision of this
Agreement, such former Participant's generation and transmission
facilities shall continue to be subject to such NEPOOL or other
requirements relating to reliability as the Commission may
approve in acting on the termination, for so long as the
Commission may direct. Further, if any of such former
Participant's transmission facilities are required in order to
permit transactions among any of the remaining Participants
pursuant to this Agreement or the Tariff, all pending requests
for transmission service under the Tariff relating to such
Participant's facilities shall be followed to completion under
the Participant's own tariff and all existing service over the
Participant's facilities shall continue to be provided under the
Tariff for a period of three years. It is the intent of this
subsection that no such termination should be allowed to
jeopardize the reliability of the bulk power facilities of any
remaining Participant or should be allowed to impose any
unreasonable financial burden on any remaining Participant.
(f) No such termination of a Participant's status as a Participant
shall affect any obligation of, or to, such former Participant
arising prior to the effective time of such termination.
21.3 ASSIGNMENT. The Agreement shall inure to the benefit of, and shall be
binding upon, the successors and assigns of the respective signatories
hereto, but no assignment of a signatory's interests or obligations
under the Agreement or any portion thereof shall be made without the
written consent of the Management Committee, except as otherwise
permitted by the Tariff, or except in connection with a sale, merger,
or consolidation which results in the transfer of all or a portion of
a signatory's generation or transmission assets to, and the assumption
of all of the obligations of the signatory under this Agreement (or in
the case of a transfer of a portion of a signatory's generation or
transmission assets, the assumption of obligations of the signatory
under this Agreement with respect to such assets) by, an acquiring or
surviving Entity which either is, or concurrently becomes, a
Participant, or agrees to assume such of the signatory's obligations
with respect to such assets as the Management Committee may reasonably
require, or except in connection with the grant of a security interest
in a Participant's assets as security for bonds or other financing.
21.4 FORCE MAJEURE. A Participant shall not be considered to be in default
in respect of any obligation hereunder if prevented from fulfilling
such obligation by an event of Force Majeure. An event of Force
Majeure means any act of God, labor disturbance, act of the public
enemy, war, insurrection, riot, fire, storm or flood, explosion,
breakage or accident to machinery or equipment, any Curtailment, any
order, regulation or restriction imposed by a court or governmental
military or lawfully established civilian authorities, or any other
cause beyond a Participant's control, provided that no event of Force
Majeure affecting any Participant shall excuse that Participant from
making any payment that it is obligated to make under this Agreement.
A Participant whose performance under this Agreement is hindered by an
event of Force Majeure shall make all reasonable efforts to perform
its obligations under this Agreement, and shall promptly notify the
Management Committee of the commencement and end of any event of Force
Majeure.
21.5 WAIVER OF DEFAULTS. No waiver of the performance by a Participant of
any obligation under this Agreement or with respect to any default or
any other matter arising in connection with this Agreement shall be
effective unless given by the Management Committee. Any such waiver
by the Management Committee in any particular instance shall not be
deemed a waiver with respect to any subsequent performance, default or
matter.
21.6 OTHER CONTRACTS. No Participant shall be a party to any other
agreement which in any manner is inconsistent with its obligations
under this Agreement.
21.7 LIABILITY AND INSURANCE.
(a) Each Participant will indemnify and save each of the other
Participants, its officers, directors and Related Persons (each
an "Indemnified Party") harmless from and against all actions,
claims, demands, costs, damages and liabilities asserted by a
third party against the Indemnified Party seeking indemnification
and arising out of or relating to bodily injury, death or damage
to property caused by or sustained on facilities owned or
controlled by such Participant that are the subject of this
Agreement, or caused by a failure to act in accordance with this
Agreement by the Participant from which indemnification is
sought, except (i) to the extent that such liabilities result
from the negligence or willful misconduct of the Participant
seeking indemnification, and (ii) each Participant shall be
responsible for all claims of its own employees, agents and
servants growing out of any workmen's compensation law. The
amount of any indemnity payment under the provisions of this
Section 21.7 shall be reduced (including, without limitation,
retroactively) by any insurance proceeds or other amounts
actually recovered by the Indemnified Party in respect of the
indemnified action, claim, demand, cost, damage or liability.
Notwithstanding the foregoing, no Participant shall be liable to
any Indemnified Party for any claim for loss of profits or
revenues, attorneys' fees or costs, cost of capital or financing,
loss of goodwill or cost of replacement power arising from a
Participant's carrying out, or failing to carry out, any
obligations contemplated by this Agreement or for any other
indirect, incidental, special, consequential, punitive, or
multiple damages or loss; provided, however, that nothing herein
shall reduce or limit the obligations of any Participant to Non-
Participants.
(b) Each Participant shall furnish, at its sole expense, such
insurance coverage as the Management Committee may reasonably
require with respect to its obligation pursuant to Section
21.7(a).
21.8 RECORDS AND INFORMATION. Each Participant shall keep such records as
may reasonably be required by a NEPOOL committee or the System
Operator, and shall furnish to such committee or the System Operator
such records, reports and information (including forecasts) as it may
reasonably require, provided the confidentiality thereof is protected
in accordance with NEPOOL's information policy.
21.9 CONSISTENCY WITH NPCC AND NERC STANDARDS. The standards, criteria and
rules adopted by NEPOOL committees under this Agreement shall be
consistent with those adopted by the Northeast Power Coordinating
Council and the North American Electric Reliability Council or any
successor to either.
21.10CONSTRUCTION.
(a) The Table of Contents contained in this Agreement and the
headings of the Sections of this Agreement are intended for
convenience only and shall not be deemed to be part of this
Agreement or considered in construing it.
(b) This Agreement shall be interpreted, construed and governed in
accordance with the laws of the State of Connecticut.
21.11AMENDMENT. This Agreement, including the Tariff, and any attachment
or exhibit hereto may be amended from time to time by an instrument
signed by Participants having aggregate Voting Shares equal to at
least 70% of the Voting Shares of all Participants; provided that an
amendment shall not become effective if two or more Participants which
are not Related Persons of each other and which have aggregate Voting
Shares at least equal to 20% of the Voting Shares of all Participants
give notice to the Secretary of the Management Committee that they
object to the amendment within thirty days after the giving of notice
to them of the prospective effectiveness of the amendment. In
determining whether the 20% requirement has been met, the following
limitation shall be applied: if the aggregate Voting Share of any
objecting Participant and its Related Persons exceeds 18%, the
aggregate Voting Share of such Participant and its Related Persons for
this purpose shall be reduced to 18%.
Any amendment to this Agreement shall be in writing and shall become
effective on the date specified in the amendment, subject to
acceptance or approval by the Commission, whether or not the remaining
Participants agree, provided that the remaining Participants shall
have been given written notice of the prospective effectiveness of
such amendment at least thirty days prior to the effective date of
such amendment, and provided further, that such an amendment does not
impose a burden on such remaining Participants which is materially
different in nature or materially greater in degree than that imposed
on the Participants which have agreed to such amendment. Such notice
shall be accompanied by a form of notice which may be signed and
returned to the Secretary of the Management Committee to state a
Participant's objection to the amendment. Any Participant which has
given notice of its objection to such amendment shall be entitled to
terminate its status as a Participant effective as of the effective
date of such amendment by giving to the Secretary of the Management
Committee written notice of such termination within thirty days after
notice has been given to it of the prospective effectiveness of such
amendment. Effective as of thirty days after the giving of such
notice of the prospective effectiveness of such amendment, any
Participant which has not previously given notice of its objection to
such amendment and which does not give notice of termination of status
as herein provided within such thirty-day period shall thereafter be
bound by such amendment; provided that nothing herein shall be
construed to prevent any Participant from challenging any proposed
amendment before a court or regulatory agency on the ground that the
proposed amendment or its application to the Participant is in
violation of law or of this Section 21.11.
21.12TERMINATION. This Agreement shall continue in effect until
terminated, in accordance with the Commission's regulations, by
Participants represented by members of the Management Committee having
Voting Shares equal to at least 70% of the Voting Shares of all
Participants. No such termination shall relieve any party of any
obligation arising prior to the effective time of such termination.
21.13NOTICES TO PARTICIPANTS.
(a) Any notice, demand, request or other communication required or
authorized by this Agreement to be given to any Participant shall
be in writing, and shall be (1) personally delivered to the
Management Committee member or alternate appointed by the
Participant; (2) mailed, postage prepaid, to the Participant at
the address of its member on the Management Committee as set out
in the NEPOOL roster; (3) sent by facsimile ("faxed") to the
Participant at the fax number of its member on the Management
Committee as set out in the NEPOOL roster; or (4) delivered
electronically to the Participant at the electronic mail address
of its member on the Management Committee or at the address of
its principal office. The designation of any such address may be
changed at any time by written notice delivered to the Secretary
of the Management Committee, who shall cause such change to be
reflected in the NEPOOL roster.
(b) Any notice, demand, request or other communication required or
authorized by this Agreement to be given to any NEPOOL committee
shall be in writing and shall be delivered to the Secretary of
the committee. Each such notice shall either be personally
delivered to the Secretary, mailed, postage prepaid, or sent by
facsimile ("faxed") to the Secretary at the address or fax number
set out in the NEPOOL roster, or delivered electronically to the
Secretary. The designation of such address may be changed at any
time by written notice delivered to each Participant.
(c) Any such notice, demand or request so addressed and mailed by
registered or certified mail shall be deemed to be given when so
mailed. Any such notice, demand, request or other communication
sent by regular mail or by facsimile ("faxed") or delivered
electronically shall be deemed given when received by the
Participant or by the Secretary of the committee, whichever is
applicable.
21.14SEVERABILITY AND RENEGOTIATION. If any provision of this Agreement is
held by a court or regulatory authority of competent jurisdiction to
be invalid, void or unenforceable, the remainder of the terms,
provisions, covenants and restrictions of this Agreement shall
continue in full force and effect and shall in no way be affected,
impaired or invalidated, except as otherwise explicitly provided in
this Section.
If any provision of this Agreement is held by a court or regulatory
authority of competent jurisdiction to be invalid, void or
unenforceable, or if the Agreement is modified or conditioned by a
regulatory authority exercising jurisdiction over this Agreement, the
Participants shall endeavor in good faith to negotiate such amendment
or amendments to this Agreement as will restore the relative benefits
and obligations of the Participants under this Agreement immediately
prior to such holding, modification or condition. If after sixty days
such negotiations are unsuccessful the Participants may exercise their
withdrawal or termination rights under this Agreement.
21.15NO THIRD-PARTY BENEFICIARIES. Except for the provisions of this
Agreement and the Tariff which provide for service to Non-
Participants, this Agreement is intended to be solely for the benefit
of the Participants and their respective successors and permitted
assigns and, unless expressly stated herein, is not intended to and
shall not confer any rights or benefits on any third party (other than
successors and permitted assigns) not a signatory hereto.
21.16COUNTERPARTS. This Agreement may be executed in any number of
counterparts, and each executed counterpart shall have the same force
and effect as an original instrument and as if all the parties to all
of the counterparts had signed the same instrument. Any signature
page of this Agreement may be detached from any counterpart of this
Agreement without impairing the legal effect of any signatures
thereon, and may be attached to another counterpart of this Agreement
identical in form hereto but having attached to it one or more
signature pages.
IN WITNESS WHEREOF, the signatories have caused this Agreement to be
executed by their duly authorized officers or representatives.
<PAGE>
ATTACHMENT A
TO RESTATED
NEPOOL AGREEMENT
METHODOLOGY FOR
DETERMINATION OF
TRANSMISSION FLOWS
<PAGE>
The methodology for determining parallel path transmission flows to be
used in determining the distribution of revenues received for Regional
Network Service provided during the Transition Period, or for Through or
Out Service, is as follows, and shall be determined (1) on the basis of the
flows for all transactions in the NEPOOL Control Area ("Regional Flows")
for the purpose of allocating during the Transition Period Regional Network
Service revenues, and (2) on the basis of the flows for the particular
transaction ("Transaction Flows") for the purpose of allocating revenues
during or after the Transition Period from the furnishing of Through or Out
Service:
A. RESPONSIBILITY FOR CALCULATIONS
The calculation of megawatt mile allocations in accordance with this
methodology shall be performed under the direction of the Regional
Transmission Planning Committee ("RTPC").
B. PERIODIC REVIEW
Calculations of MW-Mile allocations shall be performed whenever
significant changes to the transmission system load flows, as determined by
the RTPC, occur.
C. FACILITIES INCLUDED IN THE ANALYSIS
1. Transmission Lines
A calculation of MW-miles shall be determined for all PTF
lines.
2. Generators
The analysis shall include all generators with a Winter
Capability equal to or greater than 10.0 MW. Multiple
generators connected to a single bus with a total Winter
Capability equal to or greater than 10.0 MW shall also be
included.
3. Transformers
All transformers connecting PTF transmission lines shall be
included in the analysis.
D. DETERMINATION OF RATE DISTRIBUTION
1. General
Modeling of the transmission system shall be performed using
a system simulation program and associated cases as approved
by the RTPC.
2. Determination of Regional Flows
The change in real power flow (MW) over each transmission
line and transformer shall be determined for each generator
(or group of generators on a single bus) by determining the
absolute value of the difference between the flows on each
facility with the generator(s) modeled off and while
operating at its net Winter Capability. In addition, a
generator shall be simulated at each transmission line tie
to the NEPOOL Control Area and changes in flow determined
for this generator off or while generating at a level of 100
MW. Loads throughout the NEPOOL Control Area shall be
proportionally scaled to account for differences in
generator output and electrical losses. The changes in flow
shall be multiplied by the length of each respective line.
Changes in flow through transformers shall be multiplied by
a factor of five. Changes in flow through phase-shifting
transformers shall be multiplied by a factor of ten. The
resulting values represent the MW-miles associated with each
facility.
3. Determination of Transaction Flows
a. Definition of Supply and Receipt Areas
For the purposes of these calculations, areas of supply
and receipt shall be determined by the RTPC. These
areas shall be based on the system boundaries of each
Local Network.
b. Calculation of MW-Miles
The change in real power flow (MW) over each
transmission line and transformer shall be determined
for each combination of supply and receipt areas by
determining the absolute value of the difference
between the flows on each facility following a scaled
increase of the supplying areas generation by 100 MW.
Loads in the area of receipt shall be scaled to account
for changes in generation and electrical losses. In
instances where the areas of supply and/or receipt are
outside the NEPOOL Control Area, the changes in real
power flow will be determined only for facilities
within the NEPOOL Control Area. The changes in flow
shall then be multiplied by the length of each
respective line. Changes in flow through transformers
shall be multiplied by a factor of five. Changes in
flow through phase-shifting transformers shall be
multiplied by a factor of ten. The resulting values
represent the MW-miles associated with each facility.
4. Assignment of MW-Miles to Participants
Each Participant shall have assigned to it the MW-miles
associated with each PTF facility for which it has full
ownership. Each Participant shall also be assigned MW-miles
in proportion to the percentage of its ownership of jointly-
owned facilities or the percentage of its support for
facilities for which it provides support.
<PAGE>
RESTATED NEPOOL OPEN ACCESS
TRANSMISSION TARIFF
<PAGE>
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 1
TABLE OF CONTENTS
I. COMMON SERVICE PROVISIONS. . . . . . . . . . . . . . . . . 13
1 Definitions. . . . . . . . . . . . . . . . . . . . . . . . . 13
1.1 Administrative Costs. . . . . . . . . . . . . . . . . 13
1.2 Agreement . . . . . . . . . . . . . . . . . . . . . . 13
1.3 Ancillary Services. . . . . . . . . . . . . . . . . . 13
1.4 Annual Transmission Revenue
Requirements. . . . . . . . . . . . . . . . . . . . 14
1.5 Application . . . . . . . . . . . . . . . . . . . . . 14
1.6 Backyard Generation:. . . . . . . . . . . . . . . . . 14
1.7 Business Day. . . . . . . . . . . . . . . . . . . . . 14
1.8 Commission. . . . . . . . . . . . . . . . . . . . . . 14
1.9 Completed Application . . . . . . . . . . . . . . . . 14
1.10 Compliance Effective Date . . . . . . . . . . . . . . 14
1.11 Control Area. . . . . . . . . . . . . . . . . . . . . 15
1.12 Curtailment . . . . . . . . . . . . . . . . . . . . . 16
1.13 Delivering Party. . . . . . . . . . . . . . . . . . . 16
1.14 Designated Agent. . . . . . . . . . . . . . . . . . . 16
1.15 Direct Assignment Facilities. . . . . . . . . . . . . 16
1.16 Eligible Customer . . . . . . . . . . . . . . . . . . 17
1.17 Energy Imbalance Service. . . . . . . . . . . . . . . 18
1.18 Entitlement . . . . . . . . . . . . . . . . . . . . . 18
1.19 Excepted Transaction. . . . . . . . . . . . . . . . . 19
1.20 Facilities Study. . . . . . . . . . . . . . . . . . . 19
1.21 Firm Contract . . . . . . . . . . . . . . . . . . . . 19
1.22 Firm Point-To-Point Transmission
Service . . . . . . . . . . . . . . . . . . . . . . 20
1.23 Firm Transmission Service . . . . . . . . . . . . . . 20
1.24 Generator Owner . . . . . . . . . . . . . . . . . . . 20
1.25 Good Utility Practice . . . . . . . . . . . . . . . . 20
1.26 HQ Interconnection. . . . . . . . . . . . . . . . . . 21
1.27 HQ Phase II Firm Energy Contract. . . . . . . . . . . 22
1.28 In Service. . . . . . . . . . . . . . . . . . . . . . 22
1.29 Interchange Transactions. . . . . . . . . . . . . . . 23
1.30 0MITTED . . . . . . . . . . . . . . . . . . . . . . . 23
1.31 Interest. . . . . . . . . . . . . . . . . . . . . . . 23
1.32 Internal Point-to-Point Service . . . . . . . . . . . 23
1.33 Internal Point-to-Point Service . . . . . . . . . . . 23
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 2
1.34 Interruption. . . . . . . . . . . . . . . . . . . . . 23
1.35 ISO . . . . . . . . . . . . . . . . . . . . . . . . . 24
1.36 Load Ratio Share. . . . . . . . . . . . . . . . . . . 24
1.37 Load Shedding . . . . . . . . . . . . . . . . . . . . 24
1.38 Local Network . . . . . . . . . . . . . . . . . . . . 25
1.39 Local Network Service . . . . . . . . . . . . . . . . 25
1.40 Local Point-To-Point Service. . . . . . . . . . . . . 25
1.41 Long-Term Firm Service. . . . . . . . . . . . . . . . 26
1.42 Management Committee. . . . . . . . . . . . . . . . . 26
1.43 Monthly Network Load. . . . . . . . . . . . . . . . . 26
1.44 Monthly Peak. . . . . . . . . . . . . . . . . . . . . 26
1.45 Native Load Customers . . . . . . . . . . . . . . . . 26
1.46 NEPOOL. . . . . . . . . . . . . . . . . . . . . . . . 26
1.47 NEPOOL Control Area . . . . . . . . . . . . . . . . . 27
1.48 NEPOOL Transmission System. . . . . . . . . . . . . . 27
1.49 Network Customer. . . . . . . . . . . . . . . . . . . 27
1.50 Network Integration Transmission
Service . . . . . . . . . . . . . . . . . . . . . . 27
1.51 Network Load. . . . . . . . . . . . . . . . . . . . . 27
1.52 Network Operating Agreement . . . . . . . . . . . . . 28
1.53 Network Operating Committee . . . . . . . . . . . . . 28
1.54 Network Resource. . . . . . . . . . . . . . . . . . . 29
1.55 Network Upgrades. . . . . . . . . . . . . . . . . . . 30
1.56 Non-Firm Point-To-Point Transmission
Service . . . . . . . . . . . . . . . . . . . . . . 31
1.57 Non-Participant . . . . . . . . . . . . . . . . . . . 31
1.58 Non-PTF . . . . . . . . . . . . . . . . . . . . . . . 31
1.59 Open Access Same-Time Information
System (OASIS). . . . . . . . . . . . . . . . . . . 31
1.60 Operating Reserve - 10-Minute Non-Spinning Reserve
Service . . . . . . . . . . . . . . . . . . . . . . 31
1.61 Operating Reserve - 10-Minute Spinning
Reserve Service . . . . . . . . . . . . . . . . . . 32
1.62 Operating Reserve - 30-Minute Reserve
Service . . . . . . . . . . . . . . . . . . . . . . 32
1.63 Participant . . . . . . . . . . . . . . . . . . . . . 32
1.64 Participant RNS Rate. . . . . . . . . . . . . . . . . 32
1.65 Point(s) of Delivery. . . . . . . . . . . . . . . . . 32
1.66 Point(s) of Receipt . . . . . . . . . . . . . . . . . 32
1.67 Point-To-Point Transmission Service . . . . . . . . . 33
1.68 Pool-Planned Unit . . . . . . . . . . . . . . . . . . 33
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 3
1.69 Pool PTF Rate . . . . . . . . . . . . . . . . . . . . 34
1.70 Pool RNS Rate . . . . . . . . . . . . . . . . . . . . 34
1.71 Power Purchaser . . . . . . . . . . . . . . . . . . . 34
1.72 Prior NEPOOL Agreement. . . . . . . . . . . . . . . . 34
1.73 PTF or Pool Transmission Facilities . . . . . . . . . 34
1.74 Pre-1997 PTF Rate . . . . . . . . . . . . . . . . . . 34
1.75 Reactive Supply and Voltage Control From
Generation Sources Service. . . . . . . . . . . . . 35
1.76 Receiving Party . . . . . . . . . . . . . . . . . . . 35
1.77 Regional Network Service. . . . . . . . . . . . . . . 35
1.78 Regulation and Frequency Response Service . . . . . . 35
1.79 Reserved Capacity . . . . . . . . . . . . . . . . . . 35
1.80 Scheduling, System Control and Dispatch Service . . . 36
1.81 Second Effective Date . . . . . . . . . . . . . . . . 36
1.82 Service Agreement . . . . . . . . . . . . . . . . . . 36
1.83 Service Commencement Date . . . . . . . . . . . . . . 36
1.84 Short-Term Firm Service . . . . . . . . . . . . . . . 37
1.85 System Contract . . . . . . . . . . . . . . . . . . . 37
1.86 System Impact Study . . . . . . . . . . . . . . . . . 37
1.87 System Operator . . . . . . . . . . . . . . . . . . . 38
1.88 Tariff. . . . . . . . . . . . . . . . . . . . . . . . 38
1.89 Third-Party Sale. . . . . . . . . . . . . . . . . . . 38
1.90 Through or Out Service. . . . . . . . . . . . . . . . 38
1.91 Third Effective Date. . . . . . . . . . . . . . . . . 39
1.92 Ties. . . . . . . . . . . . . . . . . . . . . . . . . 39
1.93 Transition Period . . . . . . . . . . . . . . . . . . 40
1.94 Transmission Customer . . . . . . . . . . . . . . . . 40
1.95 Transmission Provider . . . . . . . . . . . . . . . . 40
1.96 Unit Contract . . . . . . . . . . . . . . . . . . . . 41
1.97 Use . . . . . . . . . . . . . . . . . . . . . . . . . 41
1.98 Year. . . . . . . . . . . . . . . . . . . . . . . . . 42
2 Purpose of This Tariff . . . . . . . . . . . . . . . . . . . 43
3 Initial Allocation and Renewal Procedures. . . . . . . . . . 44
3.1 Initial Allocation of Available Transmission
Capability. . . . . . . . . . . . . . . . . . . . . 44
3.2 Reservation Priority For Existing Firm
Service Customers . . . . . . . . . . . . . . . . . 45
3.3 Initial Election of Optional Internal
Point-to-Point Service. . . . . . . . . . . . . . . 46
3.4 Election as to In Service . . . . . . . . . . . . . . 47
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 4
4 Ancillary Services . . . . . . . . . . . . . . . . . . . . . 48
4.1 Scheduling, System Control and Dispatch Service . . . 50
4.2 Reactive Supply and Voltage Control from
Generation Sources Service. . . . . . . . . . . . . 50
4.3 Regulation and Frequency Response Service . . . . . . 50
4.4 Energy Imbalance Service. . . . . . . . . . . . . . . 50
4.5 Operating Reserve - 10-Minute Spinning
Reserve Service . . . . . . . . . . . . . . . . . . 50
4.6 Operating Reserve - 10-Minute Non-Spinning Reserve
Service . . . . . . . . . . . . . . . . . . . . . . 50
4.7 Operating Reserve - 30-Minute Reserve
Service . . . . . . . . . . . . . . . . . . . . . . 51
5 Open Access Same-Time Information System (OASIS) . . . . . . 51
6 Local Furnishing and Other Tax-Exempt Bonds. . . . . . . . . 51
6.1 Participants That Own Facilities Financed
by Local Furnishing or Other Tax-Exempt Bonds . . . 51
6.2 Alternative Procedures for Requesting Transmission
Service - Local Furnishing Bonds. . . . . . . . . . . 52
6.3 Alternative Procedures for Requesting Transmission
Service - Other Tax-Exempt Bonds. . . . . . . . . . . 54
7 Reciprocity. . . . . . . . . . . . . . . . . . . . . . . . . 55
8 Billing and Payment; Accounting. . . . . . . . . . . . . . . 56
8.1 Participant Billing Procedure . . . . . . . . . . . . 56
8.2 Non-Participant Billing Procedure . . . . . . . . . . 56
8.3 Interest on Unpaid Balances . . . . . . . . . . . . . 57
8.4 Customer Default. . . . . . . . . . . . . . . . . . . 57
8.5 Study Costs and Revenues. . . . . . . . . . . . . . . 59
9 Regulatory Filings . . . . . . . . . . . . . . . . . . . . . 60
10 Force Majeure and Indemnification . . . . . . . . . . . . . 61
10.1 Force Majeure . . . . . . . . . . . . . . . . . . . . 61
10.2 Indemnification . . . . . . . . . . . . . . . . . . . 62
11 Creditworthiness. . . . . . . . . . . . . . . . . . . . . . 63
12 Dispute Resolution Procedures . . . . . . . . . . . . . . . 63
12.1 Internal Dispute Resolution Procedures. . . . . . . . 63
12.2 Rights Under The Federal Power Act. . . . . . . . . . 65
13 Stranded Costs. . . . . . . . . . . . . . . . . . . . . . . 65
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 5
13.1 General . . . . . . . . . . . . . . . . . . . . . . . 65
13.2 Commission Requirements . . . . . . . . . . . . . . . 65
13.3 Wholesale Contracts . . . . . . . . . . . . . . . . . 66
13.4 Right to Seek or Contest Recovery Unimpaired. . . . . 66
II. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION
TRANSMISSION SERVICE). . . . . . . . . . . . . . . . . . . 66
14 Nature of Regional Network Service. . . . . . . . . . . . . 67
15 Availability of Regional Network Service. . . . . . . . . . 67
15.1 Provision of Regional Network Service . . . . . . . . 67
15.2 Eligibility to Receive Regional Network Service . . . 68
16 Payment for Regional Network Service. . . . . . . . . . . . 68
17 Procedure for Obtaining Regional Network Service. . . . . . 69
III. THROUGH OR OUT SERVICE; INTERNAL POINT-TO-POINT
SERVICE . . . . . . . . . . . . . . . . . . . . . . . . 69
18 Through or Out Service. . . . . . . . . . . . . . . . . . . 70
18.1 Provision of Through or Out Service . . . . . . . . . 70
18.2 Use of Through or Out Service . . . . . . . . . . . . 70
19 Internal Point-to-Point Service . . . . . . . . . . . . . . 71
19.1 Provision of Internal Point-to-Point Service. . . . . 71
19.2 Use of Internal Point-to-Point Service. . . . . . . . 71
19.3 Use by a Transmission Customer. . . . . . . . . . . . 72
20 Payment for Through or Out Service. . . . . . . . . . . . . 74
21 Payment for Internal Point-to-Point Service . . . . . . . . 75
22 Reservation of Capacity for Point-to-Point Transmission
Service . . . . . . . . . . . . . . . . . . . . . . . . . . 78
22A In Service . . . . . . . . . . . . . . . . . . . . . . . . 78
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 6
IV. SERVICE DURING THE TRANSITION PERIOD; CONGESTION
COSTS; EXCEPTED TRANSACTIONS . . . . . . . . . . . . . . 83
23 Transition Arrangements . . . . . . . . . . . . . . . . . . 84
24 Congestion Costs. . . . . . . . . . . . . . . . . . . . . . 84
25 Excepted Transactions . . . . . . . . . . . . . . . . . . . 87
V. POINT-TO-POINT TRANSMISSION SERVICE; IN SERVICE . . . . . . 92
Preamble. . . . . . . . . . . . . . . . . . . . . . . . . 92
26 Scope of Application of Part V. . . . . . . . . . . . . . . 93
27 Nature of Firm Point-To-Point Transmission Service. . . . . 94
27.1 Term. . . . . . . . . . . . . . . . . . . . . . . . . 94
27.2 Reservation Priority. . . . . . . . . . . . . . . . . 94
27.3 Use of Firm Point-To-Point Transmission Service by
the Participants That Own PTF . . . . . . . . . . . 96
27.4 Service Agreements. . . . . . . . . . . . . . . . . . 96
27.5 Transmission Customer Obligations for Facility
Additions or Redispatch Costs. . . . . . . . . . . 97
27.6 Curtailment of Firm Transmission Service. . . . . . . 98
27.7 Classification of Firm Point-To-Point Transmission
Service . . . . . . . . . . . . . . . . . . . . . .100
27.8 Scheduling of Firm Point-To-Point Transmission
Service. . . . . . . . . . . . . . . . . . . . . . 104
28 Nature of Non-Firm Point-To-Point Transmission Service. . .105
28.1 Term. . . . . . . . . . . . . . . . . . . . . . . . .105
28.2 Reservation Priority. . . . . . . . . . . . . . . . .106
28.3 Use of Non-Firm Point-To-Point Transmission
Service by the Transmission Provider. . . . . . . .108
28.4 Service Agreements. . . . . . . . . . . . . . . . . .108
28.5 Classification of Non-Firm Point-To-Point
Transmission Service. . . . . . . . . . . . . . . .109
28.6 Scheduling of Non-Firm Point-To-Point Transmission
Service:. . . . . . . . . . . . . . . . . . . . . .111
28.7 Curtailment or Interruption of Service. . . . . . . .113
29 Service Availability. . . . . . . . . . . . . . . . . . . .116
29.1 General Conditions. . . . . . . . . . . . . . . . . .116
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 7
29.2 Determination of Available Transmission Capability. .116
29.3 Initiating Service in the Absence of an Executed
Service Agreement . . . . . . . . . . . . . . . . .116
29.4 Obligation to Provide Transmission Service that
Requires Expansion or Modification of the
Transmission System . . . . . . . . . . . . . . . .117
29.5 Deferral of Service . . . . . . . . . . . . . . . . .118
29.6 Real Power Losses . . . . . . . . . . . . . . . . . .119
29.7 Load Shedding . . . . . . . . . . . . . . . . . . . .120
30 Transmission Customer Responsibilities. . . . . . . . . . .120
30.1 Conditions Required of Transmission Customers . . . .120
30.2 Transmission Customer Responsibility for Third-
Party Arrangements. . . . . . . . . . . . . . . . .121
31 Procedures for Arranging Firm Point-To-Point Transmission
Service . . . . . . . . . . . . . . . . . . . . . . . . . .122
31.1 Application . . . . . . . . . . . . . . . . . . . . .122
31.2 Completed Application . . . . . . . . . . . . . . . .123
31.3 Deposit . . . . . . . . . . . . . . . . . . . . . . .124
31.4 Notice of Deficient Application . . . . . . . . . . .126
31.5 Response to a Completed Application . . . . . . . . .127
31.6 Execution of Service Agreement. . . . . . . . . . . .128
31.7 Extensions for Commencement of Service. . . . . . . .129
32 Procedures for Arranging Non-Firm Point-To-Point
Transmission Service. . . . . . . . . . . . . . . . . . . .130
32.1 Application . . . . . . . . . . . . . . . . . . . . .130
32.2 Completed Application:. . . . . . . . . . . . . . . .130
32.3 Reservation of Non-Firm Point-To-Point Transmission
Service. . . . . . . . . . . . . . . . . . . . . . .132
32.4 Determination of Available Transmission Capability. .132
33 Additional Study Procedures For Firm Point-To-Point
Transmission Service Requests . . . . . . . . . . . . . . .133
33.1 Notice of Need for System Impact Study. . . . . . . .133
33.2 System Impact Study Agreement and Cost
Reimbursement . . . . . . . . . . . . . . . . . . .135
33.3 System Impact Study Procedures. . . . . . . . . . . .136
33.4 Facilities Study Procedures . . . . . . . . . . . . .138
33.5 Facilities Study Modifications. . . . . . . . . . . .140
33.6 Due Diligence in Completing New
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 8
Facilities. . . . . . . . . . . . . . . . . . . . .141
33.7 Partial Interim Service . . . . . . . . . . . . . . .141
33.8 Expedited Procedures for New Facilities . . . . . . .142
34 Procedures if New Transmission Facilities for Firm
Point-To-Point Transmission Service Cannot be Completed . .143
34.1 Delays in Construction of New Facilities. . . . . . .143
34.2 Alternatives to the Original Facility Additions . . .144
34.3 Refund Obligation for Unfinished Facility
Additions . . . . . . . . . . . . . . . . . . . . .145
35 Provisions Relating to Transmission Construction and
Services on the Systems of Other Utilities. . . . . . . . .146
35.1 Responsibility for Third-Party System Additions . . .146
35.2 Coordination of Third-Party System Additions . . . .147
36 Changes in Service Specifications . . . . . . . . . . . . .148
36.1 Modifications on a Non-Firm Basis . . . . . . . . . .148
36.2 Modification on a Firm Basis. . . . . . . . . . . . .150
37 Sale, Assignment or Transfer of Transmission Service. . . .151
37.1 Procedures for Sale, Assignment or
Transfer of Service . . . . . . . . . . . . . . . .151
37.2 Limitations on Assignment or Transfer of Service. . .152
37.3 Information on Assignment or Transfer of Service. . .153
38 Metering and Power Factor Correction at Receipt and
Delivery Points(s). . . . . . . . . . . . . . . . . . . . .153
38.1 Transmission Customer Obligations . . . . . . . . . .153
38.2 NEPOOL Access to Metering Data. . . . . . . . . . . .154
38.3 Power Factor. . . . . . . . . . . . . . . . . . . . .154
39 Compensation for New Facilities and Redispatch Costs. . . .154
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 9
VI. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION
TRANSMISSION SERVICE). . . . . . . . . . . . . . . . . . .155
40 Nature of Regional Network Service. . . . . . . . . . . . .155
40.1 Scope of Service. . . . . . . . . . . . . . . . . . .155
40.2 Transmission Provider Responsibilities. . . . . . . .156
40.3 Network Integration Transmission Service. . . . . . .157
40.4 Secondary Service . . . . . . . . . . . . . . . . . .157
40.5 Real Power Losses . . . . . . . . . . . . . . . . . .158
40.6 Restrictions on Use of Service. . . . . . . . . . . .159
41 Initiating Service. . . . . . . . . . . . . . . . . . . . .159
41.1 Condition Precedent for Receiving Service . . . . . .159
41.2 Application Procedures. . . . . . . . . . . . . . . .160
41.3 Technical Arrangements to be Completed Prior to
Commencement of Service . . . . . . . . . . . . . .164
41.4 Network Customer Facilities . . . . . . . . . . . . .165
41.5 Filing of Service Agreement . . . . . . . . . . . . .165
42 Network Resources . . . . . . . . . . . . . . . . . . . . .165
42.1 Designation of Network Resources. . . . . . . . . . .165
42.2 Designation of New Network Resources. . . . . . . . .166
42.3 Termination of Network Resources. . . . . . . . . . .167
42.4 Network Customer Redispatch Obligation. . . . . . . .167
42.5 Transmission Arrangements for Network Resources Not
Physically Interconnected With The NEPOOL
Transmission System . . . . . . . . . . . . . . . .167
42.6 Limitation on Designation of Resources. . . . . . . .168
42.7 Use of Interface Capacity by the Network Customer . .169
43 Designation of Network Load . . . . . . . . . . . . . . . .169
43.1 Network Load. . . . . . . . . . . . . . . . . . . . .169
43.2 New Network Loads Connected With the NEPOOL
Transmission System . . . . . . . . . . . . . . . .170
43.3 Network Load Not Physically Interconnected with
the NEPOOL Transmission System. . . . . . . . . . .170
43.4 New Interconnection Points. . . . . . . . . . . . . .172
43.5 Changes in Service Requests . . . . . . . . . . . . .172
43.6 Annual Load and Resource Information
Updates . . . . . . . . . . . . . . . . . . . . . .173
44 Additional Study Procedures For Network Integration
Transmission Service Requests . . . . . . . . . . . . . . .173
44.1 Notice of Need for System Impact Study. . . . . . . .173
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 10
44.2 System Impact Study Agreement and Cost
Reimbursement . . . . . . . . . . . . . . . . . . .175
44.3 System Impact Study Procedures. . . . . . . . . . . .176
44.4 Facilities Study Procedures . . . . . . . . . . . . .178
45 Load Shedding and Curtailments. . . . . . . . . . . . . . .181
45.1 Procedures. . . . . . . . . . . . . . . . . . . . . .181
45.2 Transmission Constraints. . . . . . . . . . . . . . .181
45.3 Cost Responsibility for Relieving Transmission
Constraints . . . . . . . . . . . . . . . . . . . .182
45.4 Curtailments of Scheduled Deliveries. . . . . . . . .183
45.5 Allocation of Curtailments. . . . . . . . . . . . . .183
45.6 Load Shedding . . . . . . . . . . . . . . . . . . . .184
45.7 System Reliability. . . . . . . . . . . . . . . . . .184
46 Rates and Charges . . . . . . . . . . . . . . . . . . . . .186
46.1 Determination of Network Customer's Monthly
Network Load. . . . . . . . . . . . . . . . . . . .186
47 Operating Arrangements. . . . . . . . . . . . . . . . . . .186
47.1 Operation under The Network Operating Agreement . . .186
47.2 Network Operating Agreement . . . . . . . . . . . . .187
47.3 Network Operating Committee . . . . . . . . . . . . .189
48 Scope of Application of Part VI to Participants . . . . . .189
VII. INTERCONNECTIONS . . . . . . . . . . . . . . . . . . . .192
49 Interconnection Requirements . . . . . . . . . . . . . . .192
50 Rights of Generator Owners . . . . . . . . . . . . . . . .197
51 New Interconnection to Other Control Area. . . . . . . . .199
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 11
SCHEDULE 1 - Scheduling, System Control and Dispatch Service.201
SCHEDULE 2 - Reactive Supply and Voltage Control from
Generation Sources Service . . . . . . . . . . .204
SCHEDULE 3 - Regulation and Frequency Response Service
(Automatic Generator Control). . . . . . . . . .208
SCHEDULE 4 - Energy Imbalance Service . . . . . . . . . . . .211
SCHEDULE 5 - Operating Reserve - 10-Minute Spinning
Reserve Service. . . . . . . . . . . . . . . . .213
SCHEDULE 6 - Operating Reserve - 10-Minute Non-Spinning
Reserve Service. . . . . . . . . . . . . . . . .216
SCHEDULE 7 - Operating Reserve - 30-Minute Reserve Service. .219
SCHEDULE 8 - Through or Out Service -The Pool PTF Rate. . . .222
SCHEDULE 9 - Regional Network Service . . . . . . . . . . . .225
SCHEDULE 10 - Internal Point-to-Point Service. . . . . . . . .232
SCHEDULE 11 - Additions to or Upgrades of PTF. . . . . . . . .234
<PAGE>
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 12
ATTACHMENT A - Form of Service Agreement for Through or Out
Service or Internal Point-To-Point Service. . .245
ATTACHMENT B - Form Of Service Agreement For Regional
Network Service . . . . . . . . . . . . . . . .252
ATTACHMENT C - Methodology To Assess Available Transmission
Capability. . . . . . . . . . . . . . . . . . .256
ATTACHMENT D - Methodology for Completing a System Impact
Study . . . . . . . . . . . . . . . . . . . . .259
ATTACHMENT E - Local Networks. . . . . . . . . . . . . . . . .262
ATTACHMENT F - Annual Transmission Revenue Requirements. . . .264
Attachment G - List of Excepted Transaction Agreements . . . .278
Attachment G-1 - List of Excepted Agreements . . . . . . . . .283
Attachment G-2 - List of Certain Arrangements over External
Ties. . . . . . . . . . . . . . . . . . . . .285
ATTACHMENT H - Form of Network Operating Agreement . . . . . .287
ATTACHMENT I - Form of System Impact Study Agreement . . . . .310
ATTACHMENT J - Form of Facilities Study Agreement. . . . . . .326
<PAGE>
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 13
I. COMMON SERVICE PROVISIONS
1 Definitions
Whenever used in this Tariff, in either the singular or plural number, the
following capitalized terms shall have the meanings specified in this
Section 1. Terms used in this Tariff that are not defined in this Tariff
shall have the meanings customarily attributed to such terms by the
electric utility industry in New England.
1.1 Administrative Costs: Those costs incurred in connection with the
review of Applications for transmission service and the carrying out
of System Impact Studies and Facilities Studies.
1.2 Agreement: The Restated New England Power Pool Agreement dated as
of September 1, 1971, as amended and restated from time to time, of
which this Tariff forms a part.
1.3 Ancillary Services: Those services that are necessary to support
the transmission of electric capacity and energy from resources to
loads while maintaining reliable operation of the NEPOOL
Transmission System in accordance with Good Utility Practice.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 14
1.4 Annual Transmission Revenue Requirements: The annual revenue
requirements of a Participant's PTF or of all Participants' PTF for
purposes of this Tariff shall be the amount determined in accordance
with Attachment F to this Tariff.
1.5 Application: A written request by an Eligible Customer for
transmission service pursuant to the provisions of this Tariff.
1.6 Backyard Generation: Generation which interconnects directly with
distribution facilities dedicated solely to load not designated as
Network Load. Any distribution facilities which are shared with
Network Load will not qualify.
1.7 Business Day: Any day other than a Saturday or Sunday or a
national or Massachusetts holiday.
1.8 Commission: The Federal Energy Regulatory Commission.
1.9 Completed Application: An Application that satisfies all of the
information and other requirements of this Tariff, including any
required deposit.
1.10 Compliance Effective Date: The date upon which the changes in
this Tariff which have been reflected
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 15
herein to comply with the Commission's Order of April 20, 1998 in the
NEPOOL restructuring proceedings become effective.
1.11 Control Area: An electric power system or combination of electric
power systems to which a common automatic generation control scheme
is applied in order to:
(l) match, at all times, the power output of the generators within
the electric power system(s) and capacity and energy purchased
from entities outside the electric power system(s), with the
load within the electric power system(s);
(2) maintain scheduled interchange with other Control Areas, within
the limits of Good Utility Practice;
(3) maintain the frequency of the electric power system(s) within
reasonable limits in accordance with Good Utility Practice and
the criteria of the applicable regional reliability council or
the North American Electric Reliability Council; and
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 16
(4) provide sufficient generating capacity to maintain operating
reserves in accordance with Good Utility Practice.
1.12 Curtailment: A reduction in firm or non-firm transmission service
in response to a transmission capacity shortage as a result of
system reliability conditions.
1.13 Delivering Party: The entity supplying capacity and/or energy to
be transmitted at Point(s) of Receipt under this Tariff.
1.14 Designated Agent: Any entity that performs actions or functions
required under the Tariff on behalf of NEPOOL, an Eligible Customer,
or a Transmission Customer.
1.15 Direct Assignment Facilities: Facilities or portions of
facilities that are Non-PTF and are constructed for the sole
use/benefit of a particular Transmission Customer requesting service
under this Tariff or a Generator Owner requesting an
interconnection. Direct Assignment Facilities shall be specified in
a separate agreement with the Transmission Provider whose
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 17
transmission system is to be modified to include and/or interconnect
with said Facilities, shall be subject to applicable Commission
requirements and shall be paid for by the Transmission Customer or a
Generator Owner or Interconnection Requester in accordance with the
separate agreement and not under this Tariff.
1.16 Eligible Customer: (i) Any Participant that is engaged, or
proposes to engage, in the wholesale or retail electric power
business is an Eligible Customer under the Tariff. (ii) Any
electric utility (including any power marketer), Federal power
marketing agency, or any other entity generating electric energy for
sale or for resale is an Eligible Customer under the Tariff.
Electric energy sold or produced by such entity may be electric
energy produced in the United States, Canada or Mexico. However,
with respect to transmission service that the Commission is
prohibited from ordering by Section 212(h) of the Federal Power Act,
such entity is eligible only if the service is provided pursuant to a
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 18
state requirement that the Transmission Provider with which that
entity is directly interconnected offer the unbundled transmission
service, or pursuant to a voluntary offer of such service by the
Transmission Provider with which that entity is directly
interconnected. (iii) Any end user taking or eligible to take
unbundled transmission service pursuant to a state requirement that
the Transmission Provider with which that end user is directly
interconnected offer the transmission service, or pursuant to a
voluntary offer of such service by the Transmission Provider with
which that end user is directly interconnected, is an Eligible
Customer under the Tariff.
1.17 Energy Imbalance Service: This service is the form of Ancillary
Service described in Schedule 4.
1.18 Entitlement: An Installed Capability Entitlement, Operable
Capability Entitlement, Energy Entitlement, Operating Reserve
Entitlement, or AGC Entitlement, in each case as defined in the
Agreement. When used in the plural form, it may be any or all such
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 19
Entitlements or combinations thereof, as the context requires.
1.19 Excepted Transaction: A transaction specified in Section 25 for
the applicable period specified in that Section.
1.20 Facilities Study: An engineering study conducted pursuant to the
Agreement or this Tariff by the System Operator and/or one or more
affected Participants to determine the required modifications to the
NEPOOL Transmission System, including the cost and scheduled
completion date for such modifications, that will be required to
provide a requested transmission service or interconnection.
1.21 Firm Contract: Any contract, other than a Unit Contract, for the
purchase of Installed Capability, Operable Capability, Energy,
Operating Reserves, and/or AGC (as defined in the Agreement),
pursuant to which the purchaser's right to receive such Installed
Capability, Operable Capability, Energy, Operating Reserves, and/or
AGC is subject only to the supplier's
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 20
inability to make deliveries thereunder as the result of events
beyond the supplier's reasonable control.
1.22 Firm Point-To-Point Transmission Service: Point-To-Point
Transmission Service which is reserved and/or scheduled between
specified Points of Receipt and Delivery in accordance with the
applicable procedure specified in Part V of this Tariff.
1.23 Firm Transmission Service: Service for Native Load Customers,
firm Regional Network Service (Network Integration Transmission
Service), service for Excepted Transactions, Firm Internal Point-To-
Point Transmission Service, or Firm Through or Out Service.
1.24 Generator Owner: The owner, in whole or part, of a generating
unit whether located within or outside the NEPOOL Control Area.
1.25 Good Utility Practice: Any of the practices, methods and acts
engaged in or approved by a significant portion of the electric
utility industry during the relevant time period, or any of the
practices, methods and acts which, in the exercise of reasonable
judgment in light of the facts known at the time the decision
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 21
was made, could have been expected to accomplish the desired result
at a reasonable cost consistent with good business practices,
reliability, safety and expedition. Good Utility Practice is not
intended to be limited to the optimum practice, method, or act to
the exclusion of all others, but rather includes all acceptable
practices, methods, or acts generally accepted in the region.
1.26 HQ Interconnection: The United States segment of the transmission
interconnection which connects the systems of Hydro-Quebec and the
Participants. "Phase I" is the United States portion of the 450 kV
HVDC transmission line from a terminal at the Des Cantons Substation
on the Hydro-Quebec system near Sherbrooke, Quebec to a terminal
having an approximate rating of 690 MW at a substation at the
Comerford Generating Station on the Connecticut River. "Phase II"
is the United States portion of the facilities required to increase
to approximately 2000 MW the transfer capacity of the HQ
Interconnection, including an extension of the HVDC transmission
line from the
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 22
terminus of Phase I at the Comerford Station through New Hampshire to
a terminal at the Sandy Pond Substation in Massachusetts. The HQ
Interconnection does not include any PTF facilities installed or
modified to effect reinforcements of the New England AC transmission
system required in connection with the HVDC transmission line and
terminals.
1.27 HQ Phase II Firm Energy Contract: The Firm Energy Contract dated
as of October 14, 1985 between Hydro-Quebec and certain of the
Participants, as it may be amended from time to time.
1.28 In Service: The service provided by NEPOOL with respect to an
import transaction which requires the use of PTF and goes into the
NEPOOL Transmission System from the Maine Electric Power Company
line or New York, or into the NEPOOL Control Area on any new
interconnection constructed after the Compliance Effective Date in
accordance with Section 22A of this Tariff.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 23
1.29 Interchange Transactions: Transactions deemed to be effected
under Section 12 of the Prior NEPOOL Agreement prior to the Second
Effective Date, and transactions deemed to be effected under Section
14 of the Agreement on and after the Second Effective Date.
1.30 0MITTED
1.31 Interest: Interest calculated in the manner specified in Section
8.3.
1.32 Internal Point-to-Point Service: Point-to-Point Transmission
Service with respect to a transaction where the Point of Receipt is
at the boundary of or within the NEPOOL Control area and the Point
of Delivery is within the NEPOOL Control Area.
1.33 Internal Point-to-Point Service Rate: The rate applicable to
Internal Point-to-Point Service, which shall be equal for each
delivery to the Participant RNS Rate per Kilowatt for the current
Year for the Participant which owns the Local Network from which the
Customer's load is served.
1.34 Interruption: A reduction in non-firm transmission service due to
economic reasons pursuant to Section
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 24
28.7, other than a reduction which results from a failure to dispatch
a generating resource (including a contract used in a transaction
requiring In Service or Through or Out Service) which is out of merit
order.
1.35 ISO: The Independent System Operator which is responsible for the
continued operation of the NEPOOL Control Area from the NEPOOL
control center and the administration of this Tariff, subject to
regulation by the Commission.
1.36 Load Ratio Share: Ratio of a Transmission Customer's most
recently reported Monthly Network Load in the case of Network
Customers and including where applicable Point-to-Point Customers'
Reserved Capacity, to the total load of Network Customers and Point-
to-Point customers, computed in accordance with Part VI of the
Tariff.
1.37 Load Shedding: The systematic reduction of system demand by
temporarily decreasing load in response to transmission system or
area capacity shortages, system instability, or for voltage control
considerations under Part VI of the Tariff.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 25
1.38 Local Network: The transmission facilities constituting a local
network identified on Attachment E, and any other local network or
change in the designation of a Local Network as a Local Network
which the Management Committee may designate or approve from time to
time. The Management Committee may not unreasonably withhold
approval of a request by a Participant that it effect such a change
or designation.
1.39 Local Network Service: Local Network Service is the service
provided, under a separate tariff or contract, by a Participant that
is a Transmission Provider to another Participant or other entity
connected to the Transmission Provider's Local Network to permit the
other Participant or entity to efficiently and economically utilize
its resources to serve its load.
1.40 Local Point-To-Point Service: Local Point-To-Point service is
Point-to-Point Transmission Service provided, under a separate
tariff or contract, by a Participant that is a Transmission Provider
over Non-PTF or distribution facilities to permit deliveries to
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 26
or from an interconnection point on the NEPOOL Transmission System.
1.41 Long-Term Firm Service: Firm Transmission Service with a term of
one year or more.
1.42 Management Committee: The committee established pursuant to
Section 6 of the Agreement.
1.43 Monthly Network Load: Has the meaning specified in Section 46.1.
1.44 Monthly Peak: Has the meaning specified in Section 46.1.
1.45 Native Load Customers: The wholesale and retail power customers
of a Participant or other entity which is a Transmission Provider on
whose behalf the Participant or other entity, by statute, franchise,
regulatory requirement, or contract, has undertaken an obligation to
construct and operate its system to meet the reliable electric needs
of such customers.
1.46 NEPOOL: The New England Power Pool, the power pool created under
and governed by the Agreement, and the entities collectively
participating in the New England Power Pool.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 27
1.47 NEPOOL Control Area: The Control Area (as defined in Section
1.11) for NEPOOL.
1.48 NEPOOL Transmission System: The PTF transmission facilities.
1.49 Network Customer: A Participant or Non-Participant receiving
transmission service pursuant to the terms of the Network
Integration Transmission Service under Part II and Part VI of the
Tariff.
1.50 Network Integration Transmission Service: Regional Network
Service, which may be used with respect to Network Resources or
Network Load not physically interconnected with the NEPOOL
Transmission System.
1.51 Network Load: The load that a Network Customer designates for
Network Integration Transmission Service under Part II and Part VI
of the Tariff. The Network Customer's Network Load shall include
all load designated by the Network Customer (including losses) and
shall not be credited or reduced for any behind-the-meter generation.
A Network Customer may elect to designate less than its total load as
Network Load but may not designate only part of the load at a
discrete
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 28
Point of Delivery. Where an Eligible Customer has elected not to
designate a particular load at discrete Points of Delivery as Network
Load, the Eligible Customer is responsible for making separate
arrangements under Part III and Part V of the Tariff for any
Point-to-Point Transmission Service that may be necessary for such
non-designated load.
1.52 Network Operating Agreement: An executed agreement in the form of
Attachment H, or any other form that is mutually agreed to, that
contains the terms and conditions under which the Network Customer
shall operate its facilities and the technical and operational
matters associated with the implementation of Network Integration
Transmission Service under Part II and Part VI of this Tariff. The
Agreement and the rules adopted thereunder shall constitute the
Network Operating Agreement for Participants.
1.53 Network Operating Committee: A group made up of representatives
from the Network Customer(s) and the System Operator established to
coordinate operating criteria and other technical considerations
required
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 29
for implementation of Network Integration Transmission Service under
Part II and Part VI of this Tariff. The Network Operating Committee
for Network Customers that are Participants shall be the NEPOOL
Regional Transmission Operations Committee and the NEPOOL Regional
Transmission Planning Committee, meeting jointly in a meeting
designated as the annual Network Operating Committee
meeting. Notice of each meeting of the Committee pursuant to
Section 47.3 shall be given to each Non-Participant receiving
Regional Network Service under this Tariff and the Non-Participant
shall have the right to be represented at each of such meetings.
1.54 Network Resource: (1) With respect to Participants, (a) any
generating resource located in the NEPOOL Control Area which has
been placed in service prior to the Compliance Effective Date
(including a unit that has lost its capacity value when its capacity
value is restored and a deactivated unit which may be reactivated
without satisfying the requirements of Section 49 of this Tariff in
accordance with the
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 30
provisions thereof) until retired; (b) any generating resource
located in the NEPOOL Control Area which is placed in service after
the Compliance Effective Date until retired, provided that (i) the
Generator Owner has complied with the requirements of Section 49 of
the Tariff, and (ii) the output of the unit shall be limited in
accordance with Section 49, if required; and (c) any generating
resource or combination of resources (including bilateral purchases)
located outside the NEPOOL Control Area for so long as any
Participant has an Entitlement in the resource or resources which is
being delivered to it in the NEPOOL Control Area to serve Network
Load located in the NEPOOL Control Area or other designated Network
Loads contemplated by Section 43.3 of this Tariff taking Regional
Network Service. (2) With respect to Non-Participant Network
Customers, any generating resource owned, purchased or leased by the
Network Customer which it designates to serve Network Load.
1.55 Network Upgrades: Modifications or additions to transmission-
related facilities that are integrated
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 31
with and support the overall NEPOOL Transmission System for the
general benefit of all users of such Transmission System.
1.56 Non-Firm Point-To-Point Transmission Service: Point-To-Point
Transmission Service under this Tariff that is subject to
Curtailment or Interruption under the circumstances specified in
Section 28.7 of this Tariff.
1.57 Non-Participant: Any entity that is not a Participant.
1.58 Non-PTF: The transmission facilities owned by the Participants
that do not constitute PTF.
1.59 Open Access Same-Time Information System (OASIS): The NEPOOL
information system and standards of conduct responding to
requirements of 18 C.F.R. <section>37 of the Commission's
regulations and all additional requirements implemented by
subsequent Commission orders dealing with OASIS.
1.60 Operating Reserve - 10-Minute Non-Spinning Reserve Service: This
service is the form of Ancillary Service described in Schedule 6.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 32
1.61 Operating Reserve - 10-Minute Spinning Reserve Service: This
service is the form of Ancillary Service described in Schedule 5.
1.62 Operating Reserve - 30-Minute Reserve Service: This service is
the form of Ancillary Service described in Schedule 7.
1.63 Participant: A participant in NEPOOL under the Agreement.
1.64 Participant RNS Rate: The rate applicable to Regional Network
Service to effect a delivery to load in a particular Local Network,
as determined in accordance with Schedule 9 to this Tariff.
1.65 Point(s) of Delivery: Point(s) where capacity and/or energy
transmitted by the Participants will be made available to the
Receiving Party under this Tariff. The Point of Delivery may be
designated as the NEPOOL power exchange. The Point(s) of Delivery
shall be specified in the Service Agreement, if applicable, for
Long-Term Firm Point-To-Point Transmission Service.
1.66 Point(s) of Receipt: Point(s) of interconnection where capacity
and/or energy to be transmitted by the
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 33
Participants will be made available to NEPOOL by the Delivering Party
under this Tariff. The Point of Receipt may be designated as the
NEPOOL power exchange in circumstances where the System Operator does
not require greater specificity. The Point(s) of Receipt shall be
specified in the Service Agreement, if applicable, for Long-Term Firm
Point-To-Point Transmission Service.
1.67 Point-To-Point Transmission Service: The transmission of capacity
and/or energy on either a firm or non-firm basis from the Point(s)
of Receipt to the Point(s) of Delivery under this Tariff. NEPOOL
Point-to-Point Transmission Service includes both Internal Point-to-
Point Service and Through or Out Service.
1.68 Pool-Planned Unit: One of the following units: New Haven Harbor
Unit 1 (Coke Works), Mystic Unit 7, Canal Unit 2, Potter Unit 2,
Wyman Unit 4, Stony Brook Units 1, 1A, 1B, 1C, 2A and 2B, Millstone
Unit 3, Seabrook Unit 1 and Waters River Unit 2 (to the extent of 7
megawatts of its Summer Capability and 12 megawatts of its Winter
Capability).
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 34
1.69 Pool PTF Rate: The transmission rate determined in accordance
with Schedule 8 to this Tariff.
1.70 Pool RNS Rate: The transmission rate determined in accordance
with paragraph (2) of Schedule 9 to this Tariff.
1.71 Power Purchaser: The entity that is purchasing the capacity
and/or energy to be transmitted under the Tariff.
1.72 Prior NEPOOL Agreement: The NEPOOL Agreement as in effect on
December 1, 1996.
1.73 PTF or Pool Transmission Facilities: (i) The transmission
facilities owned by the Participants and their Related Persons which
constitute PTF pursuant to the Agreement, and (ii) the static VAR
compensator installed at Chester, Maine at the request of the
Participants.
1.74 Pre-1997 PTF Rate: The transmission rate of a Participant
determined in accordance with paragraph (5) of Schedule 9 to this
Tariff.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 35
1.75 Reactive Supply and Voltage Control From Generation Sources
Service: This service is the form of Ancillary Service described in
Schedule 2.
1.76 Receiving Party: The entity receiving the capacity and/or energy
transmitted to Point(s) of Delivery under this Tariff.
1.77 Regional Network Service: The transmission service described in
Section 14 and Part VI of this Tariff.
1.78 Regulation and Frequency Response Service: This service is the
form of Ancillary Service described in Schedule 3.
1.79 Reserved Capacity: The maximum amount of capacity and energy that
is committed to the Transmission Customer for transmission over the
NEPOOL Transmission System between the Point(s) of Receipt and the
Point(s) of Delivery under Part V of this Tariff. Reserved Capacity
shall be expressed in terms of whole kilowatts on a sixty-minute
interval (commencing on the clock hour) basis.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 36
1.80 Scheduling, System Control and Dispatch Service: This service is
the form of Ancillary Service described in Schedule 1.
1.81 Second Effective Date: The date on which the provisions of Part
Three of the Agreement (other than the Installed Capability
Responsibility provisions of Section 12) shall become effective and
shall be such date as the Commission may fix on its own or pursuant
to a request of the Management Committee.
1.82 Service Agreement: The initial agreement and any amendments or
supplements thereto entered into by the Transmission Customer and
the System Operator for service under this Tariff.
1.83 Service Commencement Date: The date service is to begin pursuant
to the terms of an executed Service Agreement, or the date service
begins in accordance with Section 29.3 or Section 41.1 under this
Tariff, or in the case of Regional Network Service which is not
required to be furnished under a Service Agreement pursuant to
Section 48 of this Tariff, the date service actually commences.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 37
1.84 Short-Term Firm Service: Firm Transmission Service with a term of
less than one year.
1.85 System Contract: Any contract for the purchase of Installed
Capability, Operable Capability, Energy, Operating Reserves and/or
AGC (as defined in the Agreement), other than a Unit Contract or
Firm Contract, pursuant to which the purchaser is entitled to a
specifically determined or determinable amount of such Installed
Capability, Operable Capability, Energy, Operating Reserves and/or
AGC.
1.86 System Impact Study: An assessment pursuant to Part V, VI or VII
of this Tariff of (i) the adequacy of the NEPOOL Transmission System
to accommodate a request for the interconnection of a new or
materially changed generating unit or a new or materially changed
interconnection to another Control Area or new Regional Network
Service, Internal Point-to-Point Service or Through or Out Service,
and (ii) whether any additional costs may be required to be incurred
in order to provide the interconnection or transmission service.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 38
1.87 System Operator: The central dispatching agency provided for in
the Agreement which has responsibility for the operation of the
NEPOOL Control Area from the control center and the administration
of this Tariff. The System Operator is the ISO.
1.88 Tariff: This NEPOOL Open Access Transmission Tariff and
accompanying schedules and attachments, as modified and amended from
time to time.
1.89 Third-Party Sale: Any sale for resale in interstate commerce to a
Power Purchaser that is not designated as part of Network Load under
the Regional Network Service.
1.90 Through or Out Service: Point-to-Point Transmission Service
provided by NEPOOL with respect to a transaction which requires the
use of PTF and which goes through the NEPOOL Control Area, as, for
example, from the Maine Electric Power Company line or New Brunswick
to New York, or from one point on the NEPOOL Control Area boundary
with New York to another point on the Control Area boundary with New
York, or with respect to a transaction which goes out of the NEPOOL
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Original Sheet No. 39
Control Area from a point in the NEPOOL Control Area, as, for
example, from Boston to New York.
1.91 Third Effective Date: The date on which all Interchange
Transactions shall begin to be effected on the basis of separate Bid
Prices for each type of Entitlement. The Third Effective Date shall
be fixed at the discretion of the Management Committee to occur
within six months to one year after the Second Effective Date, or at
such later date as the Commission may fix on its own or pursuant to
a request by the Management Committee.
1.92 Ties: (1) The PTF lines and facilities which connect the NEPOOL
Transmission System to the transmission line owned by Maine Electric
Power Company, which is in turn connected to the transmission system
in New Brunswick, (2) the PTF lines and facilities which connect the
NEPOOL Transmission System to the transmission system in New York
and (3) any new PTF lines and facilities which connect the NEPOOL
Transmission System to the transmission system in another Control
Area.
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1.93 Transition Period: The five-year period commencing on March 1,
1997.
1.94 Transmission Customer: Any Eligible Customer that (i) is a
Participant which is not required to sign a Service Agreement with
respect to a service to be furnished to it in accordance with
Section 48 of this Tariff, or (ii) executes, on its own behalf or
through its Designated Agent, a Service Agreement, or (iii) requests
in writing, on its own behalf or through its Designated Agent, that
NEPOOL file with the Commission, a proposed unexecuted Service
Agreement in order that the Eligible Customer may receive
transmission service under this Tariff. This term is used in Part I
to include customers receiving transmission service under this
Tariff.
1.95 Transmission Provider: The Participants, collectively, which own
PTF and are in the business of providing transmission service or
provide service under a local open access transmission tariff, or in
the case of a municipal Participant, would be required to do so if
requested pursuant to the reciprocity
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Original Sheet No. 41
requirements specified in the Tariff, or an individual such
Participant, whichever is appropriate.
1.96 Unit Contract: A purchase contract pursuant to which the
purchaser is in effect currently entitled either (i) to a
specifically determined or determinable portion of the Installed
Capability of a specific electric generating unit or units, or (ii)
to a specifically determined or determinable amount of Operable
Capability, Energy, Operating Reserves and/or AGC if, or to the
extent that, a specific electric generating unit or units is or can
be operated.
1.97 Use: For a Transmission Customer which has exercised its option to
take Internal Point-to-Point Service to serve all or a portion of
its load at any Point of Delivery, the greatest for the hour of (i)
the maximum amount that it will receive in the hour, as determined
from meters and adjusted for losses, at that Point of Delivery from
the resources covered by its Completed Applications and from
Interchange Transactions, or (ii) the portion of its Installed
Capability Responsibility (as determined in accordance with the
NEPOOL Restated Open Access Transmission Tariff
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Agreement) for the month which must be satisfied at that Point of
Delivery with such resources if the Transmission Customer is a
Participant, or (iii) the portion of its Operable Capability
Responsibility (as determined in accordance with the Agreement) for
the hour which must be satisfied at that Point of Delivery with such
resources if the Transmission Customer is a Participant, or (iv) the
amount of capacity from such resources that the Transmission
Customer must receive, adjusted to include losses, at such Point of
Delivery for the hour to meet its reliability obligations if the
Transmission Customer is a Non-Participant. Use shall be expressed
in terms of whole kilowatts on a sixty-minute interval (commencing
on the clock hour) basis.
1.98 Year: A period of 365 or 366 days, whichever is appropriate,
commencing on, or on the anniversary of, March 1, 1997. Year One is
the Year commencing on March 1, 1997, and Years Two and higher
follow it in sequence.
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2 Purpose of This Tariff
This Tariff, together with the transmission provisions in Part Four of the
Agreement, is intended to provide a regional arrangement which will cover
new uses of the NEPOOL Transmission System. The arrangement is designed
and shall be operated in such a manner as to encourage and promote
competition in the electric market to the benefit of ultimate users of
electric energy. New uses of transmission facilities which require the use
of a single Participant Local Network will continue to be provided in part
under that Participant's filed tariff. Any new regional use of the NEPOOL
Transmission System must be obtained from NEPOOL pursuant to this Tariff
and not from individual Participants. Ancillary Services will be supplied
in accordance with Section 4 of this Tariff.
A five-year transitional arrangement, which is described in Part IV of this
Tariff, and continuing service for Excepted Transactions, have been
negotiated to phase in the financial impacts of the change from the
historic regime in which uses of the NEPOOL Transmission System had to be
obtained and paid for under the individual tariffs of the Participants to a
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Original Sheet No. 44
regime in which the service will be obtained from the Participants through
NEPOOL at a rate which will not vary with distance. This Tariff is
intended to provide for comparable, non-discriminatory treatment of all
similarly situated Transmission Providers and all Participants and Non-
Participants that are transmission users, and it shall be construed in the
manner which best achieves this objective. This Tariff, and the provisions
of Part Four of the Agreement, provide for a two-tier transmission
arrangement integrating regional service which is provided under this
Tariff, and local service which is provided under the Participants'
individual system tariffs.
3 Initial Allocation and Renewal Procedures
3.1 Initial Allocation of Available Transmission Capability: For
purposes of determining whether existing capability on the NEPOOL
Transmission System is adequate to accommodate a request for new
Through or Out Service under Part V of this Tariff, all Completed
Applications for new service received during the initial sixty-day
period of the Transition Period will be deemed to have been filed
simultaneously. A lottery system conducted by
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an independent accounting firm shall be used to assign priorities for
Completed Applications filed simultaneously. All Completed
Applications for Through or Out Service received after the initial
sixty-day period shall be assigned a priority pursuant to Section 27.2.
3.2 Reservation Priority For Existing Firm Service Customers: Existing
firm service customers receiving service with respect to Excepted
Transactions and any other existing firm service customers of the
Participants (wholesale requirements customers and transmission-only
customers) with a contract term of one year or more have the right to
continue to take transmission service at the same or a reduced level
under this Tariff at the time when the existing contract terminates
during or after the Transition Period. This transmission reservation
priority is independent of whether the existing customer continues to
purchase capacity and energy from its existing supplier or elects to
purchase capacity and energy from another supplier. If, at the end of
the contract term, the NEPOOL Transmission System cannot
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accommodate all of the requests for transmission service, the existing
firm service customer must agree to accept a contract term at least
equal to a competing request by any new Eligible Customer and to pay
the current just and reasonable rate, filed with the Commission, for
such service. This transmission reservation priority for existing firm
service customers is an ongoing right that may be exercised as to any
firm contract with a term of one year or longer by filing an
Application in accordance with this Tariff at least sixty days in
advance of the first day of the calendar month in which the existing
contract term is to terminate.
3.3 Initial Election of Optional Internal Point-to-Point Service:
Participants and Non-Participants receiving Regional Network Service
under the Tariff on the Compliance Effective Date shall have sixty
days to make an initial election to receive Internal Point-to-Point
Service in lieu of, in whole or part, Regional Network Service. The
election shall take effect as to such service at the end of such
sixty-day period and shall be made by delivering an application to the
System Operator,
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together with a deposit, if required, pursuant to Part V of this
Tariff.
Participants and Non-Participants receiving Regional Network Service
which do not make such an initial election within such sixty-day
period shall continue to receive Regional Network Service, subject to
their right to elect at any time later to receive Internal Point-to-
Point Service.
3.4 Election as to In Service: If a Transmission Customer has in effect
on the Compliance Effective Date a reservation for capacity for In
Service on the Ties effective under the provisions of the Tariff
(other than a reservation for an Excepted Transaction) it shall be
obligated, on or prior to the Compliance Effective Date, either (i) to
terminate in whole or part the reservation by notice to the System
Operator, or (ii) effect compliance, for the period commencing on the
Compliance Effective Date, with the applicable requirements of Section
22A of this Tariff.
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4 Ancillary Services
Ancillary Services are needed with transmission service to maintain
reliability within the NEPOOL Control Area. The Participants are required
to provide through NEPOOL, and the Transmission Customer is required to
purchase from NEPOOL, Scheduling, System Control and Dispatch Service, and
Reactive Supply and Voltage Control from Generation Sources Service.
The Participants offer to provide or arrange for, through NEPOOL, the
following Ancillary Services, but only to a Transmission Customer serving
load within the NEPOOL Control Area (i) Regulation and Frequency Response
(Automatic Generator Control), (ii) Energy Imbalance, (iii) Operating
Reserve - 10-Minute Spinning, (iv) Operating Reserve - 10-Minute Non-
Spinning and (v) Operating Reserve - 30-Minute. A Participant or other
Transmission Customer serving load within the NEPOOL Control Area is
required to provide these Ancillary Services, whether from the System
Operator, from a third party, or by self-supply. A Transmission Customer
may not decline NEPOOL's offer of these Ancillary Services unless the
Transmission Customer demonstrates to the System Operator that the
Transmission Customer has acquired Ancillary Services of
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equal quality from another source. The Transmission Customer that is not a
Participant must list in its Application which Ancillary Services it will
purchase through NEPOOL.
In the event of an unauthorized use of any Ancillary Service by the
Transmission Customer, the Transmission Customer will be required to pay
200% of the charge which would otherwise be applicable.
The specific Ancillary Services, prices and/or compensation methods are
described on the Schedules that are attached to and made a part of this
Tariff. Three principal requirements apply to discounts for Ancillary
Services provided by NEPOOL in conjunction with its provision of
transmission service as follows: (1) any offer of a discount made by NEPOOL
must be announced to all Eligible Customers solely by posting on the OASIS,
(2) any customer-initiated requests for discounts (including requests for
use by one's wholesale merchant or an affiliate's use) must occur solely by
posting on the OASIS, and (3) once a discount is negotiated, details must
be immediately posted on the OASIS. A discount agreed upon for
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Original Sheet No. 50
an Ancillary Service must be offered for the same period to all Eligible
Customers on the NEPOOL Transmission System. Sections 4.1 through 4.7
below list the seven Ancillary Services.
4.1 Scheduling, System Control and Dispatch Service: The rates and/or
methodology are described in Schedule 1.
4.2 Reactive Supply and Voltage Control from Generation Sources Service:
The rates and/or methodology are described in Schedule 2.
4.3 Regulation and Frequency Response Service: Where applicable, the
rates and/or methodology are described in Schedule 3.
4.4 Energy Imbalance Service: Where applicable, the rates and/or
methodology are described in Schedule 4.
4.5 Operating Reserve - 10-Minute Spinning Reserve Service: Where
applicable, the rates and/or methodology for this service are
described in Schedule 5.
4.6 Operating Reserve - 10-Minute Non-Spinning Reserve Service: Where
applicable, the rates and/or methodology for this service are
described in Schedule 6.
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4.7 Operating Reserve - 30-Minute Reserve Service: Where applicable,
the rates and/or methodology for this service are described in
Schedule 7.
5 Open Access Same-Time Information System (OASIS)
Terms and conditions regarding the NEPOOL Open Access Same-Time Information
System and standards of conduct are set forth in 18 C.F.R. <section>37 of
the Commission's regulations (Open Access Same-Time Information System and
Standards of Conduct for Public Utilities). In the event available
transmission capability, as posted on OASIS, is insufficient to accommodate
a request for firm transmission service, additional studies may be required
as provided by this Tariff pursuant to Sections 33 and 44.
6 Local Furnishing and Other Tax-Exempt Bonds
6.1 Participants That Own Facilities Financed by Local Furnishing or
Other Tax-Exempt Bonds: This provision is applicable only to
Participants that have financed facilities for the local furnishing of
electric energy with tax-exempt bonds, as described in Section 142(f)
of the Internal Revenue Code ("local furnishing bonds") or other tax-
exempt bonds, as described in Section 103(b) of
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the Internal Revenue Code ("other tax-exempt bonds"). Notwithstanding
any other provision of this Tariff, a Participant shall not be required
to provide service to any Eligible Customer pursuant to this Tariff if
the provision of such transmission service would jeopardize the
tax-exempt status of any local furnishing bond(s) or other tax-exempt
bonds used to finance the Participant's facilities that would be used
in providing such Transmission Service.
6.2 Alternative Procedures for Requesting Transmission Service - Local
Furnishing Bonds:
(i) If a Participant determines that the provision of transmission
service to be provided under this Tariff would jeopardize the
tax-exempt status of any local furnishing bond(s) used to finance
the Participant's facilities that would be used in providing such
transmission service, the Management Committee shall be advised
within thirty days of receipt of a Completed Application by an
Eligible Customer requesting such service, or the date on
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which this Tariff becomes effective, whichever is applicable.
(ii) If an Eligible Customer thereafter renews its request for the
same transmission service referred to in (i) by tendering an
application under Section 211 of the Federal Power Act, or the
Management Committee tenders such an application requesting that
service be provided under this Tariff, the Participant, within
ten days of receiving a copy of the Section 211 application, will
waive its rights to receive a request for service under Section
213(a) of the Federal Power Act and to the issuance of a proposed
order under Section 212(c) of the Federal Power Act. The
Commission, upon receipt of the Transmission Provider's waiver of
its rights to a request for service under Section 213(a) of the
Federal Power Act and to the issuance of a proposed order under
Section 212(c) of the Federal Power Act, shall issue an order
under Section 211 of the Federal Power Act. Upon issuance of the
order under Section 211 of the Federal Power Act, the
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Original Sheet No. 54
Transmission Provider shall be required to provide the requested
transmission service in accordance with the terms and conditions
of this Tariff.
6.3 Alternative Procedures for Requesting Transmission Service - Other
Tax-Exempt Bonds:
If a Participant determines that the provision of transmission service
to be provided under the Tariff would jeopardize the tax-exempt status
of any other tax-exempt bonds used to finance the Participant's
facilities that would be used in furnishing such transmission service,
it shall notify the Management Committee within thirty days of the
date on which this Tariff becomes effective, and shall elect in its
notice either to comply with the procedure specified in Section
6.2(ii) or to make its facilities unavailable under the Tariff and
thereby waive its right to share in the distribution of revenues
received under the Tariff derived from such facilities. Any such
election may be changed at any time.
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7 Reciprocity
A Transmission Customer receiving transmission service under this Tariff,
whether a Participant or a Non-Participant, agrees to provide comparable
transmission service that it is capable of providing to the Participants on
similar terms and conditions over facilities used for the transmission of
electric energy in Canada or used for such transmission in the United
States and that are owned, controlled or operated by, or on behalf of the
Transmission Customer and over facilities used for the transmission of
electric energy owned, controlled or operated by the Transmission
Customer's corporate affiliates. Transmission of power on the Transmission
Customer's system to the border of the NEPOOL Control Area and transfer of
ownership at that point shall not satisfy, or relieve the Transmission
Customer of, the obligation to provide reciprocal service.
This reciprocity requirement applies not only to the Transmission Customer
that obtains transmission service under the Tariff, but also to all parties
to a transaction that involves the use of transmission service under the
Tariff,
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Original Sheet No. 56
including the power seller, buyer and any intermediary, such as a
power marketer. This reciprocity requirement also applies to any Eligible
Customer that owns, controls or operates transmission facilities that uses
an intermediary, such as a power marketer, to request transmission service
under the Tariff. If the Transmission Customer does not own, control or
operate transmission facilities, the Transmission Customer must include in
its Application a sworn statement of one of its duly authorized officers or
other representatives that the purpose of its Application is not to assist
an Eligible Customer to avoid the requirements of this provision.
8 Billing and Payment; Accounting
8.1 Participant Billing Procedure: Billings to Participants for
services received under this Tariff shall be made in accordance with
the billing procedures established pursuant to the Agreement.
8.2 Non-Participant Billing Procedure: Within a reasonable time after
the first day of each month, the System Operator will submit on behalf
of the Participants an invoice to each Non-Participant Transmission
Customer for the charges for all services furnished under this Tariff
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Original Sheet No. 57
during the preceding month. The invoice shall be paid by the Non-
Participant Transmission Customer to the System Operator for NEPOOL
within ten days of receipt. All payments shall be made, in accordance
with the procedure specified by the System Operator, in immediately
available funds payable to the System Operator or by wire transfer to
a bank account designated by the System Operator.
8.3 Interest on Unpaid Balances: Interest on any unpaid amounts
(including amounts placed in escrow) will be calculated in accordance
with the methodology specified for interest on refunds in 18 C.F.R.
<section>35.19a(a)(2)(iii) of the Commission's regulations. Interest
on delinquent amounts will be calculated from the due date of the bill
to the date of payment. When payments are made by mail, bills will be
considered as having been paid on the date of receipt of payment by
the System Operator or by the bank designated by the System Operator.
8.4 Customer Default: In the event a Non-Participant Transmission
Customer fails, for any reason other than a billing dispute as
described below, to make payment to
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the System Operator on or before the due date as described above, and
such failure of payment is not corrected within thirty calendar days
after the System Operator notifies the Transmission Customer to cure
such failure, a default by the Transmission Customer will be deemed to
exist. Upon the occurrence of a default, NEPOOL may initiate a
proceeding with the Commission to terminate service but shall not
terminate service until the Commission approves such termination. In
the event of a billing dispute between NEPOOL and the Transmission
Customer, service will continue to be provided under the Service
Agreement as long as the Transmission Customer (i) continues to make
all payments not in dispute, and (ii) pays into an independent escrow
account the portion of the invoice in dispute, pending resolution of
such dispute. If the Transmission Customer fails to meet these two
requirements for continuation of service, then the System Operator may
provide notice to the Transmission Customer of NEPOOL's intention to
suspend service in sixty days, in accordance with applicable
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Commission rules and regulations, and may proceed with such suspension.
In the event a Transmission Customer that is a Participant fails to
perform its obligations under the Tariff, Section 21.2 of the
Agreement shall be applicable to that failure. That section of the
Agreement addresses defaults under both the Tariff and the Agreement
and also addresses termination of an entity's status as a Participant.
8.5 Study Costs and Revenues: A Participant which is a Transmission
Provider shall (i) include in a separate operating revenue account or
subaccount the revenues, if any, it receives from transmission service
when making Third-Party Sales under Part V of this Tariff, and (ii)
include in a separate transmission operating expense account or
subaccount, costs properly chargeable to expense that are incurred to
perform any System Impact Studies or Facilities Studies which the
Transmission Provider conducts to determine if it must construct new
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Original Sheet No. 60
transmission facilities or upgrades necessary for its own uses,
including Third-Party Sales, if any, under this Tariff; and include in
a separate operating revenue account or subaccount the revenues
received for System Impact Studies or Facilities Studies performed
when such amounts are separately stated and identified in a billing
under the Tariff.
9 Regulatory Filings
Nothing contained in this Tariff or any Service Agreement shall be
construed as affecting in any way the right of the Participants to file
with the Commission under Section 205 of the Federal Power Act and pursuant
to the Commission's rules and regulations promulgated thereunder for a
change in any rates, terms and conditions, charges, classification of
service, Service Agreement, rule or regulation. Nothing contained in this
Tariff or any Service Agreement shall be construed as affecting in any way
the ability of any Transmission Customer receiving service under this
Tariff or for an Excepted Transaction to exercise its rights under the
Federal Power Act and pursuant to the Commission's rules and regulations
promulgated thereunder.
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10 Force Majeure and Indemnification
10.1 Force Majeure: An event of Force Majeure means any act of God,
labor disturbance, act of the public enemy, war, insurrection, riot,
fire, storm or flood, explosion, breakage or accident to machinery or
equipment, any Curtailment, any order, regulation or restriction
imposed by a court or governmental military or lawfully established
civilian authorities, or any other cause beyond a party's control. A
Force Majeure event does not include an act of negligence or
intentional wrongdoing. Neither the Participants, NEPOOL, the System
Operator nor the Transmission Customer will be considered in default
as to any obligation under this Tariff if prevented from fulfilling
the obligation due to an event of Force Majeure; provided that no
event of Force Majeure affecting any entity shall excuse that entity
from making any payment that it is obligated to make hereunder or
under a Service Agreement. However, an entity whose performance under
this Tariff is hindered by an
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event of Force Majeure shall make all reasonable efforts to perform its
obligations under this Tariff, and shall promptly notify the System
Operator or the Transmission Customer, whichever is appropriate, of the
commencement and end of each event of Force Majeure.
10.2 Indemnification: The Transmission Customer shall at all times
indemnify, defend, and save harmless the System Operator, NEPOOL and
each Participant from any and all damages, losses, claims, including
claims and actions relating to injury to or death of any person or
damage to property, demands, suits, recoveries, costs and expenses,
court costs, attorney fees, and all other obligations by or to third
parties, arising out of or resulting from the performance by the
System Operator, NEPOOL or any Participant of their obligations under
this Tariff on behalf of the Transmission Customer, except in cases of
negligence or intentional wrongdoing by the System Operator, NEPOOL or
a Participant, as the case may be.
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11 Creditworthiness
For the purpose of determining the ability of a Transmission Customer which
is a Non-Participant to meet its obligations related to service hereunder,
NEPOOL may require reasonable credit review procedures. This review shall
be made in accordance with standard commercial practices. In addition,
NEPOOL may require the Transmission Customer to provide and maintain in
effect during the term of the Service Agreement an irrevocable letter of
credit as security to meet its responsibilities and obligations under this
Tariff, or an alternative form of security proposed by the Transmission
Customer and acceptable to NEPOOL and consistent with commercial practices
established by the Uniform Commercial Code that protects the Participants
against the risk of non-payment.
12 Dispute Resolution Procedures
12.1 Internal Dispute Resolution Procedures: Any dispute between an
Eligible Customer or Transmission Customer which is a Participant and
NEPOOL involving transmission service under the Tariff may be
submitted to mediation and/or arbitration and
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Original Sheet No. 64
resolved in accordance with the alternate dispute resolution procedures
set forth in Section 21.1 of the Agreement. Any dispute between a
Non-Participant Eligible Customer or Transmission Customer and NEPOOL
involving this Tariff excluding applications for rate changes or other
changes to this Tariff, or to any Service Agreement entered into under
this Tariff, which shall be presented directly to the Commission for
resolution)shall be referred to a designated senior representative of
the Eligible Customer or Transmission Customer and a representative of
the Management Committee for resolution on an informal basis as
promptly as practicable. In the event the designated representatives
are unable to resolve the dispute within thirty days or such other
period as the parties may fix by mutual agreement, such dispute may be
submitted to mediation and/or arbitration and resolved in accordance
with the alternate dispute resolution procedures set forth in Section
21.1 of the Agreement, with any Non-Participant being
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treated as if it were a Participant for purposes of such procedures.
12.2 Rights Under The Federal Power Act: Nothing in this section shall
restrict the rights of any party to file a complaint with the
Commission, or seek any other available remedy, under relevant
provisions of the Federal Power Act.
13 Stranded Costs
13.1 General: This Tariff shall not be used to evade or enhance in whole
or in part the stranded cost policies or charges established by law or
by the regulatory commission with jurisdiction.
13.2 Commission Requirements: A Participant which seeks to recover
stranded costs from a Transmission Customer pursuant to this Tariff
may do so in accordance with the terms, conditions and procedures in
the Commission's Order No. 888 or other relevant Commission orders.
However, the Participant must separately file any specific proposed
stranded cost charge under Section 205 of the Federal Power Act.
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13.3 Wholesale Contracts: Nothing in this Section 13 is intended to
affect or alter the rights or obligations of parties under wholesale
requirements contracts.
13.4 Right to Seek or Contest Recovery Unimpaired: No provision in this
Tariff shall impair a Participant's right to seek stranded cost relief
from the appropriate regulatory body or court or the right of any
Participant or other entity to contest such relief.
II. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE)
Regional Network Service or Network Integration Transmission Service will
be provided by the Participants through NEPOOL during and after the
Transition Period to Transmission Customers pursuant to the applicable
terms and conditions of this Tariff. Local Network Service will be
provided during and after the Transition Period pursuant to the applicable
terms and conditions of tariffs filed by an individual Participant that is
a Transmission Provider and/or pursuant to an agreement between a
Participant that is a Transmission
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Provider and a Transmission Customer. This Tariff does not prescribe the
methodology to be used by the individual Participant in developing its Local
Network Service rate, but the Agreement prescribes certain requirements with
respect thereto.
14 Nature of Regional Network Service
Regional Network Service or Network Integration Transmission Service is the
service provided under Parts II and VI of this Tariff over the NEPOOL
Transmission System which is provided to Network Customers to serve their
loads. It includes firm transmission service for the delivery to a Network
Customer of its energy and capacity in Network Resources and secondary
service for the delivery to or by Network Customers of energy and capacity
in Interchange Transactions. Regional Network Service also includes In
Service, as provided in Section 22A.
15 Availability of Regional Network Service
15.1 Provision of Regional Network Service: Regional Network Service
shall be provided by the Participants through NEPOOL, and shall be
available to each Eligible Customer.
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Original Sheet No. 68
15.2 Eligibility to Receive Regional Network Service: Regional Network
Service shall be taken and paid for by (i) each Eligible Customer
which has a load within the NEPOOL Control Area and has not elected to
take Internal Point-to-Point Service at all of its Point(s) of
Delivery, and (ii) each Non-Participant which is an Eligible Customer
and has a load within the NEPOOL Control Area unless such Non-
Participant operates its own Control Area or has elected to take
Internal Point-to-Point Service at all of its Point(s) of Delivery.
Participants and Non-Participants which take Regional Network Service
must also take Local Network Service except as otherwise provided in
Section 25.
16 Payment for Regional Network Service
Each Participant or Non-Participant which has a load in the NEPOOL Control
Area and takes Regional Network Service for a month shall pay to NEPOOL for
such month an amount equal to its Monthly Network Load for the month times
the applicable Participant RNS Rate, and shall pay in addition any amount
which it is required to pay for the service pursuant to
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Section 43.3 of this Tariff. It shall also be obligated to pay any
applicable congestion or other uplift charge required to be paid pursuant to
Section 24 of this Tariff. The applicable Participant RNS Rate shall be the
rate, determined in accordance with Schedule 9, which is applicable to a
delivery to load in the particular Local Network in which the load served by
the Participant or Non-Participant is located. In the event the Participant
or Non-Participant serves Network Load located on more than one Local
Network, the amount to be paid by it shall be separately computed for the
Network Load located on each Local Network.
17 Procedure for Obtaining Regional Network Service
A Participant or Non-Participant which takes Regional Network Service shall
be subject to the applicable provisions of Part II and Part VI of this
Tariff, except to the extent otherwise specifically provided in Section 48
of this Tariff.
III. THROUGH OR OUT SERVICE; INTERNAL POINT-TO-POINT SERVICE
Point-to-Point Transmission Service as Through or Out Service or Internal
Point-to-Point Service will be provided during and after the Transition
Period pursuant to the applicable terms and conditions of this Tariff.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 70
18 Through or Out Service
18.1 Provision of Through or Out Service: Through or Out Service shall
be provided by the Participants through NEPOOL, and shall be available
to any Participant and to any Non-Participant which is an Eligible
Customer.
18.2 Use of Through or Out Service: A Participant or Non-Participant
shall take Through or Out Service as Firm or Non-Firm Point-To-Point
Transmission Service for the transmission of any Unit Contract
Entitlement or System Contract transaction with respect to a
transaction which requires the use of PTF if either (i) the
transaction goes through the NEPOOL Control Area and the Point(s) of
Receipt for NEPOOL are at one point on the NEPOOL Control Area
boundary and the Point(s) of Delivery for NEPOOL are at another point
on the NEPOOL Control Area boundary, as, for example, from the Maine
Electric Power Company line or New Brunswick to New York or from one
point on the NEPOOL Control Area boundary with New York to another
point on the Control Area
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 71
boundary with New York (which in the case of such transaction will also
require In Service as part of the Through or Out Service in accordance
with Section 22A of this Tariff), or (ii) the transaction goes out of
the NEPOOL Control Area and the Point(s) of Receipt are within the
NEPOOL Control Area and the Point(s) of Delivery for NEPOOL are at a
NEPOOL Control Area boundary, as, for example, from Boston to New York.
19 Internal Point-to-Point Service
19.1 Provision of Internal Point-to-Point Service: Internal Point-to-
Point Service shall be provided by the Participants through NEPOOL,
and shall be available to any Participant and to any Non-Participant
which is an Eligible Customer.
19.2 Use of Internal Point-to-Point Service: A Participant or Non-
Participant which is an Eligible Customer may take Internal Point-to-
Point Service as Firm or Non-Firm Point-to-Point Transmission Service
with respect to any transaction if the Point(s) of Receipt are at the
NEPOOL Control Area boundary
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 72
(which in the case of such transaction will also require In Service as
part of the Internal Point-to-Point Service in accordance with Section
22A of this Tariff) or within the NEPOOL Control Area, and the Point(s)
of Delivery are within the NEPOOL Control Area, including Interchange
Transactions meeting these requirements. Non-Firm Internal
Point-to-Point Service shall be available to serve a load that is
served by an entity only if the entity (i) demonstrates to the
satisfaction of the System Operator a physical ability to interrupt its
receipt of energy and/or capacity and (ii) gives the System Operator
physical control over such an interruption.
19.3 Use by a Transmission Customer: If a Transmission Customer elects to
take Internal Point-to-Point Service with respect to any Points of
Delivery, it may reserve transmission capacity for the service to
cover both the delivery to it of energy and capacity covered by the
Entitlements or System Contracts designated by it in Completed
Applications and the delivery to or from it in Interchange Transactions
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 73
of energy and/or capacity. A Transmission Customer which takes
Internal Point-to-Point Service to serve its load must also take
point-to-point service under the applicable Local Network Service
tariff. A load-serving Participant or Non-Participant which takes
Internal Point-to-Point Service in this manner must reserve each month
sufficient Reserved Capacity, after adjusting for any Backyard
Generation, at a Point of Delivery to cover the greater of (i) the
maximum amount of energy that it will receive in any hour, as
determined from meters and adjusted for losses, or (ii) in the case of
a Participant, the portion of its Installed Capability Responsibility
or its Operable Capability Responsibility which must be satisfied with
the resources covered by its Completed Applications and from
Interchange Transactions or (iii) in the case of a Non-Participant the
portions of its reliability obligations to be satisfied with such
resources. Any load-serving entity may use Internal Point-to-Point
Service to effect sales in bilateral
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 74
transactions, whether or not it elects to take Point-to-Point Service
to serve load.
20 Payment for Through or Out Service
Each Participant or Non-Participant which takes firm or non-firm Through or
Out Service shall pay to NEPOOL a charge per Kilowatt of Reserved Capacity
based on an annual rate (the "T or O Rate") which shall be the highest of
(i) the Pool PTF Rate, or (ii) a rate which is derived from the annual
incremental cost, not otherwise borne by the Transmission Customer or a
Generation Owner, of any new facilities or upgrades that would not be
required but for the need to provide the requested service or (iii) a rate
which is equal to the Pool's opportunity cost (if and when available)
capped at the cost of expansion. If at any time NEPOOL proposes to charge
a rate based on opportunity cost, it shall first file with the Commission
procedures for computing opportunity cost pricing for all Transmission
Customers. The Transmission Customer shall also be obligated to pay any
applicable congestion or other uplift charge required to be paid pursuant
to Section 24 of this Tariff. The rate for firm Through or Out Service
shall be as follows:
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 75
Per year - the T or O Rate
Per month - the T or O Rate divided by 12
Per week - the T or O Rate divided by 52
Per day - the T or O Rate "per week" divided by 5; provided that
the rate for 5 to 7 consecutive days may not exceed the
"per week" rate.
The rate for non-firm Through or Out Service shall be as follows:
Per year - the T or O Rate
Per month - the T or O Rate divided by 12
Per week - the T or O Rate divided by 52
Per day - the T or O Rate "per week" divided by 7;
Per hour - the non-firm T or O Rate "per day" divided by 24.
The Pool PTF Rate shall be the Rate determined annually in accordance with
paragraph (2) of Schedule 8.
21 Payment for Internal Point-to-Point Service
Each Participant or Non-Participant which takes firm or non-firm Internal
Point-to-Point Service shall pay to NEPOOL a charge per Kilowatt of
Reserved Capacity based on an annual
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 76
rate (the "IPTP Charge") which shall be the Internal Point-to-Point Service
Rate; provided that if either or both (i) a rate which is derived from the
annual incremental cost, not otherwise borne by the Transmission Customer or
a Generator Owner, of any new facilities or upgrades that would not be
required but for the need to provide the requested service, or (ii) a rate
which is equal to the Pool's opportunity cost (if and when available) capped
at the cost of expansion is greater than the Pool PTF Rate, the IPTP Charge
shall be the higher of such amounts; provided further that no such charge
shall be payable with respect to the use of Internal Point-to-Point Service
to effect a delivery to the NEPOOL power exchange in an Interchange
Transaction. If at any time NEPOOL proposes to charge a rate based on
opportunity cost, it shall first file with the Commission procedures for
computing opportunity cost pricing for all Transmission Customers. The
Transmission Customer shall also be obligated to pay any ancillary service
charges and any applicable congestion or other uplift charge required to be
paid pursuant to Section 24 of this Tariff. The charge for firm Internal
Point-to-Point Service shall be as follows:
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 77
Per year - the IPTP Charge
Per month - the IPTP Charge divided by 12
Per week - the IPTP Charge divided by 52
Per day - the IPTP Charge "per week" divided by 5; provided that
the rate for 5 to 7 consecutive days may not exceed the
"per week" rate.
The rate for non-firm Internal Point-to-Point Service shall be as follows:
Per year - the IPTP Charge
Per month - the IPTP Charge divided by 12
Per week - the IPTP Charge divided by 52
Per day - the IPTP Charge "per week" divided by 7;
Per hour - the non-firm IPTP Charge "per day" divided by 24.
If several power marketers or other entities are involved in a series of
sales of the same energy and/or capacity, transmission service shall be
required only with respect to the delivery to the ultimate wholesale buyer,
and if an Internal Point-to-Point Service charge is payable with respect to
the transaction, the charge shall be paid only with respect
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 78
to the delivery to, and absent other arrangements the charge shall be paid
by, the ultimate wholesale buyer.
22 Reservation of Capacity for Point-to-Point Transmission Service
Compliance with the applicable requirements of Part V of this Tariff is
required for the initiation of Through or Out Service or Internal Point-to-
Point Service.
22A In Service
22A.1 Firm or Non-Firm In Service will be provided by the Transmission
Providers through NEPOOL to Eligible Customers in conjunction
with Regional Network Service, Internal Point-to-Point Service or
Through or Out Service, pursuant to the applicable terms and
conditions of this Section 22A and the other applicable
provisions of the Tariff. In Service shall be required with
Through or Out Service only if it is provided with respect to a
transaction which goes through the NEPOOL Control Area. In
Service will not be provided as a separate service under this
Tariff; it may only be provided in
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 79
conjunction with Regional Network Service, Internal Point-to-Point
Service or Through or Out Service.
22A.2 An Eligible Customer requesting Reserved Capacity for In Service
shall request the Service in an Application pursuant to Part V,
which in the case of Through or Out Service may be included in
the Application for Through or Out Service.
22A.3 A Transmission Customer which receives Reserved Capacity for In
Service shall be obligated to pay for such Service as follows:
(1) A Transmission Customer which has Reserved Capacity for In
Service as part of or in conjunction with Through or Out
Service shall be obligated only to pay for the Through or
Out Service in accordance with Section 20.
(2) A Transmission Customer which has Reserved Capacity for In
Service as part of or in conjunction with Internal Point-to-
Point Service or Regional Network Service shall be obligated
to pay the Pool PTF Rate per Kilowatt (as determined for
Firm and Non-Firm Service
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 80
for the period of the service in the manner specified in
Section 20 of this Tariff with respect to the rate for
Through or Out Service) of the Reserved Capacity, subject to
reduction in accordance with paragraph (3) or (4) hereof.
(3) A Transmission Customer which has Reserved Capacity for In
Service as part of or in conjunction with Internal Point-to-
Point Service or Regional Network Service to serve its load
shall be entitled to a credit against the payment required
by paragraph (2) above for each hour in an amount equal to
(a) the Pool PTF Rate per Kilowatt per hour times (b) the
greater of (i) the amount of Energy received for the hour
from the resources covered by its Completed Applications for
the In Service, or (ii) the Installed Capability credit
allowed for such resources.
(4) A Transmission Customer which has Reserved Capacity for In
Service as part of or in conjunction with Internal Point-to-
Point
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 81
Service to effect a sale to the power exchange of
Energy or Installed Capability imported pursuant to such
reservation in an Interchange Transaction shall be entitled
to a credit against the payment required by paragraph (2)
above for each hour in an amount equal to (a) the Pool PTF
Rate per Kilowatt per hour times (b) the greater of (i) the
amount of Energy delivered to the power exchange for the
hour from the resources covered by its Completed
Applications for the In Service, or (ii) the credit allowed
for the Installed Capability delivered by it to the power
exchange.
Notwithstanding the foregoing, a Transmission Customer which
has Reserved Capacity for In Service in conjunction with
Internal Point-to-Point Service or Regional Network Service,
shall not be obligated to pay the Pool PTF Rate for any hour
for which all requests for Reserved Capacity for In Service
have been satisfied of the same type (Firm or Non-Firm)
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 82
and the same duration, and this shall be so whether or not
the rate would be required to be paid pursuant to paragraph
(3) or (4) above.
Three principal requirements apply to discounts for In
Service as follows (1) any offer of a discount made by the
Participants must be announced to all Eligible Customers
solely by posting on the OASIS, (2) any customer-initiated
requests for discounts (including requests for use by one's
wholesale merchant or an affiliate's use) must occur solely
by posting on the OASIS, and (3) once a discount is
negotiated, details must be immediately posted on the OASIS.
For any discount agreed upon for service on a path, from
Point(s) of Receipt to Point(s) of Delivery, the
Participants must offer the same discounted transmission
service rate for the same time period to all Eligible
Customers on all unconstrained transmission paths that go to
the
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 83
same Point(s) of Delivery on the NEPOOL Transmission System.
22A.4 The provisions of Section 22A.3 are intended as an interim
measure to discourage hoarding of capacity for import
transactions on the Ties. The Participants agree to attempt to
negotiate alternate provisions to discourage hoarding to become
effective October 1, 1999 and to file the alternate provisions by
August 1, 1999. If the Participants fail to make such a filing
by August 1, 1999, any Participant may make its own filing of
proposed provisions to discourage hoarding. If alternate
provisions have not become effective by October 1, 1999, Section
22A.3 shall remain in effect until superseded.
IV. SERVICE DURING THE TRANSITION PERIOD; CONGESTION COSTS; EXCEPTED
TRANSACTIONS
The five-year Transition Period, and additional arrangements to be in
effect during the succeeding five-year period, will permit the phase-in on
a negotiated basis of the Tariff rates.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 84
23 Transition Arrangements
The transition arrangements include (i) the treatment provided for certain
Excepted Transactions in Section 25, (ii) the provisions in Schedule 9 for
the phase-in of the rates for Regional Network Service, and (iii) the rules
provided in Sections 16.3 and 16.6 of the Agreement for the distribution
and application of revenues received by NEPOOL on behalf of the
Participants from the payment of the Tariff rates.
24 Congestion Costs
If limitations in available transmission capacity over any interface within
the NEPOOL Control Area in any hour require that the System Operator
dispatch resources out-of-merit, the System Operator shall determine for
the affected area or areas the aggregate of the Congestion Costs for all
such out-of-merit resources for the hour. The Congestion Costs for each
hour in any month shall be paid as a transmission charge and included in
the charge for Regional Network Service or Internal Point-to-Point Service
or Through or Out Service, whichever is applicable, by those Participants
and Non-Participants which are obligated to pay a Regional Network Service,
Internal Point-to-Point Service or Through or Out
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 85
Service charge for the month, in accordance with the following formula:
CH = CC {circle} (HL{i} + RC{i})
-------------
(HL + RC)
in which
CH = the amount to be paid by a Participant or Non-
Participant for the hour;
CC = the Congestion Costs for the hour to be allocated
and paid pursuant to this Section 24;
HL{i} = the Network Load of the Participant or Non-
Participant for the hour, if it is obligated to
pay a Regional Network Service charge for the
month;
HL = the aggregate of the Network Loads for the hour of
all Participants and Non-Participants which are
obligated to pay a Regional Network Service charge
for the month;
RC{i} = the Reserved Capacity, if any, for Internal Point-
to-Point Service or Through or Out Service of the
Participant or Non-Participant for the hour; and
RC = the aggregate Reserved Capacity, if any, for
Internal Point-to-Point Service or Through or Out
Service of
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 86
all Participants and Non-Participants for the hour.
Except as provided in the next sentence, this Section 24 shall terminate no
later than December 31, 1999. Notwithstanding the foregoing, if prior to
January 1, 2000, Participants having in the aggregate the requisite number
of Voting Shares have executed and filed with the Commission an amendment
to the Agreement and/or the Tariff to modify subsection (b) of Section
14.14 of the Agreement or to adopt some other modified or substitute
provision dealing with the allocation of Congestion Costs in a constrained
transmission area, but such amendment has not become effective, and/or the
preparation of necessary implementing rules and computer software has not
been completed prior to January 1, 2000, if the Management Committee so
elects this Section 24 shall continue in effect until such amendment
becomes effective and such rules and computer software have been completed.
As used in this Section 24, the "Congestion Cost" of an out-of-merit
resource for an hour means the product of (i) the difference between its
Dispatch Price and the Energy Clearing
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 87
Price for the hour, times (ii) the number of megawatt hours of out-of-merit
generation produced by the resource for the hour. The "Dispatch Price" of
an out-of-merit resource for an hour is the price to provide energy from the
resource, as determined pursuant to market operation rules approved by the
NEPOOL Regional Market Operations Committee to incorporate the Bid Price for
such energy and any loss adjustments, if and as appropriate under such
market operation rules. The "Energy Clearing Price" for an hour is the
price determined for the hour in accordance with Section 14.8 of the
Agreement.
25 Excepted Transactions
Notwithstanding any other section of the Tariff, the power transfers and
other uses of the NEPOOL Transmission System effected under the
transmission agreements in effect on November 1, 1996 specified below
("Excepted Transactions") will continue to be effected under such
agreements for the respective periods specified below rather than under
this Tariff, but not thereafter, and such transfers and other uses will
continue to be effected after such period, if still occurring, under this
Tariff. Participants receiving service under the agreements listed in
Exhibit G-1 shall not be
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 88
required to take Local Network Service for such
transfers and other uses. The period for which each Excepted Transaction
will continue to be effected under such existing transmission agreements
shall be:
(1) for the Transition Period, the following transfers pursuant to Section
17 of the Agreement:
(a) the transfer to a Participant's system within the NEPOOL Control
Area of its ownership interest in a Pool-Planned Unit which is
off its system;
(b) the transfer to a Participant's system within the NEPOOL Control
Area of its Unit Contract Entitlement, under a contract entered
into by it on or before November 1, 1996, in a Pool-Planned Unit
which is off its system; and
(c) the transfer to a Participant's system within the NEPOOL Control
Area of its Entitlement in a purchase (including a purchase
under the HQ Phase II Firm Energy Contract) from Hydro-Quebec
under a contract entered into by it on or before November 1,
1996, where the line over which the transfer is made into New
England is the HQ Interconnection;
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 89
(2) for the Transition Period, the transfer to a Participant's system
within the NEPOOL Control Area of its Unit Contract Entitlement in
the Vermont Yankee Nuclear Power Corporation unit or the Pilgrim 1
unit; provided the transfer is pursuant to a transmission agreement
in effect on November 1, 1996 and is to the entity which was
receiving the service on November 1, 1996; and
(3) for the period from the effective date of the Tariff until the
termination of the transmission agreement:
(a) transfers and other uses within the NEPOOL Control Area, as of
November 1, 1996, of the NEPOOL Transmission System under the
support or exchange agreements specified in Attachment G;
(b) transfers and other uses within the NEPOOL Control Area, as of
November 1, 1996, of the NEPOOL Transmission System under the
comprehensive network service agreements specified in Attachment
G-1; and
(c) transfers and other uses within the NEPOOL Control Area, as of
November 1, 1996, of the NEPOOL Transmission System under the
other transmission
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 90
agreements or tariff service agreements specified in Attachment
G.
The Management Committee is authorized to add additional agreements to
Attachment G if they have been inadvertently omitted. The transfers or
other uses under any of the transmission agreements covering the transfers
referred to in paragraphs (1), (2) and (3) above shall be in accordance
with the terms of the transmission agreement as in effect on November 1,
1996, or a modification of the terms which is expressly provided for in
the agreement as in effect on November 1, 1996 and is accomplished without
amendment of the agreement or by an amendment entered into after November
1, 1996 that does not extend the term of the agreement or increase the
amount of the service. Further, notwithstanding the foregoing restriction
on the amendment after November 1, 1996 of transmission agreements with
respect to Excepted Transactions, the transmission arrangements for the
Masspower and Altresco facilities may continue as Excepted Transactions in
accordance with transmission agreement amendments or memoranda of
understanding entered into as of December, 1996 which do not extend the
term of the agreements.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 91
For the purpose of determining priorities under this Tariff, Excepted
Transactions shall have the same priority as Firm Point-To-Point
Transmission Service transactions for resources in existence on the
effective date of this Tariff which are effected as Regional Network
Service or as Internal Point-to-Point Service or as Through or Out
Service.
When the transfers and other uses effected under the transmission
agreements that are Excepted Transactions cease to be Excepted
Transactions before the end of their term, the transactions shall be
effected under this Tariff and under any applicable Local Network Service
tariff, to the extent appropriate, but the transactions shall continue to
have a priority not less than the priority that they would have had if
Regional Network Service had been used for the transactions from the
effective date of this Tariff. New transactions entered into after
November 1, 1996 under umbrella tariff agreements then in effect will not
be Excepted Transactions.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 92
Notwithstanding the foregoing or any other section of the Tariff, existing
agreements which provide for the support of the costs of transmission
facilities or for the interconnection of transmission facilities shall
continue in effect until the termination of the agreement to provide for
such support or for the rights and obligations of the parties with respect
to the interconnection arrangements. Attachment G-2 lists certain
additional agreements covering transactions, the status of which is
described in the Attachment.
V. POINT-TO-POINT TRANSMISSION SERVICE; IN SERVICE
Preamble
Firm or Non-Firm Point-To-Point Transmission Service (including any In
Service to be applied for in an Application pursuant to this Part V, which
shall be deemed to be Point-to-Point Transmission for purposes of
determining the application of this Part V to the Application for In
Service) shall be reserved by all Transmission Customers, whether
Participants or Non-Participants, for all new transfers to be effected as
Internal Point-to-Point Service or as Through or Out Service, pursuant to
the applicable terms and conditions
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 93
of Part III and this Part V of the Tariff. Point-To-Point Transmission
Service is the service required for the receipt of capacity and/or energy
at designated Point(s) of Receipt and the transmission of such capacity
and/or energy to designated Point(s) of Delivery.
26 Scope of Application of Part V
Except for the deposit and creditworthiness requirement of Section 31.3,
which will apply only to Non-Participants, all of the requirements of this
Part V shall be fully applicable to both Participants and Non-Participants
requesting In Service, Internal Point-to-Point Service or Through or Out
Service. Alternative deposit and creditworthiness requirements are
applicable to Participants under NEPOOL's Financial Assurance Policy.
Reservations under the Tariff shall not be required for the use of
Internal Point-to-Point Service for deliveries to the NEPOOL power
exchange in Interchange Transactions from a Point of Receipt within the
NEPOOL Control Area, but are required for the use of In Service for such
deliveries from a Point of Receipt at the NEPOOL Control Area boundary.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 94
27 Nature of Firm Point-To-Point Transmission Service
27.1 Term: The minimum term of Firm Point-To-Point Transmission Service
shall be one day and the maximum term shall be that specified in the
Service Agreement.
27.2 Reservation Priority: Long-Term Firm Point-To-Point Transmission
Service shall be available to Participants and Non-Participants on a
first-come, first-served basis, I.E., in the chronological sequence
in which each Transmission Customer's application for reserved
service is received by the System Operator pursuant to Section 31.
Reservations for Short-Term Firm Point-To-Point Transmission Service
will be conditional based upon the length of the requested
transaction. If the NEPOOL Transmission System becomes
oversubscribed, requests for longer term service may preempt requests
for shorter term service up to the following deadlines: one day
before the commencement of daily service, one week before the
commencement of weekly service, and one month before the commencement
of monthly service. Before the conditional reservation deadline, if
available transmission capability is insufficient to satisfy all
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 95
Applications, an Eligible Customer with a reservation for shorter
term service has the right of first refusal to match any longer term
reservation before losing its reservation priority. A longer term
competing request for Short-Term Firm Point-To-Point Transmission
Service will be granted if the Eligible Customer with the right of
first refusal does not agree to match the competing request within 24
hours (or earlier if necessary to comply with the scheduling
deadlines provided in Section 27.8) from being notified by the System
Operator of a longer-term competing request for Short-Term Firm
Point-To-Point Transmission Service. After the conditional
reservation deadline, service will commence pursuant to the terms of
Part III of this Tariff. Firm Point-To-Point Transmission Service
will always have a reservation priority over non-firm Point-To-Point
Transmission Service under the Tariff. All Long-Term Firm Point-To-
Point Transmission Service will have reservation priority with Native
Load Customers and Excepted Transactions. Reservation priorities for
existing firm service customers, including customers receiving
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 96
receiving service with respect to Excepted Transactions, are provided
in Section 3.2.
27.3 Use of Firm Point-To-Point Transmission Service by the Participants
That Own PTF: A Transmission Provider that owns PTF will be subject
to the rates, terms and conditions of this Tariff when making Third-
Party Sales to be transmitted as Point-to-Point Transmission Service
under (i) agreements executed after November 1, 1996 or (ii)
agreements executed on or before November 1, 1996 to the extent that
the Commission requires them to be unbundled, by the date specified
by the Commission. A Transmission Provider that owns PTF will
maintain separate accounting, pursuant to Section 8, for any use of
Firm Point-To-Point Transmission Service to make Third-Party Sales to
the extent not paid for under this Tariff.
27.4 Service Agreements: A standard form Firm Point-To-Point
Transmission Service Agreement (Attachment A) will be offered to an
Eligible Customer when it submits a Completed Application for Long-
Term or Short-Term Firm Point-To-Point Transmission Service to be
transmitted
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 97
pursuant to this Tariff. Executed Service Agreements that contain the
information required under this Tariff will be filed with the
Commission in compliance with applicable Commission regulations.
27.5 Transmission Customer Obligations for Facility Additions or
Redispatch Costs: In cases where it is determined that the NEPOOL
Transmission System is not capable of providing new Firm Point-To-
Point Transmission Service without (1) degrading or impairing the
reliability of service to Native Load Customers, Network Customers,
customers taking service for Excepted Transactions and other
Transmission Customers taking Firm Point-To-Point Transmission
Service, or (2) interfering with a Participant's ability to meet
prior firm contractual commitments to others, the Transmission
Providers will be obligated to arrange to expand or upgrade PTF for
Long-Term Firm Service pursuant to the terms of Section 33. The
Transmission Customer must agree to compensate the Transmission
Providers or any other entity designated to effect construction
through the System Operator for any necessary transmission facility
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 98
additions or upgrades pursuant to the terms of Section 39. To the
extent the System Operator can relieve any system constraint more
economically by redispatching the Participants' resources, rather
than through construction of additions or upgrades, it shall do so,
provided that the Eligible Customer agrees to compensate the
Participants pursuant to the terms of Section 39. Any redispatch,
addition or upgrade or Direct Assignment Facilities costs to be
charged to the Transmission Customer on an incremental basis under
this Tariff will be specified in the Service Agreement prior to
initiating service.
27.6 Curtailment of Firm Transmission Service: In the event that a
Curtailment on the NEPOOL Transmission System, or a portion thereof,
is required to maintain reliable operation of the system, the
Curtailment will be made on a non-discriminatory basis to the
transaction(s) that effectively relieve the constraint. If multiple
transactions require Curtailment, to the extent practicable and
consistent with Good Utility Practice, the System Operator will
curtail service to Network
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 99
Customers and Transmission Customers taking Firm Point To-Point
Transmission Service on a basis comparable to the Curtailment of
service to the Participants' Native Load Customers (i.e., in
proportion to their respective Load Ratio Shares). All Curtailments
will be made on a non-discriminatory basis; however, Non-Firm
Point-To-Point Transmission Service shall be subordinate to Firm
Transmission Service. When the System Operator determines that an
electrical emergency exists on the NEPOOL Transmission System and
implements emergency procedures to effect a Curtailment of Firm
Transmission Service, the Transmission Customer shall make the
required reductions upon the System Operator's request. However,
NEPOOL reserves the right to effect a Curtailment, in whole or in
part, of any Firm Transmission Service provided under this Tariff
when, in the System Operator's sole discretion, an emergency or other
unforeseen condition impairs or degrades the reliability of the NEPOOL
Transmission System. The System Operator will notify all affected
Transmission Customers in a timely manner of any scheduled
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 100
Curtailments. In the event the System Operator exercises its right to
effect a Curtailment, in whole or part, of Firm Point-to-Point
Transmission Service, no credit or other adjustment shall be provided
as a result of the Curtailment with respect to the charge payable by
the Customer.
27.7 Classification of Firm Point-To-Point Transmission Service:
(a) A Transmission Customer taking Firm Point-To-Point Transmission
Service may (1) change its Points of Receipt and Delivery to
obtain service on a non-firm basis consistent with the terms of
Section 36.1 or (2) request a modification of the Points of
Receipt or Delivery on a firm basis pursuant to the terms of
Section 36.2; provided that if any Transmission Provider or its
designee constructed new facilities or upgraded facilities to
accommodate the original firm service, such Transmission
Provider or its designee shall continue to be compensated for
its facility costs by the Transmission Customer.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 101
(b) A Transmission Customer may purchase transmission service to
make sales from multiple generating units or contracts that are
on the NEPOOL Transmission System. For such a purchase of
transmission service the Point of Receipt shall be deemed to be
the NEPOOL power exchange, unless the multiple generating units
are at the same generating plant, in which case the units'
interconnection point with PTF will be treated as the Point of
Receipt.
(c) Firm deliveries will be provided from the Point(s) of Receipt to
the Point(s) of Delivery. Each Point of Receipt at which firm
transmission capacity is reserved for Long-Term Firm Point-to-
Point Transmission Service by the Transmission Customer shall be
set forth in the Service Agreement for such Service along with a
corresponding capacity reservation associated with each Point of
Receipt. Points of Receipt and corresponding capacity
reservations shall be as mutually agreed upon by the System
Operator and the Transmission Customer
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 102
for Short-Term Firm Point-to-Point Transmission Service and may
be identified as the NEPOOL power exchange in circumstances where
the System Operator does not require greater specificity. Each
Point of Delivery at which firm transmission capacity is reserved
for Long-Term Firm Point-to-Point Transmission Service by the
Transmission Customer shall be set forth in the Service Agreement
for such Service along with a corresponding capacity reservation
associated with Point of Delivery and may be identified as the
NEPOOL power exchange. Points of Delivery and corresponding
capacity reservations shall be as mutually agreed upon by the
System Operator and the Transmission Customer for Short-Term Firm
Point-to-Point Transmission Service. The greater of either (1)
the sum of the capacity reservations at the Point(s) of Receipt,
or (2) the sum of the capacity reservations at the Point(s) of
Delivery shall be the Transmission Customer's Reserved Capacity.
The Transmission Customer will be billed for its Reserved
Capacity
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 103
under the terms of Schedule 8 or Schedule 10, whichever is
applicable. The Transmission Customer's Use may not exceed its
firm capacity reserved at each Point of Receipt and each Point
of Delivery except as otherwise specified in Section 36. In
the event that the Use by a Transmission Customer (including
Third-Party Sales by the Participants) exceeds that Transmission
Customer's Reserved Capacity at any Point of Receipt or Point of
Delivery in any hour, it shall pay 200% of the charge which is
otherwise applicable for each Kilowatt of the excess. In
addition, the System Operator will record all instances in which
a Transmission Customer's Use exceeds that Transmission
Customer's firm Reserved Capacity, and if in any calendar year
more than 10 such instances occur with respect to any single
Transmission Customer, then the System Operator may require such
Transmission Customer to apply for additional Firm Point-to-
Point Transmission Service under the Tariff in an amount equal
to the greatest amount of
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 104
the excess of such Transmission Customer's Use over its firm
Reserved Capacity for the remainder of that calendar year.
Charges for such additional Firm Point-to-Point Transmission
Service will relate back to the first day of the month following
the month in which the System Operator notifies such Transmission
Customer that it is subject to the provisions of this paragraph.
27.8 Scheduling of Firm Point-To-Point Transmission Service:
Unless other schedules are permitted pursuant to NEPOOL rules,
schedules for the Transmission Customer's Firm Point-To-Point
Transmission Service (including schedules for resources to be self
scheduled) must be submitted to the System Operator no later than
noon of the day prior to commencement of such service. In the cases
which are bid into the power exchange, the Energy bid price must be
submitted to the System Operator by the noon deadline. Hour-to-hour
schedules of any capacity and energy that is to be delivered must be
stated in increments of 1000 kW per hour. Transmission Customers
with multiple requests for Firm Point-To-Point
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 105
Transmission Service at a Point of Receipt, each of which request is
under 1000 kW per hour, may consolidate their service requests at a
common Point of Receipt into units of 1000 kW per hour for scheduling
and billing purposes. Scheduling changes will be permitted up to
thirty-five minutes before the start of the next clock hour, provided
that the Delivering Party and Receiving Party also agree to the
schedule modification. The System Operator will furnish to the
Delivering Party's system operator hour-to-hour schedules equal to
those furnished by the Receiving Party (unless reduced for losses) and
will deliver the capacity and energy provided by such schedules.
Should the Transmission Customer, Delivering Party or Receiving Party
revise or terminate any schedule, such party shall immediately notify
the System Operator, and the System Operator will have the right to
adjust accordingly the schedule for capacity and energy to be
received and to be delivered.
28 Nature of Non-Firm Point-To-Point Transmission Service
28.1 Term: Non-Firm Point-To-Point Transmission Service will be
available for periods ranging from one hour to one
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Original Sheet No. 106
month. However, a Purchaser of Non-Firm Point-To-Point Transmission
Service will be entitled to reserve a sequential term of service (such
as a sequential monthly term without having to wait for the initial
term to expire before requesting another monthly term) so that the
total time period for which the reservation applies is greater than
one month, subject to the requirements of Section 32.3.
28.2 Reservation Priority: Non-Firm Point-To-Point Transmission Service
shall be available from transmission capability in excess of that
needed for reliable service to Native Load Customers, Network
Customers, customers for Excepted Transactions and other Transmission
Customers taking Long-Term and Short-Term Firm Point-To-Point
Transmission Service. A higher priority will be assigned to
reservations with a longer duration of service. In the event the
NEPOOL Transmission System is constrained, competing requests of
equal duration will be prioritized based on the highest price offered
by the Eligible Customer for the Transmission Service, or in the
event the price for all
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 107
Eligible Customers is the same, will be prioritized on a first-come,
first-served basis i.e., in the chronological sequence in which each
Customer has reserved service. Eligible Customers that have already
reserved shorter term service have the right of first refusal to match
any longer term reservation before being preempted. A longer term
competing request for Non-Firm Point-To-Point Transmission Service
will be granted if the Eligible Customer with the right of first
refusal does not agree to match the competing request: (a) immediately
for hourly Non-Firm Point-To-Point Transmission Service after
notification by the System Operator; and (b) within 24 hours (or
earlier if necessary to comply with the scheduling deadlines provided
in Section 28.6) for Non-Firm Point-to-Point Transmission Service
other than hourly transactions after notification by the System
Operator. Secondary transmission service for Network Customers
pursuant to Section 40.4 will have a higher priority than any Non-Firm
Point-To-Point Transmission Service. Non-Firm Point-To-Point
Transmission Service over secondary
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 108
Point(s) of Receipt and Point(s) of Delivery will have the lowest
reservation priority under this Tariff.
28.3 Use of Non-Firm Point-To-Point Transmission Service by the
Transmission Provider: A Transmission Provider will be subject to
the rates, terms and conditions of this Tariff when making Third-
Party Sales to be transmitted as Non-Firm Point-to-Point Transmission
Service under (i) agreements executed after November 1, 1996 or (ii)
agreements executed on or before November 1, 1996 to the extent that
the Commission requires them to be unbundled, by the date specified
by the Commission. A Transmission Provider will maintain separate
accounting, pursuant to Section 8, for any use of Non-Firm Point-To-
Point Transmission Service to make Third-Party Sales, to the extent
not paid for under this Tariff.
28.4 Service Agreements: The System Operator shall offer a standard
form Point-To-Point Transmission Service Agreement (Attachment A,
modified to cover non-firm service) to an Eligible Customer when the
Eligible Customer first submits a Completed Application for Non-Firm
Point-To-Point Transmission Service pursuant to the
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 109
Tariff. Executed Service Agreements that contain the information
required under this Tariff shall be filed with the Commission in
compliance with applicable Commission regulations.
28.5 Classification of Non-Firm Point-To-Point Transmission Service:
Non-Firm Point-To-Point Transmission Service shall be offered under
applicable terms and conditions contained in Part III of this Tariff.
The NEPOOL Participants undertake no obligation under this Tariff to
plan the NEPOOL Transmission System in order to have sufficient
capacity for Non-Firm Point-To-Point Transmission Service. Parties
requesting Non-Firm Point-To-Point Transmission Service for the
transmission of firm power do so with the full realization that such
service is subject to availability and to Curtailment or Interruption
under the terms of this Tariff. In the event that the Use by a
Transmission Customer (including Third-Party Sales by a Participant)
exceeds that Transmission Customer's non-firm Reserved Capacity at
any Point of Receipt or Point of Delivery, it shall pay 200% of the
charge which is otherwise applicable for
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 110
each Kilowatt of the excess. In addition, the System Operator will
record all instances in which a Transmission Customer's Use exceeds
that Transmission Customer's non-firm Reserved Capacity, and if in any
calendar year more than 10 such instances occur with respect to any
single Transmission Customer, then the System Operator may require
such Transmission Customer to apply for additional Non-Firm
Point-to-Point Transmission Service under the Tariff in an amount
equal to the greatest amount of the excess of such Transmission
Customer's Use over its non-firm Reserved Capacity for the remainder
of that calendar year. Charges for such additional Non-Firm
Point-to-Point Transmission Service will relate back to the first day
of the month following the month in which the System Operator notifies
such Transmission Customer that it is subject to the provisions of
this paragraph.
(a) Non-Firm Point-To-Point Transmission Service shall include
transmission of energy on an hourly basis and transmission of
scheduled short-term capacity and energy on a daily, weekly or
monthly basis, but
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Original Sheet No. 111
not to exceed one month's reservation for any one Application.
(b) Each Point of Receipt at which non-firm transmission capacity is
reserved by the Transmission Customer shall be set forth in the
Application along with a corresponding capacity reservation
associated with each Point of Receipt. The Point of Receipt or
Point of Delivery may be identified as the NEPOOL power exchange
in circumstances where the System Operator does not require
greater specificity.
28.6 Scheduling of Non-Firm Point-To-Point Transmission Service: Unless
other schedules are permitted pursuant to NEPOOL rules, and except as
otherwise provided below with respect to the scheduling of In
Service, schedules for Non-Firm Point-To-Point Transmission Service
must be submitted to the Transmission Provider no later than noon of
the day prior to commencement of such service. Schedules submitted
after noon will be accommodated, if practicable. Hour-to-hour
schedules of energy that is to be delivered must be stated in
increments of 1,000 kW
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 112
per hour. Transmission Customers within the NEPOOL Control Area with
multiple requests for Transmission Service at a Point of Receipt, each
of which is under 1,000 kW per hour, may consolidate their schedules
at a common Point of Receipt into units of 1,000 kW per hour.
Scheduling changes will be permitted up to thirty-five minutes before
the start of the next clock hour provided that the Delivering Party
and Receiving party also agree to the schedule modification. The
System Operator will furnish to the Delivering Party's system
operator, hour-to-hour schedules equal to those furnished by the
Receiving Party (unless reduced for losses) and shall deliver the
capacity and energy provided by such schedules. Should the
Transmission Customer, Delivering Party or Receiving Party
revise or terminate any schedule, such party shall immediately notify
the System Operator, and the System Operator shall have the right to
adjust accordingly the schedule for capacity and energy to be
received and to be delivered. In the event next-day capacity for In
Service on the Ties is available at noon on any day, this shall be
posted on
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 113
OASIS and shall be available for reservation by Eligible
Customers between noon and 6:00 p.m. If not all requested
reservations for the next-day In Service can be granted, the requests
for the longest number of consecutive hours shall be given priority.
If a Participant has available at the NEPOOL Control Area boundary a
dispatchable resource for which no reservation has been made, and the
Regional Market Operations Committee has determined that it is
appropriate to adopt rules to provide for the service and has adopted
such rules, the System Operator may schedule the resource for the
next day in accordance with such rules on the basis of the bid price
if Transmission capacity for In Service is available, notwithstanding
the lack of a reservation.
28.7 Curtailment or Interruption of Service: The System Operator
reserves the right to effect a Curtailment, in whole or in part, of
Non-Firm Point-To-Point Transmission Service provided under this
Tariff for reliability reasons when an emergency or other unforeseen
condition threatens to impair or degrade the
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 114
reliability of the NEPOOL Transmission System. The System Operator
reserves the right to effect an Interruption, in whole or in part, of
Non-Firm Point-To-Point Transmission Service provided under this
Tariff for economic reasons in order to accommodate (1) a request for
Firm Transmission Service, (2) a request for Non-Firm Point-To-Point
Transmission Service of greater duration, or (3) transmission service
for Network Customers. The System Operator also will discontinue or
reduce service to the Transmission Customer to the extent that
deliveries for transmission are discontinued or reduced at the
Point(s) of Receipt. Where required, Curtailments or Interruptions
will be made on a non-discriminarty basis to the transaction(s) that
effectively relieve the constraint; however, Non-Firm Point-To-Point
Transmission Service shall be subordinate to Firm Transmission
Service. If multiple transactions require Curtailment or
Interruption, to the extent practicable and consistent with Good
Utility Practice, Curtailments or Interruptions will be made to
transactions of the shortest term (e.g., hourly non-firm
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Original Sheet No. 115
transactions will be Curtailed or Interrupted before daily non-firm
transactions and daily non-firm transactions will be Curtailed or
Interrupted before weekly non-firm transactions). Transmission
service for Network Customers will have a higher priority than any
Non-Firm Point-To-Point Transmission Service under this Tariff.
Non-Firm Point-To-Point Transmission Service furnished over secondary
Point(s) of Receipt and Point(s) of Delivery will have a lower
priority than any other Non-Firm Point-To-Point Transmission Service
under this Tariff. The System Operator will provide advance notice of
Curtailment or Interruption where such notice can be provided
consistent with Good Utility Practice. In the event the System
Operator exercises its right to effect a Curtailment, in whole or
part, of Non-Firm Point-to-Point Transmission Service, no credit or
other adjustment shall be provided as a result of the Curtailment with
respect to the charge payable by the Customer. In the event the
System Operator exercises its right to effect an Interruption, in
whole or part, of Non-Firm Point-to-Point Transmission Service, the
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Original Sheet No. 116
charge payable by the Customer shall be computed as if the term of
service actually rendered were the term of service reserved; provided
that an adjustment of the charge shall be made only when the
Interruption is initiated by the System Operator, not when the
Customer fails to deliver energy to NEPOOL.
29 Service Availability
29.1 General Conditions: Firm Point-To-Point Transmission Service over,
on or across the NEPOOL Transmission System is available to any
Transmission Customer that has met the applicable requirements of
Section 31.
29.2 Determination of Available Transmission Capability:
A description of NEPOOL's specific methodology for assessing
available transmission capability posted on the NEPOOL OASIS(Section
5) is contained in Attachment C of this Tariff. In the event
sufficient transmission capability may not exist to accommodate a
service request, a System Impact Study will be performed.
29.3 Initiating Service in the Absence of an Executed Service Agreement:
If the System Operator and the Transmission Customer requesting Firm
Point-To-Point Transmission
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Original Sheet No. 117
Service cannot agree on all the terms and conditions of the applicable
Service Agreement, the System Operator will file with the Commission,
within thirty days after the date the Transmission Customer provides
written notification directing the System Operator to file, an
unexecuted Service Agreement containing terms and conditions deemed
appropriate by the System Operator for such requested transmission
service. The service will be commenced subject to the Transmission
Customer agreeing to (i) pay whatever rate the Commission ultimately
determines to be just and reasonable, and (ii) comply with the terms
and conditions of this Tariff including providing appropriate security
deposits in accordance with the terms of Section 31.3.
29.4 Obligation to Provide Transmission Service that Requires Expansion
or Modification of the Transmission System: If it is determined that
the service requested in a Completed Application for Long-Term Firm
Point-To-Point Transmission Service cannot be provided because of
insufficient capability on the NEPOOL Transmission System, one or
more Transmission Providers or other
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Original Sheet No. 118
entities will be designated to use due diligence to expand or modify
the NEPOOL Transmission System to provide the requested Long-Term Firm
Point-To-Point Transmission Service, provided that the Transmission
Customer agrees to compensate the Transmission Providers or other
entities that will be responsible for the construction of any new
facilities or upgrades for the costs of such new facilities or
upgrades pursuant to the terms of Section 39. The System Operator and
the designated Transmission Providers or other entities will conform
to Good Utility Practice in determining the need for new transmission
facilities or upgrades and in coordinating the design and construction
of such facilities. This obligation applies only to those facilities
that the designated Transmission Providers or other entities have the
right to expand or modify.
29.5 Deferral of Service: Long-Term Firm Point-To-Point Transmission
Service may be deferred until the designated Transmission Providers
or other entities complete construction of new transmission
facilities or upgrades needed to provide such service whenever it is
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 119
determined that providing the requested service would, without such
new facilities or upgrades, impair or degrade reliability to any
existing Firm Transmission Service.
29.6 Real Power Losses: Real power losses are associated with all
transmission service. The Transmission Provider is not obligated to
provide real power losses. To the extent PTF losses are not
specifically allocated through the market procedures provided for in
Section 14 of the Agreement, point-to-point losses will be allocated
on the basis of PTF average losses as established by the System
Operator. The System Operator shall post on the OASIS the PTF
average losses, which are initially set at 1.13% but shall be
adjusted by the System Operator from time to time. The applicable
real power loss factor shall be determined, after the Second
Effective Date, on the basis of PTF average losses. Average losses
shall be determined initially on an estimated basis, pending the
accumulation of the data needed to make the determination on an
actual basis.
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Original Sheet No. 120
29.7 Load Shedding: To the extent that a system contingency exists on
the NEPOOL Transmission System and the System Operator determines
that it is necessary for the Participants and the Transmission
Customer to shed load, the Parties shall shed load in accordance with
the procedures under the Agreement and the rules adopted thereunder,
or in accordance with other mutually agreed-to provisions.
30 Transmission Customer Responsibilities
30.1 Conditions Required of Transmission Customers: Firm Point-To-Point
Transmission Service will be provided only if the following
conditions are satisfied by the Transmission Customer:
a. The Transmission Customer has pending a Completed Application
for service;
b. In the case of a Non-Participant, the Transmission Customer
meets the creditworthiness criteria set forth in Section 11;
c. The Transmission Customer will have arrangements in place for
any other transmission service necessary to effect the delivery
from the generating source
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 121
to the Point of Receipt prior to the time service under the
Tariff commences;
d. The Transmission Customer agrees to pay for any facilities or
upgrades constructed or any redispatch costs chargeable to such
Transmission Customer under this Tariff, whether or not the
Transmission Customer takes service for the full term of its
reservation; and
e. The Transmission Customer has executed a Service Agreement or
has agreed to receive service pursuant to Section 29.3.
30.2 Transmission Customer Responsibility for Third-Party Arrangements:
Any scheduling arrangements that may be required by other electric
systems shall be the responsibility of the Transmission Customer
requesting service. (If Local Network Service will be required, the
System Operator shall notify the Transmission Customer and the
affected Participants.) The Transmission Customer shall provide,
unless waived by the System Operator, notification to the System
Operator identifying such other electric systems and authorizing
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Original Sheet No. 122
them to schedule the capacity and energy to be transmitted pursuant to
this Tariff on behalf of the Receiving Party at the Point of Delivery
or the Delivering Party at the Point of Receipt. The System Operator
will undertake reasonable efforts to assist the Transmission Customer
in making such arrangements, including without limitation, providing
any information or data required by such other electric system
pursuant to Good Utility Practice.
31 Procedures for Arranging Firm Point-To-Point Transmission Service
31.1 Application: A request for Firm Point-To-Point Transmission
Service for periods of one year or longer must be made in an
Application, delivered to ISO New England Inc., One Sullivan Road,
Holyoke, MA 01040-2841 or such other address as may be specified from
time to time. The request should be delivered at least sixty days in
advance of the calendar month in which service is requested to
commence. The System Operator will consider requests for such firm
service on shorter notice when practicable. Requests for firm
service for
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Original Sheet No. 123
periods of less than one year will be subject to expedited procedures
that will be negotiated between the System Operator and the party
requesting service within the time constraints provided in Section
27.8. All Firm Point-To-Point Transmission Service requests should be
submitted by transmitting the Completed Application to NEPOOL by mail
or telefax. Each of these methods will provide a time-stamped record
for establishing the priority of the Application.
31.2 Completed Application: A Completed Application for Firm Point-To-
Point Transmission Service shall provide all of the information
included at 18 C.F.R. <section>2.20 of the Commission's regulations,
including but not limited to the following:
(i) The identity, address, telephone number and facsimile
number of the entity requesting service;
(ii) A statement that the entity requesting service is, or will
be upon commencement of service, an Eligible Customer under
this Tariff;
(iii) The location of the Point(s) of Receipt and Point(s) of
Delivery and the identities of the Delivering Parties and
the Receiving Parties;
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Original Sheet No. 124
(iv) The location of the generating facility(ies) supplying the
capacity and energy, and the location of the load
ultimately served by the capacity and energy transmitted.
The System Operator will treat this information as
confidential in accordance with the NEPOOL information
policy except to the extent that disclosure of this
information is required by this Tariff, by regulatory or
judicial order, or for reliability purposes pursuant to
Good Utility Practice. The System Operator will treat this
information consistent with the standards of conduct
contained in 18 C.F.R. Part 37 of the Commission's
regulations;
(v) A description of the supply characteristics of the capacity
and energy to be delivered;
(vi) An estimate of the capacity and energy expected to be
delivered to the Receiving Party;
(vii) The Service Commencement Date and the term of the requested
transmission service; and
(viii) The transmission capacity requested for each Point of
Receipt and each Point of Delivery on the NEPOOL
Transmission System; customers may combine their requests
for service in order to satisfy the minimum transmission
capacity requirement.
The System Operator will treat this information consistent with the
standards of conduct contained in 18 C.F.R. Part 37 of the
Commission's regulations.
31.3 Deposit: A Completed Application for Firm Point-To-Point
Transmission Service by a Non-Participant shall
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Original Sheet No. 125
also include a deposit of either one month's charge for Reserved
Capacity or the full charge for Reserved Capacity for service requests
of less than one month. If the Application is rejected by the System
Operator because it does not meet the conditions for service as set
forth herein, or in the case of requests for service arising in
connection with losing bidders in a request for proposals (RFP), the
deposit will be returned with Interest, less any reasonable
Administrative Costs incurred by the System Operator or any affected
Participants in connection with the review of the Application. The
deposit also will be returned with Interest less any reasonable
Administrative Costs incurred by the System Operator or any affected
Participants if the new facilities or upgrades needed to provide the
service cannot be completed. If an Application is withdrawn or the
Eligible Customer decides not to enter into a Service Agreement for
the Service, the deposit will be refunded in full, with Interest, less
reasonable Administrative Costs incurred by the System Operator or any
affected Participants
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 126
to the extent such costs have not already been recovered from the
Eligible Customer. The System Operator will provide to the Eligible
Customer a complete accounting of all costs deducted from the refunded
deposit, which the Eligible Customer may contest if there is a dispute
concerning the deducted costs. Deposits associated with construction
of new facilities or upgrades are subject to the provisions of Section
33. If a Service Agreement for Firm Point-To-Point Transmission
Service is executed, the deposit, with interest, will be returned to
the Transmission Customer upon expiration or termination of the
Service Agreement. Applicable Interest will be calculated from the
day the deposit is credited to the System Operator's account.
31.4 Notice of Deficient Application: If an Application fails to meet
the requirements of this Tariff, the System Operator will notify the
entity requesting service within fifteen days of the System Operator's
receipt of the Application of the reasons for such failure. The
System Operator will attempt to remedy minor deficiencies in the
Application through informal
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Original Sheet No. 127
communications with the Eligible Customer. If such efforts are
unsuccessful, the System Operator will return the Application, along
with any deposit (less the reasonable Administrative Costs incurred by
the System Operator or any affected Participants in connection with
the Application), with Interest. Upon receipt of a new or revised
Application that fully complies with the requirements of this Tariff,
the Eligible Customer will be assigned a new priority based upon the
date of receipt by the System Operator of the new or revised
Application.
31.5 Response to a Completed Application: Following receipt of a
Completed Application for Firm Point-To-Point Transmission Service, a
determination of available transmission capability will be made
pursuant to Section 29.2. The Eligible Customer will be notified as
soon as practicable, but not later than thirty days after the date of
receipt of a Completed Application, if required, that either (i)
service will be provided without performing a System Impact Study, or
(ii) such a study is needed to evaluate the impact of the Application
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 128
pursuant to Section 33.1. Responses by the System Operator must be
made as soon as practicable to all completed applications and the
timing of such responses must be made on a non-discriminatory basis.
31.6 Execution of Service Agreement: Whenever the System Operator
determines that a System Impact Study is not required and that the
requested service can be provided, it will notify the Eligible
Customer as soon as practicable but no later than thirty days after
receipt of the Completed Application, and will tender a Service
Agreement to the Eligible Customer. Failure of an Eligible Customer
to execute and return the Service Agreement or request the filing of
an unexecuted Service Agreement pursuant to Section 29.3, within
fifteen days after it is tendered by the System Operator shall be
deemed a withdrawal and termination of the Application and any deposit
(less the reasonable Administrative Costs incurred by the System
Operator and any affected Participants in connection with the
Application) submitted will be refunded with Interest. Nothing herein
limits the right of an Eligible Customer to file
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Original Sheet No. 129
another Application after such withdrawal and termination. Where
a System Impact Study is required, the provisions of Section 33 will
govern the execution of a Service Agreement.
31.7 Extensions for Commencement of Service: The Transmission Customer
can obtain up to five one-year extensions for the commencement of
service. The Transmission Customer may postpone service by paying a
non-refundable annual reservation fee equal to one-month's charge for
Firm Point-To-Point Transmission Service for each year or fraction
thereof. If during any extension for the commencement of service an
Eligible Customer submits a Completed Application for Firm Point-To-
Point Transmission Service, and such request can be satisfied only by
releasing all or part of the Transmission Customer's Reserved
Capacity, the original Reserved Capacity will be released unless the
following condition is satisfied: within thirty days, the original
Transmission Customer agrees to pay the applicable rate for Firm
Point-To-Point Transmission Service for its Reserved Capacity for the
period that
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Original Sheet No. 130
its reservation overlaps the period covered by such Eligible Customer's
Completed Application. In the event the Transmission Customer elects
to release the Reserved Capacity, the reservation fees or portions
thereof previously paid will be forfeited.
32 Procedures for Arranging Non-Firm Point-To-Point Transmission Service
32.1 Application: Eligible Customers seeking Non-Firm Point-To-Point
Transmission Service must submit a Completed Application to the System
Operator. Applications should be submitted by entering the
information listed below on the NEPOOL OASIS.
32.2 Completed Application: A Completed Application shall provide all of
the information included in 18 C.F.R. <section>2.20 including but not
limited to the following:
(i) The identity, address, telephone number and facsimile number
of the entity requesting service;
(ii) A statement that the entity requesting service is, or will
be upon commencement of service, an Eligible Customer under
this Tariff;
(iii) The Point(s) of Receipt and the Point(s) of Delivery;
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(iv) The maximum amount of capacity requested at each Point of
Receipt and Point of Delivery; and
(v) The proposed dates and hours for initiating and terminating
transmission service hereunder.
In addition to the information specified above, when required to
properly evaluate system conditions, the System Operator also may ask
the Transmission Customer to provide the following:
(vi) The electrical location of the initial source of the power
to be transmitted pursuant to the Transmission Customer's
request for service; and
(vii) The electrical location of the ultimate load.
The System Operator will treat this information in (vi) and (vii) as
confidential at the request of the Transmission Customer except to the
extent that disclosure of this information is required by this Tariff,
by regulatory or judicial order, or for reliability purposes pursuant
to Good Utility Practice. The System Operator shall treat this
information consistent with the standards of conduct contained in Part
37 of the Commission's regulations.
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32.3 Reservation of Non-Firm Point-To-Point Transmission Service:
Requests for monthly service shall be submitted no earlier than sixty
days before service is to commence; requests for weekly service shall
be submitted no earlier than fourteen days before service is to
commence; requests for daily service shall be submitted no earlier
than five days before service is to commence; and requests for hourly
service shall be submitted no earlier than 9:00 a.m. the second day
before service is to commence. Requests for service received later
than noon of the day prior to the day service is scheduled to commence
will be accommodated if practicable.
32.4 Determination of Available Transmission Capability: Following
receipt of a tendered schedule the System Operator will make a
determination on a non-discriminatory basis of available transmission
capability pursuant to Section 29.2. Such determination shall be made
as soon as reasonably practicable after receipt, but not later than
the following time periods for the following terms of service (i)
thirty-five minutes for hourly service, (ii) thirty-five minutes for
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daily service, (iii) four hours for weekly service, and (iv) two days
for monthly service.
33 Additional Study Procedures For Firm Point-To-Point Transmission Service
Requests
33.1 Notice of Need for System Impact Study: After receiving a request
for Firm Point-To-Point Transmission Service, the System Operator will
review the effect of the proposed service on the reliability
requirements to meet existing and pending obligations of the
Participants and Non-Participants, and the obligations of the
particular Participants whose PTF facilities will be impacted by the
proposed service and determine on a non-discriminatory basis whether a
System Impact Study is needed. A description of the methodology for
completing a System Impact Study is provided in Attachment D. If the
System Operator determines that a System Impact Study is necessary to
accommodate the requested service, as soon as practicable thereafter
the System Operator will so inform the Eligible Customer and any
affected Participants if the System Impact Study is to be performed by
the Participants. If the likely
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result of the study is that a Direct Assignment Facility will be
required, the study shall be performed by the affected Participants,
subject to review by the System Operator. In such cases, the System
Operator will within thirty days of receipt of a Completed Application,
tender a System Impact Study agreement in the form of Exhibit I to this
Tariff, or in any other form that is mutually agreed to, pursuant to
which the Eligible Customer shall agree to reimburse the System
Operator and any affected Participants for performing the required
System Impact Study. For a service request to remain a Completed
Application, the Eligible Customer shall execute the System Impact
Study agreement and return it to the System Operator within fifteen
days. If the Eligible Customer elects not to execute a System Impact
Study agreement, its application shall be deemed withdrawn and its
deposit (less the reasonable Administrative Costs incurred by the
System Operator and any affected Participants in connection with the
Application), will be returned with Interest.
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33.2 System Impact Study Agreement and Cost Reimbursement:
(i) The System Impact Study agreement shall clearly specify the
System Operator's estimate of the actual cost, and time for
completion of the System Impact Study. The charge shall not
exceed the actual cost of the study. In performing the System
Impact Study, the System Operator and any affected Participants
will rely, to the extent reasonably practicable, on existing
transmission planning studies. The Eligible Customer shall not
be assessed a charge for such existing studies; however, the
Eligible Customer shall be responsible for charges associated
with any modifications to existing planning studies that are
reasonably necessary to evaluate the impact of the Eligible
Customer's request for service on the NEPOOL Transmission
System.
(ii) If in response to multiple Eligible Customers requesting service
in relation to the same competitive solicitation, a single
System Impact Study is sufficient for the System Operator to
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accommodate the requests for service, the costs of that study
will be equitably prorated among the Eligible Customers.
(iii) For System Impact Studies that the System Operator and any
affected Participants conduct on behalf of the Transmission
Providers, the Participants will record the cost of the System
Impact Studies pursuant to Section 8.5.
33.3 System Impact Study Procedures: Upon receipt of an executed System
Impact Study agreement, the System Operator and any affected
Participants will use due diligence to complete the required System
Impact Study within a sixty-day period. The System Impact Study, if
required, shall identify any system constraints and redispatch options
and the need for additional Direct Assignment Facilities or facility
additions or upgrades required to provide the requested service. In
the event that the required System Impact Study cannot be completed
within such time period, the System Operator will so notify the
Eligible Customer and provide an estimated completion date along with
an explanation of
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the reasons why additional time is required to complete the required
study and an estimate of any increase in cost which will result from
the delay. A copy of the completed System Impact Study and related
work papers shall be made available to the Eligible Customer. The
System Operator will use the same due diligence in completing the
System Impact Study for an Eligible Customer that is a Non-Participant
as it uses when completing studies for the Participants. The System
Operator will notify the Eligible Customer immediately upon completion
of the System Impact Study if the NEPOOL Transmission System will be
adequate to accommodate all or part of a request for service or that no
costs are likely to be incurred for new transmission facilities or
upgrades. Within fifteen days of completion of the System Impact
Study, the Eligible Customer must execute a Service Agreement or
request the filing of an unexecuted Service Agreement pursuant to
Section 29.3, or the Application shall be deemed terminated and
withdrawn.
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33.4 Facilities Study Procedures: If a System Impact Study indicates
that additions or upgrades to the NEPOOL Transmission System are
needed to supply the Eligible Customer's service request, the affected
Transmission Provider(s), within thirty days of the completion of the
System Impact Study, will tender to the Eligible Customer a Facilities
Study agreement in the form of Exhibit J to this Tariff, or in any
other form that is mutually agreed to, pursuant to which the Eligible
Customer shall agree to reimburse the System Operator and any affected
Transmission Providers or other entity designated by the affected
Transmission Provider(s) for performing any required Facilities Study.
For a service request to remain a Completed Application, the Eligible
Customer shall execute the Facilities Study agreement and return it to
the System Operator within fifteen days. If the Eligible Customer
elects not to execute the Facilities Study agreement, its application
shall be deemed withdrawn and its deposit (less the reasonable
Administrative Costs incurred by the System Operator and any affected
Participants in connection with the
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Application) will be returned with Interest. Upon receipt of an
executed Facilities Study agreement, the affected Transmission
Provider(s) or other designated entity will use due diligence to cause
the required Facilities Study to be completed within a sixty-day
period. If a Facilities Study cannot be completed in the allotted time
period, the affected Transmission Provider(s) will notify the
Transmission Customer and provide an estimate of the time needed to
reach a final determination and any resulting increase in the cost,
along with an explanation of the reasons that additional time is
required to complete the study. When completed, the Facilities Study
shall include a good faith estimate of (i) the cost of Direct
Assignment Facilities to be charged to the Transmission Customer, or
(ii) the Transmission Customer's appropriate share of the cost of any
required additions or upgrades, and (iii) the time required to complete
such construction and initiate the requested service. The Transmission
Customer shall provide a letter of credit or other reasonable form of
security acceptable to the Transmission Providers or
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other entities that will be responsible for the construction of the new
facilities or upgrades equivalent to the costs of the new facilities or
upgrades and consistent with relevant commercial practices, as
established by the Uniform Commercial Code. The Transmission Customer
shall have thirty days to execute a Service Agreement, if required, or
request the filing of an unexecuted Service Agreement with the
Commission and provide the required letter of credit or other form of
security or the request will no longer be a Completed Application and
shall be deemed terminated and withdrawn.
33.5 Facilities Study Modifications: Any change in design arising from
inability to site or construct proposed facilities will require
development of a revised good faith estimate. New good faith
estimates also will be required in the event of new statutory or
regulatory requirements that are effective before the completion of
construction or other circumstances beyond the control of the
Transmission Providers or other entities that are responsible for the
construction of the new facilities
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or upgrades and that significantly affect the final cost of the new
facilities or upgrades to be charged to the Transmission Customer
pursuant to the provisions of this Tariff.
33.6 Due Diligence in Completing New Facilities: The System Operator will
use due diligence to designate Transmission Providers or other
entities to add necessary facilities or upgrade the NEPOOL
Transmission System within a reasonable time. A Transmission Provider
or other entity will have no obligation to upgrade its existing or
planned transmission system in order to provide the requested Firm
Point-To-Point Transmission Service if doing so would impair system
reliability or otherwise impair or degrade existing firm service.
33.7 Partial Interim Service: If the System Operator determines that
there will not be adequate transmission capability to satisfy the full
amount of a Completed Application for Long-Term Firm Point-To-Point
Transmission Service, the portion of the requested Service that can be
accommodated without addition of any
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facilities or upgrades and through redispatch will be offered and
provided. However, there shall be no obligation to provide the
incremental amount of requested Long-Term Firm Point-To-Point
Transmission Service that requires the addition of facilities or
upgrades to the NEPOOL Transmission System until such facilities or
upgrades have been placed in service.
33.8 Expedited Procedures for New Facilities: In lieu of the procedures
set forth above, the Eligible Customer shall have the option to
expedite the process by requesting the System Operator to tender at
one time, together with the results of required studies, an "Expedited
Service Agreement" pursuant to which the Eligible Customer would agree
to pay for all costs incurred pursuant to the terms of this Tariff.
In order to exercise this option, the Eligible Customer shall request
in writing an Expedited Service Agreement covering all of the above-
specified items within thirty days of receiving the results of the
System Impact Study identifying the need for facility additions or
upgrades and costs to be incurred in providing the requested service.
While the
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System Operator, on behalf of the Transmission Providers or
other entities that will be responsible for constructing the new
facilities or upgrades, agrees to provide the Eligible Customer with
its best estimate of the new facility costs and other charges that may
be incurred, such estimate shall not be binding and the Eligible
Customer shall agree in writing to pay for all costs incurred pursuant
to the provisions of this Tariff. The Eligible Customer shall execute
and return such an Expedited Service Agreement within fifteen days of
its receipt or the Eligible Customer's request for service will cease
to be a Completed Application and will be deemed terminated and
withdrawn.
34 Procedures if New Transmission Facilities for Firm Point-To-Point
Transmission Service Cannot be Completed
34.1 Delays in Construction of New Facilities: If any event occurs that
will materially affect the time for completion of new facilities for
Firm Point-To-Point Service, or the ability to complete such
facilities, the System Operator will promptly notify the Transmission
Customer. In such circumstances, the System Operator
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will within thirty days of notifying the Transmission Customer of such
delays, convene a technical meeting with the Transmission Customer and
any affected Transmission Providers or other entities responsible for
construction to evaluate the alternatives available to the
Transmission Customer. The System Operator and the affected
Transmission Providers or other entities will make available to the
Transmission Customer studies and work papers related to the delay,
including all information that is in the possession of the System
Operator or the Transmission Providers or other entities that are
responsible for the construction of the new facilities or upgrades
that is reasonably needed by the Transmission Customer to evaluate any
alternatives.
34.2 Alternatives to the Original Facility Additions: When the review
process of Section 34.1 determines that one or more alternatives exist
to the originally planned construction project, the System Operator
will present such alternatives for consideration by the Transmission
Customer. If, upon review of any alternatives, the Transmission
Customer desires to proceed with its
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Completed Application subject to construction of the alternative
facilities, it may request the System Operator to submit a revised
Service Agreement. If the alternative approach solely involves
Non-Firm Point-To-Point Transmission Service, the System Operator will
promptly tender a Service Agreement for Non-Firm Point-To-Point
Transmission Service providing for such service. In the event the
System Operator and the affected Participants or other entities
responsible for construction conclude that no reasonable alternative
exists and the Transmission Customer disagrees, the Transmission
Customer may seek relief under the dispute resolution procedures
pursuant to Section 12 or it may refer the dispute to the Commission
for resolution.
34.3 Refund Obligation for Unfinished Facility Additions:
If the System Operator, the affected Transmission Providers or other
entities responsible for construction and the Transmission Customer
mutually agree that no other reasonable alternatives exist and the
requested service cannot be provided out of existing capability under
the conditions of this Tariff, the obligation to
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provide the requested Firm Point-To-Point Transmission Service shall
terminate and any deposit made by the Transmission Customer shall be
returned, with Interest. The Transmission Customer shall be
responsible for all costs prudently incurred by the System Operator and
by the Transmission Providers or other entities that have been
responsible for the construction of the new facilities or upgrades
through the date that any required regulatory approval is denied or
construction is suspended and for cost of removal, if necessary, of
facilities constructed prior to suspension.
35 Provisions Relating to Transmission Construction and Services on the
Systems of Other Utilities
35.1 Responsibility for Third-Party System Additions: Neither the System
Operator nor any Participant will be responsible for making
arrangements for any necessary engineering, permitting, and
construction of transmission or distribution facilities on the
system(s) of any other entity or for obtaining any regulatory approval
for such facilities. The System Operator will undertake reasonable
efforts to assist the Transmission
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Customer in obtaining such arrangements, including without limitation,
providing any information or data required by such other electric
system pursuant to Good Utility Practice.
35.2 Coordination of Third-Party System Additions: In circumstances
where the need for transmission facilities or upgrades is identified
pursuant to the provisions of this Tariff, and if such upgrades
further require the addition of transmission facilities on third-party
systems, the System Operator and the Transmission Providers or other
entities that are responsible for the construction of any new
facilities or upgrades on the NEPOOL Transmission System will have the
right to coordinate construction on the NEPOOL Transmission System
with the construction required by the third parties. The System
Operator and the Transmission Providers or other entities that are
responsible for the construction of any new facilities or upgrades on
the NEPOOL Transmission System may, after consultation with the
Transmission Customer and representatives of such other systems, defer
construction of new transmission
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facilities or upgrades on the NEPOOL Transmission System if the new
transmission facilities on another system cannot be completed in a
timely manner. The System Operator will notify the Transmission
Customer in writing of the basis for any decision to defer construction
and the specific problems that must be resolved before the construction
of new facilities will be initiated or resumed. Within sixty days of
receiving written notification by the System Operator of a decision to
defer construction pursuant to this section, the Transmission Customer
may challenge the decision in accordance with the dispute resolution
procedures contained in Section 12 or it may refer the dispute to the
Commission for resolution.
36 Changes in Service Specifications
36.1 Modifications on a Non-Firm Basis: The Transmission Customer taking
Firm Point-To-Point Transmission Service may submit a request to the
System Operator for transmission service on a non-firm basis over
Point(s) of Receipt and Point(s) of Delivery other than those
specified in the Service Agreement ("Secondary Receipt
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and Delivery Points"), in amounts not to exceed the Transmission
Customer's firm capacity reservation, without incurring an additional
Non-Firm Point-to-Point Transmission Service charge or executing a new
Service Agreement, subject to the following conditions:
(a) service provided over Secondary Receipt and Delivery Points will
be non-firm only, on an as-available basis, and will not displace
any firm or non-firm service reserved or scheduled by
Participants or Non-Participants under this Tariff or by the
Participants on behalf of their Native Load Customers or Excepted
Transactions;
(b) the sum of all Firm Point-To-Point Transmission Service and
Non-Firm Point-To-Point Transmission Service provided to the
Transmission Customer at any time pursuant to this section shall
not exceed the Reserved Capacity specified in the relevant
Service Agreement under which such services are provided;
(c) the Transmission Customer shall retain its right to schedule Firm
Point-To-Point Transmission Service
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at the Point(s) of Receipt and Point(s) of Delivery specified in
the relevant Service Agreement in the amount of the Transmission
Customer's original capacity reservation; and
(d) service over Secondary Receipt and Delivery Points on a non-firm
basis shall not require the filing of an Application for Non-Firm
Point-to-Point Transmission Service under the Tariff. However,
all other requirements of this Tariff (except as to transmission
rates) shall apply to transmission service on a non-firm basis
over Secondary Receipt and Delivery Points.
36.2 Modification on a Firm Basis: Any request by a Transmission
Customer to modify Point(s) of Receipt and Point(s) of Delivery on a
firm basis shall be treated as a new request for service in accordance
with Section 31, except that such Transmission Customer shall not be
obligated to pay any additional deposit if the capacity reservation
does not exceed the amount reserved in the existing Service Agreement.
While such new request is pending, the Transmission Customer shall
retain its
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priority for service at the firm Receipt Point(s) and Delivery Point(s)
specified in the Transmission Customer's Service Agreement.
37 Sale, Assignment or Transfer of Transmission Service
37.1 Procedures for Sale, Assignment or Transfer of Service:
Subject to Commission action on any necessary filings, a Transmission
Customer may sell, assign, or transfer all or a portion of its rights
under its Service Agreement, but only to another Eligible Customer
(the "Assignee"). The Transmission Customer that sells, assigns or
transfers its rights under its Service Agreement is hereafter referred
to as the "Reseller." Compensation to the Reseller shall not exceed
the higher of (i) the original rate paid by the Reseller,(ii) the
maximum applicable rate on file under this Tariff at the time of the
assignment, or (iii) the Reseller's opportunity cost capped at the
Participants' cost of expansion. If the Assignee does not request any
change in the Point(s) of Receipt or the Point(s) of Delivery, or a
change in any other term or condition set forth in the original
Service Agreement, the Assignee shall receive the same
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services as did the Reseller and the priority of service for the
Assignee shall be the same as that of the Reseller. A Reseller shall
notify the System Operator as soon as possible after any sale,
assignment or transfer of service occurs, but in any event,
notification must be provided prior to any provision of service to the
Assignee. The Assignee shall be subject to all terms and conditions of
this Tariff. If the Assignee requests a change in service, the
reservation priority of service will be determined by the System
Operator pursuant to Section 27.2.
37.2 Limitations on Assignment or Transfer of Service: If the Assignee
requests a change in the Point(s) of Receipt or Point(s) of Delivery,
or a change in any other specifications set forth in the original
Service Agreement, the System Operator will consent to such change
subject to the provisions of this Tariff, provided that the change
will not impair the operation and reliability of the Participants'
generation, transmission, or distribution systems. The Assignee shall
compensate the System Operator and any affected
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Participants for performing any System Impact Study needed to evaluate
the capability of the NEPOOL Transmission System to accommodate the
proposed change and any additional costs resulting from such change.
The Reseller shall remain liable for the performance of all obligations
under the Service Agreement, except as specifically agreed to by the
System Operator, the Reseller and the Assignee through an amendment to
the Service Agreement.
37.3 Information on Assignment or Transfer of Service: In accordance
with Section 5, Transmission Customers may use the NEPOOL OASIS to
post information regarding transmission capacity available for resale.
38 Metering and Power Factor Correction at Receipt and Delivery Points(s)
38.1 Transmission Customer Obligations: Unless the System Operator
otherwise agrees, the Transmission Customer shall be responsible for
installing and maintaining compatible metering and communications
equipment to accurately account for the capacity and energy being
transmitted under this Tariff and to communicate the
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information to the System Operator. Unless otherwise agreed, such
equipment shall remain the property of the Transmission Provider.
38.2 NEPOOL Access to Metering Data: The System Operator will have
access to such metering data as may reasonably be required to
facilitate measurements and billing under the Service Agreement.
38.3 Power Factor: Unless otherwise agreed, the Transmission Customer is
required to maintain a power factor within the same range as the
Participants maintain pursuant to Good Utility Practice and applicable
NEPOOL requirements. The power factor requirements are specified in
the Service Agreement, where applicable.
39 Compensation for New Facilities and Redispatch Costs
Whenever a System Impact Study performed in connection with the provision
of Firm Point-To-Point Transmission Service identifies the need for new
facilities or upgrades, the Transmission Customer shall be responsible for
such costs to the extent they are consistent with Commission policy and
Schedule 11. Whenever a System Impact Study identifies capacity
constraints that may be relieved more economically
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by redispatching the Participants' resources than by building new facilities
or upgrading existing facilities to eliminate such constraints, the
Transmission Customer shall be responsible for the redispatch costs to the
extent consistent with applicable Commission policy.
VI. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE)
The Participants will provide NEPOOL Regional Network Service (Network
Integration Transmission Service), as described in Part II of this Tariff
to Participants and Non-Participants pursuant to the applicable terms and
conditions contained in this Tariff. Part II of this Tariff specifies
certain terms and conditions which are generally applicable to the receipt
of Regional Network Service by both Participants and Non-Participants.
This Part VI specifies additional provisions with respect to the provision
of Regional Network Service.
40 Nature of Regional Network Service
40.1 Scope of Service: Regional Network Service (Network Integration
Transmission Service) is the transmission service described in Section
14 that allows Network Customers to efficiently and economically
utilize their
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resources and Interchange Transactions to serve their Network Load
located in the NEPOOL Control Area and any additional load that may be
designated pursuant to Section 43.3 of this Tariff. The Network
Customer taking Regional Network Service must obtain or provide
Ancillary Services pursuant to Section 4.
40.2 Transmission Provider Responsibilities: The NEPOOL Participants will
plan, construct, operate and maintain the NEPOOL Transmission System
in accordance with Good Utility Practice in order to provide the
Network Customer with Regional Network Service over the NEPOOL
Transmission System. Subject to Section 48, each Participant which is
individually a Transmission Provider, on behalf of its Native Load
Customers, shall be required to designate resources and loads in the
same manner as any Network Customer under Part VI of this Tariff.
This information must be consistent with the information used by the
Transmission Provider to calculate available transmission capacity.
The Participants shall include the Network Customer's Network Load in
NEPOOL Transmission System planning and
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shall, consistent with Good Utility Practice, endeavor to construct and
place into service sufficient transmission capacity to deliver Network
Resources to serve the Network Customer's Network Load on a basis
comparable to the Participants' delivery of their own generating and
purchased resources to their Native Load Customers.
40.3 Network Integration Transmission Service: The Participants that are
individually Transmission Providers will provide firm transmission
service over the NEPOOL Transmission System to the Network Customer
for the delivery of energy and/or capacity from its resources to
service its Network Loads on a basis that is comparable to the
Participants' use of the NEPOOL Transmission System to reliably serve
their Native Load Customers.
40.4 Secondary Service: The Network Customer may use the NEPOOL
Transmission System to receive or deliver energy and/or capacity in
connection with Interchange Transactions. Such energy and capacity
shall be transmitted, on an as-available basis, at no additional
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charge as part of Regional Network Service. Deliveries from resources
other than Network Resources will have a higher priority than any Non-
Firm Point-To-Point Transmission Service under this Tariff.
40.5 Real Power Losses: Real Power Losses are associated with all
transmission service. The Transmission Provider is not obligated to
provide Real Power Losses. To the extent PTF losses are not
specifically allocated through the market procedures provided for in
Section 14 of the Agreement, total remaining PTF losses, minus point-
to-point losses, shall be allocated on the basis of average losses as
established by the System Operator. The System Operator shall post on
the OASIS the PTF average losses, which are initially set at 1.13%,
but shall be adjusted by the System Operator from time to time. The
applicable real power loss factor shall be determined, after the
Second Effective Date, on the basis of PTF average losses. Average
losses will be determined initially on an estimated basis, pending the
accumulation of the data needed to make the determinations on an
actual basis.
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40.6 Restrictions on Use of Service: The Network Customer is entitled to
use Regional Network Service for any of the uses specified in Part II
of this Tariff.
41 Initiating Service
41.1 Condition Precedent for Receiving Service: Subject to the terms and
conditions of Parts II and VI of this Tariff, the Participants will
provide Regional Network Service to any Eligible Customer, provided
that, except as otherwise provided in Section 48, (i) the Eligible
Customer completes an Application for service as provided under Part
VI of this Tariff, (ii) the Eligible Customer and the System Operator
complete the technical arrangements set forth in Sections 41.3 and
41.4, (iii) the Eligible Customer executes a Service Agreement in the
form of Attachment B for service under Part VI of this Tariff or
requests in writing that the Transmission Provider file a proposed
unexecuted Service Agreement with the Commission, and (iv) the
Eligible Customer executes a Network Operating Agreement in the form
of Exhibit H to this Tariff, or in any other form that is mutually
agreed to, with the Transmission Provider.
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41.2 Application Procedures: Except as otherwise provided in Section 48,
an Eligible Customer requesting Network Integration Transmission
Service under this Tariff must submit an Application, with a deposit
approximating the charge for one month of service, to the System
Operator as far as possible in advance of the month in which service
is to commence. Completed Applications for Network Integration
Transmission Service will be assigned a priority according to the date
and time the Application is received, with the earliest Application
receiving the highest priority. Applications should be submitted by
entering the information listed below on the NEPOOL OASIS to the
extent feasible. A Completed Application shall provide all of the
information included in 18 CFR <section>2.20 including but not
limited to the following:
(i) The identity, address, telephone number and facsimile number
of the party requesting service;
(ii) A statement that the party requesting service is, or will be
upon commencement of service, an Eligible Customer under
this Tariff;
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(iii) A description of the Network Load at each delivery point.
This description should separately identify and provide the
Eligible Customer's best estimate of the total loads to be
served at each transmission voltage level, and the loads to
be served from each Transmission Provider substation at the
same transmission voltage level. The description should
include a ten year forecast of summer and winter load
resource requirements beginning with the first year after
the service is scheduled to commence;
(iv) The amount and location of any interruptible loads included
in the Network Load. This shall include the summer and
winter capacity requirements for each interruptible load
(had such load not been interruptible), that portion of the
load subject to Interruption, the conditions under which an
Interruption can be implemented and any limitations on the
amount and frequency of Interruptions. An Eligible Customer
should identify the amount of interruptible customer load
(if any) included in the ten year load forecast provided in
response to (iii) above;
(v) A description of Network Resources (current and ten-year
projection), which shall include, for each Network Resource,
if not otherwise available to the System Operator:
- Unit size and amount of capacity from that unit to be
designated as Network Resource
- VAR capability (both leading and lagging) of all
generators
- Operating restrictions
- Any periods of restricted operations throughout
the year
- Maintenance schedules
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- Minimum loading level of unit
- Normal operating level of unit
- Any must-run unit designations required for system
reliability or contract reasons
- Approximate variable dispatch price ($/MWH) for
redispatch computations
- Arrangements governing sale and delivery of power to
third parties from generating facilities located in the
NEPOOL Control Area, where only a portion of unit
output is designated as a Network Resource
- Description of external purchased power designated as a
Network Resource including source of supply, Control
Area location, transmission arrangements and delivery
point(s) to the Transmission Provider's Transmission
System;
(vi) Description of Eligible Customer's transmission system:
- Load flow and stability data, such as real and reactive
parts of the load, lines, transformers, reactive
devices and load type, including normal and emergency
ratings of all transmission equipment in a load flow
format compatible with that used by the Participants
- Operating restrictions needed for reliability
- Operating guides employed by system operators
- Contractual restrictions or committed uses of the
Eligible Customer's transmission system, other than the
Eligible Customer's Network Loads and Resources
- Location of Network Resources described in subsection
(v) above
- ten-year projection of system expansions or upgrades
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- Transmission System maps that include any proposed
expansions or upgrades
- Thermal ratings of Eligible Customer's Control Area
ties with other Control Areas; and
(vii) Service Commencement Date and the term of the requested
Network Integration Transmission Service. The minimum term
for Network Integration Transmission Service is one year.
Unless the Eligible Customer and the System Operator agree to a
different time frame, the System Operator must acknowledge the request
within ten days of receipt. The acknowledgment must include a date by
which a response, including a Service Agreement, will be sent to the
Eligible Customer. If an Application fails to meet the requirements
of this section, the System Operator shall notify the Eligible
Customer requesting service within fifteen days of receipt and specify
the reasons for such failure. Wherever possible, the System Operator
will attempt to remedy deficiencies in the Application through
informal communications with the Eligible Customer. If such efforts
are unsuccessful, the System Operator shall return the Application
without prejudice to the Eligible Customer, who may thereafter
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file a new or revised Application that fully complies with the
requirements of this section. The Eligible Customer will be assigned
a new priority consistent with the date of the new or revised
Application. The System Operator shall treat this information
consistent with the standards of conduct contained in Part 37 of the
Commission's regulations.
41.3 Technical Arrangements to be Completed Prior to Commencement of
Service: Except as otherwise provided in Section 48, Regional Network
Service shall not commence until the Participants and the Network
Customer, or a third party, have completed installation of all
equipment specified under a Network Operating Agreement consistent
with Good Utility Practice and any additional requirements reasonably
and consistently imposed to ensure the reliable operation of the
NEPOOL Transmission System. The Participants shall exercise
reasonable efforts, in coordination with the Network Customer, to
complete such arrangements as soon as practicable taking into
consideration the Service Commencement Date.
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41.4 Network Customer Facilities: The provision of Regional Network
Service shall be conditioned upon the Network Customer's constructing,
maintaining and operating the facilities on its side of each delivery
point or interconnection necessary to reliably deliver capacity and
energy from the NEPOOL Transmission System to the Network Customer.
The Network Customer shall be solely responsible for constructing or
installing and operating and maintaining all facilities on the Network
Customer's side of each such delivery point or interconnection.
41.5 Filing of Service Agreement: The System Operator will file Service
Agreements with the Commission in compliance with applicable
Commission regulations.
42 Network Resources
42.1 Designation of Network Resources: The designation of generation
resources as Network Resources shall be effected automatically in
accordance with the definition thereof for Participant Network
Customers. A Network Customer shall designate to the System Operator
those Network Resources which are owned, purchased or leased by it.
The Network Resources so designated may not
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include resources, or any portion thereof, that are committed for sale
to non-designated third party load or otherwise cannot be called upon
to meet the Network Customer's Network Load on a non-interruptible
basis, or to the extent that the resource is being delivered directly
to a load being served with Internal Point-to-Point Service. Any
owned, purchased or leased resources that were serving the Network
Customer's loads under firm agreements entered into on or before the
Compliance Effective Date shall be deemed to continue to be so owned,
purchased or leased by it until the Network Customer informs the System
Operator of a change. Nothing in this Section is intended to relieve
any customer of its obligation to pay the charge for Internal Point-
to-Point Service deliveries of Network Resources to it.
42.2 Designation of New Network Resources: The Network Customer shall
identify the Network Resources which are owned, purchased or leased by
it to the System Operator with as much advance notice as practicable.
A designation of a Network Resource as owned, purchased or
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leased by the Customer must be made by a notice to the System Operator.
Each such designation shall be effective as of the beginning of a
month, shall remain in effect for at least one full month, and shall
only be terminated at the end of a month.
42.3 Termination of Network Resources: The Network Customer may
terminate the designation of all or part of a Network Resource as
owned, purchased or leased by it at any time but should provide
notification to the System Operator as soon as reasonably practicable.
42.4 Network Customer Redispatch Obligation: As a condition to receiving
Network Integration Transmission Service, the Network Customer agrees
to redispatch its Network Resources as requested by the System
Operator pursuant to Section 45.2. To the extent practical, the
redispatch of resources pursuant to this section shall be on a least
cost, non-discriminatory basis between all Network Customers, and the
Participants.
42.5 Transmission Arrangements for Network Resources Not Physically
Interconnected With The NEPOOL Transmission System: The Network
Customer shall be responsible for
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any arrangements necessary to deliver capacity and energy from a
Network Resource not physically interconnected with the NEPOOL
Transmission System. The System Operator will undertake reasonable
efforts to assist the Network Customer in obtaining such arrangements,
including without limitation, providing any information or data
required by such other entity pursuant to Good Utility Practice.
42.6 Limitation on Designation of Resources: The Network Customer must
demonstrate that it owns, leases or has committed to purchase an
Entitlement in a generation resource pursuant to an executed contract
in order to designate the generating resource to serve its Network
Load. Alternatively, the Network Customer may establish that
execution of a contract is contingent upon the availability of
transmission service under Part II of this Tariff. An Entitlement in
a generating unit within the NEPOOL Control Area which is placed in
service after the Compliance Effective Date (other than a unit which
has lost its capacity value when its capacity value is restored or a
deactivated unit which may be reactivated
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without satisfying the requirements of Section 49 of the Tariff in
accordance with the provisions thereof) may not be designated to serve
a Network Customer's load unless, and only to the extent that, it has
been determined to be integrated into the NEPOOL Transmission System in
accordance with Section 49 of this Tariff.
42.7 Use of Interface Capacity by the Network Customer: There is no
limitation upon a Network Customer's use of the NEPOOL Transmission
System at any particular interface to integrate the Network Customer's
resources (or substitute purchases in Interchange Transactions) with
its Network Loads. However, a Network Customer's use of the NEPOOL
total interface capacity with other transmission systems to serve its
Network Load may not exceed the Network Customer's load.
43 Designation of Network Load
43.1 Network Load: Except as otherwise provided in Section 48, the
Network Customer must designate the individual Network Loads on whose
behalf the Participants will provide through NEPOOL Network
Integration Transmission
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Service. The Network Loads shall be specified in the Service
Agreement.
43.2 New Network Loads Connected With the NEPOOL Transmission System:
The Network Customer shall provide the System Operator with as much
advance notice as reasonably practicable of the designation of new
Network Load that will be added to the NEPOOL Transmission System. A
designation of new Network Load must be made through a modification of
service pursuant to a new Application. The Participants will use due
diligence to install or cause to be installed any transmission
facilities required to interconnect a new Network Load designated by
the Network Customer. The costs of new facilities required to
interconnect a new Network Load shall be determined in accordance
with the procedures provided in Section 44.4 and shall be charged to
the Network Customer in accordance with Commission policy and
Schedule 11.
43.3 Network Load Not Physically Interconnected with the NEPOOL
Transmission System: This section applies to both initial designation
pursuant to Section 43.1 and
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the subsequent addition of new Network Load not physically
interconnected with the NEPOOL Transmission System. To the
extent that the Network Customer desires to obtain transmission
service for a load outside the NEPOOL Control Area, the Network
Customer shall have the option of (1) electing to include the
entire load as Network Load for all purposes under Part VI of this
Tariff and designating resources to serve such additional Network
Load, or (2) excluding that entire load from its Network Load. To the
extent that the Network Customer gives notice of its intent to add a
new Network Load as part of its Network Load pursuant to this section
the request must be made through a modification of service pursuant to
a new Application, and shall be available only so long as a scheduling
and interconnection agreement acceptable to the System Operator shall
be required to be in effect with the Control Area in which the load is
located. Charges for such portion of the service shall be based on
the Through or Out Service rate applied to the amount
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reserved for the Network Load which is not physically interconnected
with the NEPOOL Transmission System.
43.4 New Interconnection Points: To the extent the Network Customer
desires to add a new Delivery Point or interconnection point between
the NEPOOL Transmission System and a Network Load, the Network
Customer shall provide the System Operator with as much advance notice
as reasonably practicable.
43.5 Changes in Service Requests: Under no circumstances shall the
Network Customer's decision to cancel or delay a requested change in
Network Integration Transmission Service (the addition of a new
Network Resource, if any, or designation of a new Network Load) in any
way relieve the Network Customer of its obligation to pay the costs of
transmission facilities constructed by the Participants and charged to
the Network Customer as reflected in the Service Agreement or other
appropriate agreement. However, the System Operator must treat any
requested change in Network Integration Transmission Service in a non-
discriminatory manner.
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43.6 Annual Load and Resource Information Updates: The Network Customer
shall provide the System Operator with annual updates of Network Load
and Network Resource forecasts consistent with those included in its
Application under Part VI of this Tariff. The Network Customer also
shall provide the System Operator with timely written notice of
material changes in any other information provided in its Application
relating to the Network Customer's Network Load, Network Resources,
its transmission system or other aspects of its facilities or
operations affecting the Participants' ability to provide reliable
service.
44 Additional Study Procedures For Network Integration Transmission Service
Requests
44.1 Notice of Need for System Impact Study: After receiving a request
for service, the System Operator shall review the effect of the
requested service on the reliability requirements to meet existing and
pending obligations of the Participant(s) and on the obligations of
the particular Participant(s) whose PTF facilities will be impacted by
the proposed service and shall determine on
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a non-discriminatory basis whether a System Impact Study is needed.
A description of the methodology for completing a System Impact
Study is provided in Attachment D. If the System Operator
determines that a System Impact Study is necessary to accommodate
the requested service, it shall as soon as practicable inform
the Eligible Customer and any affected Participant(s) if
the System Impact Study is to be performed by the Participant(s).
If the likely result of the study is that a Direct Assignment
Facility will be required, the study shall be performed by the
affected Participant(s), subject to review by the System Operator.
In such cases, the System Operator shall within thirty days of receipt
of a Completed Application, tender a System Impact Study agreement in
the form of Attachment I to this Tariff, or in any other form that is
mutually agreed to, pursuant to which the Eligible Customer shall
agree to reimburse the System Operator and any affected Participant
for performing the required System Impact Study. For a service
request to remain a Completed Application, the Eligible Customer
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shall execute a System Impact Study agreement and return it to the
System Operator within fifteen days. If the Eligible Customer elects
not to execute a System Impact Study agreement, its Application shall
be deemed withdrawn and its deposit (less the reasonable Administrative
Costs incurred by the System Operator and any affected Participant(s))
shall be returned with Interest.
44.2 System Impact Study Agreement and Cost Reimbursement:
(i) The System Impact Study agreement, whether in the form detailed
in Attachment I or in any other form that is mutually agreed to,
will clearly specify the System Operator's actual estimate of the
actual cost, and time for completion of the System Impact Study.
The actual charge shall not exceed the actual cost of the study.
In performing the System Impact Study, the System Operator and
the affected Participants shall rely, to the extent reasonably
practicable, on existing transmission planning studies. The
Eligible Customer will not be assessed a charge for such existing
studies;
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however, the Eligible Customer will be responsible for
charges associated with any modifications to existing planning
studies that are reasonably necessary to evaluate the impact of
the Eligible Customer's request for service on the NEPOOL
Transmission System.
(ii) If in response to multiple Eligible Customers requesting service
in relation to the same competitive solicitation, a single System
Impact Study is sufficient for the System Operator and the
affected Participants to accommodate the service requests, the
costs of that study shall be prorated among the Eligible
Customers.
(iii) For System Impact Studies that the System Operator and any
affected Participants conduct on behalf of a Participant which is
a Transmission Provider, the Participant will record the cost of
the System Impact Studies pursuant to Section 8.5.
44.3 System Impact Study Procedures: Upon receipt of an executed System
Impact Study agreement, the System Operator and any affected
Participants will use due
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diligence to complete the required System Impact Study within
a 60-day period. The System Impact Study, if required, shall
identify any system constraints, redispatch options, or the
need for additional Direct Assignment Facilities or other facility
additions or upgrades to provide the requested service. In
the event that the System Operator and any affected Participants are
unable to complete the required System Impact Study within such time
period, the System Operator shall so notify the Eligible Customer and
provide an estimated completion date along with an explanation of the
reasons why additional time is required to complete the required
studies and an estimate of any increase in cost which will result from
the delay. A copy of the completed System Impact Study and related
work papers shall be made available to the Eligible Customer. The
System Operator will use the same due diligence in completing the
System Impact Study for an Eligible Customer as it uses when
completing studies for the Participants. The System Operator shall
notify the Eligible Customer immediately upon completion of the System
Impact Study
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if the NEPOOL Transmission System will be adequate to accommodate
all or part of a request for service or that no costs are likely
to be incurred for new transmission facilities or upgrades. In
order for a request to remain a Completed Application, within fifteen
days of completion of the System Impact Study the Eligible Customer
must execute a Service Agreement or request the filing of an
unexecuted Service Agreement, or the Application shall be deemed
terminated and withdrawn.
44.4 Facilities Study Procedures: If a System Impact Study indicates
that additions or upgrades to the NEPOOL Transmission System are
needed to supply the Eligible Customer's service request, the affected
Transmission Provider(s), within thirty days of the completion of the
System Impact Study, shall tender to the Eligible Customer a
Facilities Study agreement in the form of Exhibit J to this Tariff, or
in any other form that is mutually agreed to, pursuant to which the
Eligible Customer shall agree to reimburse the affected Transmission
Provider(s) for performing the required Facilities Study. For a
service request to remain a
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Completed Application, the Eligible Customer shall execute the
Facilities Study agreement and return it to the System Operator
within fifteen days. If the Eligible Customer elects not to
execute a Facilities Study agreement, its Application shall be
deemed withdrawn and its deposit (less the reasonable Administrative
Costs incurred by the System Operator and any affected
Transmission Provider(s)) shall be returned with Interest. Upon
receipt of an executed Facilities Study agreement, the affected
Transmission Provider(s) will use due diligence to complete the
required Facilities Study within a sixty-day period. If the affected
Transmission Provider(s) are unable to complete the Facilities Study
in the allotted time period, the affected Transmission Provider(s)
shall notify the Eligible Customer and provide an estimate of the time
needed to reach a final determination and any resulting increase in
the cost, along with an explanation of the reasons that additional
time is required to complete the study. When completed, the
Facilities Study will include a good faith estimate of (i) the cost of
Direct
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Assignment Facilities to be charged to the Eligible Customer,
(ii) the Eligible Customer's appropriate share of the cost of any
required Network Upgrades, and (iii) the time required to complete
such construction and initiate the requested service. The Eligible
Customer shall provide a letter of credit or other reasonable form of
security acceptable to the affected Transmission Provider(s) or other
entities that will be responsible for the construction of the new
facilities or upgrades equivalent to the costs of new facilities or
upgrades consistent with commercial practices as established by the
Uniform Commercial Code. The Eligible Customer shall have thirty days
to execute a Service Agreement or request the filing of an unexecuted
Service Agreement and provide the required letter of credit or other
form of security or the request no longer will be a Completed
Application and shall be deemed terminated and withdrawn.
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45 Load Shedding and Curtailments
45.1 Procedures: Prior to the Service Commencement Date, the System
Operator and the Network Customer shall establish Load Shedding and
Curtailment procedures pursuant to the Network Operating Agreement
with the objective of responding to contingencies on the NEPOOL
Transmission System. The parties will implement such programs during
any period when the System Operator determines that a system
contingency exists and such procedures are necessary to alleviate such
contingency. The System Operator will notify all affected Network
Customers in a timely manner of any scheduled Curtailment.
45.2 Transmission Constraints: During any period when the System
Operator determines that a transmission constraint exists on the
NEPOOL Transmission System, and such constraint may impair the
reliability of the NEPOOL Transmission System, the System Operator
will take whatever actions, consistent with Good Utility Practice,
that are reasonably necessary to maintain the reliability of the
system. To the extent the System Operator determines that the
reliability of the System
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can be maintained by redispatching resources, the System Operator
will initiate procedures pursuant to a Network Operating Agreement
to redispatch all the Network Customer's resources and the
Participants' own resources on a least-cost basis without regard
to the ownership of such resources. Any redispatch under this
section may not unduly discriminate between the Participants' use
of the NEPOOL Transmission System on behalf of their Native Load
Customers and any Network Customer's use of the Transmission System
to serve its designated Network Load.
45.3 Cost Responsibility for Relieving Transmission Constraints: To the
extent not otherwise covered under the Network Operating Agreement,
whenever the System Operator implements least-cost redispatch
procedures in response to a transmission constraint, the customers
taking Internal Point-to-Point Service, Through or Out Service and/or
In Service and Network Customers will each bear a proportionate share
of the total redispatch cost.
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45.4 Curtailments of Scheduled Deliveries: If a transmission constraint
on the NEPOOL Transmission System cannot be relieved through the
implementation of least-cost redispatch procedures and the System
Operator determines that it is necessary to effect a Curtailment of
scheduled deliveries, such schedule shall be curtailed in accordance
with the Network Operating Agreement.
45.5 Allocation of Curtailments: The System Operator shall on a non-
discriminatory basis, effect a Curtailment of the transaction(s) that
effectively relieve the constraint. However, to the extent
practicable and consistent with Good Utility Practice, any Curtailment
will be shared by the customers taking Internal Point-to-Point
Service, Through or Out Service and/or In Service and Network
Customers in proportion to their respective Load Ratio Shares. The
System Operator shall not direct the Network Customer to effect a
Curtailment of schedules to an extent greater than the System Operator
would effect a Curtailment of the Participants' schedules under
similar circumstances.
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45.6 Load Shedding: To the extent that a system contingency exists on the
NEPOOL Transmission System and the System Operator determines that it
is necessary for the customers taking Internal Point-to-Point Service,
Through or Out Service and/or In Service and Network Customers to shed
load, the Parties shall shed load in accordance with previously
established procedures under the Network Operating Agreement, or in
accordance with other mutually agreed-to provisions.
45.7 System Reliability: Notwithstanding any other provisions of this
Tariff, the System Operator reserves the right, consistent with Good
Utility Practice and on a not unduly discriminatory basis, to effect a
Curtailment of Network Integration Transmission Service without
liability on the part of the System Operator or the Participants for
the purpose of making necessary adjustments to, changes in, or repairs
on the Participants' lines, substations and facilities, and in cases
where the continuance of Network Integration Transmission Service
would endanger persons or property. In the event of any adverse
condition(s) or
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disturbance(s) on the NEPOOL Transmission System or on any other
system(s) directly or indirectly interconnected with the NEPOOL
Transmission System, the System Operator, consistent with Good
Utility Practice, also may effect a Curtailment of Network Integration
Transmission Service in order to (i) limit the extent or damage of the
adverse condition(s) or disturbance(s), (ii) prevent damage to
generating or transmission facilities, or (iii) expedite restoration
of service. The System Operator will give the Network Customer as
much advance notice as is practicable in the event of such
Curtailment. Any Curtailment of Network Integration Transmission
Service will be not unduly discriminatory relative to the
Participants' use of the Transmission System on behalf of their Native
Load Customers. The Network Operating Agreement shall specify the
rate treatment and all related terms and conditions applicable in the
event that the Network Customer fails to respond to established Load
Shedding and Curtailment procedures.
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46 Rates and Charges
The Network Customer shall pay Transmission Providers for any Direct
Assignment Facilities and its share of the cost of any required Network
Upgrades and applicable study costs consistent with Commission policy and
Schedule 11, along with the payment to the System Operator of the charges
for Ancillary Services and the charge for Regional Network Service provided
under this Tariff.
46.1 Determination of Network Customer's Monthly Network Load: The
Network Customer's "Monthly Network Load" is its hourly Network Load
(including its designated Network Load not physically interconnected
with the Transmission Provider under Section 43.3) coincident with the
coincident aggregate Network Load of the Participants and other
Network Customers served in each Local Network in the hour in which
the coincident Network Load is at its maximum for the month ("Monthly
Peak").
47 Operating Arrangements
47.1 Operation under The Network Operating Agreement: The Network
Customer shall plan, construct, operate and
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maintain its facilities in accordance with Good Utility Practice and in
conformance with the Network Operating Agreement which shall be in the
form of Exhibit H to this Tariff, or in any other form that is mutually
agreed to.
47.2 Network Operating Agreement: The terms and conditions under which
the Network Customer shall operate its facilities and the technical
and operational matters associated with the implementation of Part VI
of the Tariff shall be specified in the Network Operating Agreement.
The Network Operating Agreement shall provide for the Parties to (i)
operate and maintain equipment necessary for integrating the Network
Customer within the NEPOOL Transmission System (including, but not
limited to, remote terminal units, metering, communications equipment
and relaying equipment), (ii) transfer data between the System
Operator and the Network Customer (including, but not limited to, heat
rates and operational characteristics of Network Resources,
generation schedules for units outside the NEPOOL Transmission System,
interchange schedules, unit
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outputs for redispatch required under Section 45, voltage schedules,
loss factors and other real time data), (iii) use software programs
required for data links and constraint dispatching, (iv) exchange data
on forecasted loads and resources necessary for long-term planning, and
memorandum address any other technical and operational considerations
required for implementation of Part VI of this Tariff, including
scheduling protocols. The Network Operating Agreement will recognize
that the Network Customer shall either (i) operate as a Control Area
under applicable guidelines of the North American Electric Reliability
Council (NERC) and the Northeast Power Coordinating Council (NPCC),
(ii) satisfy its Control Area requirements, including all necessary
Ancillary Services, by contracting with the System Operator and the
Participants, or (iii) satisfy its Control Area requirements, including
all necessary Ancillary Services, by contracting with another entity,
consistent with Good Utility Practice, which satisfies NERC and NPCC
requirements. The System Operator shall not unreasonably refuse to
accept
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contractual arrangements with another entity for Ancillary Services.
47.3 Network Operating Committee: A Network Operating Committee
(Committee) shall be established to coordinate operating criteria for
the Parties' respective responsibilities under the Network Operating
Agreement, where the Network Customer is not a Participant. Each
Network Customer shall be entitled to have at least one representative
on the Committee. The Committee shall meet from time to time as need
requires, but no less than once each calendar year.
48 Scope of Application of Part VI to Participants
(a) All Participants which are receiving Regional Network Service on the
Compliance Effective Date shall be deemed to have requested to
continue Regional Network Service and to have identified as their
Network Resources and Network Load all of their resources and load as
of the Compliance Effective Date, unless they elect in accordance with
Section 3.3 of this Tariff to receive Internal Point-to-Point Service
at one or more Points of Delivery from one or more Point(s) of
Receipt.
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(b) In view of the operational, informational and financial obligations
imposed on Participants by the Agreement, the NEPOOL Financial
Assurance Policy and NEPOOL rules, the following requirements of Part
VI of this Tariff shall not be applicable to Participants:
(1) the Application requirement specified in Sections 41.1(i) and 42
of this Tariff;
(2) the deposit requirement specified in Section 41.2 of this Tariff;
(3) the requirement that a Network Customer execute a Service
Agreement, as specified in Section 41.1 (iii) of this Tariff;
provided that a Service Agreement shall be required (i) for any
Participant initially taking Regional Network Service after the
Compliance Effective Date, (ii) if a Participant serves load not
physically interconnected with the NEPOOL Transmission System
pursuant to Section 43.3 of this Tariff or (iii) if a new
facility or upgrade is to be constructed pursuant to Section 44.4
of this Tariff;
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(4) the requirement that a Network Customer execute a Network
Operating Agreement, as specified in Section 41.1(iv) of this
Tariff; provided that a Network Operating Agreement shall be
required if a Participant serves load not physically
interconnected with the NEPOOL Transmission System pursuant to
Section 43.3 of this Tariff; and
(5) the requirement that a Network Customer provide an annual update
of Network Load and Network Resource forecasts, as specified in
Section 43.6 of the Tariff.
Notwithstanding the foregoing, if the System Operator determines at any
time that it requires information from a Participant which would be
contained in an Application submitted pursuant to Section 41.2 or an annual
update of Network Load and Network Resource forecasts provided pursuant to
Section 43.6, it has the right to require that the Customer provide the
information.
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VII.INTERCONNECTIONS
49 Interconnection Requirements
Any Participant or Non-Participant which proposes to site a new generating
unit at a site owned by it, or which it has the right to acquire, or to
materially change and increase the capacity of an existing generating unit,
located in the NEPOOL Control Area, shall be obligated to:
(a) satisfy any applicable requirements under the local tariff of the
Transmission Provider in whose Local Network the generator would be
located or to which the interconnection would be connected, including
the filing with the Commission of an interconnection agreement, which
interconnection agreement may be filed by the Transmission Provider
unsigned either on its own or at the request of the Generator Owner;
(b) submit to the System Operator an interconnection application complying
with requirements specified by the System Operator, and enter into an
agreement with the System Operator and, if necessary, one or more
affected Transmission Providers to provide for the conduct of a
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System Impact Study and, if required, enter into an agreement with one
or more Transmission Providers to provide for the conduct of a
Facilities Study, to determine what additions or upgrades to the NEPOOL
Transmission System and to the Non-PTF System are required in order to
permit the full integration of its generating unit into the NEPOOL
system. The System Impact Study and Facilities Study shall be
conducted in accordance with the procedures, and subject to the
obligations, specified in Section 33 of this Tariff; and
(c) submit its proposal for review in accordance with Section 18.4 of the
Agreement and to take any action required pursuant to Section 18.5 of
the Agreement as a result of such review in order that its generating
unit will be fully integrated into the NEPOOL Transmission System on a
basis which permits the firm delivery of the output of the unit;
provided that the Participant or Non-Participant may proceed with the
siting of a new or materially changed generating unit under
circumstances which do not permit full integration of the unit
temporarily or permanently if it agrees in writing that
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 194
the output of the unit will be limited to below its full capacity, to
the levels which can be delivered on a firm basis as identified in
accordance with Sections 18.4 and 18.5 of the Agreement except in
emergency conditions, as such conditions are determined by the System
Operator; and upon the satisfaction of the obligations described in
(a), (b) and (c) above the Generator Owner shall have the right to be
interconnected to the NEPOOL Transmission System. (If required, any
preliminary feasibility study shall be performed under a separate
agreement.)
If the studies conducted pursuant to this Section indicate that new PTF
facilities or a facility modification or other PTF upgrades are necessary
in connection with a new or materially changed generating unit, or
otherwise in order to ensure adequate, economic and reliable operation of
the bulk power supply systems of the Participants for regional purposes,
whether or not a particular customer is benefited, upon approval of the
studies by the Regional Transmission Planning Committee, subject to review
by the System Operator, one or more Transmission Providers or their
designees shall be designated by the Regional Transmission Planning
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 195
Committee, subject to review by the System Operator, to design and effect
the construction or modification.
Upon the designation of a Transmission Provider or its designee to design
and effect a PTF addition or upgrade and the fixing of the cost
responsibilities of the Participants and Non-Participants and agreement as
to the security and other provisions of said arrangement, the Transmission
Provider or its designee designated to perform the construction shall, (i)
in accordance with the terms of the arrangements described in this
paragraph and subject to Sections 18.4 and 18.5 of the Agreement, use its
best efforts to design and effect the proposed construction or modification
and (ii) enter into an interconnection agreement with the Generator Owner
as described in paragraph (a) of this Section 49.
Any facilities required in connection with a new generating unit or the
material change of an existing generating unit which constitute a Direct
Assignment Facility shall be fully paid for by the Participant or Non-
Participant proposing the new generating unit or material change under an
interconnection agreement with the Transmission Provider.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 196
Subject to the foregoing, a Participant or Non-Participant proposing a new
or materially changed generating unit, shall be obligated to pay, under an
interconnection agreement with the Transmission Provider, a share of the
full costs of any new PTF facilities or facility modification or other PTF
upgrade which is required and to provide security for its obligations in
accordance with Schedule 11 to this Tariff.
For purposes of determining whether a generating unit is placed in service
after the Compliance Effective Date for purposes of Section 42.6 of this
Tariff or is obligated to satisfy the requirements of this Section, on
January 1, 1999 and thereafter, any unit in active or deactivated status,
as classified in the April 1998 NEPOOL Capacity, Energy, Loads and
Transmission Report and any other generating unit in active status on that
date may receive deactivated status, subject to criteria developed by the
appropriate NEPOOL committee. If so designated, the deactivated unit may
retain this status for a period not to exceed three (3) years from the date
the unit receives deactivated status and shall not be obligated to comply
with this Section if it is reactivated during such period, but if not
reactivated during such period
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 197
shall be deemed retired at the end of such period for purposes of this
Section. Notwithstanding the foregoing, if a proposal is submitted and
approved under Section 18.4 of the Agreement during the three-year period to
1) reactivate, 2) materially modify and reactivate or 3) replace the
deactivated unit, the unit may be reactivated without material modification
without compliance with this Section. The cost of any PTF upgrade required
by 2) or 3) above shall be shared in accordance with Schedule 11 of this
Tariff. Notwithstanding the foregoing, any unit in deactivated status prior
to January 1, 1999 shall be entitled to retain such status through December
31, 2001 whether or not a submission is made under Section 18.4 during such
period.
50 Rights of Generator Owners
Upon compliance with the applicable requirements of the Tariff, (i) any
generating unit located in the NEPOOL Control Area which is in service on
the Compliance Effective Date (including a unit that has lost its capacity
value when its capacity value is restored or a deactivated unit which may
be reactivated without satisfying the requirements of Section 49 of this
Tariff in accordance with the provisions thereof);
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 198
(ii) any generating unit located in the NEPOOL Control Area which is placed
in service after the Compliance Effective Date after complying with Section
49 and Schedule 11 of the Tariff; and (iii) any resource outside the NEPOOL
Control Area that is the subject of a Firm Transmission Service transaction
shall with respect to NEPOOL internal services have rights equal to all
other firmly integrated resources, and shall not at any later time (other
than in connection with service over the Ties not specifically referred to
in the Section 18.4 approval) be required to pay for any additional Network
or other upgrades or costs required in order to further reinforce the
transmission system; provided that any generating unit placed in service
after the Compliance Effective Date, the output of which is limited in
accordance with Section 18.4 of the Agreement to below its full capacity
shall have such rights only up to the permitted output level(s); provided
further that there will be no adverse distinctions in the planning process
or with respect to transmission facility construction between Firm
Transmission Service Customers, any generators referred to in (i) or (ii)
above, and any resources referred to in (iii)
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 199
above. It is further provided that, in accordance with Section 18.4 of the
Agreement, no generator referred to in (i) or (ii) above shall have its
established operating limits reduced, except for emergency situations, as a
result of any new request for NEPOOL interconnection or subsequent Section
18.4 approvals.
51 New Interconnection to Other Control Area
The allocation of PTF upgrade costs associated with interconnections to
other Control Areas placed in service or modified after the Compliance
Effective Date ("New Interconnections") is not presently addressed in this
Tariff. The Participants intend to address in a filing with the Commission
prior to the Compliance Effective Date arrangements for the allocation and
payment of such PTF upgrade costs as follows:
(i) costs of PTF upgrades for New Interconnections to accommodate a
reservation for In Service shall be allocated and paid in a manner
that is consistent with the cost allocation mechanism set forth in
Schedule 11 to this Tariff; and
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 200
(ii) costs of PTF upgrades for New Interconnections to accommodate a
reservation for Through or Out Service shall be allocated and paid in
a manner that is consistent with Section 20 of this Tariff.
It is expected that the rights associated with these reservations will be
equal to the rights for similar reservations for service on existing Ties
that are in service on the Compliance Effective Date.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 201
SCHEDULE 1
Scheduling, System Control and Dispatch Service
Scheduling, System Control and Dispatch Service is the service required to
schedule at the pool level the movement of power through, out of, within, or
into the NEPOOL Control Area. It is anticipated that local level service would
be provided under the Local Network Service tariffs of the individual
Transmission Providers. For transmission service under this Tariff, this
Ancillary Service can be provided only by the System Operator and the
Transmission Customer must purchase this service from the System Operator.
Charges for Scheduling, System Control and Dispatch Service are to be based on
the expenses incurred by the System Operator, the satellite dispatch centers
and the Participants to provide these services. A surcharge for these services
will be added to the Internal Point-to-Point Service rate, to the Through or
Out Service rate and to the Regional Network Service rate.
The System Operator expenses will be based on the functions required to
provide these services and include, but are not limited to:
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 202
o Processing and implementation of requests for service, including
support of the NEPOOL OASIS node;
o Coordination of transmission system operation and implementation of
necessary control actions by the System Operator and support for
these functions;
o Billing associated with transmission services provided under this
Tariff;
o Transmission system planning which supports this service;
o Administrative costs associated with the aforementioned functions.
The satellite dispatch center expenses and the Participant expenses will in
each case be an allocated portion of dispatch center expense for the PTF
dispatch functions performed.
This amended Schedule 1 shall be effective as of September 1, 1997 and the
initial surcharge herein under shall be effective from September 1, 1997 to
June 1, 1998. The surcharge shall be redetermined annually as of June 1 in
each year and shall be in effect for the succeeding twelve months. The rate
surcharge per kilowatt for each month is one-twelfth of the amount derived by
dividing the total annual expenses for providing the service by the sum of the
average of the coincident Monthly Peaks (as defined in Section 46.1) of all
Local Networks for the prior calendar year.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 203
The rate surcharge for each Participant or Non-Participant which pays the
Regional Network Service rate for a month shall be based on the number of
kilowatts of its Monthly Network Load (as defined in Section 46.1) for the
month. The rate surcharge for each Participant or Non-Participant which is
obligated to pay the Internal Point-to-Point Service rate or the Through or Out
Service rate for the month shall be based on the highest amount of its Reserved
Capacity for each transaction scheduled as Internal Point-to-Point Service
and/or Through or Out Service for the month.
The revenues received by the System Operator for NEPOOL for providing
Scheduling, System Control and Dispatch Service shall be allocated each month
among the System Operator and the Participants whose satellite or other costs
are reflected in the computation of the surcharge for the service in proportion
to the costs for each which are reflected in the computation of the surcharge.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 204
SCHEDULE 2
Reactive Supply and Voltage Control from
Generation Sources Service
In order to maintain transmission voltages on the NEPOOL Transmission
System within acceptable limits, generation facilities are operated to produce
(or absorb) reactive power. Thus, Reactive Supply and Voltage Control from
Generation Sources Service must be provided for each transaction on the NEPOOL
Transmission System. The amount of Reactive Supply and Voltage Control from
Generation Sources Service that must be supplied with respect to a Transmission
Customer's transaction will be determined based on the reactive power support
necessary to maintain transmission voltages within limits that are generally
accepted in the region and consistently adhered to by the Participants.
Reactive Supply and Voltage Control from Generation Sources Service is to
be provided through the Participants and the System Operator and the
Transmission Customer must purchase this service from the Participants through
the System Operator. The charge for each hour for such service shall be paid
by each Participant or
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 205
Non-Participant which receives either Regional Network Service or Internal
Point-to-Point Service or Through or Out Service and shall be determined in
accordance with the following formula:
CH = (CC + LOC + SCL) (HL{1} + RC{1})
-------------
(HL + RC)
in which
CH = the amount to be paid by the Participant or Non-
Participant for the hour;
CC = the capacity costs for the hour, which shall be stated
in an informational filing with the Commission;
LOC = the lost opportunity costs for the hour to be paid to
Participants who provide VAR support in accordance
with Section 14.5(a) of the Agreement commencing on
the Second Effective Date;
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 206
SCL = the cost of energy used in the hour by generating
facilities, synchronous condensers or static
controlled VAR regulators in order to provide VAR
support to the transmission system;
HL{1} = the Network Load of the Participant or Non-Participant
for the hour;
HL = the aggregate of the Network Loads of all Participants
and Non-Participants for the hour;
RC{1} = the Reserved Capacity for Internal Point-to-Point
Service and/or Through or Out Service of the
Participant or Non-Participant for the hour; and
RC = the aggregate Reserved Capacity for Internal Point-to-
Point Service and/or Through or Out Service of all
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 207
Participants and Non-Participants for the hour.
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Original Sheet No. 208
SCHEDULE 3
Regulation and Frequency Response Service
(Automatic Generator Control)
Regulation and Frequency Response Service (Automatic Generator Control) is
necessary to provide for continuous balancing of resources (generation and
interchange) with Load, and for maintaining scheduled interconnection frequency
at sixty cycles per second (60 Hz). Regulation and Frequency Response Service
(Automatic Generation Control) is accomplished by committing on-line generation
whose output is raised or lowered (predominantly through the use of automatic
generating control equipment) as necessary to follow the moment-by-moment
changes in load. The obligation to maintain this balance between resources and
load lies with the System Operator and this service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area
which enter into separate agreements with NEPOOL through Interchange
Transactions pursuant to the Agreement which result from NEPOOL central
dispatch. The
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 209
Transmission Customer must either take this service from the System Operator or
through the Interchange or make alternative comparable arrangements to satisfy
its Regulation and Frequency Response Service (Automatic Generator Control or
AGC) obligation.
As of December 1, 1996, charges for this Service are determined under the
Prior Agreement as follows:
Payments and reimbursements under the current AGC Billing System fall into
two categories. First, those Participants who have either not made the
appropriate installation arrangements, or who have responsibility for units
that have not met the minimum AGC availability criterion, are required to
pay into a Fixed Cost fund. The dollars collected in the fund are paid to
lead Participants having AGC capability in accordance with a formula which
provides for distribution of the Fixed Cost Fund. The billing for fixed
costs is done on a calendar year basis, by April 1 of the following year.
Second, the AGC Billing system compensates the lead Participants for the
loss of efficiency and increased maintenance costs that are experienced as
a result of AGC operation of their units. An amount representing an
estimate of the total increased hourly operating costs is collected
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 210
from all Participants pro rata to their hourly load. These collected funds
are distributed to the lead Participants who incurred the costs. Billing
for hourly costs is done on a monthly basis.
As of the Second Effective Date, charges for this Service will be
determined on the basis of Bid Prices submitted by the Participants in
accordance with Section 14 of the Agreement.
The transmission service required with respect to Regulation and Frequency
Response Service (Automatic Generator Control) will be paid for as part of
Regional Network Service or Internal Point-to-Point Service by all Participants
and other entities serving load in the NEPOOL Control Area. The charge for
Regional Network Service is specified in Schedule 9. The charge for Internal
Point-to-Point Service is specified in Schedule 10.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 211
SCHEDULE 4
Energy Imbalance Service
Energy Imbalance Service is the service provided when a difference occurs
between the scheduled and the actual delivery of energy to a load located
within the NEPOOL Control Area during a single hour. This service will be
available to all Participants and other entities that serve load within the
NEPOOL Control Area which enter into separate agreements with NEPOOL through
Interchange Transactions resulting from NEPOOL central dispatch at prices which
will be determined in accordance with Section 12 of the Prior Agreement until
the Second Effective Date, and which will be determined in accordance with
Section 14 of the Agreement thereafter. The Transmission Customer may either
supply its load from its own resources or through bilateral transactions or
obtain the service through Interchange Transactions. The transmission service
required with respect to Interchange Transactions will be furnished as part of
Regional Network Service or Internal Point-to-Point Service to all Participants
and other entities serving load in the NEPOOL Control Area. The charges for
Regional Network
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 212
Service or Internal Point-to-Point Service are specified in Schedules 9 and 10.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 213
SCHEDULE 5
Operating Reserve - 10-Minute Spinning Reserve Service
10-Minute Spinning Reserve Service is a service needed to serve load
immediately in the event of a system contingency. This service will be
available to all Participants and other entities that serve load within the
NEPOOL Control Area which enter into separate agreements with NEPOOL through
Interchange Transactions resulting from NEPOOL central dispatch. The
Transmission Customer may either supply this service with its own resources or
through bilateral transactions or obtain the service through Interchange
Transactions on terms determined until the Second Effective Date in accordance
with Section 12 of the Prior NEPOOL Agreement, and on terms determined
thereafter in accordance with Sections 14.4, 14.5 and 14.9 of the Agreement.
Under the Prior Agreement arrangements which will remain in effect until
the Second Effective Date, operating reserve is provided through central
dispatch and the after-the-fact own load energy billing arrangements. Prior
NEPOOL Agreement, <section><section>12.5 - 12.8. Participants that are deemed
to carry operating reserve in any hour are entitled to share in distributions
each month from
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 214
the Pool Savings Fund. Prior NEPOOL Agreement
<section><section>14.1(e)(viii)(B) and 14.8(d). These arrangements are equally
applicable to 10-Minute Spinning Reserve Service, 10-Minute Non-Spinning
Reserve Service and 30-Minute Reserve Service. Prior NEPOOL Agreement,
<section><section>12.5, 14.1(e)(viii)(B) and 14.8(d).
Under Sections 14.4, 14.5 and 14.9 of the Agreement, as it will be in
effect after the Second Effective Date, the price to be paid for 10-Minute Non-
Spinning Reserve Service or 30-Minute Operating Reserve Service received in any
hour will be the Operating Reserve Clearing Price for the hour for that
category of reserve service, as determined on the basis of bid prices to
provide the service. Agreement, <section>14.9(a) and (b). After the Third
Effective Date, the price to be paid for 10-Minute Spinning Reserve Service
will be determined on the same basis. Agreement, <section>14.9(a) and (c).
During the period from the Second Effective Date until the Third Effective
Date, the price for 10-Minute Spinning Reserve Service will be equal to the
"Lost Opportunity Clearing Price" for the hour and the lost opportunity costs,
if any, for the generating units which supply the service, as determined in
accordance with Section 14.9 of the Agreement. Agreement, <section>14.9(c) and
(d).
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 215
The Transmission Service required with respect to Interchange Transactions
will be furnished as part of Regional Network Service or Internal Point-to-
Point Service to all Participants and other entities serving load in the NEPOOL
Control Area. The charge for Regional Network Service is determined in
accordance with Section 16 of the Tariff and Schedule 9. The charge for
Internal Point-to-Point Service is determined in accordance with Section 21 of
the Tariff and Schedule 10.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 216
SCHEDULE 6
Operating Reserve - 10-Minute Non-Spinning Reserve Service
10-Minute Non-Spinning Reserve Service is a service needed to serve load in
the event of a system contingency. This service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area
which enter into separate agreements with NEPOOL through Interchange
Transactions resulting from NEPOOL central dispatch. The Transmission Customer
may either supply this service with its own resources or through bilateral
transactions or obtain the service through Interchange Transactions on terms
determined until the Second Effective Date in accordance with Section 12 of the
Prior NEPOOL Agreement, and on terms determined thereafter in accordance with
Sections 14.4, 14.5 and 14.9 of the Agreement.
Under the Prior NEPOOL Agreement arrangements which will remain in effect
until the Second Effective Date, operating reserve is provided through central
dispatch and the after-the-fact own load energy billing arrangements. Prior
NEPOOL Agreement, <section><section>12.5 - 12.8. Participants that are deemed
to carry operating reserve in any hour are entitled to share in
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 217
distributions each month from the Pool Savings Fund. Prior NEPOOL Agreement
<section><section>14.1(e)(viii)(B) and 14.8(d). These arrangements are equally
applicable to 10-Minute Spinning Reserve Service, 10-Minute Non-Spinning
Reserve Service and 30-Minute Reserve Service. Prior NEPOOL Agreement,
<section><section>12.5, 14.1(e)(viii)(B) and 14.8(d).
Under Sections 14.4, 14.5 and 14.9 of the Agreement, as it will be in
effect after the Second Effective Date, the price to be paid for 10-Minute Non-
Spinning Reserve Service or 30-Minute Operating Reserve Service received in any
hour will be the Operating Reserve Clearing Price for the hour for that
category of reserve service, as determined on the basis of bid prices to
provide the service. Agreement, <section>14.9(a) and (b). After the Third
Effective Date, the price to be paid for 10-Minute Spinning Reserve Service
will be determined on the same basis. Agreement, <section>14.9(a) and (c).
During the period from the Second Effective Date until the Third Effective
Date, the price for 10-Minute Spinning Reserve Service will be equal to the
"Lost Opportunity Clearing Price" for the hour and the lost opportunity costs,
if any, for the generating units which supply the service, as determined in
accordance with Section 14.9 of the Agreement. Agreement, <section>14.9(c) and
(d).
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 218
The Transmission Service required with respect to Interchange Transactions
will be furnished as part of Regional Network Service or Internal Point-to-
Point Service to all Participants and other entities serving load in the NEPOOL
Control Area. The charge for Regional Network Service is determined in
accordance with Section 16 of the Tariff and Schedule 9. The charge for
Internal Point-to-Point Service is determined in accordance with Section 21 of
the Tariff and Schedule 10.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 219
SCHEDULE 7
Operating Reserve - 30-Minute Reserve Service
30-Minute Reserve Service is a service needed to serve load in the event of
a system contingency. This service will be available to all Participants and
other entities that serve load within the NEPOOL Control Area which enter into
separate agreements with NEPOOL through Interchange Transactions resulting from
NEPOOL central dispatch. The Transmission Customer may either supply this
service with its own resources or through bilateral transactions or obtain the
service through Interchange Transactions on terms determined until the Second
Effective Date in accordance with Section 12 of the Prior NEPOOL Agreement, and
on terms determined thereafter in accordance with Sections 14.4, 14.5 and 14.9
of the Agreement.
Under the Prior NEPOOL Agreement arrangements which will remain in effect
until the Second Effective Date, operating reserve is provided through central
dispatch and the after-the-fact own load energy billing arrangements. Prior
NEPOOL Agreement, <section><section>12.5 - 12.8. Participants that are deemed
to carry operating reserve in any hour are entitled to share in
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 220
distributions each month from the Pool Savings Fund. Prior NEPOOL Agreement
<section><section>14.1(e)(viii)(B) and 14.8(d). These arrangements are equally
applicable to 10-Minute Spinning Reserve Service, 10-Minute Non-Spinning
Reserve Service and 30-Minute Reserve Service. Prior NEPOOL Agreement,
<section><section>12.5, 14.1(e)(viii)(B) and 14.8(d).
Under Sections 14.4, 14.5 and 14.9 of the Agreement, as it will be in
effect after the Second Effective Date, the price to be paid for 10-Minute Non-
Spinning Reserve Service or 30-Minute Operating Reserve Service received in any
hour will be the Operating Reserve Clearing Price for the hour for that
category of reserve service, as determined on the basis of bid prices to
provide the service. Agreement, <section>14.9(a) and (b). After the Third
Effective Date, the price to be paid for 10-Minute Spinning Reserve Service
will be determined on the same basis. Agreement, <section>14.9(a) and (c).
During the period from the Second Effective Date until the Third Effective
Date, the price for 10-Minute Spinning Reserve Service will be equal to the
"Lost Opportunity Clearing Price" for the hour and the lost opportunity costs,
if any, for the generating units which supply the service, as determined in
accordance with Section 14.9 of the Agreement. Agreement, <section>14.9(c) and
(d).
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 221
The Transmission Service required with respect to Interchange Transactions
will be furnished as part of Regional Network Service or Internal Point-to-
Point Service to all Participants and other entities serving Load in the NEPOOL
Control Area. The charge for Regional Network Service is determined in
accordance with Section 16 of the Tariff and Schedule 9. The charge for
Internal Point-to-Point Service is determined in accordance with Section 21 of
the Tariff and Schedule 10.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 222
SCHEDULE 8
Through or Out Service -
The Pool PTF Rate
(1) A Transmission Customer shall pay to NEPOOL for firm or non-firm Through or
Out Service reserved for it in accordance with Section 19 of the Tariff the
highest of (a) the Pool PTF Rate or (b)a rate which is derived from the annual
incremental cost, not otherwise borne by the Transmission Customer or a
Generator Owner, of any new facilities or upgrades that would not be required
but for the need to provide the requested service or (c) a rate which is equal
to NEPOOL's opportunity cost (if and when available) capped at the cost of
expansion, as determined for the period of service in accordance with Section
20 of this Tariff. If at any time NEPOOL proposes to charge a rate based on
opportunity cost, it shall first file with the Commission procedures for
computing opportunity cost pricing for all Transmission Customers. The
Transmission Customer shall also be obligated to pay any applicable ancillary
service charges and any congestion or other uplift charge required to be paid
pursuant to Section 24 of this Tariff.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 223
(2) The Pool PTF Rate in effect at any time shall be determined annually on the
basis of the information for the most recent calendar year contained in Form 1
filings (or similar information on the books of Transmission Providers that are
not required to submit a Form 1 filing) and shall be changed annually effective
as of June 1 in each year. The Pool PTF rate shall be equal to (i) the sum for
all Participants of Annual Transmission Revenue Requirements determined in
accordance with Attachment F DIVIDED BY (ii) the sum of the coincident Monthly
Peaks (as defined in Section 46.1) of all Local Networks, excluding from the
Monthly Peak for each Local Network as applicable the loads at each applicable
Point of Delivery of each Participant or Non-Participant which has elected to
take Internal Point-to-Point Service in lieu of Regional Network Service at one
or more Points of Delivery; PLUS the Long-Term Firm Reserved Capacity amount
for each such Participant or Non-Participant which has elected to take Firm
Internal Point-to-Point Service in lieu of Regional Network Service at one or
more Points of Delivery PLUS the Long-Term Reserved Capacity amount for each
Participant or Non-Participant for Firm Through or Out Service. Revenues
associated with Short-Term Point-to-Point reservations will be credited to the
sum of
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 224
all Participants' Annual Transmission Revenue Requirements referred to
in (i) above.
(3) Discounts: Three principal requirements apply to discounts for Through or
Out Service as follows (1) any offer of a discount made by the Participants
must be announced to all Eligible Customers solely by posting on the OASIS, (2)
any customer-initiated requests for discounts (including requests for use by
one's wholesale merchant or an affiliate's use) must occur solely by posting on
the OASIS, and (3) once a discount is negotiated, details must be immediately
posted on the OASIS. For any discount agreed upon for service on a path, from
Point(s) of Receipt to Point(s) of Delivery, the Participants must offer the
same discounted transmission service rate for the same time period to all
Eligible Customers on all unconstrained transmission paths that go to the same
Point(s) of Delivery on the NEPOOL Transmission System.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 225
SCHEDULE 9
Regional Network Service
(1) A Transmission Customer which serves a Network Load in the NEPOOL Control
Area shall pay to NEPOOL each month for Regional Network Service the amount
determined in accordance with the following formula:
A = 1/12 (R {.} L)
in which
A = the amount to be paid
R = the Participant RNS Rate per Kilowatt for the current Year for the
Participant which owns the Local Network from which the Customer's
load is served
L = the Customer's Monthly Network Load for the month
It shall also be obligated to pay any applicable congestion or other uplift
charge required to be paid pursuant to Section 24 of this Tariff.
Each Participant RNS Rate is to be determined in accordance with the
remaining provisions of this Schedule 9. The Participants intend that the rate
will be determined by looking separately at the costs associated with
facilities which are in
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 226
service at December 31, 1996, and the costs associated with new facilities which
are placed in service after December 31, 1996. Costs of new facilities are to
be shared regionally on a per Kilowatt basis in determining the rates of each of
the Participants with a Local Network, unless otherwise allocated to a
particular entity pursuant to this Tariff.
Costs of existing facilities are to be determined separately for each
Participant and reflected in the rate for service to Transmission Customers
serving load in the Participant's Local Network. This is initially subject to
a band width which limits the variation of the Participant per Kilowatt cost
from the average per Kilowatt cost for all Participants to not less than 70%,
or more than 130%, of the average cost.
(2) The Pool RNS Rate per Kilowatt is $1 in Year One, $4 in Year Two, $7 in
Year Three, $10 in Year Four and $13 in Year Five and the period from the end
of Year Five to the next succeeding June 1, and is equal to the Pool PTF Rate
for each Year thereafter.
(3) The Participant RNS Rate for a Participant for a Year shall be a percentage
of the Pool RNS Rate for the year and shall be
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 227
equal to the Pool RNS Rate after the end of the transitional period described in
paragraph (4) of this Schedule. The percentage for each Participant for each
Year shall equal the percentage which the sum of (i) the Participant's pre-1997
Participant RNS Rate and (ii) the post-1996 Pool PTF Rate represents of (iii)
the Pool PTF Rate for the Year.
(4) The pre-1997 Participant RNS Rate for each Participant shall be determined
by comparing its individual pre-1997 PTF Rate, for the most recent calendar
year for which information is available from Form 1 filings or otherwise to the
pre-1997 Pool PTF Rate for the same calendar year. If the Participant's
individual pre-1997 PTF Rate for a Year is less than the pre-1997 Pool PTF
Rate, its pre-1997 Participant RNS Rate for the Year shall be the rate
determined by reducing the pre-1997 Pool PTF Rate by the percentage which the
Participant's pre-1997 PTF Rate is less than the pre-1997 Pool PTF Rate;
provided that in no event shall its pre-1997 Participant RNS Rate be less than
70% of the pre-1997 Pool PTF Rate, until the end of Year Five, and thereafter
shall be no less than 50% of the pre-1997 Pool PTF Rate for Year Six through
Year Ten, and shall be equal to the pre-1997 Pool PTF Rate
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 228
for Year Eleven and thereafter. If the Participant's individual pre-1997 PTF
Rate is greater than the pre-1997 Pool PTF Rate, its pre-1997 Participant RNS
Rate shall be the rate determined by increasing the pre-1997 Pool PTF Rate by
the percentage which its pre-1997 Participant PTF Rate is greater than the
pre-1997 Pool PTF Rate; provided that in no event shall its pre-1997 Participant
RNS Rate be greater than 130% of the pre-1997 Pool PTF Rate until the end of
Year Five, and thereafter shall be no greater than 127% of the pre-1997 Pool PTF
Rate for Year Six, 123% of the pre-1997 Pool PTF Rate for Year Seven, 118% of
the pre-1997 Pool PTF Rate for Year Eight, 112% of the pre-1997 Pool PTF Rate
for Year Nine, 105% of the pre-1997 Pool PTF Rate for Year Ten, and shall be
equal to the pre-1997 Pool PTF Rate for Year Eleven and thereafter. If for any
Year the revenues to be received from the payment by Participants or other
Transmission Customers of their respective applicable Participant RNS Rates will
average more or less than the Pool PTF Rate per Kilowatt for the Year, each
Participant RNS Rate will be increased or decreased, as appropriate, so that the
revenues to be received per Kilowatt per Year will equal the Pool PTF Rate per
Kilowatt for the Year.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 229
(5) The individual pre-1997 PTF Rate of a Participant which owns a Local
Network for a year is the amount derived annually by dividing its Annual
Transmission Revenue Requirements for the most recent calendar year for which
information is available from Form 1 filings (or similar information on the
books of Transmission Providers that are not required to submit a Form 1
filing) with respect to PTF placed in service before January 1, 1997, as
determined in accordance with Attachment F to this Tariff, by the average for
the twelve months of the calendar year on which the rate is based of the sum of
the coincident Monthly Peaks for the Local Network, as adjusted each month for
losses, excluding from the Monthly Peak the load at each applicable Point of
Delivery of each Participant or Non-Participant which has elected to take
Internal Point-to-Point Service in lieu of Regional Network Service at one or
more Points of Delivery; PLUS the Long-Term Firm Reserved Capacity amount for
each such Participant or Non-Participant which has elected to take Firm
Internal Point-to-Point Service in lieu of Regional Network Service at one or
more Points of Delivery.
(6) The pre-1997 Pool PTF Rate shall be determined in accordance with the
following formula:
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 230
R = ATRR
----
ARNL
and the post-1996 Pool PTF Rate shall be determined in accordance with the
following formula:
R' = ATRR'
----
ARNL
in which
R = the pre-1997 Pool PTF Rate
R' = the post-1996 Pool PTF Rate
ATRR = the aggregate of the Annual Transmission Revenue Requirements of
the Participants with respect to PTF placed in service before
January 1, 1997, as determined in accordance with Attachment F to
this Tariff.
ATRR' = the aggregate of the Annual Transmission Revenue Requirements of
the Participants with respect to PTF placed in service on or
after January 1, 1997, including upgrades, modifications or
additions to PTF placed in service before January 1, 1997, as
determined in accordance with Attachment F to this Tariff.
ARNL = the average for the twelve months of the calendar year on which
the rate is based of the sum of the coincident Monthly Peaks for
all Local Networks, as adjusted each month for NEPOOL losses,
excluding from the Monthly Peak for each Local Network as
applicable the load at each applicable Point of Delivery of each
Participant or Non-Participant which has elected to take Internal
Point-to-Point Service in lieu of Regional Network Service at one
or more Points of Delivery; PLUS the Long-Term Firm Reserved
Capacity amount for each such Participant
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 231
or Non-Participant which has elected to take Firm Internal
Point-to-Point Service in lieu of Regional Network Service at one
or more Points of Delivery PLUS the Long-Term Reserved Capacity
amount for each Participant or Non-Participant for Firm Through or
Out Service.
(7) As used in this Schedule, "Monthly Peak" and "Monthly Network Load" each
has the meaning specified in Section 46.1 of this Tariff.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 232
SCHEDULE 10
Internal Point-to-Point Service
(1) A Transmission Customer shall pay to NEPOOL for firm or non-firm
Internal Point-to-Point Service reserved for it in accordance with Section 19
of the Tariff a charge per Kilowatt, as determined for the period of the
service in accordance with Section 21 of this Tariff, equal to the Internal
Point-to-Point Service Rate; provided if either or both (i) a rate which is
derived from the annual incremental cost not otherwise borne by the
Transmission Customer or a Generator Owner, of any new facilities or upgrades
that would not be required but for the need to provide the requested service or
(ii) a rate which is equal to NEPOOL's opportunity cost (if and when available)
capped at the cost of expansion, is greater than the Pool PTF Rate the charge
shall be the higher of such amounts; provided further that no such charge shall
be payable with respect to the use of Internal Point-to-Point Service to effect
a delivery to the NEPOOL power exchange in an Interchange Transaction. If at
any time NEPOOL proposes to charge a rate based on opportunity cost, it shall
first file with the Commission procedures for computing opportunity cost
pricing for all Transmission Customers. The Customer shall also be
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 233
obligated to pay any applicable ancillary service charge and any applicable
congestion or other uplift charge required to be paid pursuant to Section 24 of
this Tariff.
(2) Discounts: Three principal requirements apply to discounts for
Internal Point-to-Point Service as follows (1) any offer of a discount made by
the Participants must be announced to all Eligible Customers solely by posting
on the OASIS, (2) any customer-initiated requests for discounts (including
requests for use by one's wholesale merchant or an affiliate's use) must occur
solely by posting on the OASIS, and (3) once a discount is negotiated, details
must be immediately posted on the OASIS. For any discount agreed upon for
service on a path, from Point(s) of Receipt to Point(s) of Delivery, the
Participants must offer the same discounted transmission service rate for the
same time period to all Eligible Customers on all unconstrained transmission
paths that go to the same Point(s) of Delivery on the NEPOOL Transmission
System.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 234
SCHEDULE 11
Additions to or Upgrades of PTF
If any of the studies referred to in Sections 33, 44 or 49 of the Tariff
indicates that PTF upgrades are necessary to provide the requested service, or
in connection with a new or materially changed generating unit, responsibility
for the costs of the PTF upgrades shall, where necessary, be determined by the
Regional Transmission Planning Committee before construction is commenced,
subject to the following limitations:
(i) If the construction of a PTF or upgrade is required in connection with a
new generating unit or materially changed generating unit, one-half of the
Shared Amount(as defined below) of the capital cost of the PTF upgrade
shall be included in Annual Transmission Revenue Requirements under
Attachment F, and the Generator Owner shall be obligated to pay the other
half of the Shared Amount of the capital cost of the PTF upgrade and all of
the capital cost in excess of the Shared Amount, and any applicable tax
gross-up amounts. Following completion of the construction or
modification, the Generator Owner shall be obligated to pay its pro rata
share of all of the annual costs (including cost of capital,
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 235
federal and state income taxes, O&M and A&G expenses, annual property taxes
and other related costs) which are allocable to the PTF upgrade, pursuant to
the interconnection agreements with the individual Transmission Providers or
their designees which are responsible for the construction or modification,
which agreements may be filed with the Commission by a Transmission
Provider unsigned either on its own or at the request of the Generator
Owner.
(ii)In determining the cost responsibilities for a particular PTF upgrade,
the Regional Transmission Planning Committee, subject to review by the
System Operator, may determine that all or a portion of the proposed
facilities exceed regional system, regulatory or other public
requirements. In such a case, the Regional Transmission Planning
Committee, subject to review by the System Operator, shall determine
the amount of the excess costs of the PTF upgrade which shall be borne
by the entity which is responsible for requiring such excess costs,
and the excess costs shall not be included in the calculation of the
Shared Amount, if any, of the costs of the PTF upgrade and shall be
borne directly by the responsible entity.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 236
The Shared Amount of the capital cost of the PTF upgrade required in connection
with the installation or modification of a generating facility (excluding any
costs which are determined to be excess costs in accordance with paragraph (ii)
above) shall be initially determined as of the time that the System Impact
Study agreement is executed by all parties and the Generator Owner has paid the
cost of the study, (such initial determination to be based on the estimated
cost of the PTF upgrade, subject to later adjustment as set forth below)
subject to truing up the KW element of the following formula upon completion of
the PTF upgrade, and shall be the lesser of (a) the full actual capital cost of
the PTF upgrades (excluding any costs which are determined to be excess costs
in accordance with paragraph (ii) above) or (b) the amount determined in
accordance with the following formula:
P = KW (R)(.50)
-----------
C
in which:
P is the maximum amount to be shared;
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 237
KW in the case of a generating unit, is the actual demonstrated net
capability of the new generating unit or increase in the capacity
of an existing generating unit corrected to 50<circle>F, in
kilowatts. If winter operating conditions are shown in the
System Impact Study and/or application under Section 18.4 of the
Agreement to require additional transmission reinforcements
beyond those reinforcements required for summer operating
conditions, the net capability of the unit will be corrected to
an ambient air temperature of 0<circle>F;
R is the Pool PTF Rate, as in effect on the Compliance Effective
Date; and
C is the weighted average carrying charge factor of all the
Transmission Providers which own PTF, determined, as of the
Compliance Effective Date, in accordance with Attachment F to the
Tariff, i.e., the sum for all Transmission Providers of the
amounts in Attachment F, Section I.A through I.H,
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 238
divided by the sum of PTF Transmission Plant for all Transmission
Providers as defined in Attachment F, Section I.A.1.a.
If the Regional Transmission Planning Committee (RTPC) and the System Operator
at the time of the review of a generation project under Section 18.4 of the
Agreement find that the proposed generation project would result in deferral
for two years or more or cancellation of transmission upgrade investments that
would have been required (subject to criteria proposed by the System Operator
and approved by the RTPC and the Executive Committee with respect to the siting
of generation in the most advantageous location and is only exercised when
there is a significant net benefit to load) BUT FOR the proposed generation
project in an amount that equals or exceeds 75% of the capital equivalent of
the Pool PTF Rate, then the Executive Committee shall have the authority to
vote to permit a deviation from the cost allocation formula in this Schedule 11
that would allow the cap on the Shared Amount to increase to as much as 100% of
the capital equivalent of the Pool PTF Rate.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 239
All payments required hereunder shall be determined initially on an estimated
basis, and then adjusted after the appropriate portion of the construction or
modification costs has been reflected in Tariff rates in the first adjustment
of Tariff rates after the PTF upgrade has been placed in commercial operation.
If a proposal for a new generating unit or a material change to a generating
unit requires the construction of a PTF upgrade to interconnect and/or
accommodate the generator, the Generator Owner requesting such interconnection
may, at the request of the Transmission Provider or its designee responsible
for effecting such construction, be obligated to pay to the Transmission
Provider or its designee constructing the PTF upgrade an amount equal to its
share of the estimated cost of the construction at one time or in monthly or
other periodic installments, including, without limitation, all costs
associated with acquiring land, rights of way easements, purchasing equipment
and materials, installing, constructing, interconnecting, and testing the
facilities; O&M and engineering costs; all related overheads; and any and all
associated taxes and government fees. In addition to, or in lieu of said
payment, the affected Transmission Provider or
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 240
its designee may require the Generator Owner to provide, as security for its
obligation to pay any unfunded balance of the construction costs, and its
obligation to pay the entire construction cost if the new PTF or upgrades are
partly or completely constructed and the Generator Owner then goes out of
business or abandons its project, a letter of credit or other reasonable form of
security acceptable to the Transmission Provider or its designee that will be
responsible for the construction equivalent to the cost of the new facilities or
upgrades and consistent with relevant commercial practices, as established by
the Uniform Commercial Code. As soon as reasonably practical, but in any event
within 180 days after completion of the construction, or as otherwise mutually
agreed, the Transmission Provider or its designee responsible for the
construction will determine the difference, if any, between the estimated cost
already paid by the Generator Owner to the Transmission Provider or its designee
responsible for the construction and its share of the actual cost of the
construction, and will either receive from the Generator Owner, with Interest
(if the sum paid is insufficient) or pay to the Generator Owner, with Interest,
(if the sum paid is surplus) the difference;
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 241
provided that if, at the time such determination is made, items of construction
remain to be completed and/or some construction costs have not been invoiced and
paid, the Transmission Provider or its designee responsible for the construction
shall continue to be entitled to recover from the Generator Owner the Generator
Owner's share of the costs of such remaining items and may retain a reserve to
cover such items. Furthermore, the Transmission Provider shall release any
letter of credit or other security instrument received by the Transmission
Provider, up to the amount allowed to be recovered through the Transmission
Provider's Annual Transmission Revenue Requirement, no later than 60 days after
the later of the reflection of such costs in the Pool rates and the commercial
operation of the generation addition or modification. To the extent PTF
upgrades, or any portion thereof, are completed in a calendar year, Transmission
Providers will use their best efforts to reflect such facilities in their Annual
Transmission Revenue Requirements calculated on the basis of that year. That
portion of the construction costs paid by the Generator Owner may, by mutual
agreement of the Transmission Provider and the Generator Owner, either be
retained by the Transmission Provider, or be refunded to the Generator Owner
upon the Generator Owner executing
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 242
a contract with the Transmission Provider obligating the Generator Owner to pay
the Transmission Provider the ongoing transmission revenue requirement
associated with its share of the PTF construction, including cost of capital,
federal and state income taxes, O&M and A&G costs, annual property taxes and all
other related costs, and providing the Transmission Provider with an irrevocable
letter of credit or other form of security acceptable to the Transmission
Provider. In the event the Generator Owner's portion of the construction costs
is retained by the Transmission Provider or its designee in accordance with the
preceding sentence, the Generator Owner be obligated (i) to pay the federal and
state income taxes required to be paid by the Transmission Provider with respect
to the retained amount, and (ii) to pay annually its percentage of the O&M and
A&G costs, annual property taxes and all other related costs in accordance with
the interconnection agreement; provided that in no event shall the Generator
Owner be obligated to pay any cost more than once. If the Generator Owner for
whatever reason goes out of business, or otherwise abandons its generation
project, and the PTF upgrade has already been partially or completely
constructed, the Generator Owner shall be responsible for all of the
unrecovered ongoing
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 243
costs of the PTF upgrade that would not have been incurred but for the proposed
generation project. Nothing contained herein shall prevent the Transmission
Provider or its designee responsible for the construction and the Generator
Owner from negotiating other methods for providing financial security associated
with the cost of a PTF upgrade to existing PTF deemed acceptable to the
Transmission Provider or other entity.
In any case other than the construction or modification of a PTF upgrade with
respect to a new or modified generating unit, a Transmission Customer shall
also be obligated to pay such costs and to provide such security for its
obligation as may be agreed to under an interconnection or other applicable
agreement with the Transmission Provider or its designee which will effect the
construction or modification.
Subject to the foregoing, the interconnection and support agreements for a PTF
upgrade may specify the basis for continued support of such upgrade in the
event of a termination of NEPOOL, the cancellation of the project due to a
failure to obtain regulatory approvals or permits or required rights of way or
other
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 244
property, or action to terminate the project before its completion for
whatever reason and any other matters.
Interest payable hereunder shall be calculated in accordance with Section 8.3
of the Tariff.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 245
ATTACHMENT A
Form of Service Agreement for
Through or Out Service or
Internal Point-To-Point Service
1.0 This Service Agreement, dated as of ____________, is entered into, by and
between the NEPOOL Participants acting through ____________________ (the
"System Operator") and _____________("Transmission Customer").
2.0 The Transmission Customer has been determined by the System Operator to
have a Completed Application for Firm [Non-Firm] Transmission Service under
this Tariff.
3.0 If required, the Transmission Customer has provided to the System Operator
an Application deposit in accordance with the provisions of this Tariff.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 246
4.0 Service under this Service Agreement shall commence on the later of (1) the
requested service commencement date, or (2) the date on which construction
or any Direct Assignment Facilities and/or facility additions or upgrades
are completed, or (3) such other date as it is permitted to become
effective by the Commission. Service under this Service Agreement shall
terminate on such date as is mutually agreed upon by the parties. [The
Service Agreement may be a blanket agreement for non-firm service.]
5.0 The Participants agree to provide, and the Transmission Customer agrees to
take and pay for, Transmission Service in accordance with the provisions of
the Tariff and this Service Agreement.
6.0 Any notice or request made to or by either party regarding this Service
Agreement shall be made to the representative of the other party as
indicated below.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 247
NEPOOL PARTICIPANTS:
New England Power Pool
One Sullivan Road
Holyoke, MA 01040-2841
TRANSMISSION CUSTOMER:
____________________________
____________________________
____________________________
7.0 The Tariff is incorporated in this Service Agreement and made a part
hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 248
NEPOOL Participants:
By [System Operator]
By:___________________ __________ _____________
Name Title Date
TRANSMISSION CUSTOMER:
By:___________________ __________ _____________
Name Title Date
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 249
SPECIFICATIONS FOR THROUGH OR OUT SERVICE
OR INTERNAL POINT-TO-POINT SERVICE
1.0 Term of Transaction: ________________________________
Start Date: _________________________________________
Termination Date: ___________________________________
2.0 Description of capacity and energy to be transmitted by Participants
including the electric Control Area in which the transaction originates.
______________________________________________________
3.0 Point(s) of Receipt:__________________________________
Delivering party:_____________________________________
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 250
4.0 Point(s) of Delivery:_________________________________
Receiving party:______________________________________
5.0 Maximum amount of capacity and energy to be transmitted (Reserved
Capacity):___________________________________
6.0 Designation of party(ies) or other entity(ies) subject to reciprocal
service obligation:____________________________________
_______________________________________________________
_______________________________________________________
_______________________________________________________
7.0 Name(s) of any intervening systems providing transmission
service:__________________________________________________
__________________________________________________________
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 251
8.0 Service under this Service Agreement may be subject to some combination of
the charges detailed below. (The appropriate charges for individual
transactions will be determined in accordance with the terms and conditions
of this Tariff.)
8.1 Transmission Charge:______________________________
__________________________________________________
8.2 System Impact Study and/or Facilities Study Charge(s):
__________________________________________________
__________________________________________________
8.3 direct assignment expansion charge [Need to define or reference
upgrade costs]:
__________________________________________________
__________________________________________________
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 252
ATTACHMENT B
Form Of Service Agreement For
Regional Network Service
1.0 This Service Agreement, dated as of ______________, is entered into, by and
between the NEPOOL Participants acting through ___________________________
(the "System Operator"), and ____________ ("Transmission Customer").
2.0 The Transmission Customer has been determined by the System Operator to be
a Transmission Customer under the Tariff and has requested Regional Network
Service under the Tariff.
3.0 Regional Network Service (including, if requested, Network Integration
Transmission Service) under this Agreement shall be provided by the NEPOOL
Participants upon request by an authorized representative of the
Transmission Customer.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 253
4.0 The Transmission Customer agrees to supply information the System Operator
deems reasonably necessary in accordance with Good Utility Practice in
order for it to provide the requested service.
5.0 The Participants agree to provide and the Transmission Customer agrees to
take and pay for Regional Network Service in accordance with the provisions
of the Tariff and this Service Agreement.
6.0 Any notice or request made to or by either party regarding this Service
Agreement shall be made to the representative of the other party as
indicated below.
NEPOOL PARTICIPANTS:
NEW ENGLAND POWER POOL
---------------------------
ONE SULLIVAN ROAD
---------------------------
HOLYOKE, MA 01040-2841
---------------------------
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 254
TRANSMISSION CUSTOMER:
_____________________________
_____________________________
_____________________________
7.0 The Tariff is incorporated herein and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.
TRANSMISSION CUSTOMER:
By:______________________ ______________ ___________
Name Title Date
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 255
NEPOOL PARTICIPANTS:
By: [System Operator]
By:______________________ ______________ ___________
Name Title Date
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 256
ATTACHMENT C
Methodology To Assess Available Transmission Capability
Available Transmission Capability (ATC) will be assessed based on industry-
accepted standards; currently, ATC will be established by reducing the
determined Total Transfer Capability (TTC) by the Transmission Reliability
Margin (TRM) and by transmission commitments.
Total Transfer Capability (TTC) is the determined amount of electric power that
can be reliably transferred over the network consistent with the following:
o Good utility practice
o NERC standards, guides, and procedures;
o NPCC criteria and guidelines;
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 257
o New England criteria, rules, procedures, and reliability standards;
o Applicable guides, standards, and criteria of the affected Transmission
Owner(s), whether Participant or Non-Participant;
o Other applicable guidelines and standards which may need to be
established from time to time.
As such, TTC will be determined at a level which maintains all of the
following:
o All equipment within its applicable capabilities;
o Voltages and reactive reserves within acceptable levels;
o Stability maintained with adequate levels of damping;
o Frequency (Hz) within acceptable levels.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 258
TTC will be evaluated using appropriate and suitable tools, data, and
information, considering the physical impacts of electric power transfers on
the interconnected transmission network. It will reflect anticipated system
conditions and equipment status to the degree practicable.
The Transmission Reliability Margin (TRM) will be established at a level which
incorporates the uncertainties and continued variability of system conditions
and the practical limitations of system control.
Transmission commitments include existing and pending requests for transmission
service and obligations of other existing contracts under which transmission
service is provided.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 259
ATTACHMENT D
Methodology for Completing a System Impact Study
The system impact study will be performed to evaluate the impact of the
requested service on the reliability and operating characteristics of the bulk
power system, consistent with:
o Good utility practice
o NERC standards, guides, and procedures;
o NPCC criteria and guidelines;
o New England criteria, rules, procedures, and reliability standards;
o Applicable guides, standards, and criteria of the impacted Transmission
Owner(s), whether Participant or Non-Participant;
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 260
o Other applicable guidelines and standards which may need to be
established from time to time.
As such, the study will examine the impact on the New England regional bulk
power system and its component systems and neighboring and external systems.
Consistent with the aforementioned, the ability to operate the system subject
to the following will be considered:
o All equipment within its applicable capabilities;
o Voltages and reactive reserves within acceptable levels;
o Stability maintained with adequate levels of damping;
o Frequency (Hz) within acceptable levels.
The study will consider the reliability requirements to meet existing and
pending obligations of the Participants and the obligations of the impacted
Transmission Owner(s).
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 261
The study will be performed using appropriate and suitable analysis tools and
modeling data consistent with the nature and duration of the requested service.
It is expected that the Eligible Customer will provide the information as
prescribed in Exhibit 1 of Attachment I, and such other information as may be
reasonably required and associated with the requested service and necessary for
its study. It is also recognized that it may be determined that additional or
specialized analysis tools or computer software are necessary for the study.
The responsibility for the provision of these items will be subject to the
System Impact Study Agreement.
The study will identify if the requested service or a portion of it can be
provided without adverse impact on the reliability and operating
characteristics of the system. The study will also identify if it appears that
modification of the system is necessary to provide the service.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 262
ATTACHMENT E
Local Networks
The Local Networks, as of the effective date of this Tariff, are those of
the following:
1. Bangor Hydro-Electric Company
2. Boston Edison Company
3. Central Maine Power Company
4. the Commonwealth Energy System companies
5. the Eastern Utility Associates companies
6. the New England Electric System companies
7. the Northeast Utilities companies
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 263
8. The United Illuminating Company
9. Vermont Electric Power Company and the entities which are grouped with
it as a single Participant.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 264
ATTACHMENT F
Annual Transmission Revenue Requirements
The Transmission Revenue Requirements for each Participant will reflect the
Participants' costs for Pool Transmission Facilities (PTF). The Transmission
Revenue Requirements will be an annual calculation based on the previous
calendar year's data as shown, in the case of Transmission Providers which are
subject to the Commission's jurisdiction, in the Participants' FERC Form 1
report for that year, and shall be based on actual data in lieu of allocated
data if specifically identified in the Form 1 report, as set forth below:
I. The Transmission Revenue Requirement shall equal the sum of the
Transmission Provider's (A) Return and Associated Income Taxes, (B)
Transmission Depreciation Expense, (C) Transmission Related Amortization of
Loss on Reacquired Debt, (D) Transmission Related Amortization of
Investment Tax Credits, (E) Transmission Related Municipal Tax Expense, (F)
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 265
Transmission Operation and Maintenance Expense, (G) Transmission Related
Administrative and General Expense, (H) Transmission Related Integrated
Facilities Credit, minus (I) Transmission Support Revenue, plus (J)
Transmission Support Expense, plus (K) Transmission Related Expense from
Generators, plus (L) Transmission Related Taxes and Fees Charge.
A. RETURN AND ASSOCIATED INCOME TAXES shall equal the product of the
Transmission Investment Base and the Cost of Capital Rate.
1. TRANSMISSION INVESTMENT BASE
The Transmission Investment Base will be (a) PTF Transmission
Plant, plus (b) Transmission Related General Plant, plus (c)
Transmission Plant Held for Future Use, less (d) Transmission
Related Depreciation Reserve, less (e) Transmission Related
Accumulated Deferred Taxes, plus (f) Transmission Related Loss on
Reacquired Debt, plus (g) Other
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 266
Regulatory Assets, plus (h) Transmission Prepayments, plus (i)
Transmission Materials and Supplies, plus (j) Transmission Related
Cash Working Capital.
(a) PTF TRANSMISSION PLANT will equal the balance of the
Transmission Provider's PTF Investment in Transmission
Plant, excluding (i) the Transmission Provider's capital
leases in the Hydro-Quebec DC facilities (HQ leases), and
(ii) the portion of any facilities, the cost of which is
directly assigned under the Tariff to a Transmission
Customer or a Generator Owner or Interconnection Requester.
(b) TRANSMISSION RELATED GENERAL PLANT shall equal the
Transmission Provider's balance of investment in General
Plant multiplied by the ratio of Transmission related direct
Wages and Salaries including those of the affiliated
Companies to the Transmission Provider's total
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 267
direct Wages and Salaries including those of the affiliated
Companies and excluding Administrative and General Wages and
Salaries (Transmission Wages and Salaries Allocation Factor),
multiplied by the ratio of PTF Transmission Plant to Total
Investment in Transmission Plant excluding HQ leases (PTF
Transmission Plant Allocation Factor).
(c) TRANSMISSION PLANT HELD FOR FUTURE USE shall equal the
balance of Transmission investment in FERC Account 105
multiplied by the PTF Transmission Plant Allocation Factor.
(d) TRANSMISSION RELATED DEPRECIATION RESERVE shall equal the
balance of Total Transmission Depreciation Reserve, plus the
monthly balance of Transmission Related General Plant
Depreciation Reserve. Transmission Related General Plant
Depreciation
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 268
Reserve shall equal the product of General Plant Depreciation
Reserve and the Transmission Wages and Salaries Allocation
Factor described in Section (I)(A)(1)(b) above. This sum
shall be multiplied by the PTF Transmission Plant Allocation
Factor, described in Section (I)(A)(1)(b) above.
(e) TRANSMISSION RELATED ACCUMULATED DEFERRED TAXES shall equal
the Transmission Provider's balance of Total Accumulated
Deferred Income Taxes, multiplied by the ratio of Total
Investment in Transmission Plant excluding HQ leases to
Total Plant in service excluding General Plant and HQ Leases
(Plant Allocation Factor), further multiplied by the PTF
Transmission Plant Allocation Factor described in Section
(I)(A)(1)(b) above.
(f) TRANSMISSION RELATED LOSS ON REACQUIRED DEBT shall equal the
Transmission Provider's balance of Total Loss on Reacquired
Debt
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 269
multiplied by the Plant Allocation Factor as described in
Section (I)(A)(1)(e) above, further multiplied by the PTF
Transmission Plant Allocation Factor described in Section
(I)(A)(1)(b) above.
(g) OTHER REGULATORY ASSETS shall equal the Transmission
Provider's balance of any deferred rate recovery FAS 106
expenses multiplied by the Transmission Wages and Salaries
Allocation Factor described in Section (I)(A)(1)(b), plus
the Transmission Provider's year end balance of FAS 109
multiplied by the Plant Allocation Factor described in
Section (I)(A)(1)(e) above. This sum shall be multiplied by
the PTF Transmission Plant Allocation Factor, described in
Section (I)(A)(1)(b) above.
(h) TRANSMISSION PREPAYMENTS shall equal the Transmission
Provider's balance of prepayments
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 270
multiplied by the Wages and Salaries allocator described in
Section (I)(A)(1)(b) and further multiplied by the PTF
Transmission Plant Allocation Factor described in Section
(I)(A)(1)(b) above.
(i) TRANSMISSION MATERIALS AND SUPPLIES shall equal the
Transmission Provider's balance of Transmission Plant
Materials and Supplies, multiplied by the PTF Transmission
Plant Allocation Factor described in Section I(A)(1)(b)
above.
(j) TRANSMISSION RELATED CASH WORKING CAPITAL shall be a 12.5%
allowance (45 days/360 days) of Transmission Operation and
Maintenance Expense and Transmission Related Administrative
and General Expense.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 271
2. COST OF CAPITAL RATE
The Cost of Capital Rate will equal (a) the Transmission
Provider's Weighted Cost of Capital, plus (b) Federal Income Tax
plus (c) State Income Tax.
(a) THE WEIGHTED COST OF CAPITAL will be calculated based upon
the capital structure at the end of each year and will equal
the sum of:
(i) the LONG-TERM DEBT COMPONENT, which equals the product
of the actual weighted average embedded cost to
maturity of the Transmission Provider's long-term debt
then outstanding and the ratio that long-term debt is
to the Transmission Provider's total capital.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 272
(ii) the PREFERRED STOCK COMPONENT, which equals the
product of the actual weighted average embedded cost
to maturity of the Transmission Provider's preferred
stock then outstanding and the ratio that preferred
stock is to the Transmission Provider's total capital.
(iii) the RETURN ON EQUITY COMPONENT, which equals the
product of the Transmission Provider's Return on
Equity as set in the Provider's LNS open access tariff
rate and the ratio that common equity is to the
Transmission Provider's total capital.
(b) FEDERAL INCOME TAX shall equal
A X FT
------
1 - FT
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 273
Where FT is the Federal Income Tax Rate and A is the sum of
the preferred stock component and the return on equity
component, as determined in Section (I)(A)(2)(a)(ii) and
Section (I)(A)(2)(a)(iii) above.
(c) STATE INCOME TAX shall equal
(A + FEDERAL INCOME TAX) x ST
-----------------------------
1 - ST
where ST is the State Income Tax Rate, A is the sum of the
preferred stock component and the return on equity component
determined in Section (I)(A)(2)(a)(ii) and Section
(I)(A)(2)(a)(iii) above, and Federal Income Tax is the rate
determined in Section (I)(A)(2)(b) above.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 274
B. TRANSMISSION DEPRECIATION EXPENSE shall equal the PTF Transmission
Plant Allocation Factor described in Section (I)(A)(1)(b) above,
multiplied by the sum of Depreciation Expense for Transmission Plant,
plus an allocation of General Plant Depreciation Expense calculated by
multiplying General Plant Depreciation Expense by the Wages and
Salaries Allocation Factor, described in Section (I)(A)(1)(b) above.
C. TRANSMISSION RELATED AMORTIZATION OF LOSS ON REACQUIRED DEBT shall
equal the Transmission Provider's Amortization of Loss on Reacquired
Debt multiplied by the Plant Allocation Factor as described in Section
(I)(A)(1)(e) above, and further multiplied by the PTF Transmission
Plant Allocation Factor described in Section (I)(A)(1)(b) above.
D. TRANSMISSION RELATED AMORTIZATION OF INVESTMENT TAX CREDITS shall
equal the Transmission Provider's Amortization of Investment Tax
Credits multiplied by the Plant Allocation Factor described in Section
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 275
(I)(A)(1)(e) above, and further multiplied by the PTF Transmission
Plant Allocation Factor described in Section (I)(A)(1)(b) above.
E. TRANSMISSION RELATED MUNICIPAL TAX EXPENSE shall equal the
Transmission Provider's total municipal tax expense multiplied by the
Plant Allocation Factor described in Section (I)(A)(1)(e) above, and
further multiplied by the PTF Transmission Plant Allocation Factor
described in Section (I)(A)(1)(b) above.
F. TRANSMISSION OPERATION AND MAINTENANCE EXPENSE shall equal all
expenses charged to FERC Account Numbers 560 through 573, excluding
those expenses in Account Numbers 561 and 565, and any expenses
included in Transmission Support Expense as described in section (J)
which are included in Account Numbers 560-573, multiplied by the PTF
Transmission Plant Allocation Factor described in Section (I)(A)(1)(b)
above.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 276
G. TRANSMISSION RELATED ADMINISTRATIVE AND GENERAL EXPENSES shall equal
the Transmission Provider's Administrative and General Expenses, plus
Payroll Taxes, multiplied by the Wages and Salaries Allocation Factor
described in Section (I)(A)(1)(b) above, further multiplied by the PTF
Transmission Plant Allocation Factor described in Section (I)(A)(1)(b)
above.
H. TRANSMISSION RELATED INTEGRATED FACILITIES CREDIT shall equal the
Transmission Provider's transmission payments to affiliates for use of
the integrated transmission facilities of those affiliates.
I. TRANSMISSION SUPPORT REVENUE shall equal Transmission Provider's
revenue received for PTF transmission support but excluding support
payments to Transmission Providers or their designees pursuant to
Schedule 11 of the Tariff.
J. TRANSMISSION SUPPORT EXPENSE shall equal the expense paid by
Transmission Providers or Network Customers for
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 277
PTF transmission support other than expenses for payments made for
transmission facilities or facility upgrades placed in service on or
after January 1, 1997 where the support obligation is required to be
borne by particular Participants or other entities in accordance with
the Tariff.
K. TRANSMISSION RELATED EXPENSE FROM GENERATORS as may be determined by
the Management Committee.
L. TRANSMISSION RELATED TAXES AND FEES CHARGE shall include any fee or
assessment imposed by any governmental authority on service provided
under this Tariff which is not specifically identified under any other
Section of this Attachment.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 278
ATTACHMENT G: LIST OF EXCEPTED TRANSACTION AGREEMENTS
Attachment G is a listing of transmission agreements pertaining to certain
point-to-point wheeling transactions across or out of a Local Network. In
accordance with Section 25 of the Tariff, these agreements will continue to be
in effect at the rates and terms thereunder rather than under the Tariff.
<TABLE>
<CAPTION>
Item Effective End Amount Comments
# Provider Receiver Description, Purpose or Service Date Date (MW's) FERC Docket #'s
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
1 CMP Unitil PTP firm wheeling of BHE QF's 1/1/87 2/28/03 25 25.0MW since 11/1/91,
dropping to 24.27 MW's on
7/97, decreasing further
later. 2 yr notification
2 BECO Cambridge Firm agreement to transfer energy/capacity 7/1/68 11/1/01 varies
from Canal 1 to Cambridge Electric Light
across BECO system
3 NEP BECO Long term wheeling of L'Energia{1} 7/9/96 3/13/13 65.048 See note #1
4 NEP Braintree Long term wheeling of system power{1} 7/9/96 10/31/04 2 See note #1, option to
extend
5 NEP CES Long term non-firm wheeling of power 7/9/96 life 20 See note #1
from Boott Hydro{1}
6 NEP CES Long term non-firm wheeling of power 7/9/96 10/1/04 1.5 See note #1
from Collins Dam{1}
7 NEP Hingham Long term wheeling of power from 7/9/96 12/31/27 1.446 See note #1
Manchester street{1}
8 NEP Hingham Long term wheeling of power from Bear 7/9/96 11/1/05 5.02 See note #1
Swamp{1}
9 NEP Hull Long term wheeling of power from Refuse 7/9/96 10/31/05 .341 See note #1
Fuels{1}
10 NEP Montaup Long term wheeling of McNeil 7/9/96 life 8 See note #1
Burlington{1}
11 NEP Taunton Long term wheeling of system power{1} 7/9/96 10/31/05 10 See note #1
12 NEP Unitil Long term wheeling power from Ocean 7/9/96 10/31/10 22.5 See note #1, amount
State I & II {1} changes over contract/
seasons
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 279
13 NEP Unitil Long term wheeling of power from Salem 7/9/96 10/31/05 9.8 See note #1, amount
Harbor {1} changes over contract/
seasons
14 NEP Unitil Long term wheeling power from Maine 7/9/96 10/31/05 2
Yankee
15 NU NUSCO Firm PTP Trans. Wheeling Service 9/1/94 2003 40 Madison Electric Works -
ER94-1160-000
16 NU Holyoke Firm PTP Trans. Wheeling Service 7/1/95 2003 4 NYPA Power - ER95-1354-
0000
17 NU CES Firm PTP Trans. Wheeling Service 5/1/85 2013 2 Swift River - Chicopee 1&2
ER-86-85-000/ER86-79-000
18 NU Groton Firm PTP Trans. Wheeling Service 11/1/89 1999 1 Glendale Hydro - ER92-66-
000
19 NU UI/Unitil Firm PTP Trans. Wheeling Service BHS3 to 5/1/90 2010 15 TSA Corridor - ER92-65-000
Unitil
20 NU Groton Firm PTP Trans. Wheeling Service 4/1/92 2010 1 Littleville Power Co-Texon
Hydro
ER92-458-000/ER92-66-000/
ER93-219-000
21 NU Fitchburg Firm PTP Trans. Wheeling Service 1/1/95 2012 3 Harris Hydro - ER94-559-
000/ER95-357-000
22 NU MASS Firm PTP Trans. Wheeling Service{4} 7/31/93 2014 200 ER94-902-000/ER93-219-000
POWER See note #6
23 NU LILCO Firm PTP Trans. Wheeling Service 5/1/94 1997 88 Fitzpatrich - ER94-1201-
000
24 NU Altresco Firm PTP Trans. Wheeling Service{4} 1/1/95 2010 160 ER95-306-000, See note #6
Pittsfield
25 NU MMWEC Firm PTP Trans. Wheeling Service 11/1/95 2003 27 NYPA Power - ER96-201-000
26 NU Pascoag Firm PTP Trans. Wheeling Service 11/1/95 2003 3 NYPA Power - ER96-201-000
27 NU Pontook Firm PTP Trans. Wheeling Service 7/26/85 2001 11 Pontook
28 NU Suncook Firm PTP Trans. Wheeling Service 4/8/96 2021 3 Suncook - ER96-1277-000
29 NU NUSCO Firm PTP Trans. Wheeling Service{2} 10/1/96 2006 100/200 See Note #2, Suffolk
County, NY - ER96-2338-000
30 NU NUSCO Firm PTP Trans. Wheeling Service 12/1/81 2019 variable MMWEC: Stonybrook
ER83-358-000/ER93-219-000
31 NU NUSCO Firm PTP Trans. Wheeling Service 6/1/94 2005 10 Unitil: Norwalk 1&2 -
ER94-1088-0000
32 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/94 2004 15 Fitchburg Gas & Electric -
ER93-417-001
33 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/94 2005 13 Reading Municipal Light -
ER94-1591-000
34 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/93 1998 5 Middleton Municipal Light-
ER93-901-000
35 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/93 1998 2 Georgetown Municipal
Light - ER93-884-000
36 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/93 2004 1 Princeton Municipal Light:
Holyoke Hydro
ER93-915-000
37 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/93 1998 1 VT Public Power Supply -
ER93-913-000
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 280
38 NU NUSCO Firm PTP Trans. Wheeling Service 5/1/94 1999 25 Citizens Utility Co.
ER94-1211-000/EC90-10-007
39 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/94 1998 5 Holyoke Gas & Electric -
ER94-1592-000
40 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/94 2004 20 Danver Electric Dept. -
ER94-1207-000
41 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/94 2004 20 Littleton Electric Light/
Water
ER94-1207-000
42 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/94 2004 10 Mansfield Municipal
Electric
ER94-1207-000
43 NU NUSCO Firm PTP Trans. Wheeling Service 5/1/95 2004 1 Sterling Municipal
Electric
ER95-584-000
44 NU NUSCO Firm PTP Trans. Wheeling Service 6/1/95 2002 3 Princeton Municipal
Electric
ER95-1137-000
45 NU NUSCO Firm PTP Trans. Wheeling Service 8/1/95 1999 2 VT Marble Power Div. -
ER95-1461-000
46 NU NUSCO Firm PTP Trans. Wheeling Service 11/1/95 2002 6 Rowley Municipal Lighting
ER96-160-000
47 NU Littleton Non-Firm PTP Trans. Wheeling Service 10/30/91 n/a 1 Marlboro Hydro Corp/
Minnewawa
48 NU NEP Non-Firm PTP Trans. Wheeling Service 12/6/91 n/a 3 Waste Mgmt of NH/Turnkey
49 NU NEP Non-Firm PTP Trans. Wheeling Service 11/1/93 1998 40 ER93-914-000/ER95-41-000
50 NU CMEEC Non-Firm PTP Trans. Wheeling Service 6/15/93 variable Liquid Carbonic Ind
Medical Corp
ER93-663-000
51 NU Wallingford Non-Firm PTP Trans. Wheeling Service 7/27/92 variable Ct Steel - ER92-730-000
52 NU CMP Non-Firm PTP Trans. Wheeling Service 11/1/95 1999 50 ER94-48-000
ER95-1635-000/ER95-1557-
000
53 NU CMP Non-Firm PTP Trans. Wheeling Service 11/1/95 1999 150 ER94-48-000/ER95-1635-000
54 NU BECO Non-Firm PTP Trans. Wheeling Service 11/1/95 1997 100 ER94-48-000
ER95-1851-000/ER96-3144-
000
55 NU NHEC Firm Trans. Wheeling Services 3/31/81 n/a 6 Maine Yankee Through PSNH
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 281
56 Montaup MASS Firm wheeling of Mass power 7/31/93 12/31/13 29.3/25 ER93-624-000,
ER97-2574-000
POWER 7/30/08 117/100
57 Montaup Pittsfield Firm wheeling of Pittsfield Generating 9/1/93 12/31/01 29.5 W ER93-623-000,
Company (Altresco) 26 S ER97-2574-000
58 Montaup North Non-firm wheeling of Cleary 9cc to North 11/1/84 LOU 10 ER93-396-000
Attleboro Attleboro
59 Montaup Hudson Non-firm wheeling of Cleary 9cc to Hudson 11/1/86 LOU 5 ER87-362-000
Light & Power
60 Montaup MMWEC Firm wheeling of NYPA power to Braintree, 7/1/85 6/30/01 3.03/2.09 amounts in order of co.'s
Hingham, Hull, Wellesley, Reading, Belmont, 1.11/2.33 listed & through 6/30/97,
Concord 5.84/2.32 can be extended monthly
1.69 6/30/01 thru 10/31/03
ER87-362-000
61 Montaup Braintree Non-firm wheeling of Cleary 9cc to Braintree 11/1/84(1)LOU 10 ER85-390-000/ER87-126-000
11/1/86(2)
62 Montaup Hingham Non-firm wheeling of Cleary 9cc to Hingham 11/1/88 LOU 3 ER93-137-000/ER87-126-000
63 Montaup CES Non-firm backup wheeling agreement 7/31/93 8/31/01
64 Montaup Pascoag Firm transmission service 11/1/81 11/1/97 5, Contract Demand service
agreement
Fire 10/31/98,
9 5.3, ER82-61-000
District 9,00 4.97,2.97
65 Montaup Middle- Firm transmission service 5/1/83 11/1/97 8 Contract Demand service
borough 10/31/99 6 agreement
ER83-485-000
66 UI NU Unit firm exchange of capacity, NU gas turbine 5/1/93 12/31/99 2.4:1 can be extended & requires
for UI base fossil notice of termination
Only BHS3 share - 25 MW's 120to50
67 PASNY UI Firm Niagara & St. Lawrence Hydro power 3/1/90 6/30/01
project contract
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 282
68 BECO Altresco Firm wheeling power contract 9/1/93 12/31/11 29 ER93-786-000,ER97-2500-000
69 BECO MMWEC Wheeling contract from PASNY for Braintree 10/31/03 18
Hingham, Hull, Reading, Belmont, Concord total
Wellesley
70 CVPS Unitil Firm power & wheeling of Vermont Yankee 1991 2001 25 with CVPS termination
Bundled T & G right at 11/98
71 MPSNBP CMP Firm delivery of Beaver-Ashland NELP #2 1/1/93 12/31/16 34 See Note #3
MEPCO output from MPS to CMP{3}
72 MPS/ CMP Firm transmission of capacity/energy from 10/26/94 4/30/2000 26 amount varies with Houlton
Avec in excess of Houlton Water Req. for load, See Note #3
CMP native load{3}
73 CMP HWC Firm power sales agreement for requirements 1/1/96 12/31/05 11-15 See Note #3 & #4
from CMP to Houlton Water Co.{3}
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 283
</TABLE>
ATTACHMENT G-1: LIST OF EXCEPTED AGREEMENTS
Attachment G-1 is a listing of comprehensive network service agreements. In
accordance with Section 25 of the Tariff, these agreements are to continue in
effect and transmission service for the transactions covered by such agreements
will continue to be provided at the rates and terms in effect thereunder rather
than under the Tariff. Further, service for the transactions covered by such
agreements shall continue to be excepted for their respective terms from the
requirement to pay a Local Network Service charge.
<TABLE>
<CAPTION>
Item Parties to the Description, Purpose Effective End Amount Comments
# Agreement or Service Date Date (MW's) FERC Docket #'s
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1 WMECO/NEP Service to French King/Shelburne 3/15/94 2 yr notice varies Transmission Service Agreement
2 WMECO/NEP Service to SBNGB 2/23/93 2 yr notice varies Transmission Service Agreement
3 Cambridge/BECO Support Agreements 1/1/75 open n/a Rights in perpetuity
4 UI/NU Six UI Substations Agreement 8/24/93 10/31/98 varies
5 CMP/MEW/NU Firm Transmission of Capacity/Energy 5/16/94 12/31/03 varies 1yr Notification, Can be
to serve Madison extended to 12/31/08
6 CMEEC/NU Comprehensive Transmission Service 11/29/90 1/1/09 n/a ER91-209-000, ER93-297-000
Agreement
7 Chicopee/NU Comprehensive Transmission Service 11/1/95 10/31/09 n/a ER85-689-000, ER93-219-000
Agreement
8 South Hadley/NU Comprehensive Transmission Service 11/1/95 7/1/10 n/a EC90-10-000, ER85-689-000,
Agreement ER720-000
9 Westfield/NU Comprehensive Transmission Service 1/1/95 7/1/10 n/a EC90-10-000
Agreement
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 284
10 Unitil/NU Comprehensive Transmission Service 11/1/92 n/a n/a EL92-42-000
Agreement
11 CMP/NU Firm Border Line Agreement for Bolt 12/15/81 open 35-40 Amount varies, 2yr Notification
Hill Substation
12 All VT Utilities Velco 1991 Transmission Agreement 1991 n/a Transmission Service Agreement
13 CMP/Fox Island Firm Transmission Assoc. with 1/1/94 12/31/98 varies Can be extended to 12/31/03
Bundled Requirements Contract
14 CMP/Kennebunk Firm Transmission Assoc. with 1/1/94 12/31/98 varies Can be extended to 12/31/03
Bundled Requirements Contract
15 GMP/CVPS Firm Network support with outflow- 10/19/93 10/19/08 varies Transmission Interconnection
Interconnection agreement Agreement
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 285
ATTACHMENT G-2: LIST OF CERTAIN ARRANGEMENTS
OVER EXTERNAL TIES
Attachment G-2 is a listing of agreements which relates to the use of the tie
lines to New York.
</TABLE>
<TABLE>
<CAPTION>
Item Effective End Amount Comments
# Provider Receiver Description, Purpose of Service Date Date (MW's) FERC Docket #'s
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
1 VT Electric VT Public To import NYPA power 03/01/90 10/2003 14 MW
Power Co. Systems
2 VT Electric VT Public To import power from New York 02/16/95 10/2003 5 MW S
Power Co. Power Supply State Electric & Gas Company 7 MW W
Authority (NYSE&G)
(VPPSA)
3 VT Electric VPPSA To import power from Niagara 11/01/93 10/98 9 MW
Power Co. Mohawk
4 VT Electric City of To import power from NYSE&G - 05/01/98 12/2009 10 MW
Power Co. Burlington signed 04/01/96
</TABLE>
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 286
Notes to Attachments G, G-1 and G-2
1. NEP's long-term Point-to-Point transmission services will be grandfathered
at a fixed rate of $17.00/kW-yr. Distribution, transformation, and
metering surcharges when applicable, will be subject to NEP's applicable
point-to-point tariffs.
2. See FERC Contract for specific details of agreement. In general, 100MW's
until transmission upgrades are complete. This item is still under review
and is subject to further review dependent upon outcome of Congestion
Pricing.
3. Excepted status applies to transmission by CMP. Transmission by others
(MEPCO, NBP, MPS) remains under the rates, terms and conditions of
applicable agreements.
4. This Transmission Service Agreement is governed in part by a memorandum of
understanding, filed 6/13/97 in Docket nos. EC90-10-007, ER93-294-000,
ER95-1686-000, ER96-496-000, OA97-237-000, and ER97-1079-000.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 287
ATTACHMENT H
Form of
Network Operating Agreement
1.0 Preamble
This Network Operating Agreement is entered into by and between the NEPOOL
Participants (the "Transmission Provider") acting through __________ (the
"System Operator") and ____________ (the "Transmission Customer") as an
implementing agreement for the NEPOOL Open Access Transmission Tariff and
is subject to and in accordance with the NEPOOL Open Access Transmission
Tariff. All definitions and other terms and conditions of the NEPOOL Open
Access Transmission Tariff are incorporated herein by reference. The
Transmission Provider may designate a satellite dispatch center and/or one
or more Participants to act for it under this Agreement.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 288
2.0 General Terms and Conditions
The Transmission Provider agrees to provide transmission service to the
Transmission Customer's equipment or facilities, etc., subject to the
Transmission Customer operating its facilities in accordance with
applicable NEPOOL and NPCC criteria, rules, standards, procedures, or
guidelines as they may be adopted and/or amended from time to time. In
addition to the provisions defined in those documents, service to the
Transmission Customer's equipment or facilities, etc. is provided subject
to the following specified terms and conditions.
2.1 Electrical Supply: The electrical supply to the Point(s) of Delivery
shall be in the form of three-phase sixty-hertz alternating current at
a voltage class determined by mutual agreement of the parties.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 289
2.2 Coordination of Operations: The Transmission Provider shall consult
the Transmission Customer and/or its Designated Agent regarding timing
of scheduled maintenance of the Transmission System and the
Transmission Provider shall schedule any shutdown or withdrawal of
facilities to coincide with the Transmission Customer's equipment or
facilities, etc. scheduled outages of the Transmission Customer's
resources, to the extent practicable. In the event the Transmission
Provider is unable to schedule the shutdown of its facilities to
coincide with Transmission Customer's schedule, the Transmission
Provider shall notify the Transmission Customer and/or its Designated
Agent, in advance if feasible, of reasons for the shutdown, the time
scheduled for it to take place, and its expected duration. The
Transmission Provider shall use due diligence to resume delivery of
electric power as quickly as possible.
2.3 Reporting Obligations: The Transmission Customer shall be responsible
for all information required by NPCC or
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 290
NEPOOL. The Transmission Customer shall respond promptly and
completely to the Transmission Provider's reasonable requests for
information, including but not limited to, data necessary for
operations, maintenance, regulatory requirements and analysis. In
particular, that information may include:
For Network Loads:
- 10-year coincident, seasonal (summer, winter) Annual Peak Load
forecast, aggregated by geographic distribution area
- Load Power Factor performance by geographic distribution area
- Underfrequency load shedding capability aggregated by geographic
distribution area
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 291
- Block load shedding capability aggregated by geographic
distribution area
- Disturbance/interruption reports
- Protection system setting conformance
- Protection system testing and maintenance conformance
- Planned changes to protection systems
- Metering testing and maintenance conformance
- Planned changes in transformation capability
- Conformance to harmonic and voltage fluctuation limits
- Dead station tripping conformance
- Voltage reduction capability conformance
For Network Resources and interconnected generators:
- 10-year forecast of generation capacity retirements and
additions, if applicable
- Generator reactive capability verification
- Generator underfrequency relaying conformance
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 292
- Protection system testing and maintenance conformance
- Planned changes to protection system
- Planned changes to generation parameters
- Metering testing and maintenance conformance
Failure by the Transmission Customer to do so may constitute default.
Delinquency in responding by the Transmission Customer will result in
a fine as described in 5.0 below.
The Transmission Customer shall supply accurate and reliable
information to the system operators regarding metered values for MW,
MVAR, volt, amp, frequency, breaker status indication, and all other
information deemed necessary by the Transmission Provider for reliable
operation. Information shall be gathered for electronic communication
using one or more of the following: supervisory control and data
acquisition (SCADA), remote terminal unit (RTU) equipment, and remote
access pulse recorders (RAPR). All equipment
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 293
used for metering, SCADA, RTU, RAPR, and communications must be
approved by the Transmission Provider.
2.4 Operational Obligations: The Transmission Customer shall request
permission from the system operators prior to opening and/or closing
circuit breakers per applicable switching and operating procedures.
The Transmission Customer shall carry out all switching orders from
the Transmission Provider, the System Operator or the Transmission
Provider's designee in a timely manner.
The Transmission Customer shall balance the load at the Point(s) of
Delivery such that the difference in the individual phase currents are
acceptable to the Transmission Provider.
The Transmission Customer's equipment shall conform with harmonic
distortion and voltage fluctuation standards of the Transmission
Provider.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 294
The Transmission Customer's equipment must comply with all
environmental requirements to the extent they impact the operation of
the Transmission Provider's system.
The Transmission Customer shall operate all of its equipment and
facilities connected to the Transmission Provider's system in a safe
and efficient manner and in accordance with manufacturers'
recommendations, Good Utility Practice, applicable regulations, and
requirements of the Transmission Provider, the System Operator, and
NPCC.
2.5 Notice of Transmission Service Interruptions: If at any time, in the
reasonable exercise of the system operator's judgement, operation of
the Transmission Customer's equipment adversely affects the quality of
service or interferes with the safe and reliable operation of the
system, the Transmission Provider may discontinue transmission service
until the condition has been corrected. Unless the system operators
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 295
perceive that an emergency exists or the risk of one is imminent, the
system operators shall give the Transmission Customer and/or its
Designated Agent reasonable notice of its intention to discontinue
transmission service and, where practical, allow suitable time for the
Transmission Customer to remove the interfering condition. The
Transmission Provider's judgement with regard to the discontinuance of
service under this paragraph shall be made in accordance with Good
Utility Practice. In the case of such discontinuance, the
Transmission Provider shall immediately confer with the Transmission
Customer regarding the conditions causing such discontinuance and its
recommendation concerning timely correction thereof. Failure by a
Customer to shed load would be subject to an additional charge of
10<cent>/kWh for every kWh the Customer failed to shed.
2.6 Access and Control: Properly accredited representatives of the
Transmission Provider shall at all reasonable times have access to the
Transmission
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 296
Customer's facilities to make reasonable inspections and obtain
information required in connection with this Tariff. Such
representatives shall make themselves known to the Transmission
Customer's personnel, state the object of their visit, and conduct
themselves in a manner that will not interfere with the construction
or operation of the Transmission Customer's facilities. The
Transmission Provider or its designee will have control such that it
may open or close the circuit breaker or disconnect and place safety
grounds at the Point(s) of Delivery, or at the station, if the
Point(s) of Delivery is remote from the station.
2.7 Point(s) of Delivery: Network Integration Transmission Service will be
delivered by the Transmission Provider at the Point(s) of Delivery as
specified in the customer's Service Agreement, and as amended from
time to time. Each Point of Delivery shall have a unique identifier,
meter location, meter number, metered voltage, terms on meter
compensation and, the actual,
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 297
or if not currently in service, the projected in-service year.
2.8 Maintenance of Equipment: The Transmission Customer shall maintain all
of its equipment and facilities connected to the Transmission
Provider's system in a safe and efficient manner and in accordance
with manufacturers' recommendations, Good Utility Practice, applicable
regulations, and requirements of NEPOOL, and NPCC.
The Transmission Provider may request that the Transmission Customer
test, calibrate, verify or validate the data link, metering, data
acquisition, transmission, protective, or other equipment or software
consistent with the Transmission Customer's routine obligation to
maintain its equipment and facilities or for the purposes of trouble
shooting problems on the network facilities. The Transmission
Customer will be responsible for the cost to test,
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 298
calibrate, verify or validate the equipment or software.
The Transmission Provider shall have the right to inspect the tests,
calibrations, verifications and validations of the data link,
metering, data acquisition, transmission, protective, or other
equipment or other software connected to the Transmission Provider's
system.
The Transmission Customer, at the Transmission Provider's request,
shall supply the Transmission Provider with a copy of the
installation, test, and calibration records of the data link,
metering, data acquisition, transmission, protective or other
equipment or software connected to the Transmission Provider's system.
The Transmission Provider shall have the right, at the Transmission
Customer's expense, to monitor the factory acceptance test, the field
acceptance test,
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 299
and the installation of any metering, data acquisition, transmission,
protective or other equipment or software connected to the Transmission
Provider's system.
2.9 Emergency System Operations: The Transmission Customer's equipment and
facilities, etc. shall be subject to all applicable emergency
operation standards required of and by the Transmission Provider to
operate in an interconnected transmission network.
The Transmission Provider reserves the right to have the system
operators take whatever actions or inactions they deem necessary
during emergency operating conditions to: (i) preserve the integrity
of the Transmission System, (ii) limit or prevent damage, (iii)
expedite restoration of service, or (iv) preserve public safety.
2.10 Cost Responsibility: The Transmission Customer shall be responsible
for all costs incurred by the
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 300
Transmission Provider relative to the Transmission Customer's
facilities. Some costs may be allocated to several Transmission
Customers. If the method for allocating costs is not clearly defined,
then the method for allocation will be at the Transmission Provider's
discretion.
3.0 Service For a Network Resource
The following Terms and Conditions are specific to Service for a generator
Network Resource.
3.1 Voltage or Reactive Control Requirements: Unless directed otherwise,
the Transmission Customer will operate its existing interconnected
generation facility(ies) with an automatic voltage regulator(s). The
voltage regulator will control voltage at the Point(s) of Receipt
consistent with the range of voltage scheduled by the System Operator.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 301
At the discretion of the Transmission Provider, the Transmission
Customer may be directed to deactivate the automatic voltage regulator
and to supply reactive power per a schedule provided by the
Transmission Provider.
If the Transmission Customer has not installed capacity sufficient to
operate its generation facility consistent with recommendations of the
Transmission Provider resulting from the System Impact and Facilities
Studies or fails to operate at such capacity, the Transmission
Provider may install, at the Transmission Customer's expense, reactive
compensation equipment necessary to ensure the proper voltage or
reactive supply at the Point(s) of Receipt.
3.2 Station Service: When the Transmission Customer's generation facility
is producing electricity, the Customer must supply its own station
service power. If and when the Transmission Customer's generation
facility is not producing electricity, the Customer
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 302
must obtain station service capacity and energy from another supplier
or another of its resources.
3.3 Protection Requirements: Protection requirements are defined in NEPOOL
and NPCC documents as may be adopted or amended from time to time.
3.4 Operational Obligations The Transmission Provider may require the
generator to be equipped for Automatic Generation Control (AGC). The
Transmission Customer will be responsible for all costs associated
with installing and maintaining an AGC system on the generator(s).
The Transmission Provider retains the right to require reduced
generation at times when system conditions present transmission
restrictions or otherwise adversely affect the Transmission Provider's
other customers. The Transmission Provider will use due diligence to
resolve the problems to allow the generator to return to the operating
level prior to
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 303
the Transmission Provider's notice to reduce generation.
All operations (including start-up, shutdown and determination of
hourly generation) will be coordinated by the Transmission Provider.
3.5 Coordination of Operations: The Transmission Customer shall furnish
the Transmission Provider with generator annual maintenance schedules,
advise the Transmission Provider if its Network Resource is capable of
participation in system restoration and/or if it has black start
capability.
The Transmission Provider reserves the right to specify turbine and/or
generator control (e.g., droop) settings as determined by the System
Impact or Facilities Study or subsequent studies. The Transmission
Customer agrees to comply with such specifications by the Transmission
Provider at the Transmission Customer's expense.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 304
If the generator is not dispatchable by the Transmission Provider, the
Transmission Customer shall notify the Transmission Provider at least
48 hours in advance of its intent to take its resource temporarily
off-line and its intent to resume generation. In circumstances such
as forced outages, the Transmission Customer shall notify the
Transmission Provider as promptly as possible of the Network
Resource's temporary interruption of generation and/or transmission.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 305
4.0 Service for Delivery to Load
The following Terms and Conditions are specific to Service for Delivery to
Load.
4.1 Power Factor Requirement: The Transmission Customer agrees to maintain
an overall Load Power Factor and reactive power supply within
predefined sub-areas as measured at the Point(s) of Delivery within
ranges specified by the Transmission Provider or NEPOOL criteria,
rules and standards which identify the power factor levels that must
be maintained throughout the applicable sub-area for each anticipated
level of total NEPOOL load. The Transmission Customer agrees to
maintain Load Power Factor and reactive power requirements within the
range specified by the Transmission Provider for the sub-area based on
total NEPOOL load during that hour. NEPOOL may revise the power
factor limits required from time to time. If the Transmission
Customer lacks the capability to
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 306
maintain the Load Power Factor within the ranges specified, the
Transmission Provider may:
a) install, at the Transmission Customer's expense, reactive
compensation equipment necessary to ensure proper load power
factor at the Point(s) of Delivery;
b) charge the Transmission Customer per the Tariff.
4.2 Protection Requirements: The Transmission Customer's relay and
protection systems must comply with all applicable NEPOOL and NPCC
criteria, rules, procedures, guidelines, standards or requirements as
may be adopted or amended from time to time.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 307
4.3 Operational Obligations: The Transmission Customer shall be
responsible for operating and maintaining security of its electric
system in a manner that avoids adverse impact to the Transmission
Provider's or others' interconnected systems and complies with all
applicable NEPOOL, and NPCC operating criteria, rules, procedures,
guidelines and interconnection standards as may be amended or adopted
from time to time. These actions include, but are not limited to:
- Voltage Reduction Load Shedding
- Underfrequency Load Shedding
- Block Load Shedding
- Dead Station Tripping
- Transferring Load Between Point(s) of Delivery
- Implementing Voluntary Load Reductions Including Interruptible
Customers
- Starting Stand-by Generation
- Permitting Transmission Provider Controlled Service Restoration
Following Supply Delivery Contingencies on Transmission Provider
Facilities
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 308
5.0 Default
If the Transmission Customer's equipment fails to perform consistent with
the Terms and Conditions of this agreement, then the Transmission Customer
will be deemed to be in default and service may be suspended immediately
and subject to a termination through a FERC filing. If the Transmission
Customer fails to provide the information required in Section 2.3 in a
timely manner, the Transmission Provider shall be permitted to assess a
penalty of $100 per day until such information is provided in its entirety
to the Transmission Provider.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 309
The Parties whose authorizing signatures appear below warrant that they will
abide by the foregoing terms and conditions.
____________________ _______________________
NEPOOL Participants (Transmission Customers)
By (System Operator)
____________________ ____________________
By: By:
____________________ ____________________
____________________________
Title: Title:
____________________ ____________________
Date: Date:
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 310
ATTACHMENT I
Form of
System Impact Study Agreement
This Agreement dated __________, is entered into by (the
"Transmission Customer") and the NEPOOL Participants (the "Transmission
Provider") acting through (the "System Operator"), for the purpose
of setting forth the terms, conditions and costs for conducting a System Impact
Study relative to ,in accordance with the NEPOOL Open Access
Transmission Tariff ("Tariff"). All definitions and other terms and conditions
of that Tariff are incorporated herein by reference. The Transmission Provider
may designate one or more Participants or the System Operator to act for it
under this Agreement.
1. The Transmission Customer agrees to provide, in a timely and complete
manner, the information and technical data
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 311
specified in Exhibit 1 to this Agreement and reasonably necessary for the
Transmission Provider to conduct the System Impact study. The Transmission
Customer understands that it must provide all such information and data
prior to the Transmission Provider's commencement of the Study. Such
information and technical data is specified in Exhibit 1 to this Agreement.
2. All work pertaining to the System Impact Study that is the subject of this
Agreement will be approved and coordinated only through designated and
authorized representatives of the Transmission Provider and the
Transmission Customer. Each party shall inform the other in writing of its
designated and authorized representative.
3. The Transmission Provider will advise the Transmission Customer of any
additional information as it may in its sole reasonable discretion deem
necessary to complete the study. Any such additional information shall be
obtained only if required by Good Utility Practice and shall be
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 312
subject to the Transmission Customer's consent to proceed, such consent not
to be unreasonably withheld.
4. The Transmission Provider contemplates that it will require _________ to
complete the System Impact Study. Upon completion of the Study by the
Transmission Provider, the Transmission Provider will provide a report to
the Transmission Customer based on the information provided and developed
as a result of this effort. If, upon review of the Study results, the
Transmission Customer decides to pursue , the Transmission
Provider will, at the Transmission Customer's direction, tender a
Facilities Study Agreement within thirty (30) days. The System Impact and
Facilities Studies, together with any additional studies contemplated in
Paragraph 3, shall form the basis for the Transmission Customer's proposed
use of the Transmission Provider's transmission system and shall be
furthermore utilized in obtaining necessary third-party approvals of any
interconnection facilities and requested transmission services. The
Transmission Customer understands and acknowledges that any use of study
results
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 313
by the Transmission Customer or its agents, whether in preliminary
or final form, prior to NEPOOL l8.4 approval, is completely at the
Transmission Customer's risk and that the Transmission Provider will not
guarantee or warrant the completeness, validity or utility of study results
prior to NEPOOL 18.4 approval.
5. The estimated costs contained within this Agreement are the Transmission
Provider's good faith estimate of its costs to perform the System Impact
Study contemplated by this Agreement. The Transmission Provider's
estimates do not include any estimates for wheeling charges that may be
associated with the transmission of facility output to third parties or
with rates for station service. The actual costs charged to the
Transmission Customer by the Transmission Provider may change as set forth
in this Agreement. Prepayment will be required for all study, analysis,
and review work performed by the Transmission Provider or its Designated
Agent, all of which will be billed by the Transmission provider to the
Transmission Customer in accordance with Paragraph 6 of this Agreement.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 314
6. The payment required is $________ from the Transmission Customer to the
Transmission Provider for the primary system analysis, coordination, and
monitoring of the System Impact Study. The Transmission Provider will, in
writing, advise the Transmission Customer in advance of any cost increases
for work to be performed if total amount increases by 10% or more. Any
such changes to the Transmission Provider's costs for the study work shall
be subject to the Transmission Customer's consent, such consent not to be
unreasonably withheld. The Transmission Customer shall, within thirty (30)
days of the Transmission Provider's notice of increase, either authorize
such increases and make payment in the amount set forth in such notice, or
the Transmission Provider will suspend the System Impact Study and this
Agreement will terminate if so permitted by the Federal Energy Regulatory
Commission.
In the event this Agreement is terminated for any reason, the Transmission
Provider shall refund to the Transmission Customer the portion of the above
credit or any subsequent payment to the Transmission Provider by the
Transmission
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 315
Customer that the Transmission provider did not expend in performing its
obligations under this Agreement. Any additional billings under this
Agreement shall be subject to an interest charge computed in
accordance with the provisions of the Tariff. Payments for work performed
shall not be subject to refunding except in accordance with Paragraph 7
below.
7. If the actual costs for the work exceed prepaid estimated costs, the
Transmission Customer shall make payment to the Transmission Provider for
such actual costs within thirty(30) days of the date of the Transmission
Provider's invoice for such costs. If the actual costs for the work are
less than those prepaid, the Transmission Provider will credit such
difference toward Transmission Provider costs unbilled, or in the event
there will be no additional billed expenses, the amount of the overpayment
will be returned to the Transmission Customer with interest computed as
stated in Paragraph 6 of this Agreement, from the date of reconciliation.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 316
8. Nothing in this Agreement shall be interpreted to give the Transmission
Customer immediate rights to wheel over or interconnect with the
Transmission Provider's transmission or distribution system. Such rights
shall be provided for under separate agreement and in accordance with the
Transmission Provider's open access tariff.
9. Within one (1) year following the Transmission Provider's issuance of a
final bill under this Agreement, the Transmission Customer shall have the
right to audit the Transmission Provider's accounts and records at the
offices where such accounts and records are maintained, during normal
business hours; provided that appropriate notice shall have been given
prior to any audit and provided that the audit shall be limited to those
portions of such accounts and records that relate to service under this
Agreement. The Transmission Provider reserves the right to assess a
reasonable fee to compensate for the use of its personnel time in assisting
any inspection or audit of its books, records or accounts by the
Transmission Customer or its Designated Agent.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 317
10. Each party agrees to indemnify and hold the other party and its Related
Persons of each of them (collectively "Affiliates") harmless from and
against any and all damages, costs (including attorney's fees), fines,
penalties and liabilities, in tort, contract, or otherwise (collectively
"Liabilities") resulting from claims of third parties arising, or claimed
to have arisen as a result of any acts or omissions of either party under
this Agreement. Each party hereby waives recourse against the other party
and its Related Persons for, and releases the other party and its Related
Persons from, any and all Liabilities for or arising from damage to its
property due to a performance under this Agreement by such other party
except in cases of negligence or intentional wrongdoing by either party.
11. If either party materially breaches any of its covenants hereunder, the
other party may terminate this Agreement by filing a notice of intent to
terminate with the Federal Energy Regulatory Commission and serving notice
of same on the other party to this Agreement. This remedy is in
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 318
addition to any other remedies available to the injured party.
12. This Agreement shall be construed and governed in accordance with the laws
of the State of Connecticut and with Part II of the Federal Power Act, 16
U.S.C. <section><section>824d et seq., and with Part 35 of Title 18 of the
Code of Federal Regulations, l8 C.F.R. <section><section>35 et seq.
13. All amendments to this Agreement shall be in written form executed by both
parties.
14. The terms and conditions of this Agreement shall be binding on the
successors and assigns of either party.
15. This Agreement will remain in effect for a period of up to two years from
its effective date as permitted by the Federal Energy Regulatory
Commission, and is subject to extension by mutual agreement. Either party
may terminate this Agreement by thirty (30) days' notice except as is
otherwise provided herein. If this Agreement expires by
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 319
its own terms, it shall be the Transmission Provider's responsibility to
make such filing.
TRANSMISSION CUSTOMER: NEPOOL Participants
By (System Operator)
Name: ____________________ Name:_______________________
Title:____________________ Title: _____________________
Date: ____________________ Date: ______________________
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 320
EXHIBIT 1
Information to be Provided to the Transmission Provider
by the Transmission Customer for System Impact Study
1.0 FACILITIES IDENTIFICATION
1.1 Requested capability in MW and MVA; summer and winter
1.2 Site location and plot plan with clear geographical references
1.3 Preliminary one-line diagram showing major equipment and extent of
Transmission Customer ownership
1.4 Auxiliary power system requirements
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 321
1.5 Back-up facilities such as standby generation or alternate supply
sources
2.0 MAJOR EQUIPMENT
2.1 Power transformer(s): rated voltage, MVA and BIL of each winding, LTC
and or NLTC taps and range, Z{1} (positive sequence) and Z{o} (zero
sequence) impedances, and winding connections. Provide normal,
long-time emergency and short-time emergency thermal ratings.
2.2 Generator(s): rated MVA, speed and maximum and minimum MW output,
reactive capability curves, open circuit saturation curve, power factor
(V) curve, response (ramp) rates, H (inertia), D (speed damping), short
circuit ratio, X{1} (leakage), X{2}:(negative sequence), and X{o} (zero
sequence) reactances and other data:
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 322
Direct Quadrature
Axis Axis
Saturated synchronous reactance X{dv} X{qv}
unsaturated synchronous reactance X{di} X{qt}
saturated transient reactance X'{dv} X'{qv}
unsaturated transient reactance X'{di} X'{qi}
saturated subtransient reactance X"{dv} X"{qv}
unsaturated subtransient reactance X"{di} X"{qi}
transient open-circuit time T'{do} T'{qo}
constant
transient short-circuit time T"{d} T"{q}
constant
subtransient open-circuit time T"{do} T"{qo}
constant
subtransient short-circuit time T"{d} T"{q}
constant
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 323
2.3 Excitation system, power system stabilizer and governor: manufacturer's
data in sufficient detail to allow modeling in transient stability
simulations.
2.4 Prime mover: manufacturer's data in sufficient detail to allow
modeling in transient stability simulations, if determined necessary.
2.5 Busses: rated voltage and ampacity (normal, long-time emergency and
short-time emergency thermal ratings), conductor type and
configuration.
2.6 Transmission lines: overhead line or underground cable rated voltage
and ampacity (normal, long-time emergency and short-time emergency
thermal ratings), Z{1} (positive sequence) and Z{o} (zero sequence)
impedances, conductor type, configuration, length and termination
points.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 324
2.7 Motors greater than 150 kW 3-phase or 50 kW single-phase: type
(induction or synchronous), rated hp, speed, voltage and current,
efficiency and power factor at 1/2, 3/4 and full load, stator
resistance and reactance, rotor resistance and reactance, magnetizing
reactance.
2.8 Circuit breakers and switches: rated voltage, interrupting time and
continuous, interrupting and momentary currents. Provide normal,
long-time emergency and short-time emergency thermal ratings.
2.9 Protective relays and systems: ANSI function number, quantity
manufacturer's catalog number, range, descriptive bulletin, tripping
diagram and three-line diagram showing AC connections to all relaying
and metering.
2.10 CT's and VT's: location, quantity, rated voltage, current and
ratio.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 325
2.11 Surge protective devices: location, quantity, rated voltage and
energy capability.
3.0 OTHER
3.1 Additional data reasonably necessary to perform the System Impact Study
will be provided by the Transmission Customer as requested by the
Transmission Provider.
3.2 The Transmission Provider reserves the right to require that the
Transmission Customer accept the use in the study of specific equipment
settings or characteristics necessary to meet NEPOOL and NPCC criteria
and standards.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 326
ATTACHMENT J
Form of
Facilities Study Agreement
This agreement dated ________, is entered into by ____________ (the
Transmission Customer) and the NEPOOL Participants (the "Transmission
Operator") acting through the _______ ("System Provider"), for the purpose of
setting forth the terms, conditions and costs for conducting a Facilities Study
relative to ____________________, in accordance with the NEPOOL Open Access
Transmission Tariff ("Tariff"). All definitions and other terms and conditions
of that Tariff are incorporated herein by reference. The Transmission Provider
may designate one or more Participants or the System Operator to act for it
under this Agreement. The Facilities Study will determine the detailed
engineering, design and cost of the facilities necessary to satisfy the
Transmission Customer's request for service over the NEPOOL Transmission
System.
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 327
1. The Transmission customer agrees to provide, in a timely complete manner,
the information and technical data specified in Exhibit 1 to this Agreement
and reasonably necessary for the Transmission Provider to conduct the
Facilities Study. Where such information and technical data was provided
for the System Impact Study, it should be reviewed and updated with current
information, as required.
2. All work pertaining to the Facilities Study that is the subject of this
Agreement will be approved and coordinated only through designated and
authorized representatives of the Transmission Provider and the
Transmission Customer. Each party shall inform the other in writing of its
designated and authorized representative.
3. The Transmission Provider will advise the Transmission Customer of
additional information as may be reasonably deemed necessary to
complete the study by the Transmission
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 328
Provider. Any such additional information shall be obtained only if
required by Good Utility Practice and shall be subject to the Transmission
Customer's consent to proceed, such consent not to be unreasonably
withheld.
4. The Transmission Provider contemplates that it will require ____ days to
complete the Facilities Study. Upon completion of the study by the
Transmission Provider, the Transmission Provider will provide a report to
the Transmission Customer based on the information provided and developed
as a result of this effort. If, upon review of the study results, the
Transmission Customer decides to pursue its transmission service request,
the Transmission Customer must sign a supplemental Service Agreement with
the Transmission Provider under the Tariff. The System Impact and
Facilities Studies, together with any additional studies contemplated in
Paragraph 3, shall form the basis for the Transmission Customer's proposed
use of the Transmission Provider's Transmission System and shall be
furthermore utilized in obtaining necessary third-party approvals of any
facilities and requested transmission
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 329
services. The Transmission Customer understands and acknowledges that any
use of the study results by the Transmission Customer or its agents whether
in preliminary or final form, prior to approval under Section 18.4 of the
Restated NEPOOL Agreement, is completely at the Transmission Customer's risk
and that the Transmission Provider will not guarantee or warrant the
completeness, validity or utility of the study results prior to NEPOOL 18.4
approval.
5. The estimated costs contained within this Agreement are the Transmission
Provider's good faith estimate of its costs to perform the Facilities Study
contemplated by this Agreement. The Transmission Provider's estimates do
not include any estimates for wheeling charges that may be associated with
the transmission of facility output to third parties or with rates for
station service. The actual costs charged to the Transmission Customer by
the Transmission Provider may change as set forth in this Agreement.
Prepayment will be required for all study, analysis, and review work
performed by the Transmission
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 330
Provider's or its Designated Agent's personnel, all of which will be billed
by the Transmission Provider to the Transmission Customer in accordance with
Paragraph 6 of this Agreement.
6. The payment required is $______________ from the Transmission Customer to
the Transmission Provider for the primary system analysis, coordination,
and monitoring of the Facilities Study to be performed by the Transmission
Provider for the Transmission Customer's requested service. The
Transmission Provider will, in writing, advise the Transmission Customer in
advance of any cost increases for work to be performed if the total amount
increases by 10% or more. Any such changes to the Transmission Provider's
costs for the study work to be performed shall be subject to the
Transmission Customer's consent, such consent not to be unreasonably
withheld. The Transmission Customer shall, within thirty (30) days of the
Transmission Provider's notice of increase, either authorize such increases
and make payment in the amount set forth in such notice, or the
Transmission Provider will suspend the study and this
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 331
Agreement will terminate if so permitted by the Federal Energy Regulatory
Commission.
In the event this Agreement is terminated for any reason, the Transmission
Provider shall refund to the Transmission Customer the portion of the above
credit or any subsequent payment to the Transmission Provider by the
Transmission Customer that the Transmission Provider did not expend in
performing its obligations under this Agreement. Any additional billings
under this Agreement shall be subject to an interest charge computed in
accordance with the provisions of the Tariff. Payments for work performed
shall not be subject to refunding except in accordance with Paragraph 7
below.
7. If the actual costs for the work exceed prepaid estimated costs, the
Transmission Customer shall make payment to the Transmission Provider for
such actual costs within thirty (30) days of the date of the Transmission
Provider's invoice for such costs. If the actual costs for the work are
less than that prepaid, the Transmission Provider will
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 332
credit such difference toward Transmission Provider's costs unbilled, or in
the event there will be no additional billed expenses, the amount of the
overpayment will be returned to the Transmission Customer with interest
computed in accordance with the provisions of the Tariff.
8. Nothing in this Agreement shall be interpreted to give the Transmission
Customer immediate rights to interconnect to or wheel over the NEPOOL
Transmission System. Such rights shall be provided for under separate
agreement.
9. Within one (1) year following the Transmission Provider's issuance of a
final bill under this Agreement, the Transmission Customer shall have the
right to audit the Transmission Provider's accounts and records at the
offices where such accounts and records are maintained during normal
business hours; provided that appropriate notice shall have been given
prior to any audit and provided that the audit shall be limited to those
portions of such accounts and records that relate to service under this
Agreement. The Transmission Provider reserves the right to
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 333
assess a reasonable fee to compensate for the use of its personnel time in
assisting any inspection or audit of its books, records or accounts by the
Transmission Customer or its Designated Agent.
10. Each party agrees to indemnify and hold the other party and its Related
Persons harmless from and against any and all damages, costs (including
attorney's fees), fines, penalties and liabilities, in tort, contract, or
otherwise (collectively "Liabilities") resulting from claims of third
parties arising, or claimed to have arisen as a result of any acts or
omissions of either party under this Agreement. Each party hereby waives
recourse against the other party and its Related Persons for, and releases
the other party and its Related Persons from, any and all Liabilities for
or arising from damage to its property due to performance under this
Agreement by such other party except in cases of negligence or intentional
wrongdoing by either party.
11. If any party materially breaches any of its covenants hereunder, the other
party may terminate this Agreement by
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 334
filing a notice of intent to terminate with the Federal Energy Regulatory
Commission and serving notice of same on the other party to this Agreement.
This remedy is in addition to any other remedies available for the injured
party.
12. This agreement shall be construed and governed in accordance with the laws
of the State of Connecticut and with Part II of the Federal Power Act, 16
U.S.C. <section><section>824d et seq., and with Part 35 of Title 18 of the
Code of Federal Regulations, l8 C.F.R. <section><section>35 et seq.
13. All amendments to this Agreement shall be in written form executed by both
parties.
14. The terms and conditions of this Agreement shall be binding on the
successors and assigns of either party.
15. This Agreement will remain in effect for a period of two years from its
effective date as permitted by the Federal
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. 335
Energy Regulatory Commission, and is subject to extension by mutual
agreement.
Either party may terminate this Agreement by thirty (30) days' notice
except as is otherwise provided herein. If this Agreement expires by its
own terms, it shall be the Transmission Provider's responsibility to make
such filing.
Transmission Customer: NEPOOL Participants
By (System Operator)
Name:______________________ Name:_____________________
Title:_____________________ Title:____________________
Date:______________________ Date:_____________________
Exhibit 10.23.3
THIRTY-SEVENTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
THIS THIRTY-SEVENTH AGREEMENT AMENDING NEW ENGLAND POWER POOL
AGREEMENT, dated as of August 15, 1998 ("Thirty-Seventh Agreement"), is
entered into by the signatory Participants to amend the New England Power
Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was
amended and restated by the Thirty-Third Agreement Amending New England
Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third
Agreement") in the form of the Restated New England Power Pool Agreement
("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as
Exhibit A thereto, and the Thirty-Third Agreement also provided for the
NEPOOL Open Access Transmission Tariff ("Tariff") which is Attachment B to
the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the Tariff have
subsequently been amended by five supplements dated, respectively, as of
February 7, June 1, September 1, November 1 and December 31, 1997 and by
three additional amendatory agreements dated, respectively, as of September
1, 1997, November 15, 1997 and July 20, 1998; and
WHEREAS, the signatories hereto desire to amend the Restated NEPOOL
Agreement, as amended by the Thirty-Sixth Agreement Amending New England
Power Pool Agreement, dated July 20, 1998, to amend the definition of
"Power Year" and to make certain related changes.
NOW, THEREFORE, the signatory Participants agree as follows:
SECTION 1
AMENDMENT TO RESTATED NEPOOL AGREEMENT
1.1 AMENDMENT OF SECTION 1.77. Section 1.77 of the Restated NEPOOL
Agreement is amended to read as follows:
POWER YEAR is (i) the period of twelve (12) months commencing on
November 1, in each year to and including 1997; (ii) the period
of seven (7) months commencing on November 1, 1998; and (iii) the
period of twelve (12) months commencing on June 1, 1999 and each
June 1 thereafter.
1.2 AMENDMENT OF SECTION 1.104. Section 1.104 of the Restated NEPOOL
Agreement is amended to read as follows:
WINTER PERIOD in each Power Year is (i) the seven-month period
from November through May and the month of October for the Power
Year commencing on November 1 in 1997 or a prior Power Year; (ii)
the seven-month period from November through May for the Power
Year commencing on November 1, 1998; and (iii) the eight-month
period from October through May for the Power Year commencing on
June 1, 1999 and each June 1 thereafter.
1.3 AMENDMENT OF SECTION 12.2(A)(1), DEFINITION OF "I". The
definition of "I" in Section 12.2(a)(1) of the Restated NEPOOL
Agreement is amended to read as follows:
I for the Participant for the month is the percentage which
represents the weighted average (using the Installed
Capability of each Installed Capability Entitlement for such
month for the weighting) of the Four Year Installed
Capability Target Availability Rates of the Installed
Capability Entitlements which are included in the
Participant's Installed System Capability during the hour of
the coincident peak load of the Participants for the month.
The Four Year Target Availability Rate for an Installed
Capability Entitlement for any month is the average of the
monthly Target Availability Rates for the forty-eight months
which comprise the period of four consecutive calendar years
ending within the Power Year which includes such month, as
determined on the basis of the Target Availability Rates for
each of the forty-eight months, and as applied on a basis
which is consistent with the fuel or maturity status of the
unit for each of the forty-eight months; provided, however,
that for the purpose of determining the Four Year Target
Availability Rate (i) for months included within the Power
Year which commences June 1, 1999, the determination shall
be made for the months of June through October on the basis
of the calendar years 1995 through 1998, and shall be made
for the months of November through May on the basis of the
calendar years 1996 through 1999, and (ii) for months
included within the Power Year which commences June 1, 2000,
the determination shall be made on the basis of the calendar
years 1996 through 1999. The Target Availability Rates
shall be those utilized by the Management Committee in its
most recent determination of NEPOOL Objective Capability
pursuant to Section 6.14(e).
1.4 AMENDMENT OF SECTION 12.2(A)(1), DEFINITION OF "H". The
definition of "H" in Section 12.2(a)(1) of the Restated NEPOOL
Agreement is amended to read as follows:
H for the Participant for the month is the percentage which
represents the weighted average (using the Installed
Capability of each Installed Capability Entitlement for such
month for the weighting) of the Four Year Actual
Availability Rates of the Installed Capability Entitlements
which are included in the Participant's Installed System
Capability during the hour of the coincident peak load of
the Participants for the month. The Four Year Actual
Availability Rate for an Installed Capability Entitlement
for any month is the percentage which represents the average
of the amounts determined for H{1} for the four applicable
Twelve-Month Measurement Periods within the forty-eight
months which comprise the period of four consecutive
calendar years ending within the Power Year which includes
such month; provided, however, that for the purpose of
determining the Four Year Actual Availability Rate (i) for
months included within the Power Year which commences June
1, 1999, the determination shall be made for the months of
June through October on the basis of the calendar years 1995
through 1998, and shall be made for the months of November
through May on the basis of the calendar years 1996 through
1999, and (ii) for months included within the Power Year
which commences June 1, 2000, the determination shall be
made on the basis of the calendar years 1996 through 1999.
A Twelve-Month Measurement Period is a period of twelve
sequential months. For purposes of this sequence, the first
month in the four years and the immediately succeeding
months shall be considered to follow the forty-eighth month
in the four-year period. The four applicable Twelve-Month
Measurement Periods to be used in the determination of H{1}
for an Installed Capability Entitlement shall be the four
sequential Twelve-Month Measurement Periods out of the
twelve possible combinations which yield the highest H{1}.
1.5 AMENDMENT OF SECTION 12.2(A)(1), DEFINITION OF "R". The
definition of "R" in Section 12.2(a)(1) of the Restated NEPOOL
Agreement is amended to read as follows:
R for the month is the phase-out factor for the month, which
shall be as follows:
R=0.75 for the Power Year beginning November 1,
1997.
R=0.50 for the 12 month period beginning November 1,
1998.
R=0.25 for the 12 month period beginning November 1,
1999.
R=0 for the 12 month period beginning November 1,
2000 and all subsequent 12 month periods.
SECTION 2
MISCELLANEOUS
2.1 Following execution by the requisite number of Participants in
accordance with the Restated NEPOOL Agreement, this Thirty-
Seventh Agreement shall become effective November 1, 1998, or on
such other date or dates as the Commission shall provide that the
amendments provided for in this Agreement shall become effective;
provided that such amendments shall not become effective if
Participants having the requisite number of Voting Shares give
notice in accordance with Section 21.11 of the Restated NEPOOL
Agreement that they object to the amendments.
2.2 Terms used in this Thirty-Seventh Agreement that are not defined
herein shall have the meanings ascribed to them in the Restated
NEPOOL Agreement.
2.3 This Thirty-Seventh Agreement may be executed in any number of
counterparts and each executed counterpart shall have the same
force and effect as an original instrument and as if all the
parties to all the counterparts had signed the same instrument.
Any signature page of this Thirty-Seventh Agreement may be
detached from any counterpart of this Thirty-Seventh Agreement
without impairing the legal effect of any signatures thereof, and
may be attached to another counterpart of this Thirty-Seventh
Agreement identical in form thereto but having attached to it one
or more signature pages.
IN WITNESS WHEREOF, each of the signatories has caused a counterpart
signature page for this Thirty-Seventh Agreement to be executed by its duly
authorized representative as of August 15, 1998.
<PAGE>
COUNTERPART SIGNATURE PAGE
TO THIRTY-SEVENTH AGREEMENT
AMENDING NEW ENGLAND POWER
POOL AGREEMENT
IN WITNESS WHEREOF, the undersigned has caused this counterpart
signature page to the Thirty-Seventh Agreement Amending New England Power
Pool Agreement, dated as of August 15, 1998, to be executed by its duly
authorized representative as of August 15, 1998.
Boston Edison Company________________
(Participant)
By:/s/ Douglas S. Horan______________
Name: Douglas S. Horan
Title: Senior Vice-President
<PAGE>
Central Maine Power Company__________
(Participant)
By:/s/ Arthur Adelberg______________
Name: Arthur Adelberg
Title: Exec VP
<PAGE>
Connecticut Municipal Electric Energy Cooperative
(Participant)
By:/s/ Maurice R. Scully_____________
Name: Maurice R. Scully
Title: Executive Director
<PAGE>
COMMONWEALTH ENERGY SYSTEM COMPANIES_
(Participant)
Cambridge Electric Light Company
Canal Electric Company
Commonwealth Electric Company
By:/s/ James J. Keane________________
Name: James J. Keane
Title: Vice President
Energy Supply & Engineering Services
<PAGE>
EASTERN UTILITIES ASSOCIATES COMPANIES
Blackstone Valley Electric Company
Eastern Edison Company
Newport Electric Company
(Participants)
By:/s/ Kevin A. Kirby________________
Name: Kevin A. Kirby
Title: Vice President
<PAGE>
Fitchburg Gas and Electric Light Company
(Participant)
By:/s/ David K. Foote________________
Name: David K. Foote
Title: Senior Vice President
<PAGE>
Hingham Municipal Lighting Plant_____
(Participant)
By:/s/ Joseph K. Spadea, Jr._________
Name: Joseph K. Spadea, Jr.
Title: G.M.
<PAGE>
Granite State Electric Company_______
(Participant)
By:/s/ John G. Cochrane______________
Name: John G. Cochrane
Title: Assistant Treasurer
<PAGE>
Massachusetts Electric Company_______
(Participant)
By:/s/ John G. Cochrane______________
Name: John G. Cochrane
Title: Treasurer
<PAGE>
The Narragansett Electric Company____
(Participant)
By:/s/ John G. Cochrane______________
Name: John G. Cochrane
Title: Treasurer
<PAGE>
New England Power Company____________
(Participant)
By:/s/ Cheryl A. Lafleur_____________
Name: Cheryl A. Lafleur
Title: Vice President
<PAGE>
North American Energy Conservation, Inc.
(Participant)
By:/s/ William J. Wagers_____________
Name: William J. Wagers
Title: Director, Electric
Wholesale Marketing
<PAGE>
NORTHEAST UTILITIES SYSTEM COMPANIES_
The Connecticut Light and Power Company
Holyoke Power and Electric Company
Holyoke Water Power Company
Public Service Company of New Hampshire
Western Massachusetts Electric Company
(Participants)
By:/s/ Frank P. Sabatino_____________
Name: Frank P. Sabatino
Title: Vice President of Wholesale Marketing
<PAGE>
SOUTH HADLEY ELECTRIC LIGHT DEPARTMENT
(Participant)
By:/s/ Wayne D. Doerpholz____________
Name: Wayne D. Doerpholz
Title: Manager
<PAGE>
PG&E Energy Trading-Power, L.P.______
(Participant)
By:/s/ Sarah M. Barpoulis____________
Name: Sarah M. Barpoulis
Title: Senior Vice President
<PAGE>
Strategic Energy Ltd.________________
(Participant)
By:/s/ John E. Molinda_______________
Name: John E. Molinda
Title: Director, Electricity Market &
Strategy Development
<PAGE>
The United Illuminating Company______
(Participant)
By:/s/ Stephen Goldschmidt___________
Name: Stephen Goldschmidt
Title: VP Planning & Information Resources
<PAGE>
Unitil Resources, Inc._______________
(Participant)
By:/s/ James G. Daly_________________
Name: James G. Daly
Title: President
<PAGE>
Unitil Power Corp.___________________
(Participant)
By:/s/ David K. Foote________________
Name: David K. Foote
Title: Senior Vice President
<PAGE>
Velco________________________________
(Participant)
By:/s/ Richard M. Chapman____________
Name: Richard M. Chapman
Title: President and CEO
Pres/CEO
<PAGE>
_____________________________________
(Participant)
By:__________________________________
Name:
Title:
Exhibit 10.23.4
THIRTY-EIGHTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
THIS THIRTY-EIGHTH AGREEMENT AMENDING NEW ENGLAND POWER POOL
AGREEMENT, dated as of October 30, 1998 ("Thirty-Eighth Agreement"), is
entered into by the signatory Participants to amend the New England Power
Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was
amended and restated by the Thirty-Third Agreement Amending New England
Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third
Agreement") in the form of the Restated New England Power Pool Agreement
("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as
Exhibit A thereto, and the Thirty-Third Agreement also provided for the
NEPOOL Open Access Transmission Tariff ("Tariff") which is Attachment B to
the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the Tariff have
subsequently been amended by five supplements dated, respectively, as of
February 7, June 1, September 1, November 1 and December 31, 1997 and by
four additional amendatory agreements dated, respectively, as of September
1, 1997, November 15, 1997, July 20, 1998 and August 15, 1998; and
WHEREAS, the signatories hereto desire to amend the Restated NEPOOL
Agreement, including the Tariff, as heretofore amended, to reflect the
revisions detailed below.
NOW, THEREFORE, the signatory Participants agree as follows:
SECTION 1
1.1 The Restated NEPOOL Agreement including the Tariff, as heretofore
amended, is hereby amended as set forth in Appendix A hereto.
1.2 The Restated NEPOOL Agreement, as heretofore amended, is hereby
amended to effect the errata corrections set forth in Appendix B hereto.
1.3 The Tariff, as heretofore amended, is hereby amended to effect the
errata corrections set forth in Appendix C hereto.
SECTION 2
MISCELLANEOUS
2.1 Following execution by the requisite number of Participants in
accordance with the Restated NEPOOL Agreement, this Thirty-Eighth
Agreement shall become effective as follows, provided that the
amendments contained herein shall not become effective if Participants
having the requisite number of Voting Shares give notice in accordance
with Section 21.11 of the Restated NEPOOL Agreement that they object
to such amendment:
(i) Appendix A hereto shall become effective on the later of (A) the
Second Effective Date, or (B) the first day of the calendar month
immediately following a Commission order accepting the provisions
of Appendix A, or (C) on such other date as the Commission shall
provide that the amendments reflected in Appendix A of this
Agreement shall become effective; provided that, if the
Commission has not issued an order with respect to Appendix A on
or before January 1, 1999, Appendix A shall become effective on
the later of January 1, 1999 or the Second Effective Date.
(ii) Appendix B and Appendix C hereto shall become effective on
December 1, 1998 or on such other date as the Commission shall
provide that the amendments reflected in Appendix B of this
Agreement shall become effective.
2.2 Terms used in this Thirty-Eighth Agreement that are not defined herein
shall have the meanings ascribed to them in the Restated NEPOOL
Agreement and Tariff.
2.3 This Thirty-Eighth Agreement may be executed in any number of
counterparts and each executed counterpart shall have the same force
and effect as an original instrument and as if all the parties to all
the counterparts had signed the same instrument. Any signature page
of this Thirty-Eighth Agreement may be detached from any counterpart
of this Thirty-Eighth Agreement without impairing the legal effect of
any signatures thereof, and may be attached to another counterpart of
this Thirty-Eighth Agreement identical in form thereto but having
attached to it one or more signature pages.
IN WITNESS WHEREOF, each of the signatories has caused a counterpart
signature page for this Thirty-Eighth Agreement to be executed by its duly
authorized representative as of October 30, 1998.
<PAGE>
COUNTERPART SIGNATURE PAGE
TO THIRTY-EIGHTH AGREEMENT
AMENDING NEW ENGLAND POWER
POOL AGREEMENT
IN WITNESS WHEREOF, the undersigned has caused this counterpart
signature page to the Thirty-Eighth Agreement Amending New England Power
Pool Agreement, dated as of October 30, 1998, to be executed by its duly
authorized representative as of October 30, 1998.
_____________________________________
(Participant)
By:__________________________________
Name:
Title:
<PAGE>
APPENDIX A
1. AMENDMENT OF SECTION 14.5(B).
Section 14.5(b) of the Restated NEPOOL Agreement is amended to read as
follows:
(b) A Participant that is deemed in an hour to furnish Operating
Reserve under the Agreement shall receive for each Kilowatt
of each category of Operating Reserve furnished by it the
applicable Operating Reserve Clearing Price as defined and
determined in accordance with Section 14.9 or the Bid Price
to provide such Kilowatt, if higher than the Operating
Reserve Clearing Price for the hour.
2. AMENDMENT OF SECTION 14.9.
Section 14.9 of the Restated NEPOOL Agreement is amended in its
entirety to read as follows:
14.9 DETERMINATION OF OPERATING RESERVE CLEARING PRICE.
(a) For each hour as necessary, the System Operator shall
determine the Operating Reserve Clearing Price for each
category of Operating Reserve as follows:
(i) The System Operator shall determine the aggregate
Kilowatts of the applicable category of Operating
Reserve that are deemed pursuant to Section 14.3(b) to
have been received by Participants for the hour.
(ii) For 10-Minute Non-Spinning Reserve and 30-Minute
Operating Reserve, the System Operator shall rank in
the order of lowest to highest the Bid Prices of the
resources designated by the System Operator for that
category of Operating Reserve for the hour. The
applicable Operating Reserve Clearing Price for 10-
Minute Non-Spinning Reserve or 30-Minute Operating
Reserve shall be the weighted average of the highest
Bid Prices for the 1000 Kilowatts (or such other number
as may be specified by the Regional Market Operations
Committee) of that category of Operating Reserve that
are designated by the System Operator for use in the
hour.
(iii)For 10-Minute Spinning Reserve the System Operator
shall rank in order of the lowest to highest the 10-
Minute Spinning Reserve Lost Opportunity Prices (as
defined in Section 14.9(b)) of the resources designated
by the System Operator for the hour. The Operating
Reserve Clearing Price for 10-Minute Spinning Reserve
shall be the weighted average for the 1,000 Kilowatts
(or such other number as may be specified by the
Regional Market Operations Committee) of the highest
10-Minute Spinning Reserve Lost Opportunity Prices for
the hour of the Entitlements that were designated by
the System Operator for use in the hour.
(b) The System Operator shall determine a 10-Minute Spinning
Reserve Lost Opportunity Price for each hour for use in
determining the Operating Reserve Clearing Price for 10-
Minute Spinning Reserve. For the purposes of Section 14.9,
the 10-Minute Spinning Reserve Lost Opportunity Price for a
Participant's resource shall be the amount by which the
Energy Clearing Price for the hour exceeds the resource's
Dispatch Price (not less than zero), PLUS the Bid Price in
the hour for each resource to provide 10-Minute Spinning
Reserve.
3. AMENDMENT OF SCHEDULES 5, 6 AND 7 TO TARIFF.
The third full paragraph of each of Schedules 5, 6 and 7 of the Tariff
is amended to read as follows:
Under Sections 14.4, 14.5 and 14.9 of the Agreement, as it will be in
effect after the Second Effective Date, the price to be paid for 10-Minute
Non-Spinning Reserve Service or 30-Minute Operating Reserve Service
received in any hour will be the Operating Reserve Clearing Price for the
hour for that category of reserve service, as determined on the basis of
bid prices to provide the service. Agreement, <section>14.9(a). The price
for 10-Minute Spinning Reserve Service will be the Operating Reserve
Clearing Price for 10-Minute Spinning Reserve for the hour, as determined
on the basis of the 10-Minute Spinning Reserve Lost Opportunity Prices, in
accordance with Section 14.9(b) of the Agreement. Agreement,
<section>14.9(a) and (b).
<PAGE>
APPENDIX B
ERRATA TO RESTATED
NEW ENGLAND POWER POOL AGREEMENT
The Restated New England Power Pool Agreement (the "Agreement"), as
amended and filed with the Commission on July 22, 1998, is amended to make
the following errata corrections.
1. In Section 1.13 of the Agreement, "or Interconnection Requester" is
deleted in two places.
2. In Section 1.17 of the Agreement, "person" in the fourth line of the
definition is changed to "other entity" and "with which that end user
is directly interconnected" is inserted after "Transmission Provider"
in the last line of the definition.
3. In Section 1.100 of the Agreement, "in the case of a municipal
Participant" is changed to "in the case of a state or municipal or
cooperatively-owned Participant".
4. Paragraph 1 of Section 15.1 of the Agreement is revised to read as
follows:
1. All transmission facilities owned by Participants classified as
PTF on April 1, 1998, but only so long as, in the case of each
such facility, the facility remains in service and continues to
meet the definition of PTF as in effect under this Agreement on
April 1, 1998.
5. The final sentence of Section 15.5 of the Agreement is revised to read
as follows:
Responsibility for the costs of new PTF or any modification or other
upgrade of PTF shall be determined, to the extent applicable, in
accordance with Parts V and VI and Schedule 11 of the Tariff,
including without limitation the provisions relating to responsibility
for the costs of new PTF or modifications or other upgrades to PTF
exceeding regional system, regulatory or other public requirements set
forth in paragraph (ii) of Schedule 11 to the Tariff.
6. In paragraph (ii) of Section 16.3 of the Agreement, "Network Customers
and Eligible Customers taking Internal Point-to-Point Service" is
changed to "Eligible Customers taking Regional Network Service and
Internal Point-to-Point Service".
7. Paragraph (iv) of Section 16.3 of the Agreement is revised to read as
follows:
(iv) that if the Transmission Provider receives a distribution
pursuant to Section 16.6 from NEPOOL out of revenues paid for
Through or Out Service or for In Service (as defined in the
Tariff), the amounts received shall reduce its Local Network
Service revenue requirements; and
8. Paragraph C of Section 16.6 of the Agreement is revised to read as
follows:
C. INTERNAL POINT-TO-POINT SERVICE REVENUES AND IN SERVICE REVENUES.
The revenues received by NEPOOL each month for providing Internal
Point-to-Point Service and the revenues, if any, received by
NEPOOL each month for providing In Service (as defined in the
Tariff) shall be distributed among the Participants owning or
supporting PTF in proportion to their respective Annual
Transmission Revenue Requirements for PTF under Attachment F to
the Tariff.
9. Section 18.5 is revised to insert after "the Participant shall not
proceed to implement such plan unless the Participant" the following:
"or the Non-Participant on whose behalf the Participant has submitted
its plan".
<PAGE>
APPENDIX C
ERRATA TO RESTATED
NEPOOL OPEN ACCESS TRANSMISSION TARIFF
The Restated NEPOOL Open Access Transmission Tariff, as amended and
filed with the Commission on July 22, 1998, is amended to make the
following errata corrections. Page references are to the pages in the
copies of the Tariff which were included in the July 22nd filing as Volume
III.
1. Section 1.15. In the fifth line on page 17 "or Interconnection
Requester" is deleted.
2. Section 1.28. The phrase "in accordance with Section 22A of this
Tariff" is moved from the end of the Section to the first line
and inserted after "NEPOOL". In the second line, "originating
outside the NEPOOL Control Area" is inserted after "import
transaction". In the fifth line "NEPOOL Transmission System" is
substituted for "NEPOOL Control Area". In the sixth line, "to
another Control Area or to the Maine Electric Power Company line"
is inserted after "interconnection."
3. Section 1.32. In the fourth and fifth lines, "NEPOOL
Transmission System" is substituted for "NEPOOL Control Area".
4. Section 1.34. A period is inserted after "Section 28.7" and the
balance of the definition is deleted.
5. Section 1.77. "Part II" is substituted for "Section 14".
6. Section 1.95. In the fifth line of the Section on page 40 "state
or municipal or cooperatively-owned" is substituted for
"municipal".
7. Section 1.97. In the last sentence of the definition "kilowatts"
is changed to "Kilowatts".
8. Section 3.4. At the beginning of the fourth line "effective" is
deleted.
9. Section 16. At the beginning of the second line on page 69, "any
ancillary service charges and" is inserted after "pay".
10. Part III. The following is inserted at the end of the title of
Part III: "; IN SERVICE".
11. Section 19.2. The first two and one-half lines of the final
sentence of the Section are changed to read as follows: "Non-Firm
Internal Point-to-Point Service shall be available to an entity
to serve its load only if the entity (i)".
12. Section 20. In the first two lines of the Section "firm or non-
firm" is changed to "Firm or Non-Firm". In the next to the last
sentence on page 74 "any ancillary service charge and" is
inserted after "pay". In the next to the last line on page 74
"firm" is changed to "Firm". On page 75 "non-firm" is changed to
"Non-Firm" in the first sentence and in the last listing in the
table.
13. Section 22A.1. The following is added at the end of the Section:
"Notwithstanding the foregoing, for the purpose of unauthorized
use charges assessed under Section 27.7(c) (for Firm Transmission
Service) and Section 28.5 (for Non-Firm Transmission Service), In
Service provided in conjunction with Regional Network Service
shall be treated as Point-to-Point Transmission Service."
14. Section 25. In the last line on page 87, "Exhibit" is changed to
"Attachment".
15. Section 27.2. In the next to the last sentence of the Section
"with Native Load Customers and" is deleted and replaced by
"equal to Native Load Customers, Network Customers and customers
for".
16. Section 27.6. The second sentence is modified to read as
follows: If multiple transactions require Curtailment, to the
extent practicable and consistent with Good Utility Practice, the
System Operator will curtail service to Network Customers and
Transmission Customers taking Firm Point-to-Point Transmission
Service on a non-discriminatory basis.
17. Section 27.7(c). The following phrase is inserted at the end of
the second sentence: "and the Point of Receipt may be identified
as the NEPOOL power exchange in circumstances where the System
Operator does not require greater specificity". The first line
on page 103 is modified to substitute the following for "Schedule
8 or Schedule 10": "Section 20, Section 21 or Section 22A".
18. Section 28.6. In the eighth line on page 112 "Receiving party"
is changed to "Receiving Party". In the next to the last line in
the Section on page 113 "Transmission" is changed to
"transmission".
19. Section 31.5. In the third line on page 128 "completed
applications" is changed to "Completed Applications".
20. Section 35.1. In the first line of the Section, "which is not
the Transmission Customer" is inserted after "any Participant."
21. Section 40.4. The last sentence of the Section is changed to
read as follows: "Deliveries in Interchange Transactions will
have a higher priority than any Non-Firm Point-to-Point
Transmission Service under this Tariff."
22. Section 40.5. At the end of the third sentence "to all load on a
load ratio basis" is substituted for "on the basis of average
losses as established by the System Operator". The last three
sentences of the Section are deleted.
23. Section 42.1. The following sentence is inserted between the
first and second sentences: "Each designation of a generating
resource as a Network Resource (in accordance with the definition
of Network Resource) shall be effective as of the beginning of a
month, shall remain in effect for at least one full month, and
shall only be terminated at the end of a month."
24. Section 42.2. The final sentence is deleted.
25. Section 45.5. The second sentence is modified to read as
follows: "However, to the extent practicable and consistent with
Good Utility Practice, any Curtailment will be shared by the
customers taking Internal Point-to-Point Service, Through or Out
Service and/or In Service and Network Customers on a non-
discriminatory basis."
26. Section 48(a). At the end of the next to last line "Points" is
changed to "Point(s)".
27. Section 49. In subparagraph (a) the third and fourth lines are
changed to read as follows: "Network the generator is or would be
located, including the filing". In paragraph (b) in the fifth
line on page 193 "Non-PTF System" is changed to "Non- PTF
system".
28. Section 50. The following is inserted at the end of the section:
"Notwithstanding the foregoing, nothing set forth in this Part
VII shall be deemed to relieve any Transmission Customer from its
obligations to pay any charges or costs otherwise payable by it
under Parts I through VI of this Tariff and the relevant
schedules related thereto."
29. Schedule 9. In the sentence at the end of the first paragraph of
subsection (1) "any ancillary service charges and" is inserted
after "pay".
30. Schedule 11. In the first line of paragraph (i) on page 234 "or"
is deleted after "PTF". The following is added at the end of the
first sentence of paragraph (i) on page 234: "and such amounts to
be paid by the Generator Owner shall not be included in Annual
Transmission Revenue Requirements under Attachment F." On page
236 in the 12th line, "upgrades" is changed to "upgrade". In the
11th line on page 242 "will" is inserted after "Owner".
31. Attachment F. The phrase "or Interconnection Requester" is
deleted at the end of paragraph (a) on page 266. On pages 276
and 277 paragraph J is modified to read as follows:
J. TRANSMISSION SUPPORT EXPENSE shall equal the expense
paid by Transmission Providers or other Participants
for PTF transmission support other than expenses for
payments made for transmission facilities or facility
upgrades placed in service on or after January 1, 1997
where the support obligation is required to be borne by
particular Participants or other entities in accordance
with Schedule 11 of the Tariff.
32. Attachment G. Item #9 on page 278 is deleted and the remaining
items are renumbered.
33. Attachment G-1. Item #10 on page 284 is deleted and the
remaining items are renumbered.
<PAGE>
COUNTERPART SIGNATURE PAGE
TO THIRTY-EIGHTH AGREEMENT
AMENDING NEW ENGLAND POWER
POOL AGREEMENT
IN WITNESS WHEREOF, the undersigned has caused this counterpart
signature page to the Thirty-Eighth Agreement Amending New England Power
Pool Agreement, dated as of October 30, 1998, to be executed by its duly
authorized representative as of October 30, 1998.
Boston Edison Company
-----------------------------------------
(Participant)
/s/ By: __________________________________
Name: Douglas S. Horan
Title: Senior Vice President
COMMONWEALTH ENERGY SYSTEM COMPANIES
-------------------------------------------
Cambridge Electric Light Company
Canal Electric Company
COMMONWEALTH ELECTRIC COMPANY
-------------------------------------------
(Participants)
/s/ By: ___________________________________
Name: James J. Keane
Title: Vice President
Energy Supply & Engineering Services
COMMONWEALTH ENERGY SYSTEM COMPANIES
-------------------------------------------
Cambridge Electric Light Company
Canal Electric Company
COMMONWEALTH ELECTRIC COMPANY
-------------------------------------------
(Participants)
/s/ By: ___________________________________
Name: Deborah A. McLaughlin
Title: President
EASTERN UTILITIES ASSOCIATES COMPANIES
-------------------------------------------
Blackstone Valley Electric Company
Eastern Edison Company
Montaup Electric Company
NEWPORT ELECTRIC COMPANY
------------------------------------------
(Participants)
/s/ By: ___________________________________
Name: Kevin A. Kirby
Title: Vice President
Fitchburg Gas and Electric Light Company
------------------------------------------
(Participants)
/s/ By: ___________________________________
Name: David K. Foote
Title: Senior Vice President
THE NARRAGANSETT ELECTRIC COMPANY
-------------------------------------------
(Participant)
/s/ By: ___________________________________
Name: Robert L. McCabe
Title: Chairman
MASSACHUSETTS ELECTRIC COMPANY
-------------------------------------------
(Participant)
/s/ By: ___________________________________
Name: Robert L. McCabe
Title: Chairman
NEW ENGLAND POWER COMPANY
--------------------------------------
(Participant)
/s/ By: ______________________________
Name: John G. Cochrane
Title: Treasurer
NORTHEAST UTILITIES SYSTEM COMPANIES
-------------------------------------------
The Connecticut Light and Power Company
Holyoke Power and Electric Company
Holyoke Water Power Company
Public Service Company of New Hampshire
WESTERN MASSACHUSETTS ELECTRIC COMPANY
------------------------------------------
(Participants)
/s/ By: Frank P. Sabatino__________________
Name:
Title:
THE UNITED ILLUMINATING COMPANY
-------------------------------------------
(Participant)
/s/ By: ___________________________________
Name: Stephen F. Goldschmidt
Title: Vice-President, Planning and
Information Resources
Unitil Power Corp.
------------------------------------------
(Participants)
/s/ By: ___________________________________
Name: David K. Foote
Title: Senior Vice President
Unitil Resources, Inc.
------------------------------------------
(Participant)
By: /s/ __________________________________
Name: James G. Daly
Title: President
Velco
------------------------------------------
(Participant)
By: /s/ __________________________________
Name: Richard M. Chapman
Title: President/CEO
GRANITE STATE ELECTRIC COMPANY
------------------------------------------
(Participant)
By: /s/ __________________________________
Name: Robert L. McCabe
Title: Chairman
PG&E PARTICIPANT COMPANIES
PG&E ENERGY TRADING - POWER, L.P.
By: PG&E Energy Trading - Power Holdings
Corporation, its sole general partner
By: /s/ __________________________________
Name: Sarah M. Barpoulis
Title: Senior Vice Presidnet
By: /s/ __________________________________
Name: James V. Mahoney
Title: Senior Vice Presidnet
Exhibit 10.23.5
THIRTY-NINTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
THIS THIRTY-NINTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT,
dated as of November 13, 1998 ("Thirty-Ninth Agreement"), is entered into
by the signatory Participants to amend the New England Power Pool Agreement
(the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was
amended and restated by the Thirty-Third Agreement Amending New England
Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third
Agreement") in the form of the Restated New England Power Pool Agreement
("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as
Exhibit A thereto, and the Thirty-Third Agreement also provided for the
NEPOOL Open Access Transmission Tariff ("Tariff") which is Attachment B to
the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the Tariff have
subsequently been amended by five supplements dated, respectively, as of
February 7, June 1, September 1, November 1 and December 31, 1997 and by
five additional amendatory agreements dated, respectively, as of September
1, 1997, November 15, 1997, July 20, 1998, August 15, 1998 and October 30,
1998; and
WHEREAS, the Federal Energy Regulatory Commission's Order issued
October 29, 1998 (the "Order") with respect to the Restated NEPOOL
Agreement and the Tariff, as amended through July 20, 1998, has required
that they be further amended by the date hereof in various respects; and
WHEREAS, the signatories hereto desire to implement the Order through
a compliance filing to make changes required by the Order.
NOW, THEREFORE, the signatory Participants agree as follows:
SECTION 1
AMENDMENT OF RESTATED NEPOOL AGREEMENT
1.1 AMENDMENT OF SECTION 15.1. Section 15.1 of the Restated NEPOOL
Agreement is amended to read as follows:
15.1 DEFINITION OF PTF. PTF or pool transmission facilities are the
transmission facilities owned by Participants rated 69 kV or
above required to allow energy from significant power sources to
move freely on the New England transmission network, and include:
1. All transmission lines and associated facilities owned by
Participants rated 69 kV and above, except for lines and
associated facilities that contribute little or no parallel
capability to the NEPOOL Transmission System (as defined in
the Tariff). The following do not constitute PTF:
(a) Those lines and associated facilities which are
required to serve local load only.
(b) Generator leads, which are defined as radial
transmission from a generation bus to the nearest point
on the NEPOOL Transmission System.
(c) Lines that are normally operated open.
2. Parallel linkages in network stations owned by Participants
(including substation facilities such as transformers,
circuit breakers and associated equipment) interconnecting
the lines which constitute PTF.
3. If a Participant with significant generation in its
transmission and distribution system (initially 25 MW) is
connected to the New England network and none of the
transmission facilities owned by the Participant qualify to
be included in PTF as defined in (1) and (2) above, then
such Participant's connection to PTF will constitute PTF if
both of the following requirements are met for this
connection:
(a) The connection is rated 69 kV or above.
(b) The connection is the principal transmission link
between the Participant and the remainder of the New
England PTF network.
4. Rights of way and land owned by Participants required for
the installation of facilities which constitute PTF under
(1), (2) or (3) above.
The Regional Transmission Planning Committee shall review at
least annually the status of transmission lines and related
facilities and determine whether such facilities constitute PTF
and shall prepare and keep current a schedule or catalogue of PTF
facilities.
The following examples indicate the intent of the above
definitions:
(i) Radial tap lines to local load are excluded.
(ii) Lines which loop, from two geographically separate
points on the NEPOOL Transmission System, the supply to
a load bus from the NEPOOL Transmission System are
included.
(iii)Lines which loop, from two geographically separate
points on the NEPOOL Transmission System, the
connections between a generator bus and the NEPOOL
Transmission System are included.
(iv) Radial connections or connections from a generating
station to a single substation or switching station on
the NEPOOL Transmission System are excluded, unless the
requirements of paragraph (3) above are met.
Transmission facilities owned by a Related Person of a
Participant which are rated 69 kV or above and are required to
allow Energy from significant power sources to move freely on the
New England transmission network shall also constitute PTF
provided (i) such Related Person files with the Secretary of the
Management Committee its consent to such treatment; and (ii) the
Management Committee determines that treatment of the facility as
PTF will facilitate accomplishment of NEPOOL's objectives. If a
facility constitutes PTF pursuant to this paragraph, it shall be
treated as "owned" by a Participant for purposes of the Tariff
and the other provisions of Part Four of the Agreement.
SECTION 2
AMENDMENT TO TARIFF
2.1 AMENDMENT OF SECTION 22A.3 Section 22A.3 of the Tariff is amended to
read as follows:
22A.3A Transmission Customer which has Reserved Capacity for In
Service as part of or in conjunction with Through or Out Service,
Internal Point-to-Point Service or Regional Network Service shall
receive such In Service as part of such other service without
additional charge.
2.2 DELETION OF SECTION 22A.4. Section 22A.4 of the Tariff is deleted in
its entirety.
2.3 AMENDMENT OF SECTION 33.4. Section 33.4 of the Tariff is amended to
read as follows:
33.4 Facilities Study Procedures: If a System Impact Study indicates
that additions or upgrades to the NEPOOL Transmission System are
needed to supply the Eligible Customer's service request, the
System Operator, within thirty days of the completion of the
System Impact Study, will tender to the Eligible Customer a
Facilities Study agreement in the form of Attachment J to this
Tariff, or in any other form that is mutually agreed to, which is
to be entered into by the Eligible Customer and the System
Operator and, if deemed necessary by the System Operator, by one
or more affected Transmission Provider(s) and pursuant to which
the Eligible Customer shall agree to reimburse the System
Operator and any affected Transmission Providers or other entity
designated by the System Operator for performing any required
Facilities Study. For a service request to remain a Completed
Application, the Eligible Customer shall execute the Facilities
Study agreement and return it to the System Operator within
fifteen days. If the Eligible Customer elects not to execute the
Facilities Study agreement, its application shall be deemed
withdrawn and its deposit, if any (less the reasonable
Administrative Costs incurred by the System Operator and any
affected Participants in connection with the Application), will
be returned with Interest. Upon receipt of an executed
Facilities Study agreement, the System Operator and any affected
Transmission Provider(s) or other designated entity will use due
diligence to cause the required Facilities Study to be completed
within a sixty-day period. If a Facilities Study cannot be
completed in the allotted time period, the System Operator will
notify the Transmission Customer and provide an estimate of the
time needed to reach a final determination and any resulting
increase in the cost, along with an explanation of the reasons
that additional time is required to complete the study. When
completed, the Facilities Study shall include a good faith
estimate of (i) the cost of Direct Assignment Facilities to be
charged to the Transmission Customer, or (ii) the Transmission
Customer's appropriate share of the cost of any required
additions or upgrades, and (iii) the time required to complete
such construction and initiate the requested service. The
Transmission Customer shall provide a letter of credit or other
reasonable form of security acceptable to the Transmission
Providers or other entities that will be responsible for the
construction of the new facilities or upgrades equivalent to the
costs of the new facilities or upgrades and consistent with
relevant commercial practices, as established by the Uniform
Commercial Code. The Transmission Customer shall have thirty
days to execute a Service Agreement, if required, or request the
filing of an unexecuted Service Agreement with the Commission and
provide the required letter of credit or other form of security
or the request will no longer be a Completed Application and
shall be deemed terminated and withdrawn.
2.4 AMENDMENT OF SECTION 40.4. Section 40.4 of the Tariff is amended to
read as follows:
The Network Customer may use the NEPOOL Transmission System to
deliver energy and/or capacity to its Network Loads from
resources that have not been designated as Network Resources.
Such energy and capacity shall be transmitted, on an as-available
basis, at no additional charge as part of Regional Network
Service. Deliveries from resources other than Network Resources
will have a higher priority than any Non-Firm Point-to-Point
Transmission Service under this Tariff.
2.5 AMENDMENT OF SECTION 42.1. Section 42.1 of the Tariff is amended to
delete the second sentence thereof (added in the Thirty-Eighth
Agreement Amending New England Power Pool Agreement).
2.6 AMENDMENT OF SECTION 44.4. Section 44.4 of the Tariff is amended to
read as follows:
44.4 Facilities Study Procedures: If a System Impact Study indicates
that additions or upgrades to the NEPOOL Transmission System are
needed to supply the Eligible Customer's service request, the
System Operator, within thirty days of the completion of the
System Impact Study, shall tender to the Eligible Customer a
Facilities Study agreement in the form of Attachment J to this
Tariff, or in any other form that is mutually agreed to, which is
to be entered into by the Eligible Customer and the System
Operator and, if deemed necessary by the System Operator, by one
or more affected Transmission Provider(s) and pursuant to which
the Eligible Customer shall agree to reimburse the System
Operator and any affected Transmission Provider(s) for performing
the required Facilities Study. For a service request to remain a
Completed Application, the Eligible Customer shall execute the
Facilities Study agreement and return it to the System Operator
within fifteen days. If the Eligible Customer elects not to
execute a Facilities Study agreement, its Application shall be
deemed withdrawn and its deposit, if any (less the reasonable
Administrative Costs incurred by the System Operator and any
affected Transmission Provider(s)), shall be returned with
Interest. Upon receipt of an executed Facilities Study
agreement, the System Operator and any affected Transmission
Provider(s), will use due diligence to complete the required
Facilities Study within a sixty-day period. If the System
Operator and any affected Transmission Provider(s) are unable to
complete the Facilities Study in the allotted time period, the
System Operator shall notify the Eligible Customer and provide an
estimate of the time needed to reach a final determination and
any resulting increase in the cost, along with an explanation of
the reasons that additional time is required to complete the
study. When completed, the Facilities Study will include a good
faith estimate of (i) the cost of Direct Assignment Facilities to
be charged to the Eligible Customer, (ii) the Eligible Customer's
appropriate share of the cost of any required Network Upgrades,
and (iii) the time required to complete such construction and
initiate the requested service. The Eligible Customer shall
provide a letter of credit or other reasonable form of security
acceptable to the affected Transmission Provider(s) or other
entities that will be responsible for the construction of the new
facilities or upgrades equivalent to the costs of new facilities
or upgrades consistent with commercial practices as established
by the Uniform Commercial Code. The Eligible Customer shall have
thirty days to execute a Service Agreement or request the filing
of an unexecuted Service Agreement and provide the required
letter of credit or other form of security or the request no
longer will be a Completed Application and shall be deemed
terminated and withdrawn.
2.7 AMENDMENT OF SECTION 46.1. Section 46.1 of the Tariff is amended to
read as follows:
46.1 Determination of Network Customer's Monthly Network Load: The
Network Customer's "Monthly Network Load" is its hourly load
(including its designated Network Load not physically
interconnected with the Transmission Provider under Section 43.3)
coincident with the coincident aggregate load of the Participants
and other Network Customers served in each Local Network in the
hour in which the coincident load is at its maximum for the month
("Monthly Peak").
2.8 AMENDMENT OF SECTION 49. Section 49 of the Tariff is amended to read
as follows:
49 Interconnection Requirements
Any Participant or Non-Participant which proposes to site a new
generating unit at a site owned or controlled by it, or which it
has the right to acquire or control, or to materially change and
increase the capacity of an existing generating unit, located in
the NEPOOL Control Area ("Generator Owner"), shall be obligated
to:
(a) complete and submit to the System Operator a standard
application, which is available from the System Operator,
entitled "Interconnection of New Generation to the New
England Transmission System -Application for System Impact
Study Agreement" ("Interconnection Application"), along with
the administrative fee and description of its proposal and
site information required by the Interconnection
Application;
(b) within fifteen (15) days of its tender by the System
Operator (which tender shall occur no later than thirty (30)
days following System Operator's receipt of a complete
Interconnection Application), enter into an agreement with
the System Operator and, if deemed necessary by the System
Operator, one or more affected Transmission Providers to
provide for the conduct of a System Impact Study to
determine what additions or upgrades to the NEPOOL
Transmission System and to the Non-PTF system are required
in order to permit its generating unit to interconnect in a
manner that avoids any significant adverse effect on system
reliability, stability, and operability, including
protecting against the degradation of transfer capability
for interfaces affected by the unit ("Minimum
Interconnection Standard"). If the Generator Owner does not
enter into the System Impact Study agreement within the
above time period, its application shall be deemed
withdrawn. The System Impact Study shall be conducted in
accordance with the procedures, and subject to the
obligations, specified in Sections 33.2 and 33.3 and
Attachment D of this Tariff and using the form of agreement
specified in Attachment I of this Tariff, except that: (1)
references therein to transmission service shall be deemed
to refer to interconnection; (2) references therein to
Eligible Customer or Transmission Customer shall be deemed
to refer to the Generator Owner; (3) Attachment D shall be
applied so that the interconnection is studied on a Minimum
Interconnection Standard basis; and (4)any references to, or
requirements for, a Service Agreement in Section 33.3 shall
be inapplicable.
(c) if a System Impact Study indicates that additions or
upgrades to the NEPOOL Transmission System and to the
Non-PTF system are required in order to permit its
generating unit to interconnect to the NEPOOL system on a
basis satisfying the Minimum Interconnection Standard,
within fifteen (15) days of its tender by the System
Operator (which tender shall occur no later than thirty (30)
days following the completion of the System Impact Study),
enter into an agreement with the System Operator and, if
deemed necessary by the System Operator, one or more
affected Transmission Providers to provide for the conduct
of a Facilities Study. The Facilities Study shall be
conducted in accordance with the procedures, and subject to
the obligations, specified in Sections 33.4 and 33.5 of this
Tariff, and using the form of agreement specified in
Attachment J of this Tariff, except that: (1) references
therein to transmission service shall be deemed to refer to
interconnection;(2) references therein to Eligible Customer
or Transmission Customer shall be deemed to refer to the
Generator Owner; and (3) any references to, or requirements
for, a Service Agreement in Section 33.4 shall be
inapplicable. In lieu of a Facilities Study, if
transmission system modifications are required, within 45
days of submission of the final System Impact Study report
to the Generator Owner, the Generator Owner, the System
Operator and the affected Transmission Provider(s) may
establish an agreement for "Expedited Interconnection".
While the Transmission Provider(s) or other entities that
will be responsible for constructing the new facilities or
upgrades on an expedited basis will provide the Generator
Owner with its best estimate of the new facility costs and
other charges that may be incurred, such estimate shall not
be binding and the Generator Owner shall agree in writing to
pay for all applicable costs incurred;
(d) in the event that transmission service will be needed under
a Transmission Provider's local tariff or the unit will be
interconnected to the Local Network of a Transmission
Provider, satisfy any applicable requirements under the
local tariff of the relevant Transmission Provider (except
for those relating to System Impact Studies and Facilities
Studies, which will be performed on a unified basis by the
System Operator in accordance with this Section); and
(e) submit its proposal for review in accordance with Section
18.4 of the Agreement and to take any action required
pursuant to Section 18.5 of the Agreement as a result of
such review in order that its generating unit can be
interconnected to the NEPOOL Transmission System in a manner
to satisfy the Minimum Interconnection Standard or, if
requested by the Generation Owner, to satisfy an enhanced
interconnection option pursuant to additional studies as
discussed below;
and upon the satisfaction of the obligations described in (a),
(b), (c), (d), and (e) above, the Generator Owner's unit shall
have the right to be interconnected to the NEPOOL Transmission
System.
In addition to obtaining the System Impact Study and Facilities
Study described in Subsections (b), (c), and (d) above, a
Generator Owner may elect to agree to an additional study to
determine what further additions or upgrades to the NEPOOL
Transmission System, beyond those required to satisfy the Minimum
Interconnection Standard, would be required for potentially
facilitating, under an enhanced interconnection option, a greater
level of use of the System, as specified by the Generator Owner.
A Participant other than the Generator Owner may also elect to
have performed at its expense such an additional study if and to
the extent the Generator Owner has decided not to elect such an
additional study. Generator Owners that have received prior to
October 29, 1998 all required NEPOOL approvals pursuant to
Sections 18.4 and 18.5 of the Restated NEPOOL Agreement for their
interconnections shall be deemed to have requested such an
enhanced interconnection option.
The completion of the portion of a System Impact Study or
Facilities Study addressing the Minimum Interconnection Standard
shall not be delayed by awaiting the results from any such
additional study. The performance of such additional studies
other than those underway as of October 29, 1998 shall be
accomplished at a time and in a manner that avoids such
additional studies unduly delaying the performance of studies for
other Generator Owners based on the Minimum Interconnection
Standard. The Generator Owner may, at its option, seek approval
for interconnection in a manner consistent with the results of
its System Impact Study and Facilities Study, as supplemented by
the additional study in accordance with Subsection (e) above.
If the studies conducted pursuant to this Section indicate that
new PTF or non-PTF facilities or a facility modification or other
PTF upgrades are necessary to satisfy the Minimum Interconnection
Standard or an enhanced interconnection option in connection with
a new or materially changed generating unit, or otherwise, in
order to interconnect, upon approval of the studies by the
Regional Transmission Planning Committee, subject to review by
the System Operator, one or more Transmission Providers or their
designees shall be designated by the Regional Transmission
Planning Committee, subject to review by the System Operator, to
design and effect the construction or modification. Construction
or modification of Non-PTF facilities shall be the obligation of
the appropriate local Transmission Provider(s) or its
designee(s).
Upon the designation of a Transmission Provider or its designee
to design and effect a PTF addition or upgrade and agreement on
the security and other provisions of the arrangement, the
Transmission Provider or its designee designated to perform the
construction shall, (i) in accordance with the terms of the
arrangements described in this paragraph and subject to Sections
18.4 and 18.5 of the Agreement, use its best efforts to design
and effect the proposed construction or modification and (ii)
enter into an interconnection agreement with the Generator Owner,
which interconnection agreement may be filed with the Commission
by the Transmission Provider unsigned either on its own or at the
request of the Generator Owner. Sections 34.1, 34.2 (other than
those sentences referring to Service Agreements), 34.3 and 35 of
the Tariff shall be applicable to the facilities construction,
except that: (1) references therein to transmission service
shall be deemed to refer to interconnection; and(2)references
therein to Eligible Customer or Transmission Customer shall be
deemed to refer to Generator Owner.
Any facilities required in connection with a new generating unit
or the material change of an existing generating unit which
constitute a Direct Assignment Facility shall be fully paid for
by the Participant or Non-Participant proposing the new
generating unit or material change under an interconnection
agreement with the Transmission Provider.
A Participant or Non-Participant proposing a new or materially
changed generating unit to be interconnected shall be responsible
for the cost of whatever upgrades that are identified as a result
of the study or studies performed at the request of such
Participant or Non-Participant pursuant to the procedures set
forth in this Section, including any new PTF or Non-PTF
facilities or facility modification or other PTF or Non-PTF
upgrade; provided, however, that with respect to any new PTF
facilities or facility modification or other PTF upgrades that
are required in order to interconnect, Schedule 11 of this Tariff
shall apply, subject to such changes in the Schedule or otherwise
as may be determined in connection with the development of the
New CMS (as defined below) or as the Commission may otherwise
require and subject further to any refund or surcharge
requirements that may result from retroactive implementation of
changes in Schedule 11 or otherwise as set forth in the New CMS
or a Commission order.
For purposes of determining whether a generating unit is placed
in service after the Compliance Effective Date for purposes of
Section 42.6 of this Tariff or is obligated to satisfy the
requirements of this Section, on January 1, 1999 and thereafter,
any unit in active or deactivated status, as classified in the
April 1998 NEPOOL Capacity, Energy, Loads and Transmission Report
and any other generating unit in active status on that date may
receive deactivated status, subject to criteria developed by the
appropriate NEPOOL committee. If so designated, the deactivated
unit may retain this status for a period not to exceed three (3)
years from the date the unit receives deactivated status and
shall not be obligated to comply with this Section if it is
reactivated during such period, but if not reactivated during
such period shall be deemed retired at the end of such period for
purposes of this Section. Notwithstanding the foregoing, if a
proposal is submitted and approved under Section 18.4 of the
Agreement during the three-year period to 1) reactivate, 2)
materially modify and reactivate or 3) replace the deactivated
unit, the unit may be reactivated without material modification
without compliance with this Section. The cost of any PTF
upgrade required by 2) or 3) above shall be paid for or shared in
accordance with the preceding provisions of this Section.
Notwithstanding the foregoing, any unit in deactivated status
prior to January 1, 1999 shall be entitled to retain such status
through December 31, 2001 whether or not a submission is made
under Section 18.4 during such period.
Unless amended, the Interconnection Requirements set forth in
this Section shall remain in effect at least until such time as
the substitute Congestion Management System contemplated by
Section 24 of this Tariff and by subsection (b) of Section 14.4
of the Agreement ("New CMS") has become effective. It is
recognized that, in view of the pending development of the New
CMS, there can be no assurance or implication as to the nature of
the rights beyond physical interconnection, if any, or cost
obligations that any existing or future Generator Owner may have
as a result of compliance with the Minimum Interconnection
Standard or the results of any additional studies as set forth in
this Section, and that the rights beyond physical
interconnection, if any, and obligations of all existing and
future Generator Owners are subject to future determination and
to the further orders of the Commission, including a
determination of the extent to which particular Generator Owners
are able to participate in Interchange Transactions and other
transactions in the seven products which are defined in the
Restated NEPOOL Agreement.
2.9 AMENDMENT OF SECTION 50. Section 50 of the Tariff is amended to
read as follows:
50 Rights of Generator Owners
(a) Subsection (b) of this Section shall be of no force or
effect until such time the New CMS (as defined in
Section 49) has become effective. The Participants
shall delete or modify subsection (b) of this Section
as appropriate in connection with the development of
the CMS.
(b) Upon compliance with the applicable requirements of the
Tariff, (i) any generating unit located in the NEPOOL
Control Area which is in service on the Compliance
Effective Date (including a unit that has lost its
capacity value when its capacity value is restored or a
deactivated unit which may be reactivated without
satisfying the requirements of Section 49 of this
Tariff in accordance with the provisions thereof); (ii)
any generating unit located in the NEPOOL Control Area
which is placed in service after the Compliance
Effective Date after complying with Section 49 and
Schedule 11 of the Tariff; and (iii) any resource
outside the NEPOOL Control Area that is the subject of
a Firm Transmission Service transaction shall with
respect to NEPOOL internal services have rights equal
to all other firmly integrated resources, and shall not
at any later time (other than in connection with
service over the Ties not specifically referred to in
the Section 18.4 approval) be required to pay for any
additional Network or other upgrades or costs required
in order to further reinforce the transmission system;
provided that any generating unit placed in service
after the Compliance Effective Date, the output of
which is limited in accordance with Section 18.4 of the
Agreement to below its full capacity shall have such
rights only up to the permitted output level(s);
provided further that there will be no adverse
distinctions in the planning process or with respect to
transmission facility construction between Firm
Transmission Service Customers, any generators referred
to in (i) or (ii) above, and any resources referred to
in (iii) above. It is further provided that, in
accordance with Section 18.4 of the Agreement, no
generator referred to in (i) or (ii) above shall have
its established operating limits reduced, except for
emergency situations, as a result of any new request
for NEPOOL interconnection or subsequent Section 18.4
approvals. Notwithstanding the foregoing, nothing set
forth in this Part VII shall be deemed to relieve any
Transmission Customer from its obligations to pay any
charges or costs otherwise payable by it under Parts I
through VI of this Tariff and the relevant schedules
related thereto.
SECTION 3
MISCELLANEOUS
3.1 Following execution by the requisite number of Participants in
accordance with the Restated NEPOOL Agreement, this Thirty-Ninth
Agreement shall become effective December 15, 1998, or on such
other date or dates as the Commission shall provide that the
amendments provided for in this Agreement shall become effective;
provided that such amendments shall not become effective if
Participants having the requisite number of Voting Shares give
notice in accordance with Section 21.11 of the Restated NEPOOL
Agreement that they object to the amendments.
3.2 Terms used in this Thirty-Ninth Agreement that are not defined
herein shall have the meanings ascribed to them in the Tariff.
3.3 This Thirty-Ninth Agreement may be executed in any number of
counterparts and each executed counterpart shall have the same
force and effect as an original instrument and as if all the
parties to all the counterparts had signed the same instrument.
Any signature page of this Thirty-Ninth Agreement may be detached
from any counterpart of this Thirty-Ninth Agreement without
impairing the legal effect of any signatures thereof, and may be
attached to another counterpart of this Thirty-Ninth Agreement
identical in form thereto but having attached to it one or more
signature pages.
IN WITNESS WHEREOF, each of the signatories has caused a
counterpart signature page for this Thirty-Ninth Agreement to be
executed by its duly authorized representative as of November 13,
1998.
<PAGE>
COUNTERPART SIGNATURE PAGE
TO THIRTY-NINTH AGREEMENT
AMENDING NEW ENGLAND POWER
POOL AGREEMENT
IN WITNESS WHEREOF, the undersigned has caused this counterpart
signature page to the Thirty-Ninth Agreement Amending New England
Power Pool Agreement, dated as of November 13, 1998, to be executed by
its duly authorized representative as of November 13, 1998.
_____________________________________
(Participant)
By:__________________________________
Name:
Title:
<PAGE>
COUNTERPART SIGNATURE PAGE
TO THIRTY-NINTH AGREEMENT
AMENDING NEW ENGLAND POWER
POOL AGREEMENT
IN WITNESS WHEREOF, the undersigned has caused this counterpart
signature page to the Thirty-Ninth Agreement Amending New England
Power Pool Agreement, dated as of November 13, 1998, to be executed by
its duly authorized representative as of November 13, 1998.
Boston Edison Company________________
(Participant)
By: /s/ Douglas S. Horan_____________
Name: Douglas S. Horan
Title: Senior Vice President
Central Maine Power Company__________
(Participant)
By: /s/ Arthur Adelberg______________
Name: Arthur Adelberg
Title: Exec. V.P.
COMMONWEALTH ENERGY SYSTEM COMPANIES_
Cambridge Electric Light Company
Canal Electric Company
Commonwealth Electric Company________
(Participants)
By: /s/ James J. Keane_______________
Name: JAMES J. KEANE
Title: VICE PRESIDENT-ENERGY SUPPLY AND
ENGINEERING SERVICES
EASTERN UTILITIES ASSOCIATES COMPANIES
Blackstone Valley Electric Company
Eastern Edison Company
Montaup Electric Company
Newport Electric Company_____________
(Participants)
By: /s/ Kevin A. Kirby_______________
Name: Kevin A. Kirby
Title: Vice President
Granite State Electric Company_______
(Participant)
By: /s/ Richard P. Sergel____________
Name:
Title:
Massachusetts Electric Company_______
(Participant)
By: /s/ Richard P. Sergel____________
Name:
Title:
The Narragansett Electric Company____
(Participant)
By: /s/ Richard P. Sergel____________
Name:
Title:
New England Power Company____________
(Participant)
By: /s/ Masheed H. Rosenqvist________
Name: Masheed H. Rosenqvist
Title: Vice President
NORTHEAST UTILITIES SYSTEM COMPANIES_
The Connecticut Light and Power Company
Holyoke Power and Electric Company
Holyoke Water Power Company
Public Service Company of New Hampshire
Western Massachusetts Electric Company
(Participants)
By: /s/ Frank P. Sabatino____________
Name: Frank P. Sabatino
Title: Vice President-Wholesale Marketing
PG&E Corporation PARTICIPANT COMPANIES
PG&E Trading-Power, L.P.
USGen New England, Inc.______________
(Participants)
By: /s/ Sarah M. Barpoulis___________
Name: Sarah M. Barpoulis
Title: Sr. Vice President
Vermont Electric Power Company, Inc._
(Participant)
By: /s/ R.M. Chapman_________________
Name:
Title:
Exhibit 10.23.6
FORTIETH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
THIS FORTIETH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT,
dated as of December 15, 1998 ("Fortieth Agreement"), is entered into by
the signatory Participants to amend the New England Power Pool Agreement
(the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was
amended and restated by the Thirty-Third Agreement Amending New England
Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third
Agreement") in the form of the Restated New England Power Pool Agreement
("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as
Exhibit A thereto, and the Thirty-Third Agreement also provided for the
NEPOOL Open Access Transmission Tariff ("Tariff") which is Attachment B to
the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the Tariff have
subsequently been amended by five supplements dated, respectively, as of
February 7, June 1, September 1, November 1 and December 31, 1997 and by
six additional amendatory agreements dated, respectively, as of September
1, 1997, November 15, 1997, July 20, 1998, August 15, 1998, October 30,
1998, and November 13, 1998.
WHEREAS, the signatories hereto desire to amend the Restated NEPOOL
Agreement, including the Tariff, as heretofore amended, to reflect the
revisions detailed below.
NOW, THEREFORE, the signatory Participants agree as follows:
SECTION 1
AMENDMENT TO RESTATED NEPOOL AGREEMENT
1.1 AMENDMENT OF SECTION 6.3. The proviso which follows the
definition of Y{1}, and the last sentence of the first paragraph
of Section 6.3 of the Restated NEPOOL Agreement are amended to
read as follows:
6.3 . . . PROVIDED, HOWEVER, that a Participant and its Related
Persons may not have aggregate Voting Shares exceeding 18%
of the aggregate Voting Shares to which all Participants are
entitled. If the aggregate Voting Shares of a Participant
and its Related Persons would be in excess of 18% if it were
not for this limitation, the remaining Voting Shares to
which such Participant and its Related Persons would
otherwise be entitled shall be allocated on a per capita
basis to those Participants which have a current Voting
Share of less than 18% and which receive a credit in the
computation of their Voting Shares under at least one of the
P, E, C, X, M or R components of the Voting Shares formula
as specified above.
1.2 AMENDMENT OF SECTION 6.4. Section 6.4 of the Restated NEPOOL
Agreement is amended to read as follows:
6.4 NUMBER OF VOTES NECESSARY FOR ACTION. Actions of the
Management Committee shall be effected only upon an
affirmative vote of members having at least 66% of the
aggregate Voting Shares to which all members are entitled;
PROVIDED, HOWEVER, that the negative votes of any six or
more members representing Participants which are not Related
Persons of each other and which have at least 20% of the
aggregate Voting Shares to which all members are entitled
shall defeat any proposed action. In determining whether
the negative vote total specified above has been reached,
the 18% limitation specified in Section 6.3 on the aggregate
Voting Shares of any Participant and its Related Persons
shall be applicable.
1.3 AMENDMENT OF SECTION 6.10. Section 6.10 of the Restated NEPOOL
Agreement is amended to read as follows:
6.10 ADOPTION OF BUDGETS. At each annual meeting, the Management
Committee shall adopt a NEPOOL budget for the ensuing
calendar year. In adopting budgets the Management Committee
shall give due consideration to the budgetary requests of
each committee. The Management Committee may modify any
NEPOOL budget from time to time after its adoption.
1.4 AMENDMENT OF SECTION 7.2. The introductory portion of the first
paragraph of Section 7.2 of the Restated NEPOOL Agreement is
amended to read as follows:
7.2 MEMBERSHIP. The Executive Committee shall be constituted as
follows: the ISO shall have the right to appoint a non-
voting member of the Committee; each Participant whose
Voting Share equals or exceeds 1% of the aggregate Voting
Shares of all Participants shall have the right to appoint a
voting member of the Committee; the remaining Participants
whose Voting Shares are less than 1% of the aggregate Voting
Shares of all Participants shall be divided into the
following five groups, with each having the right to appoint
one voting member of the Committee:
1.5 AMENDMENT OF SECTION 8.2. The introductory portion of the first
paragraph of Section 8.2 of the Restated NEPOOL Agreement is
amended to read as follows:
8.2 MEMBERSHIP. The Market Reliability Planning Committee shall
be constituted as follows: the ISO shall have the right to
appoint a non-voting member of the Committee; each
Participant whose Voting Share equals or exceeds 1% of the
aggregate Voting Shares of all Participants shall have the
right to appoint a voting member of the Committee; the
remaining Participants whose Voting Shares are less than 1%
of the aggregate Voting Shares of all Participants shall be
divided into the following five groups, with each having the
right to appoint one voting member of the Committee:
1.6 AMENDMENT OF SECTION 9.2. Section 9.2 of the Restated NEPOOL
Agreement is amended to read as follows:
9.2 MEMBERSHIP. The Regional Transmission Planning Committee
shall be constituted as follows:
(a) the ISO shall have the right to appoint a non-voting
member of the Committee;
(b) Transmission Service Provider Members: each Participant
which provides transmission service through NEPOOL
under the Tariff as a Transmission Provider (a "Service
Provider") and whose Voting Share equals or exceeds 1%
of the aggregate Voting Shares of all Participants
shall have the right to appoint a voting member of the
Committee (a "Transmission Service Provider Member")
and the remaining Service Providers aggregated together
shall have the right to appoint one voting Transmission
Service Provider Member.
(c) Non-Transmission Service Provider Members: each
Participant which is not a Service Provider and whose
Voting Shares equals or exceeds 1% of the aggregate
Voting Shares of all Participants shall have the right
to appoint a voting member of the Committee (a "Non-
Transmission Service Provider Member") and the
remaining Participants which are not Service Providers
whose Voting Shares are less than 1% of the aggregate
Voting Shares of all Participants shall be divided into
the following four groups, with each having the right
to appoint one voting Non-Transmission Service Provider
Member of the Committee:
(i) One group consisting of the remaining Participants
which are municipally-owned and cooperatively-
owned utilities;
(ii) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in the business of owning
or operating generation facilities and selling the
output of such generation;
(iii)One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in a business other than
the business of owning or operating generation or
PTF facilities and selling the output of such
generation; and
(iv) One group consisting of the remaining Participants
which are investor-owned utilities subject to
traditional utility rate regulation or other
Entities which do not qualify to be included in
any of the other three groups.
Notwithstanding the foregoing, any such Participant may
elect to join a different group under (c) than the one to
which it would be assigned under the foregoing provisions if
this is acceptable to the members of the group it elects to
join. In the event any Participant is a Related Person of
another Participant which has the individual right to
appoint a member of the Committee on the basis of its
individual Voting Share the Participant shall be represented
in the Committee by the member appointed by the Participant
which is its Related Person and shall not be assigned to any
of the four groups.
1.7 Amendment of Section 9.4. Section 9.4 of the Restated NEPOOL
Agreement is amended to read as follows:
9.4 VOTING. Each Transmission Service Provider Member (as
defined in Section 9.2) of the Regional Transmission
Planning Committee shall have the number of votes determined
by the following formula:
X = 50 in which:
--
Y
X is the number of votes to which the member is
entitled, and
Y is the number of Transmission Service Provider
Members at the time.
Each Non-Transmission Service Provider Member (as defined in
Section 9.2) shall have the number of votes determined by
the following formula:
A = 50 in which:
--
B
A is the number of votes to which the member is
entitled, and
B is the number of Non-Transmission Service Provider
Members at the time.
A member's vote may be cast in person by the member or the
member's alternate or by another person pursuant to a
written proxy dated not more than one year previous to the
meeting and delivered to the Secretary of the Regional
Transmission Planning Committee at or prior to the meeting
at which the proxy vote is cast.
The voting member appointed by a group may divide the
member's votes on the basis specified in a notice given to
the Secretary of the Committee at or prior to the meeting at
which the vote is to be cast, to reflect the different
positions of the members of the group.
The adoption of actions by the Regional Transmission
Planning Committee shall require affirmative votes by voting
members having in the aggregate at least 60% of the number
of votes which the members in attendance at a meeting at
which a quorum is present are entitled to cast. Voting
members having a majority of the votes to which all members
are entitled at any time shall constitute a quorum.
When the number of votes on any action is greater than or
equal to 50% but less than 60% of the total votes, then the
non-voting member of the Committee that is appointed by the
ISO shall have the right to cast a vote and a positive vote
by the ISO shall cause an action to pass.
1.8 AMENDMENT OF SECTION 10.2. The introductory portion of the first
paragraph of Section 10.2 of the Restated NEPOOL Agreement is
amended to read as follows:
10.2 MEMBERSHIP. The Regional Market Operations Committee shall
be constituted as follows: the ISO shall have the right to
appoint a non-voting member of the Committee; each
Participant whose Voting Share equals or exceeds 1% of the
aggregate Voting Shares of all Participants shall have the
right to appoint a voting member of the Committee; the
remaining Participants whose Voting Shares are less than 1%
of the aggregate Voting Shares of all Participants shall be
divided into the following five groups, with each having the
right to appoint one voting member of the Regional Market
Operations Committee:
1.9 AMENDMENT OF SECTION 11.2. Section 11.2 of the Restated NEPOOL
Agreement is amended to read as follows:
11.2 MEMBERSHIP. The Regional Transmission Operations Committee
shall be constituted as follows:
(a) the ISO shall have the right to appoint a non-voting
member of the Committee;
(b) Transmission Service Provider Members: each Participant
which is a Service Provider (as defined in Section 9.2)
and whose Voting Share equals or exceeds 1% of the
aggregate Voting Shares of all Participants shall have
the right to appoint a voting member of the Committee
(a "Transmission Service Provider Member") and the
remaining Service Providers aggregated together shall
have the right to appoint one voting Transmission
Service Provider Member.
(c) Non-Transmission Service Provider Members: each
Participant which is not a Service Provider and whose
Voting Shares equals or exceeds 1% of the aggregate
Voting Shares of all Participants shall have the right
to appoint a voting member of the Committee (a "Non-
Transmission Service Provider Member") and the
remaining Participants which are not Service Providers
which own PTF whose Voting Shares are less than 1% of
the aggregate Voting Shares of all Participants shall
be divided into the following four groups, with each
having the right to appoint one voting Non-Transmission
Service Provider Member of the Committee:
(i) One group consisting of the remaining Participants
which are municipally-owned and cooperatively-
owned utilities;
(ii) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in the business of owning
or operating generation facilities and selling the
output of such generation;
(iii)One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in a business other than
the business of owning or operating generation or
PTF facilities and selling the output of such
generation; and
(iv) One group consisting of the remaining Participants
which are investor-owned utilities subject to
traditional utility rate regulation or other
Entities which do not qualify to be included in
any of the other three groups.
Notwithstanding the foregoing, any such Participant may
elect to join a different group under (c) than the one to
which it would be assigned under the foregoing provisions if
this is acceptable to the members of the group it elects to
join. In the event any Participant is a Related Person of
another Participant which has the individual right to
appoint a member of the Committee on the basis of its
individual Voting Share the Participant shall be represented
in the Committee by the member appointed by the Participant
which is its Related Person and shall not be assigned to any
of the four groups.
1.10 AMENDMENT OF SECTION 11.4. Section 11.4 of the Restated NEPOOL
Agreement is amended to read as follows:
11.4 VOTING. Each Transmission Service Provider Member (as
defined in Section 11.2) of the Regional Transmission
Operations Committee shall have the number of votes
determined by the following formula:
X = 50 in which:
--
Y
X is the number of votes to which the member is
entitled, and
Y is the number of Transmission Service Provider
Members at the time.
Each Non-Transmission Service Provider Member (as defined in
Section 11.2) shall have the number of votes determined by
the following formula:
A = 50 in which:
--
B
A is the number of votes to which the member is
entitled, and
B is the number of Non-Transmission Service Provider
Members at the time.
A member's vote may be cast in person by the member or the
member's alternate or by another person pursuant to a
written proxy dated not more than one year previous to the
meeting and delivered to the Secretary of the Regional
Transmission Operations Committee at or prior to the meeting
at which the proxy vote is cast.
The voting member appointed by a group may divide the
member's votes on the basis specified in a notice given to
the Secretary of the Committee at or prior to the meeting at
which the vote is to be cast, to reflect the different
positions of the members of the group.
The adoption of actions by the Regional Transmission
Operations Committee shall require affirmative votes by
voting members having in the aggregate at least 60% of the
number of votes which the members in attendance at a meeting
at which a quorum is present are entitled to cast. Voting
members having a majority of the votes to which all members
are entitled at any time shall constitute a quorum.
When the number of votes on any action is greater than or
equal to 50% but less than 60% of the total votes, then the
non-voting member of the Committee that is appointed by the
ISO shall have the right to cast a vote and a positive vote
by the ISO shall cause an action to pass.
1.11 AMENDMENT OF SECTION 16.7. Section 16.7 of the Restated NEPOOL
Agreement is amended to read as follows:
16.7 CHANGES TO TARIFF. The Tariff constitutes part of the
Agreement and shall be subject to change either in
accordance with Section 21.11 or by an affirmative vote of
members of the Management Committee having at least 70% of
the aggregate Voting Shares to which all members are
entitled; PROVIDED, HOWEVER, that the negative votes of any
six or more members representing Participants which are not
Related Persons of each other and which have at least 20% of
the aggregate Voting Shares to which all members are
entitled shall defeat any proposed change. In determining
whether the negative vote total specified above has been
reached, the 18% limitation specified in Section 6.3 on the
aggregate Voting Shares of any Participant and its Related
Persons shall be applicable. Nothing in this Agreement
shall be deemed to affect in any way the ability of any
Participant or Non-Participant to apply to the Commission
under Section 205 or 206 of the Federal Power Act for a
change in any rate, charge, term, condition or
classification of service under the Tariff.
1.12 AMENDMENT OF SECTION 19.2. Paragraph 1 of Section 19.2 of the
Restated NEPOOL Agreement is amended to read as follows:
19.2 NEPOOL EXPENSES. Commencing on January 1, 1999, or such
other date as the Commission may determine, most expenses of
the System Operator are to be recovered by it directly from
Participants and Non-Participants under the ISO's Tariff for
Transmission Dispatch and Power Administration (the "ISO
Tariff") and shall cease to be NEPOOL expenses. At such
time, whether or not the Second Effective Date has occurred,
the payment of a portion of NEPEX expenses from the Savings
Fund in accordance with the Prior NEPOOL Agreement shall
terminate.
Further, commencing as of such time, the balance of NEPOOL
expenses remaining to be paid after the application of (i)
the annual fee to be paid pursuant to Section 19.1, and (ii)
any fees or other charges for services or other revenues
received by NEPOOL, or collected on its behalf by the System
Operator, shall, except as otherwise provided in Sections
19.3 and 19.4, be allocated among and paid monthly by the
Participants in accordance with their respective Voting
Shares.
1.13 NEW SECTION 19.3. Section 19 of the Restated NEPOOL Agreement is
amended by adding a new Section 19.3 as follows:
19.3 REALLOCATION OF CERTAIN ISO CHARGES. Schedule 3 of the ISO
Tariff (as defined in Section 19.2) provides for the
allocation of a portion of the ISO's expenses (the "Schedule
3 Expenses") to Participants in accordance with their Voting
Shares, as determined under the formula in Section 6.3, as
in effect prior to December 31, 1998. However, effective
commencing with the month for which the revised Voting
Shares formula provided for in Section 1.1 of the Fortieth
Agreement first becomes effective, the Schedule 3 Expenses
for the remaining months of 1999 shall be reallocated in the
monthly billings to Participants which combine charges for
ISO and NEPOOL expenses as follows. Schedule 3 Expenses
shall be allocated among Participants based on the Voting
Share formula in Section 6.3 of this Agreement as in effect
prior to December 31, 1998, but with a maximum allocation of
22% of Schedule 3 Expenses to any one Participant and its
Related Persons. If the aggregate Schedule 3 Expenses of a
Participant and its Related Persons would be in excess of
22% if it were not for this limitation, the remaining
Schedule 3 Expenses for which such Participant and its
Related Persons would otherwise be liable shall be allocated
each month on a per capita basis to those Participants which
receive a credit in the computation of their Voting Shares
for the month under at least one of the P, E, C, X, M or R
components of the Voting Share formula specified in Section
6.3. It is expected that commencing in 2000 all of the
Schedule 3 Expenses may be recovered by the ISO under the
ISO Tariff on a transaction basis.
1.14 NEW SECTION 19.4. Section 19 of the Restated NEPOOL Agreement is
amended by adding a new Section 19.4 as follows:
19.4 RESTRUCTURING COSTS. The expense of restructuring NEPOOL
("Restructuring Expense"), including but not limited to (i)
software development, hardware and system software costs for
implementation of the Tariff and the new market system, (ii)
the costs of the formation of the Independent System
Operator and related separation costs, and (iii) legal and
consultant costs related to the amendment of the NEPOOL
Agreement (including the Tariff) and the proceeding with
respect thereto at the Federal Energy Regulatory Commission,
has been funded during the restructuring period by those
Entities which have been the Participants during such
period. Commencing as the Second Effective Date, the
Restructuring Expense shall be amortized in equal monthly
amounts and repaid over the next 60 months with interest
thereon at the rate of 8% per annum from the date of
payment. Each month during the first twelve months of such
period each Participant shall pay its percentage "X", as
determined below, of 1/60th of the Restructuring Expense,
plus accumulated interest, and each Participant or other
Entity which previously paid an unreimbursed portion of the
aggregate Restructuring Expense shall be entitled to receive
each month its percentage "Y", as determined below, of the
aggregate amount to be paid for the month, including
accumulated interest. "X" and "Y" shall be determined in
accordance with the following formulas:
X = A
--- in which
A{1}
X is the percentage to be paid pursuant to this Section
for a month by a Participant of the aggregate amount
payable by all Participants for the month.
A is the amount payable by the Participant for the month
under Schedule 2 of the ISO Tariff (as defined in
Section 19.2).
A{1} is the aggregate amount payable by all Participants
for the month under Schedule 2 of the ISO Tariff.
B
---
B{1}
Y = in which
Y is the percentage to be received for a month by a
Participant or other Entity of the aggregate amount to
be received pursuant to this Section by all
Participants or other Entities for the month.
B is the amount of Restructuring Expense paid by the
Participant or other Entity with respect to the
restructuring period which has not previously been
reimbursed.
B{1} is the aggregate amount of Restructuring Expense paid
by all Participants and other Entities with respect to
the restructuring period which has not previously been
reimbursed.
The Participants agree to amend the Agreement within twelve
months after the Second Effective Date to specify how the
balance of the Restructuring Expense is to be paid.
1.15 AMENDMENT OF SECTION 20(B). Section 20(b) of the Restated NEPOOL
Agreement is amended to read as follows:
20(b)The fees and charges of the ISO (other than those recovered
under the ISO Tariff, as defined in Section 19.2, and fees
and charges for services which are separately billed), and
any indemnification payable under the ISO Agreement, shall
be shared by the Participants in accordance with Section 19.
1.16 AMENDMENT OF SECTION 21.11. The first Paragraph of Section 21.11
of the Restated NEPOOL Agreement is amended to read as follows:
21.11AMENDMENT. This Agreement, including the Tariff, and any
attachment or exhibit hereto may be amended from time to
time by an instrument signed by Participants having
aggregate Voting Shares equal to at least 70% of the Voting
Shares of all Participants; provided that an amendment shall
not become effective if six or more Participants which are
not Related Persons of each other and which have aggregate
Voting Shares at least equal to 20% of the Voting Shares of
all Participants give notice to the Secretary of the
Management Committee that they object to the amendment
within thirty days after the giving of notice to them of the
prospective effectiveness of the amendment. In determining
whether the 20% requirement has been met, the 18% limitation
specified in Section 6.3 on the aggregate Voting Shares of
any Participant and its Related Persons shall be applicable.
SECTION 2
AMENDMENT TO RESTATED NEPOOL TARIFF
2.1 AMENDMENT OF SCHEDULE 1. Schedule 1 of the Restated NEPOOL
Tariff is amended to read as shown in Attachment A to this
Fortieth Agreement.
SECTION 3
MISCELLANEOUS
3.1 Following execution by the requisite number of Participants in
accordance with the Restated NEPOOL Agreement, this Fortieth
Agreement shall become effective January 1, 1999, or on such
other date or dates as the Commission shall provide that the
amendments provided for in this Agreement shall become effective,
or as may be required in order to effect compliance with the
requirements of Section 21.11 of the Restated NEPOOL Agreement;
provided that the amendment provided by Section 1.14 shall become
effective as of the Second Effective Date or such other date or
dates as the Commission shall provide; and provided further that
the Amendment provided by Section 2.1 shall become effective as
of the date that the ISO Tariff (as defined in Section 1.12 of
this Fortieth Agreement) becomes effective or such other date or
dates as the Commission shall provide; and provided further that
such amendments shall not become effective if Participants having
the requisite number of Voting Shares give notice in accordance
with Section 21.11 of the Restated NEPOOL Agreement that they
object to the amendments.
3.2 Terms used in this Fortieth Agreement that are not defined herein
shall have the meanings ascribed to them in the Restated NEPOOL
Agreement.
3.3 This Fortieth Agreement may be executed in any number of
counterparts and each executed counterpart shall have the same
force and effect as an original instrument and as if all the
parties to all the counterparts had signed the same instrument.
Any signature page of this Fortieth Agreement may be detached
from any counterpart of this Fortieth Agreement without impairing
the legal effect of any signatures thereof, and may be attached
to another counterpart of this Fortieth Agreement identical in
form thereto but having attached to it one or more signature
pages.
IN WITNESS WHEREOF, each of the signatories has caused a counterpart
signature page for this Fortieth Agreement to be executed by its duly
authorized representative as of December 15, 1998.
<PAGE>
COUNTERPART SIGNATURE PAGE
TO FORTIETH AGREEMENT
AMENDING NEW ENGLAND POWER
POOL AGREEMENT
IN WITNESS WHEREOF, the undersigned has caused this counterpart
signature page to the Fortieth Agreement Amending New England Power Pool
Agreement, dated as of December 15, 1998, to be executed by its duly
authorized representative as of December 15, 1998.
Boston Edison
-----------------------------------------
(Participant)
/s/ By:__________________________________
Name: Douglas S. Horan
Title: Senior Vice President and
General Counsel
Granite State Electric Company
-----------------------------------------
(Participant)
/s/ By:__________________________________
Name: Christopher E. Root
Title: Sr. V.P. of Operations
Massachusetts Electric Company
-----------------------------------------
(Participant)
/s/ By:__________________________________
Name: Christopher E. Root
Title: Sr. V.P. of Operations
The Narragansett Electric Company
-----------------------------------------
(Participant)
/s/ By:__________________________________
Name: Christopher E. Root
Title: Sr. V.P. of Operations
Unitil Resources, Inc.
-----------------------------------------
(Participant)
/s/ By:__________________________________
Name: James G. Daly
Title: President
VERMONT ELECTRIC POWER COMPANY, INC.
-----------------------------------------
(Participant)
/s/ By:__________________________________
Name: RICHARD M. CHAPMAN
Title: PRESIDENT AND CEO
Fitchburg Gas and Electric Light Company
-----------------------------------------
(Participant)
/s/ By:__________________________________
Name: David K. Foote
Title: Senior Vice President
New England Power Company
-----------------------------------------
(Participant)
/s/ By:__________________________________
Name: Masheed H. Rosenquist
Title: Vice President
Central Maine Power Company
-----------------------------------------
(Participant)
/s/ By:__________________________________
Name: Frederick Woodruff
Title: Vice President-Maine Power
Acting as Agent for Central
Maine Power Co.
COMMONWEALTH ENERGY SYSTEM COMPANIES
--------------------------------------------
Cambridge Electric Light Company
Canal Electric Company
Commonwealth Electric Company
-------------------------------------------
(Participants)
/s/ By:_____________________________________
Name: James J. Keane
Title: Vice President - Energy Supply
& Engineering Services
EASTERN UTILITIES ASSOCIATES COMPANIES
--------------------------------------------
Blackstone Valley Electric Company
Eastern Edison Company
Montaup Electric Company
Newport Electric Company
-------------------------------------------
(Participants)
/s/ By:_____________________________________
Name: Kevin A. Kirby
Title: Vice President
NORTHEAST UTILITIES SYSTEM COMPANIES
--------------------------------------------
The Connecticut Light and Power Company
Holyoke Power and Electric Company
Holyoke Water Power Company
Public Service Company of New Hampshire
Western Massachusetts Electric Company
-------------------------------------------
(Participants)
/s/ By:_____________________________________
Name:
Title:
Sithe New England Holdings LLC
--------------------------------------------
(Participant)
/s/ By:_____________________________________
Name: Timothy R. Bush
Title: Vice President
SOUTHERN COMPANY ENERGY MARKETING L.P.
--------------------------------------------
(Participant)
/s/ By:_____________________________________
Name: John W. Ragan
Title: Vice President - Asset
Management
The United Illuminating Company
--------------------------------------------
(Participant)
/s/ By:_____________________________________
Name: Stephen Goldschmidt
Title: Vice President
UNITIL CORPORATION PARTICIPANT COMPANIES
--------------------------------------------
Concord Electric Company
Exeter & Hampton Electric Company
Until Power Corporation
--------------------------------------------
(Participants)
/s/ By:_____________________________________
Name: David K. Foote
Title: Senior Vice President
Unitil Power Corp.
<PAGE>
ATTACHMENT A
NEPOOL Restated Open Access Transmission Tariff
Original Sheet No. _____
SCHEDULE 1
Scheduling, System Control and Dispatch Service
Scheduling, System Control and Dispatch Service is the service
required to schedule at the pool level the movement of power through, out
of, within, or into the NEPOOL Control Area. Local level service is
provided under the Local Network Service tariffs of the Participants which
are the individual Transmission Providers. For transmission service under
this Tariff, this Ancillary Service can be provided only by the System
Operator and the Transmission Customer must purchase this service from the
System Operator. Charges for Scheduling, System Control and Dispatch
Service are to be based on the expenses incurred by the System Operator,
and by the individual Transmission Providers in the operation of satellite
dispatch centers or otherwise, to provide these services. Effective as of
January 1, 1999, or such other date as the Commission may determine, the
expenses incurred by the System Operator in providing these services are to
be recovered under its Tariff for Transmission Dispatch and Power
Administration Services, which has been filed in Docket No. ER98-3554-000.
A surcharge for the expenses incurred by Participants in the provision of
these services will be added to the Internal Point-to-Point Service rate,
to the Through or Out Service rate and to the Regional Network Service
rate.
The expenses incurred in providing Scheduling, System Control and
Dispatch Service for each Participant will be determined by an annual
calculation based on the previous calendar year's data as shown, in the
case of Transmission Providers which are subject to the Commission's
jurisdiction, in the Participants' FERC Form 1 report for that year, and
shall be based on actual data in lieu of allocated data if specifically
identified in the Form 1 report.
This amended Schedule 1 shall be effective as of January 1, 1999, or
such other date as the Commission may determine. The surcharge shall be
redetermined annually as of June 1 in each year and shall be in effect for
the succeeding twelve months. The rate surcharge per kilowatt for each
month is one-twelfth of the amount derived by dividing the total annual
Participant expenses for providing the service by the sum of the average of
the coincident Monthly Peaks (as defined in Section 46.1) of all Local
Networks for the prior calendar year.
Each Participant or Non-Participant which is obligated to pay the rate
for Regional Network Service for a month shall pay the surcharge on the
basis of the number of kilowatts of its Monthly Network Load (as defined in
Section 46.1) for the month. Each Participant or Non-Participant which is
obligated to pay the rate for Internal Point-to-Point Service or Through or
Out Service for the applicable period shall pay the surcharge on the basis
of the highest amount of its Reserved Capacity for each transaction
scheduled as Internal Point-to-Point Service and/or Through or Out Service
for such period.
The revenues received under this Schedule 1 to cover the expenses
incurred by Participants for providing Scheduling, System Control and
Dispatch Service shall be allocated each month among the Participants whose
satellite or other costs are reflected in the computation of the surcharge
for the service in proportion to the costs for each which are reflected in
the computation of the surcharge.
Exhibit 10.23.7
ISO NEW ENGLAND INC.
FERC TARIFF FOR TRANSMISSION DISPATCH AND
POWER ADMINISTRATION SERVICES
<PAGE>
TABLE OF CONTENTS
PAGE
1 Definitions. . . . . . . . . . . . . . . . . . . . . . . . 5
1.1 Automatic Generation Control Market. . . . . . . . . . 5
1.2 Calendar Year. . . . . . . . . . . . . . . . . . . . . 5
1.3 Commission . . . . . . . . . . . . . . . . . . . . . . 5
1.4 Customer . . . . . . . . . . . . . . . . . . . . . . . 5
1.5 Designated Agent . . . . . . . . . . . . . . . . . . . 5
1.6 Effective Date . . . . . . . . . . . . . . . . . . . . 5
1.7 Energy . . . . . . . . . . . . . . . . . . . . . . . . 5
1.8 Energy Administration Service (or "EAS") . . . . . . . 5
1.9 Energy Market. . . . . . . . . . . . . . . . . . . . . 6
1.10 Financial Assurance Policy. . . . . . . . . . . . . . 6
1.11 Force Majeure . . . . . . . . . . . . . . . . . . . . 6
1.12 Installed Capability Market . . . . . . . . . . . . . 6
1.13 Interest. . . . . . . . . . . . . . . . . . . . . . . 6
1.14 ISO . . . . . . . . . . . . . . . . . . . . . . . . . 6
1.15 ISO Agreement . . . . . . . . . . . . . . . . . . . . 7
1.16 Markets . . . . . . . . . . . . . . . . . . . . . . . 7
1.17 Monthly RAS Expenses. . . . . . . . . . . . . . . . . 7
1.18 NEPOOL. . . . . . . . . . . . . . . . . . . . . . . . 7
1.19 NEPOOL Agreement. . . . . . . . . . . . . . . . . . . 7
1.20 NEPOOL Control Area . . . . . . . . . . . . . . . . . 7
1.21 NEPOOL Tariff . . . . . . . . . . . . . . . . . . . . 7
1.22 Network Customer. . . . . . . . . . . . . . . . . . . 7
1.23 Operable Capability Market. . . . . . . . . . . . . . 7
1.24 Operating Reserve Markets . . . . . . . . . . . . . . 8
1.25 Participant Share . . . . . . . . . . . . . . . . . . 8
1.26 Parties . . . . . . . . . . . . . . . . . . . . . . .11
1.27 Policy Statement. . . . . . . . . . . . . . . . . . .11
1.28 RAS Fee . . . . . . . . . . . . . . . . . . . . . . .11
1.29 Reliability Administration Service (or "RAS") . . . .11
1.30 Reliability Markets . . . . . . . . . . . . . . . . .11
1.31 Sanctions Rule. . . . . . . . . . . . . . . . . . . .11
1.32 Scheduling, System Control and Dispatch Service (or
"Scheduling Service") . . . . . . . . . . . . . . . .11
1.33 Service Agreement . . . . . . . . . . . . . . . . . .12
1.34 Services. . . . . . . . . . . . . . . . . . . . . . .12
1.35 System Operator . . . . . . . . . . . . . . . . . . .12
1.36 Transmission Service Agreement. . . . . . . . . . . .12
2 Purpose of This Tariff . . . . . . . . . . . . . . . . . .12
3 Billing and Payment. . . . . . . . . . . . . . . . . . . .14
3.1 Billing Procedure. . . . . . . . . . . . . . . . . . .14
3.2 Interest on Unpaid Balances. . . . . . . . . . . . . .15
3.3 Late Payment Charge. . . . . . . . . . . . . . . . . .15
3.4 Customer Default . . . . . . . . . . . . . . . . . . .15
4 Regulatory Filings . . . . . . . . . . . . . . . . . . . .16
5 Force Majeure and Indemnification. . . . . . . . . . . . .17
5.1 Force Majeure. . . . . . . . . . . . . . . . . . . . .17
5.2 Liability. . . . . . . . . . . . . . . . . . . . . . .17
5.3 Indemnification. . . . . . . . . . . . . . . . . . . .18
6 Creditworthiness . . . . . . . . . . . . . . . . . . . . .19
7 Dispute Resolution Procedures. . . . . . . . . . . . . . .19
7.1 Dispute Resolution Procedures. . . . . . . . . . . . .19
7.2 Mediation. . . . . . . . . . . . . . . . . . . . . . .20
7.3 Selection of Arbitrator. . . . . . . . . . . . . . . .20
7.4 Costs. . . . . . . . . . . . . . . . . . . . . . . . .21
7.5 Hearing Location . . . . . . . . . . . . . . . . . . .21
7.6 Rules and Procedures . . . . . . . . . . . . . . . . .21
8 Direct Billing; Sanctions. . . . . . . . . . . . . . . . .24
8.1 Transmission Studies . . . . . . . . . . . . . . . . .24
8.2 Information Requests . . . . . . . . . . . . . . . . .24
8.3 Sanctions Rule . . . . . . . . . . . . . . . . . . . .24
9 Metering . . . . . . . . . . . . . . . . . . . . . . . . .25
9.1 Customer Obligations . . . . . . . . . . . . . . . . .25
9.2 ISO Access to Metering Data. . . . . . . . . . . . . .25
Schedule 1
Scheduling, System Control and Dispatch Service. . . . . .26
Schedule 2
Energy Administration Service. . . . . . . . . . . . . . .29
Schedule 3
Reliability Administration Service . . . . . . . . . . . .32
ATTACHMENT A
Form of Service Agreement. . . . . . . . . . . . . . . . .35
ATTACHMENT B
Definitions and Provisions Extracted From NEPOOL
Agreement and NEPOOL Tariff. . . . . . . . . . . . . . . .37
ATTACHMENT C
Financial Assurance Policy . . . . . . . . . . . . . . . .49
ATTACHMENT D
RULE 13
Imposition of Sanctions by the ISO . . . . . . . . . . . .58
ATTACHMENT E
Policy Statement . . . . . . . . . . . . . . . . . . . . 101
<PAGE>
1 Definitions
Whenever used in this Tariff, in either the singular or
plural number, capitalized terms shall have the meanings
specified in Sections 1.1 to 1.36 of this Tariff or in Attachment
B hereto. Attachment B consists of definitions and provisions
extracted from the NEPOOL Agreement and/or the NEPOOL Tariff.
1.1 Automatic Generation Control Market: The market for
Automatic Generation Control ("AGC") administered by the ISO
in accordance with the NEPOOL Agreement.
1.2 Calendar Year: A period of 365 or 366 days, whichever is
appropriate, commencing on January 1.
1.3 Commission: The Federal Energy Regulatory Commission.
1.4 Customer: Any Entity taking any of the Services provided
under this Tariff.
1.5 Designated Agent: Any Entity that performs actions or
functions required under this Tariff on behalf of a
Customer.
1.6 Effective Date: January 1, 1999.
1.7 Energy: Power produced in the form of electricity,
measured in kilowatthours or megawatthours.
1.8 Energy Administration Service (or "EAS"): The service
provided by the ISO, as described in Schedule 2 of this
Tariff, in order to facilitate: (1) bilateral Energy
transactions; (2) self-scheduling of Energy; (3) Interchange
Transactions in the Energy Market; and (4) Energy Imbalance
Service under the NEPOOL Tariff.
1.9 Energy Market: The NEPOOL market for Energy administered
by the ISO.
1.10 Financial Assurance Policy: The "Financial Assurance
Policy for NEPOOL Members" adopted by the Participants on
May 1, 1998, provided as Attachment C hereto, as utilized by
the ISO, as modified and amended from time to time.
1.11 Force Majeure: An event of Force Majeure means any act
of God, labor disturbance, act of the public enemy, war,
insurrection, riot, fire, storm or flood, explosion,
breakage or accident to machinery or equipment, any
Curtailment, order, regulation or restriction imposed by a
court or governmental military or lawfully established
civilian authorities, or any other cause beyond a Party's
control. A Force Majeure event does not include an act of
negligence or intentional wrongdoing.
1.12 Installed Capability Market: The NEPOOL market for
Installed Capability administered by the ISO.
1.13 Interest: Interest calculated in the manner specified in
Section 3.2 hereof.
1.14 ISO: ISO New England Inc., the non-profit independent
system operator that, pursuant to the ISO Agreement and the
authorization of the Commission: (i) operates the NEPOOL
Control Area consistent with proper standards of
reliability; (ii) administers the NEPOOL Tariff; and (iii)
administers a power exchange consisting of several markets
and provides support for bilateral and self-scheduled
transactions.
1.15 ISO Agreement: The Interim Independent System Operator
Agreement made and entered into as of July 1, 1997, as
modified from time to time, between the ISO and the
Participants, acting by and through the NEPOOL Management
Committee, or any successor agreement thereto.
1.16 Markets: Collectively, the Energy Market and the
Reliability Markets.
1.17 Monthly RAS Expenses: For a month, the expenses incurred
by the ISO during that month for providing RAS, less RAS
Fees received during that month.
1.18 NEPOOL: The New England Power Pool, the power pool
created under and governed by the NEPOOL Agreement, and the
Entities collectively participating in the New England Power
Pool.
1.19 NEPOOL Agreement: The New England Power Pool Agreement
dated as of September 1, 1971, as amended and restated from
time to time.
1.20 NEPOOL Control Area: The Control Area for NEPOOL.
1.21 NEPOOL Tariff: The Restated NEPOOL Open Access
Transmission Tariff and accompanying schedules and
attachments, as modified and amended from time to time.
1.22 Network Customer: An Entity receiving transmission
service pursuant to the terms of Part II and Part VI of the
NEPOOL Tariff.
1.23 Operable Capability Market: The NEPOOL market for
Operable Capability administered by the ISO.
1.24 Operating Reserve Markets: Collectively, the NEPOOL
markets for Operating Reserve administered by the ISO, and
pending the initiation of the market for 10-Minute Spinning
Reserve, the activities of the ISO supporting the provision
of such reserve.
1.25 Participant Share: Each Participant shall have a
Participant Share in any month which shall be determined in
accordance with the following formula:
P E C X M R Y
S=.15833(--)+.15833(--)+.15833(--)+.15833(--)+.15833(--)+.15833(--)+.05(--)
1 1 1 1 1 1 1
P E C X M R Y
in which
S = the Participant Share as a percentage of the aggregate
Participant Shares of all Participants;
P = the average for each of the most recently completed
twelve months of the Participant's maximum Load during
any clock hour in a month;
P{1} = the average of the sums for each of the most recently
completed twelve months of the noncoincidental maximum Load
during any clock hour in a month of all Participants;
E = the average for the most recently completed twelve
months of the sum for each month of the Participant's
Load for each hour of the month PLUS any kilowatthours
delivered during the month to loads classified as
interruptible under market operation rules approved by
the NEPOOL Regional Market Operations Committee;
E{1} = the average for the most recently completed twelve months
of the sum for each month of the Loads of all Participants
for each hour of the month PLUS any kilowatthours delivered
during the month to loads classified as interruptible under
market operation rules approved by the NEPOOL Regional
Market Operations Committee.
C = the average in megawatts for the most recently
completed twelve months of the sum for each month of
the Generation Ownership Shares of the Participant;
C{1} = the average in megawatts for the most recently completed
twelve months of the sum for each month of the Generation
Ownership Shares of all Participants;
X = the average for the most recently completed twelve
months of the sum for each month of (i) a number of
kilowatthours EQUAL TO the Kilowatts of the
Participant's Generation Ownership Shares, TIMES the
number of hours in the month, PLUS (ii) the number of
kilowatthours that the Participant was entitled to
receive in each hour with respect to its Energy
Entitlements under Unit Contracts or System Contracts
TIMES, in the case of each contract, the number of
hours the contract was in effect in the month, as
computed without giving effect to any resale in whole
or part of any such Energy Entitlement;
X{1} = the average for the most recently completed twelve months
of the sum for each month of (i) a number of kilowatthours
EQUAL TO the Kilowatts of the Generation Ownership Shares of
all Participants, TIMES the number of hours in the month,
PLUS (ii) the number of kilowatthours that all Participants
were entitled to receive in each hour with respect to their
Energy Entitlements under Unit Contracts or System Contracts
TIMES, in the case of each contract, the number of hours the
contract was in effect in the month, as computed without
giving effect to any resale in whole or part of any such
Energy Entitlement;
M = the circuit miles of the Participant's Transmission
Ownership Shares of PTF transmission lines TIMES, in
the case of each line, the nominal operating voltage of
the line;
M{1} = the aggregate of the circuit miles of the Transmission
Ownership Shares of PTF transmission lines of all
Participants TIMES, in the case of each line, the nominal
operating voltage of the line;
R = the Annual Transmission Revenue Requirements of the
Participant's PTF as of the beginning of the current
calendar year as determined in accordance with
Attachment F to the NEPOOL Tariff except that 1) such
Revenue Requirements shall not be reduced by the
transmission support revenue received as described in
Section I of that Attachment and 2) such Revenue
Requirements shall not include transmission support
payments as described in Section J of that Attachment
for support arrangements which were entered into after
December 31, 1996;
R{1} = the aggregate Annual Transmission Revenue Requirements of
the PTF of all Participants as of the beginning of the
current calendar year as determined in accordance with
Attachment F to the NEPOOL Tariff, except that 1) such
Revenue Requirements shall not be reduced by the
transmission support revenue received as described in
Section I of that Attachment and 2) such Revenue
Requirements shall not include transmission support payments
as described in Section J of that Attachment for support
arrangements which were entered into after December 31,
1996;
Y = 1; and
Y{1} = the number of NEPOOL Participants at the beginning of the
month;
PROVIDED, HOWEVER, that a Participant and its Related
Persons may not have aggregate Participant Shares exceeding
25% of the aggregate Participant Shares of all Participants.
If the aggregate Participant Shares of a Participant and
its Related Persons would be in excess of 25% if it were not
for this limitation, the remaining Participant Shares which
would otherwise be allocated to such Participant and its
Related Persons shall be allocated to the other Participants
on a pro rata basis.
For purposes of the preceding formula (i) if an Entity has
been a Participant for less than twelve months, the amounts
to be taken into account for purposes of "P", "E", "C" and
"X" in the formula shall be for the period during which the
Entity has been a Participant; (ii) for purposes of "X" and
"X{1}" in the formula, the number of kilowatthours to be
taken into account with respect to the HQ Phase II Firm
Energy Contract for each Participant which has a share in
the HQ Phase II Firm Energy Contract shall be computed on
the basis of the number of Kilowatts of its HQ
Interconnection Capability Credit, if any, for the month as
calculated pursuant to the NEPOOL Agreement; and (iii) for
purposes of "X" and "X{1}" in the formula, the number of
kilowatthours to be taken into account with respect to an
Energy Entitlement under a Unit Contract or System Contract,
other than the HQ Phase II Firm Energy Contract, under which
a Participant is entitled to receive Energy from outside the
NEPOOL Control Area shall be computed on the basis of the
number of Kilowatts of Installed Capability credit, or
Monthly Peak reduction, for which the Participant is given
credit in determining whether it has satisfied its Installed
Capability Responsibility pursuant to Section 12 of the
NEPOOL Agreement.
1.26 Parties: Collectively, the ISO and the Customers; individually,
a "Party."
1.27 Policy Statement: The "Policy Statement for the
Financial Assurance Requirements and Administration Thereof
for NEPOOL Open Access Tariff," included as Attachment E to
this Tariff, as modified from time to time.
1.28 RAS Fee: The fee payable pursuant to Schedule 3 hereto
by Transmission Customers that are not Participants.
1.29 Reliability Administration Service (or "RAS"): The
service provided by the ISO, as described in Schedule 3 of
this Tariff, in order to administer the Reliability Markets
and provide other reliability-related and informational
functions.
1.30 Reliability Markets: Collectively, the Automatic
Generation Control Market, Installed Capability Market, the
Operable Capability Market, and the Operating Reserve
Markets.
1.31 Sanctions Rule: "Imposition of Sanctions by the ISO," a
rule administered by the ISO, and included as Attachment D
to this Tariff.
1.32 Scheduling, System Control and Dispatch Service (or
"Scheduling Service"): The service described in Schedule 1
of this Tariff.
1.33 Service Agreement: An agreement between the ISO and a
Customer in the form provided in Attachment A hereto.
1.34 Services: Collectively, the Scheduling Service, EAS and
RAS; individually, a "Service."
1.35 System Operator: ISO New England Inc.
1.36 Transmission Service Agreement: The initial agreement
and any amendments or supplements thereto entered into by
the Transmission Customer and the ISO on behalf of the
Participants (or filed in unexecuted form), for service
under the NEPOOL Tariff.
2 Purpose of This Tariff
This Tariff is the means by which the ISO collects the
revenues necessary to carry out its functions. This Tariff
contains rates, charges, terms and conditions for the following
Services, which together encompass the functions carried out by
the ISO: (1) Scheduling, System Control and Dispatch Service
(Schedule 1 hereto); (2) Energy Administration Service (Schedule
2 hereto); and (3) Reliability Administration Service (Schedule 3
hereto).
The rates and charges for each Service during a Calendar
Year are based on the allocated portion of that year's budgeted
total expense (the "Budget Amount"), as adjusted by true-ups
described herein. The portion of the Budget Amount allocated to
a Service consists of: (1) the direct (E.G., personnel, software
and equipment) costs of performing the Service; plus (2) in
general, the percentage of the ISO's general and administrative
costs determined by dividing the direct costs of providing that
Service by the direct costs of providing all Services.
By way of example, the Budget Amount for Calendar Year 1999
for all Services is $38,415,141. If the ISO determines during
Calendar Year 1999 that collections under this Tariff (for all
Services) will exceed 105 percent of the Budget Amount for 1999,
the ISO will file with the Commission an amended or superseding
tariff or rate schedule.
For the Services described in Schedules 1 and 2, deviations
between collections under the Tariff and the ISO's actual
expenses will be reconciled through a year-to-year, prospective
true-up. For example, before the close of Calendar Year 1999,
the ISO will compute the total actual-to-date and projected-to-
year-end expenses of providing each of those Services, and
compare these totals with the total charges actually collected
(and projected to be collected through 1999) under this Tariff
for each Service during Calendar Year 1999. Based on these
comparisons, the ISO will adjust the otherwise-projected revenue
requirement for Calendar Year 2000 (I.E., the Calendar Year 2000
Budget Amount) for either or both Services, as needed, downward
or upward to reflect the expected Calendar Year 1999 surplus or
deficit, respectively, while preserving a reasonable amount of
cash working capital. From these figures the ISO will calculate
rates for Calendar Year 2000, and make a rate change filing for
Calendar Year 2000 and succeeding years, as required, to reflect
the Budget Amount for the applicable Calendar Year and the true-
ups calculated by means of the foregoing analysis and
adjustments. Any deviation between projected and actual true-up
amounts for Calendar Year 1999 will be reflected in the rate
changes for Calendar Year 2001. The ISO will also analyze, as
necessary, the need for any adjustments to allocation methodology
or rate design.
The charges for Schedule 3 consist of actual monthly
expenses for RAS, and thus are not subject to true-up. The
provision noted above limiting total annual collections to 105
percent of the pertinent Budget Amount (for all Services)
effectively limits the amounts collected for RAS under Schedule
3.
The revenues collected through this Tariff are not
recovering funding and reimbursement of NEPOOL restructuring
costs, including the costs relating to the separation of NEPOOL
staff and costs associated with the design, installation and
implementation of the Markets, which are to be recovered by the
NEPOOL Participants through contractual arrangements. Budget
Amounts also do not reflect any amounts received by the ISO due
to indemnification payments.
3 Billing and Payment
3.1 Billing Procedure: By the 15th day of each month, the ISO
shall submit an invoice to each Customer for the charges for
all Services furnished under this Tariff during the
preceding month. The invoice shall be paid by the Customer
by 10:00 a.m. Eastern Time on the first business day after
the 19th day of the calendar month. All payments shall be
made by electronic funds transfer to a bank account
designated by the ISO. The ISO may bill Participants more
frequently than monthly, in accordance with the Financial
Assurance Policy.
3.2 Interest on Unpaid Balances: Interest on any unpaid
amounts (including amounts placed in escrow due to a payment
dispute as described in Section 3.3 below) shall be
calculated and payable to the ISO in accordance with the
methodology specified for interest on refunds in the
Commission's regulations at 18 C.F.R. <section>
35.19a(a)(2)(iii); PROVIDED, HOWEVER, that interest due on
amounts placed in escrow shall be limited to the interest
actually earned on those amounts while in escrow. Interest
on delinquent amounts will be calculated from the due date
of the bill to the date of payment.
3.3 Late Payment Charge: In order to cover ISO expenses
occasioned by Customers' late payments, if a Customer is
delinquent two or more times within any period of twelve
months in paying on time amounts owed to the ISO, the
Customer shall pay, in addition to interest on each late
payment, a late payment charge for its second failure to pay
on time, and for each subsequent failure to pay on time,
within the same twelve-month period, in an amount equal to
the greater of (i) two percent (2%) of the total amount of
such late payment and (ii) $250.00. Late payment charges
collected by the ISO will be credited proportionately to the
revenue requirement for each Service.
3.4 Customer Default: In the event a Customer fails, for any
reason other than a billing dispute as described below, to
make payment to the ISO on or before the due date as
described above, and such failure of payment is not
corrected within thirty (30) calendar days after the ISO
notifies the Customer to cure such failure, a default by the
Customer will be deemed to exist. Upon the occurrence of a
default, the ISO and NEPOOL may jointly initiate a
proceeding with the Commission to terminate the Service and
service under the NEPOOL Agreement and/or NEPOOL Tariff (as
applicable) but shall not terminate the Service until the
Commission approves such termination. In the event of a
billing dispute between the ISO and the Customer, the
Service will continue to be provided under the Service
Agreement as long as the Customer (i) continues to make all
payments not in dispute, and (ii) pays as of the bill due
date into an independent escrow account the portion of the
invoice in dispute, pending resolution of such dispute. If
the Customer fails to meet these two requirements for
continuation of the Service, then the ISO and NEPOOL may
jointly provide notice to the Customer of their intention to
suspend service in sixty (60) days or such longer period as
is provided for in the NEPOOL Agreement, in accordance with
Commission rules and regulations, and may proceed with such
suspension.
4 Regulatory Filings
Nothing contained in this Tariff or any Service Agreement
shall be construed as affecting in any way the right of the ISO
to file with the Commission under Section 205 of the Federal
Power Act and pursuant to the Commission's rules and regulations
promulgated thereunder for a change in any rates, terms and
conditions, charges, classification of service, Service
Agreement, rule or regulation.
Nothing contained in this Tariff or any Service Agreement
shall be construed as affecting in any way the ability of any
Customer receiving a Service under this Tariff to exercise its
rights under the Federal Power Act and pursuant to the
Commission's rules and regulations promulgated thereunder.
5 Force Majeure and Indemnification
5.1 Force Majeure: Neither the ISO nor a Customer will be
considered in default as to any obligation under this Tariff
if prevented from fulfilling the obligation due to an event
of Force Majeure; provided that no event of Force Majeure
affecting any Entity shall excuse that Entity from making
any payment that it is obligated to make hereunder or under
a Service Agreement. However, an Entity whose performance
under this Tariff is hindered by an event of Force Majeure
shall make all reasonable efforts to perform its obligations
under this Tariff, and shall promptly notify the ISO or the
Customer, whichever is appropriate, of the commencement and
end of each event of Force Majeure .
5.2 Liability: The ISO shall not be liable for money damages
or other compensation to the Customer for actions or
omissions by the ISO in performing its obligations under
this Tariff or Service Agreement thereunder, provided it has
not willfully breached this Tariff or a Service Agreement or
engaged in willful misconduct. To the extent the Customer
has claims against the ISO, the Customer may only look to
the assets of the ISO for the enforcement of such claims and
may not seek to enforce any claims against the directors,
members, officers, employees or agents of the ISO who, the
Customer acknowledges and agrees, have no personal liability
for obligations of the ISO by reason of their status as
directors, members, officers, employees or agents of the
ISO. In no event shall either the ISO or any Customer be
liable for any incidental, consequential, multiple or
punitive damages, loss of revenues or profits, attorneys
fees or costs arising out of, or connected in any way with
the performance or non-performance of this Tariff, any
Service Agreement thereunder or the ISO Agreement.
5.3 Indemnification: Each Customer shall at all times
indemnify, defend, and save harmless the ISO and its
directors, officers, members, employees and agents from any
and all damages, losses, claims and liabilities by or to
third parties arising out of or resulting from the
performance by the ISO under this Tariff or Service
Agreement thereunder, any bankruptcy filings made by a
Customer, or the actions or omissions of the Customer in
connection with this Tariff or Service Agreement thereunder,
except in cases of gross negligence or willful misconduct by
the ISO or its directors, officers, members, employees or
agents. The amount of any indemnity payment hereunder shall
be reduced (including, without limitation, retroactively) by
any insurance proceeds or other amounts actually recovered
by the indemnified party in respect of the indemnified
action, claim, demand, cost, damage or liability. The
obligations of each Customer to indemnify the ISO shall be
several, and not joint or joint and several. A Customer's
obligation to contribute to any indemnity payment hereunder
shall be limited to a percentage thereof equal to the
Customer's payments under this Tariff over the twelve (12)
calendar months preceding the date of payment divided by the
total payments of all Customers under this Tariff over the
same period.
6 Creditworthiness
For the purpose of determining the ability of a Customer to
meet its obligations related to a Service hereunder, the ISO will
apply the Financial Assurance Policy (Attachment C hereto) to
Participants and the Policy Statement (Attachment E hereto) to
non-Participant Transmission Customers. The Customer shall
comply with the requirements of the Financial Assurance Policy or
Policy Statement, as applicable.
7 Dispute Resolution Procedures
7.1 Dispute Resolution Procedures: Any dispute between a
Customer and the ISO involving Service provided under this
Tariff (excluding applications for rate changes or other
changes to this Tariff, or to any Service Agreement entered
into under this Tariff, which shall be presented directly to
the Commission for resolution) shall be referred to a
designated senior representative of the Customer and a
senior representative of the ISO for resolution on an
informal basis as promptly as practicable. In the event the
designated representatives are unable to resolve the dispute
within thirty (30) days or such other period as the Parties
may fix by mutual agreement, a Party may invoke arbitration
by notice to the other Party and may also (with the
agreement of the other Party) submit such dispute to
mediation for resolution in accordance with the procedures
set forth below. The arbitration procedure shall not exceed
90 calendar days from the date of the notice by the Party
invoking arbitration (the "Aggrieved Party") to the
arbitrator's decision unless the Parties agree upon a longer
or shorter time. All agreements by the ISO and Customer to
use mediation shall establish a schedule which will control
unless later changed by mutual agreement.
7.2 Mediation: All mediation proceedings are confidential and
shall be treated as compromise and settlement negotiations
for purposes of applicable rules of evidence.
Notwithstanding the initiation of mediation, the arbitration
proceeding shall proceed concurrently with the selection of
the arbitrator pursuant to Section 7.3 hereof.
7.3 Selection of Arbitrator: The Parties shall attempt to
choose by mutual agreement a single neutral arbitrator to
hear the dispute. If the Parties fail to agree upon a
single arbitrator within ten calendar days of the giving of
notice of arbitration, the American Arbitration Association
shall be asked to appoint an arbitrator. In either case,
the arbitrator shall be knowledgeable in matters involving
the electric power industry, including the operation of
control areas and bulk power systems, and shall not have any
substantial business or financial relationships with the
ISO, NEPOOL or its Participants, or the Customer (other than
previous experience as an arbitrator) unless otherwise
mutually agreed by the Parties.
7.4 Costs: Each Party shall be responsible for the following
arbitration costs, if applicable:
(i) its own costs incurred during the arbitration process;
plus
(ii) One half of the common costs of the arbitration
including, but not limited to, the arbitrator's fee and
expenses, the rental charge for a hearing room and, if
both Parties agree to the necessity therefor, the cost
of a court reporter and transcript.
7.5 Hearing Location: Unless otherwise mutually agreed, the
site for all arbitration hearings shall be Springfield,
Massachusetts.
7.6 Rules and Procedures:
(1) PROCEDURE AND DISCOVERY: The procedural rules (if
any), the conduct of the arbitration and the
availability, extent and duration of pre-hearing
discovery (if any), which shall be limited to the
minimum necessary to resolve the matters in dispute,
shall be determined by the arbitrator in his/her sole
discretion at or prior to the initial hearing. The
arbitrator shall provide each of the Parties an
opportunity to be heard and, except as otherwise
provided herein, shall generally conduct the
arbitration in accordance with the COMMERCIAL
ARBITRATION RULES OF THE AMERICAN ARBITRATION
ASSOCIATION. In addition, each Party shall designate
one or more individuals to be available to answer
questions the arbitrator may have on the documents or
other materials submitted by that Party. The answers
to all such questions shall be reduced to writing by
the Party providing the answer and a copy shall be
furnished to the other Party.
(2) PRE-HEARING SUBMISSIONS: The Aggrieved Party shall
provide the arbitrator with a brief written statement
of its complaint and a statement of the remedy or
remedies it seeks, accompanied by copies of any
documents or other materials it wishes the arbitrator
to review.
(3) INITIAL HEARING: An initial hearing will be held no
later than 10 days after the selection of the
arbitrator and shall be limited to issues raised in the
pre-hearing filings. The scheduling of further
hearings at the request of either Party or on the
arbitrator's own motion shall be within the sole
discretion of the arbitrator.
(4) DECISION: The arbitrator's decision shall be due,
unless the deadline is extended by mutual agreement of
the Parties, within thirty days of the initial hearing
or within ninety days of the Aggrieved Party's
initiation of arbitration, whichever occurs first. The
arbitrator shall be authorized only to interpret and
apply the provisions of this Tariff or Service
Agreement thereunder (or, to the extent applicable, the
NEPOOL Agreement, NEPOOL Tariff or ISO Agreement) and
the arbitrator shall have no power to modify or change
this Tariff or Service Agreement (or, to the extent
applicable, the NEPOOL Agreement, NEPOOL Tariff or ISO
Agreement) thereunder in any manner. The arbitrator's
decision shall be in writing and shall state the basis
for the decision.
(5) EFFECT OF ARBITRATION DECISION: The decision of the
arbitrator will be conclusive in a subsequent
regulatory or legal proceeding as to the facts
determined by the arbitrator but will not be conclusive
as to the law or constitute precedent on issues of law
in any subsequent regulatory or legal proceedings.
An Aggrieved Party may initiate a proceeding with
a court or with the Commission with respect to the
arbitration or arbitrator's decision only:
o if the arbitration process does not result in a
decision within the time period specified and the
proceeding is initiated within thirty days after
the expiration of such time period; or
o on the grounds specified in Sections 10 and 11
of Title 9 of the United States Code for judicial
vacation or modification of an arbitration award
and the proceeding is initiated within thirty days
of the issuance of the arbitrator's decision.
8 Direct Billing; Sanctions
8.1 Transmission Studies: The ISO will conduct and coordinate
certain System Impact Studies pursuant to, and in accordance
with, the NEPOOL Tariff and the NEPOOL Agreement. In
addition, the ISO will conduct and coordinate certain
Facilities Studies pursuant to, and in accordance with, the
NEPOOL Tariff and the NEPOOL Agreement. The costs of System
Impact Studies and Facilities Studies will be charged
directly to the pertinent Eligible Customers or
interconnection applicants. The ISO will include in a
separate operating revenue account or subaccount any
revenues received for System Impact Studies or Facilities
Studies (excluding the costs of study contractors which are
directly charged to study requestors) which represent costs
for ISO staff or related overhead, and these revenues and
any other miscellaneous revenues will be credited to revenue
requirements for the Scheduling Service.
8.2 Information Requests: In fulfilling information requests
of a significant and non-routine nature, the ISO will charge
its associated direct and indirect costs to the requestor.
Revenue from these charges will be credited to revenue
requirements for the Service to which the information
request is most closely related.
8.3 Sanctions Rule: Amounts collected by the ISO during a
month from Participants pursuant to the Sanctions Rule shall
be a credit to that month's Monthly RAS Expenses; provided,
however, that a sanctioned Participant shall receive no part
of such credit attributable to a payment made by such
sanctioned Participant. The part of such credit
attributable to the sanctioned Participant's payment shall
be allocated among the Participants (excluding the
sanctioned Participant) on the basis of a recalculation of
Voting Share (determined in accordance with the NEPOOL
Agreement) excluding the factors associated with the
sanctioned Customer.
9 Metering
9.1 Customer Obligations: The Customer shall be responsible
for compliance with metering requirements under the NEPOOL
Tariff and any applicable local transmission provider's
tariff and to communicate the metering information to the
ISO.
9.2 ISO Access to Metering Data: The ISO will have access to
such metering data as may reasonably be required to
facilitate measurements and billing under this Tariff and
Service Agreement, the NEPOOL Agreement, the NEPOOL Tariff,
or other arrangements for which the ISO is required to bill.
<PAGE>
Schedule 1
Scheduling, System Control and Dispatch Service
Scheduling, System Control and Dispatch Service ("Scheduling
Service") is the service required to schedule at the pool level the
movement of power through, out of, within, or into the NEPOOL Control
Area. It is anticipated that local level service would be provided
under the Local Network Service tariffs of the individual Transmission
Providers. For Transmission Service under the NEPOOL Tariff,
Scheduling Service is an Ancillary Service that can be provided only
by the ISO and all Transmission Customers must be Customers under this
Tariff and purchase this Service from the ISO. Customers must enter
into a Service Agreement of the type specified in Attachment A hereto.
The ISO's charges stated herein for Scheduling Service are based on
the expenses incurred by the ISO in providing this Service. In
addition, the ISO acts as a billing agent for the operators of the
NEPOOL satellite dispatch centers and certain Participants in order to
collect their expenses incurred in providing this service pursuant to
Schedule 1 of the NEPOOL Tariff.
The ISO's expenses are based on the functions required to provide
this Service and include, but are not limited to:
o Processing and implementation of requests for
Transmission Service, including support of the NEPOOL OASIS
node;
o Coordination of transmission system operation (including
administration of reactive power requirements under Schedule
2 of the NEPOOL Tariff) and implementation of necessary
control actions by the ISO and support for these functions;
o Billing associated with transmission services provided
under the NEPOOL Tariff;
o Transmission system planning which supports this Service;
and
o Administrative costs associated with the aforementioned
functions.
The satellite dispatch center expenses and the Participant
expenses collected pursuant to Schedule 1 of the NEPOOL Tariff are in
each case an allocated portion of dispatch center expense for the PTF
dispatch functions performed.
For the ISO's expenses in providing transmission-related Scheduling
Service, each Customer that is obligated to pay the Regional Network
Service rate shall pay each month an amount equal to the product of
$0.0420 per kilowatt times its Monthly Network Load for that month;
the annual charge per kilowatt is $0.5036. Each Customer that is a
Transmission Customer receiving Point-to-Point Transmission Service
shall pay each month an amount equal to the product of the
Transmission Customer's highest amount of Reserved Capacity (expressed
in kilowatts) for each transaction scheduled to occur during the month
as Point-to-Point Transmission Service times:
(1) for each month of firm annual or monthly service, $0.0420;
(2) for each week of firm weekly service, $0.0097;
(3) for each day of firm daily service, $0.0019, but the rate
for 5 to 7 consecutive days may not exceed the per-week
rate;
(4) for each month of non-firm annual or monthly service,
$0.0420;
(5) for each week of non-firm weekly service, $0.0097;
(6) for each day of non-firm daily service, $0.0014; and
(7) for each hour of non-firm hourly service, $0.0006.
The ISO shall also collect from each Customer, as billing agent,
the charges specified in Schedule 1 of the NEPOOL Tariff.
All general terms and conditions of this Tariff apply to this
Service.
<PAGE>
Schedule 2
Energy Administration Service
Energy Administration Service ("EAS") is the Service provided by
the ISO to administer the Energy Market and facilitate Interchange
Transactions, bilateral transactions and self-scheduling in accordance
with the NEPOOL Agreement and the corresponding rules promulgated
thereunder. Each Participant that buys, sells, or produces Energy
utilizes EAS (even when utilizing bilateral transactions or self-
scheduling, because the ISO must account for these activities and
implement them) and must purchase EAS as a Customer hereunder. Each
non-Participant Transmission Customer that receives Energy pursuant to
Schedule 4 of the NEPOOL Tariff (I.E., Energy Imbalance Service)
utilizes EAS and must purchase EAS as a Customer hereunder. Each
Customer must enter into a Service Agreement of the type specified in
Attachment A hereto.
The ISO's expenses are based on the functions required to provide
this Service and include, but are not limited to:
o Core operation of the Energy Market;
o Generation dispatch related to the Energy Market;
o Energy accounting;
o Loss determination and allocation;
o Billing preparation;
o Administration of the Energy Imbalance Service under
Schedule 4 of the NEPOOL Tariff;
o Market power monitoring and mitigation for the Energy
Market;
o Sanctions activities;
o Market assessment and reports; and
o Formulation of additional market rules and proposals to
modify existing rules.
For EAS, each Participant shall pay each month in arrears: (1)
an amount equal to the product of $0.0000698 per kilowatt-hour times
the Customer's total Electrical Load for all hours in that month; and
(2) an amount equal to the product of $0.0000263 per kilowatt-hour
times the sum of: (a) a number of kilowatt-hours equal to the
kilowatts of the Customer's Generation Ownership Shares for that
month, times the number of hours in the month, plus (b) the total
number of kilowatt-hours that the Customer was entitled to receive
during that month with respect to its Energy Entitlements under Unit
Contracts or System Contracts (taking into account, in the case of
each contract, the number of hours the contract was in effect in the
month), as computed without giving effect to any resale in whole or
part of any such Energy Entitlement; plus (c) the absolute value of
the sum of the kilowatt-hours of the Customer's ANI in the hours of
that month in which the Customer's ANI is a negative number; provided
that if a Participant has both a Generation Ownership Share in a
generating unit as the result of its Related Person affiliation with
the owner of the generating unit and an Energy Entitlement as the
result of its purchase of Energy from the same generating unit, the
Participant's Energy Entitlement with respect to such purchase shall
be excluded from consideration under Part (b) of the formula. For
purposes of this paragraph, a Customer's Electrical Load, Generation
Ownership Shares and Energy Entitlements shall be calculated subject
to the provisions of NEPOOL Agreement Section 3.2.
For EAS, a Customer that is not a Participant shall pay each
month in arrears an amount equal to the product of $0.0000263 per
kilowatt-hour times the number of kilowatt-hours of Energy Imbalance
Service taken by the Customer during that month.
All general terms and conditions of this Tariff apply to this
Service.
<PAGE>
Schedule 3
Reliability Administration Service
Reliability Administration Service ("RAS") is the Service
provided by the ISO to administer the Reliability Markets (and
facilitate reliability-associated transactions and arrangements) in
accordance with the NEPOOL Agreement and the corresponding rules
promulgated thereunder, and to provide other reliability and
informational services. Each Participant (and each Transmission
Customer that is not a Participant) benefits (as do their respective
customers) from the reliability ensured by the administration of the
Reliability Markets and associated services, and therefore must
purchase RAS as a Customer hereunder. The Reliability Markets are
also a means by which certain Ancillary Services are obtained under
the NEPOOL Tariff. Each Customer must enter into a Service Agreement
of the type specified in Attachment A hereto.
The ISO's administrative expenses are based on the functions
required to provide this Service and include, but are not limited to:
o Generation dispatch associated with Reliability Markets;
o Reliability Markets accounting;
o Billing preparation;
o NEPOOL generation emissions analysis;
o Risk profile updates;
o Triennial review of resource adequacy;
o Preparation of regional reports and load forecasts and
profiles (CELT, EIA, NERC);
o Support of power supply, environmental and market
reliability planning activities;
o Reliability Markets: market power monitoring, mitigation
and assessment; and
o Formulation of additional Market rules and proposals to
modify existing rules.
For RAS: (1) Each Transmission Customer that is not a
Participant shall pay each month, in arrears, a RAS Fee (corresponding
to the Transmission Service taken in that month) in the following
amounts:
(a) Entities required to make a payment for Regional Network
Service in a month, $500 (whether firm or non-firm);
(b) for each month of annual or monthly Point-to-Point
Transmission Service received, $500;
(c) for each week of weekly Point-to-Point Transmission Service
received (whether firm or non-firm), $115.38;
(d) for each day of firm daily Point-to-Point Transmission
Service received, $23.07, provided that the rate for 5 to 7
consecutive days may not exceed the "per week" rate;
(e) for each day of non-firm daily Point-to-Point Transmission
Service received, $16.48; and
(f) for each hour of non-firm hourly Point-to-Point Transmission
Service received, $0.69;
and (2) each Customer that is a Participant shall pay each month in
arrears, an amount equal to the product of its Participant Share as of
the end of that month and the Monthly RAS Expenses.
RAS does not include any amounts paid by the ISO on behalf of the
Participants to purchase emergency power. If one or more states
requires Participants to undertake disclosure or tracking obligations
that result in the ISO incurring expenses, the ISO will segregate the
expenses associated with such obligations.
All general terms and conditions of this Tariff apply to this
Service.
<PAGE>
ATTACHMENT A
Form of Service Agreement
1.0 This Service Agreement, dated as of __________ , is entered
into, by and between ISO New England Inc. __________________ (the
"ISO") and __________ ("Customer") pursuant to the ISO's Tariff
for Transmission Dispatch and Power Administration Services (the
"Tariff").
2.0 Service under this Service Agreement shall commence on the later
of (1) the requested service commencement date or (2) such other
date as it is permitted to become effective by the Commission.
Service under this Service Agreement shall terminate on such date
as is mutually agreed upon by the parties, except as otherwise
provided under the Tariff.
3.0 The ISO agrees to provide, and the Customer agrees to take and
pay for, Services indicated below in accordance with the
provisions of the Tariff and this Service Agreement:
Scheduling, System Control and Dispatch Service (Schedule 1)
Energy Administration Service (Schedule 2)
Reliability Administration Service (Schedule 3)
4.0 Any notice or request made to or by either party regarding this
Service Agreement shall be made to the representative of the
other party as indicated below.
ISO:
[Title]
ISO New England Inc.
One Sullivan Road
Holyoke, MA 01040-2841
CUSTOMER:
___________________________
___________________________
___________________________
___________________________
___________________________
5.0 The Tariff is incorporated in this Service Agreement and made a
part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to
be executed by their respective authorized officials.
ISO NEW ENGLAND INC.:
By:___________________ __________ _____________
Name Title Date
CUSTOMER:
By:___________________ __________ _____________
Name Title Date
<PAGE>
ATTACHMENT B
Definitions and Provisions Extracted From
NEPOOL Agreement and NEPOOL Tariff
Adjusted Net Interchange (or "ANI"): The Adjusted Net
Interchange of a Participant for an hour is (a) the kilowatts produced
by or delivered to the Participant from its Energy Entitlements or
pursuant to arrangements entered into under Section 14.6 of the NEPOOL
Agreement as adjusted in accordance with uniform market operation
rules approved by NEPOOL's Regional Market Operations Committee to
take account of losses, as appropriate, MINUS (b) the sum of (i) the
Electrical Load of the Participant for the hour, and (ii) the
kilowatt-hours delivered by such Participant to other Participants
pursuant to Firm Contracts or System Contracts in accordance with the
treatment agreed to by the parties thereto and reported to the ISO,
together with any associated electrical losses.
Ancillary Services: Those services that are necessary to support the
transmission of electric capacity and energy from resources to loads
while maintaining reliable operation of the NEPOOL Transmission System
in accordance with Good Utility Practice.
Automatic Generation Control (or "AGC"): A measure of the ability of
a generating unit or portion thereof to respond automatically within a
specified time to a remote direction from the ISO to increase or
decrease the level of output in order to control frequency and to
maintain currently proper power flows into and out of the NEPOOL
Control Area.
Control Area: An electric power system or combination of electric
power systems to which a common automatic generation control scheme is
applied in order to:
(1) match, at all times, the power output of the generators
within the electric power system(s) and capacity and energy
purchased from entities outside the electric power
system(s), with the load within the electric power
system(s);
(2) maintain scheduled interchange with other Control Areas,
within the limits of Good Utility Practice;
(3) maintain the frequency of the electric power system(s)
within reasonable limits in accordance with Good Utility
Practice and the criteria of the applicable regional
reliability council or the North American Electric
Reliability Council; and
(4) provide sufficient generating capacity to maintain operating
reserves in accordance with Good Utility Practice.
<PAGE>
Curtailment: A reduction in firm or non-firm transmission
service in response to a transmission capacity shortage as a result of
system reliability conditions.
Electrical Load: Electrical Load (in kilowatts) of a Participant
during any particular hour is the total during such hour (eliminating
any distortion arising out of (i) Interchange Transactions, or (ii)
transactions across the system of such Participant, or (iii)
deliveries between Entities constituting a single Participant, or (iv)
other electrical losses, if and as appropriate), of
(a) kilowatt-hours provided by such Participant to its retail
customers for consumption, PLUS
(b) kilowatt-hours of use by such Participant, PLUS
(c) kilowatt-hours of electrical losses and unaccounted for use
by the Participant on its system, PLUS
(d) kilowatt-hours used by such Participant for pumping Energy
for its Entitlements in pumped storage hydroelectric
generating facilities, PLUS
(e) kilowatt-hours delivered by such Participant to Non-
Participants.
The Electrical Load of a Participant may be calculated in any
reasonable manner which substantially complies with this definition.
Eligible Customer: (i) Any Participant that is engaged, or
proposes to engage, in the wholesale or retail electric power business
is an Eligible Customer under the NEPOOL Tariff. (ii) Any electric
utility (including any power marketer), Federal power marketing
agency, or any other entity generating electric energy for sale for
resale is an Eligible Customer under the NEPOOL Tariff. Electric
energy sold or produced by such entity may be electric energy produced
in the United States, Canada or Mexico. However, with respect to
transmission service that the Commission is prohibited from ordering
by Section 212(h) of the Federal Power Act, such entity is eligible
only if the service is provided pursuant to a state requirement that
the Transmission Provider with which the entity is directly
interconnected offer the unbundled transmission service, or pursuant
to a voluntary offer of such service by the Transmission Provider with
which the entity is directly interconnected. (iii) Any end user
taking or eligible to take unbundled transmission service pursuant to
a state requirement that the Transmission Provider with which that end
user is directly interconnected offer the transmission service, or
pursuant to a voluntary offer of such service by the Transmission
Provider with which that entity is directly interconnected, is an
Eligible Customer under the NEPOOL Tariff.
Energy Entitlement: An Energy Entitlement is (i) a right to
receive Energy under a System Contract or a Firm Contract, or (ii) a
right to receive all or a portion of the electric output of a
generating unit or units to which an Entity is entitled as an owner
(either sole or in common) or as a purchaser pursuant to a Unit
Contract, REDUCED BY (iii) any portion thereof which such Entity is
selling pursuant to a Unit Contract. An Energy Entitlement in a
generating unit or units may, but need not, be combined with any other
Entitlements relating to such generating unit or units and may be
transferred separately from the related Installed Capability
Entitlement, Operable Capability Entitlement, Operating Reserve
Entitlements, or AGC Entitlement.
Entitlement: An Installed Capability Entitlement, Operable
Capability Entitlement, Energy Entitlement, Operating Reserve
Entitlement, or AGC Entitlement. When used in the plural form, it may
be any or all such Entitlements or combinations thereof, as the
context requires.
Entity: Any person or organization whether in the United States of
America or Canada or a state or province or a political subdivision
thereof or a duly established agency of any of them, a private
corporation, a partnership, an individual, an electric cooperative or
any other person or organization recognized in law as capable of
owning property and contracting with respect thereto that is either:
(a) engaged in the electric power business (the
generation and/or transmission and/or distribution
of electricity for consumption by the public or
the purchase, as a principal or broker, of
Installed Capability, Operable Capability, Energy,
Operating Reserve, and/or AGC for resale); or
(b) an end user of electricity that is taking or eligible to
take unbundled transmission service pursuant to an effective
state requirement that the Participant that is the
Transmission Provider with which that end user is directly
interconnected offer the transmission service, or pursuant
to a voluntary offer of unbundled transmission service to
that end user by the Participant that is the Transmission
Provider with which that end user is directly
interconnected.
Facilities Study: An engineering study conducted pursuant to the
NEPOOL Agreement or the NEPOOL Tariff by the ISO and/or one or more
affected Participants to determine the required modifications to the
NEPOOL Transmission System, including the cost and scheduled
completion date for such modifications, that will be required to
provide a requested transmission service or interconnection.
Firm Contract: Any contract, other than a Unit Contract, for the
purchase of Installed Capability, Operable Capability, Energy,
Operating Reserves, and/or AGC, pursuant to which the purchaser's
right to receive such Installed Capability, Operable Capability,
Energy, Operating Reserves, and/or AGC is subject only to the
supplier's inability to make deliveries thereunder as the result of
events beyond the supplier's reasonable control.
Generator Owner: The owner, in whole or part, of a generating
unit whether located within or outside of the NEPOOL Control Area.
Generation Ownership Shares: The Generation Ownership Shares of a
Customer means and includes:
(a) the direct ownership interest which the Customer has as a
sole or joint owner in the Installed Capability of a
generating unit which is subject to NEPOOL central dispatch;
(b) the indirect ownership interest which the Customer has, as a
shareholder in Vermont Yankee Nuclear Power Corporation or a
similar corporation, or as a general or limited partner in
Ocean State Power or a similar partnership, in the Installed
Capability of a generating unit which is subject to NEPOOL
central dispatch, provided the corporation or partnership is
itself not a Participant;
(c) any other interest which the Customer has in the Installed
Capability of a generating unit which is subject to NEPOOL
central dispatch, under a lease or other contractual
arrangement, provided the other party to the arrangement is
itself not a Participant and the NEPOOL Management Committee
determines, at the request of the affected Customer, that
the Customer has benefits and rights, and assumes risks,
under the arrangement with respect to the unit which are
substantially equivalent to the benefits, rights and risks
of an owner; and
(d) an interest which the Customer shall be deemed to have in
the direct ownership interest, or the indirect ownership
interest as a shareholder or general or limited partner, of
a Related Person of the Customer in the Installed Capability
of a generating unit which is subject to NEPOOL central
dispatch, provided the Related Person is itself not a
Participant.
Good Utility Practice: Any of the practices, methods and acts
engaged in or approved by a significant portion of the electric
utility industry during the relevant time period, or any of the
practices, methods and acts which, in the exercise of reasonable
judgment in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired result at a
reasonable cost consistent with good business practices, reliability,
safety and expedition. Good Utility Practice is not intended to be
limited to the optimum practice, method, or act to the exclusion of
all others, but rather includes all acceptable practices, methods, or
acts generally accepted in the region.
<PAGE>
HQ Phase II Firm Energy Contract: The Firm Energy Contract dated
as of October 14, 1985 between Hydro-Quebec and certain of the
Participants, as it may be amended from time to time.
Installed Capability: The Installed Capability of an electric
generating unit or combination of units during the Winter Period is
the Winter Capability of such unit or units and during the Summer
Period is the Summer Capability of such unit or units.
Interchange Transactions: Transactions deemed to be effected under
Section 12 of the Prior NEPOOL Agreement (that is, the agreement as in
effect on December 1, 1996) prior to the Second Effective Date, and
transactions deemed to be effected under Section 14 of the NEPOOL
Agreement on and after the Second Effective Date.
Internal Point-to-Point Service: Point-to-Point Transmission
Service with respect to a transaction where the Point of Receipt is at
the boundary of or within the NEPOOL Transmission System and the Point
of Delivery is within the NEPOOL Transmission System.
Load: (in Kilowatts) of a Participant during any particular hour
is the total during such hour (eliminating any distortion arising out
of (i) Interchange Transactions, or (ii) transactions across the
system of such Participant, or (iii) deliveries between Entities
constituting a single Participant, or (iv) other electrical losses, if
and as appropriate) of
(a) kilowatthours provided by such Participant to its retail
customers for consumption (excluding any kilowatthours which
may be classified as interruptible under market operation
rules approved by the NEPOOL Regional Market Operations
Committee), PLUS
(b) kilowatthours delivered by such Participant pursuant to Firm
Contracts to its wholesale customers for resale, PLUS
(c) kilowatthours of use by such Participant, exclusive of use
by such Participant for the operation and maintenance of its
generating unit or units, PLUS
(d) kilowatthours of electrical losses and unaccounted for use
by the Participant on its system.
The Load of a Participant may be calculated in any reasonable manner
which substantially complies with this definition.
For the purposes of calculating a Participant's Monthly Peak, the
Load of a Participant shall be adjusted to eliminate any distortions
resulting from voltage reductions. In addition, upon the request of
any Participant, the NEPOOL Regional Market Operations Committee shall
make, or supervise the making of, appropriate adjustments in the
computation of Load for the purposes of calculating any Participant's
Annual Peak, Adjusted Monthly Peak, Adjusted Annual Peak and Monthly
Peak to eliminate any distortions resulting from emergency load
curtailments which would significantly affect the Load of any
Participant.
The definition of the term "Load" is modified as follows when a
Participant purchases a portion of its requirements of electricity
from another Participant pursuant to a Firm Contract:
(a) If the Firm Contract limits deliveries to a specifically
stated number of Kilowatts and requires payment of a demand
charge thereon (thus placing the responsibility for meeting
additional demands on the purchasing Participant):
(1) in computing the ADJUSTED LOAD of the purchasing
Participant, the Kilowatts received pursuant to such
Firm Contract shall be deemed to be the number of
Kilowatts specified in the Firm Contract; and
(2) in computing the LOAD of the supplying Participant, the
Kilowatts delivered pursuant to such Firm Contract
shall be deemed to be the number of Kilowatts specified
in the Firm Contract.
(b) If the Firm Contract does not limit deliveries to a
specifically stated number of Kilowatts, but entitles the
Participant to receive such amounts of electricity as it may
require to supply its electric needs (thus placing the
responsibility for meeting additional demands on the
supplying Participant):
(1) the INSTALLED CAPABILITY RESPONSIBILITY of the
purchasing Participant shall be EQUAL TO the amount of
its Installed Capability Entitlements;
(2) in computing the ADJUSTED LOAD of the purchasing
Participant, the Kilowatts received pursuant to such
Firm Contract shall be deemed to be a quantity R{l};
and
(3) in computing the LOAD of the supplying Participant, the
Kilowatts delivered pursuant to such Firm Contract
shall be deemed to be a quantity R{l}.
The quantity R{l} equals (i) the Load of the purchasing
Participant less (ii) the amount of the purchasing
Participant's Installed Capability Entitlements multiplied
by a fraction X wherein:
---
Y
X is the maximum Load of the purchasing Participant in
the month, and
Y is the NEPOOL Installed Capability Responsibility
multiplied by the purchasing Participant's fraction P
determined pursuant to Section 12.2(a)(1) of the NEPOOL
Agreement, computed as if the Firm Contract did not
exist.
Local Network: The transmission facilities, constituting a local
network, of the following companies: (i) Bangor Hydro-Electric
Company; (ii) Boston Edison Company; (iii) Central Maine Power
Company; (iv) the Commonwealth Energy System companies; (v) the
Eastern Utility Associates companies; (vi) the New England Electric
System companies; (vii) the Northeast Utilities companies; (viii) The
United Illuminating Company; and (ix) Vermont Electric Power Company
and the entities which are grouped with it as a single Participant and
any other local network or change in the designation of a Local
Network which the NEPOOL Management Committee may designate or approve
from time to time. The NEPOOL Management Committee may not
unreasonably withhold approval of a request by a Participant that it
effect such a change or designation.
Local Network Service: Local Network Service is the service
provided, under a separate tariff or contract, by a Participant that
is a Transmission Provider to another Participant, or other Entity
connected to the Transmission Provider's Local Network to permit the
other Participant or Entity to efficiently and economically utilize
its resources to serve its load.
Monthly Network Load: A Customer's hourly load (including its
designated Network Load not physically interconnected with the
Transmission Provider under Section 43.3 of the NEPOOL Tariff)
coincident with the coincident aggregate load of the Participants and
other Network Customers served in each Local Network in the hour in
which the coincident load is at its maximum for the month ("Monthly
Peak").
NEPOOL Agreement Section 3.2: Subject to the reciprocity
requirements of the NEPOOL Tariff, if a Participant serves a Load, or
has rights in supply or demand-side resources or owns transmission
and/or distribution facilities, located outside of the NEPOOL Control
Area, such Load and resources shall not be included for purposes of
determining the Participant's rights, responsibilities and obligations
under the NEPOOL Agreement, except that the Participant's Entitlements
in facilities or its rights in demand side-resources outside the
NEPOOL Control Area shall be included in such determinations if, to
the extent, and while such Entitlements are used for retail or
wholesale sales within the NEPOOL Control Area or such Entitlements or
rights are designated by a Participant for purposes of meeting its
obligations under Section 12 of the NEPOOL Agreement.
NEPOOL Management Committee: The committee established pursuant
to Section 6 of the NEPOOL Agreement.
NEPOOL Transmission System: The PTF transmission facilities.
Network Integration Transmission Service: Regional Network
Service which may be used with respect to Network Resources or Network
Load not physically interconnected with the NEPOOL Transmission
System.
Network Load: The load that a Network Customer designates for
Network Integration Transmission Service under Part II and Part VI of
the NEPOOL Tariff. The Network Customer's Network Load shall include
all load designated by the Network Customer (including losses) and
shall not be credited or reduced for any behind-the-meter generation.
A Network Customer may elect to designate less than its total load as
Network Load but may not designate only part of the load at a discrete
Point of Delivery. Where an Eligible Customer has elected not to
designate a particular load at discrete Points of Delivery as Network
Load, the Eligible Customer is responsible for making separate
arrangements under Part III and Part V of the NEPOOL Tariff for any
Point-to-Point Transmission Service that may be necessary for such
non-designated load.
Network Resource: (1) With respect to Participants, (a) any
generating resource located in the NEPOOL Control Area which has been
placed in service prior to October 1, 1998 (including a unit that has
lost its capacity value when its capacity value is restored and a
deactivated unit which may be reactivated without satisfying the
requirements of Section 49 of the NEPOOL Tariff in accordance with the
provisions thereof) until retired; (b) any generating resource located
in the NEPOOL Control Area which is placed in service after October 1,
1998 until retired, provided that (i) the Generator Owner has complied
with the requirements of Section 49 of the NEPOOL Tariff, and (ii) the
output of the unit shall be limited in accordance with Section 49, if
required; and (c) any generating resource or combination of resources
(including bilateral purchases) located outside the NEPOOL Control
Area for so long as any Participant has an Entitlement in the resource
or resources which is being delivered to it in the NEPOOL Control Area
to serve Network Load located in the NEPOOL Control Area or other
designated Network Loads contemplated by Section 43.3 of the NEPOOL
Tariff taking Regional Network Service. (2) With respect to Non-
Participant Network Customers, any generating resource owned,
purchased or leased by the Network Customer which it designates to
serve Network Load.
Open Access Same-Time Information System (OASIS): The NEPOOL
information system and standards of conduct responding to requirements
of 18 C.F.R. <section>37 of the Commission's regulations and all
additional requirements implemented by subsequent Commission orders
dealing with OASIS.
Operable Capability: Operable Capability of an electric
generating unit or units in any hour is the portion of the Installed
Capability of the unit or units which is operating or available to
respond within an appropriate period (as identified in market
operation rules approved by the Regional Market Operations Committee)
to the ISO's call to meet the Energy and/or Operating Reserve and/or
AGC requirements of the NEPOOL Control Area during a Scheduled
Dispatch Period or is available to respond within an appropriate
period to a schedule submitted by a Participant for the hour in
accordance with market operation rules approved by the Regional Market
Operations Committee.
Operating Reserve: Any or a combination of 10-Minute Spinning
Reserve, 10-Minute Non-Spinning Reserve, and 30-Minute Operating
Reserve, as the context requires.
Participant: A Participant is an eligible Entity (or group of
Entities which has elected to be treated as a single Participant)
which is a signatory to the NEPOOL Agreement and has become a
Participant in accordance therewith until such time as such Entity's
status as a Participant terminates.
Point-to-Point Transmission Service: The transmission of capacity
and/or energy on either a firm or non-firm basis from the Point(s) of
Receipt to the Point(s) of Delivery under the NEPOOL Tariff. NEPOOL
Point-to-Point Transmission Service includes both Internal Point-to-
Point Service and Through or Out Service.
Pool Transmission Facilities (or "PTF"): The transmission facilities
owned by the Participants and their Related Persons which constitute
PTF pursuant to the NEPOOL Agreement.
Power Year: The period of twelve months commencing on November 1.
Regional Market Operations Committee: The committee established
pursuant to Section 10 of the NEPOOL Agreement.
Regional Network Service: Transmission service provided by the
Participants pursuant to Part II and Part IV of the NEPOOL Tariff.
Related Persons: With respect to a Customer, either (i) a
corporation, partnership, business trust or other business
organization 10% or more of the stock or equity interest in which is
owned directly or indirectly by, or is under common control with, the
Customer, or (ii) a corporation, partnership, business trust or other
business organization which owns directly or indirectly 10% or more of
the stock or other equity interest in the Customer, or (iii) a
corporation, partnership, business trust or other business
organization 10% or more of the stock or other equity interest in
which is owned, directly or indirectly by a corporation, partnership,
business trust or other business organization which also owns 10% or
more of the stock or other equity interest in the Customer.
<PAGE>
Reserved Capacity: The maximum amount of capacity and energy
that is committed to the Transmission Customer for transmission over
the NEPOOL Transmission System between the Point(s) of Receipt and the
Point(s) of Delivery under Part V of the NEPOOL Tariff. Reserved
Capacity shall be expressed in terms of whole kilowatts on a sixty-
minute interval (commencing on the clock hour) basis.
Scheduled Dispatch Period: The shortest period for which the ISO
performs and publishes a projected dispatch schedule.
Second Effective Date: The date on which the provisions of Part
Three of the NEPOOL Agreement (other than those relating to the
Installed Capability Market) shall become effective and shall be such
date as the Commission may fix on its own or pursuant to a request of
the NEPOOL Management Committee.
System Contract: Any contract for the purchase of Installed
Capability, Operable Capability, Energy, Operating Reserves and/or
AGC, other than a Unit Contract or Firm Contract, pursuant to which
the purchaser is entitled to a specifically determined or determinable
amount of such Installed Capability, Operable Capability, Energy,
Operating Reserves and/or AGC.
Summer Capability: Summer Capability of an electric generating
unit or combination of units is the maximum dependable load carrying
ability in Kilowatts of such unit or units (exclusive of capacity
required for station use) during the Summer Period, as determined by
the NEPOOL Regional Market Operations Committee.
Summer Period: Summer Period in each Power Year is the four-
month period from June through September.
System Impact Study: An assessment of: (i) the adequacy of the
NEPOOL Transmission System to accommodate a request for the
interconnection of a new or materially changed generating unit or a
new or materially changed interconnection to another Control Area or
new Regional Network Service, internal Point-to-Point Service or
Through or Out Service, and (ii) whether any additional costs may be
required to be incurred in order to provide the interconnection or
transmission service.
Through or Out Service: Point-to-Point Transmission Service provided
by NEPOOL pursuant to Part III of the NEPOOL Tariff with respect to a
transaction which requires the use of PTF and which goes through the
NEPOOL Control Area, as, for example, from the Maine Electric Power
Company line or New Brunswick to New York, or from one point on the
NEPOOL Control Area boundary with New York to another point on the
Control Area boundary with New York, or with respect to a transaction
which goes out of the NEPOOL Control Area from a point in the NEPOOL
Control Area, as, for example, from Boston to New York.
Transmission Customer: Any Eligible Customer that (i) is a
Participant which is not required to sign a Transmission Service
Agreement with respect to a service to be furnished to it in
accordance with Section 48 of the NEPOOL Tariff, or (ii) executes, on
its own behalf or through its Designated Agent, a Transmission Service
Agreement, or (iii) requests in writing, on its own behalf or through
its Designated Agent, that NEPOOL file with the Commission, a proposed
unexecuted Transmission Service Agreement in order that the Eligible
Customer may receive transmission service under the NEPOOL Tariff.
This term is used in Part I of the NEPOOL Tariff to include customers
receiving transmission service under the NEPOOL Tariff.
Transmission Ownership Shares: The Transmission Ownership Shares
of a Participant means and includes:
(A) the direct ownership interest which the Participant has as a
sole or joint owner of PTF;
(B) the indirect ownership interest which the Participant has,
as a shareholder in a corporation, or as a general or
limited partner in a partnership, in PTF owned by such
corporation or partnership, provided the corporation or
partnership is not itself a Participant;
(C) any other interest which the Participant has in PTF under a
lease or other contractual arrangement, provided the other
party to the arrangement is not itself a Participant and the
NEPOOL Management Committee determines, at the request of
the affected Participant, that the Participant has benefits
and rights, and assumes risks, under the arrangement with
respect to the PTF which are substantially equivalent to the
benefits, rights and risks of an owner; and
(D) an interest which the Participant shall be deemed to have in
the direct ownership interest, or the indirect ownership
interest as a shareholder or general or limited partner, of
a Related Person of the Participant in PTF, provided the
Related Person is itself not a Participant.
Transmission Provider: The Participants, collectively, which own
PTF and are in the business of providing transmission service or
provide service under a local open access transmission tariff, or in
the case of a state or municipal or cooperatively-owned Participant,
would be required to do so if requested pursuant to the reciprocity
requirements specified in the NEPOOL Tariff, or an individual such
Participant, whichever is appropriate.
Unit Contract: A purchase contract pursuant to which the
purchaser is in effect currently entitled either (i) to a specifically
determined or determinable portion of the Installed Capability of a
specific electric generating unit or units, or (ii) to a specifically
determined or determinable amount of Operable Capability, Energy,
Operating Reserve and/or AGC if, or to the extent that, a specific
electric generating unit or units is or can be operated.
Winter Capability: Winter Capability of an electric generating
unit or combination of units is the maximum dependable load carrying
ability in Kilowatts of such unit or units (exclusive of capacity
required for station use) during the Winter Period, as determined by
the NEPOOL Regional Market Operations Committee.
Winter Period: Winter Period in each Power Year is the seven-
month period from November through May and the month of October.
<PAGE>
ATTACHMENT C
Financial Assurance Policy
FINANCIAL ASSURANCE POLICY FOR NEPOOL MEMBERS
This Financial Assurance Policy for NEPOOL Members ("Policy") shall
become effective on the Second Effective Date.
The purpose of this Policy is (i) to establish a financial assurance
policy for NEPOOL members ("Participants") that includes commercially
reasonable credit review procedures to assess the financial ability of
an applicant for membership in NEPOOL ("Applicant") or of a
Participant to pay for service transactions under the Restated NEPOOL
Agreement and the NEPOOL Open Access Transmission Tariff (the
"Tariff") and to pay its share of NEPOOL expenses, including amounts
owed to ISO New England Inc. under its tariff, (ii) to set forth
requirements for alternative forms of security that will be deemed
acceptable to NEPOOL and consistent with commercial practices
established by the Uniform Commercial Code that protects the
Participants against the risk of non-payment by other, defaulting
Participants, (iii) to set forth the conditions under which NEPOOL
will conduct business so as to avoid the possibility of failure of
payment for services rendered under the Tariff or the Restated NEPOOL
Agreement, and (iv) to collect amounts past due, make up shortfalls in
payments, and terminate membership of defaulting Participants.
In accordance with Sections 3.5 and 6.14 of the Restated NEPOOL
Agreement, NEPOOL requires the following procedures and requirements
to apply to all Applicants and Participants. Generally, any Applicant
or Participant that does not have an investment grade rating by either
Standard & Poor's, Moody's, Duff & Phelps, or Fitch will be required
to provide financial assurances, as described in detail below.
GENERAL REQUIREMENTS
Each Applicant or Participant must comply with the following general
requirements.
In the case of a group of members that are treated as a single
Participant pursuant to Section 4.1 of the Restated NEPOOL Agreement,
the group members shall be deemed to have elected to be jointly and
severally liable for all debts to NEPOOL of any of the group members
unless (i) charges of an individual member can be tracked and
allocated to the member incurring such charges by the System Operator
{1} utilizing all information available to the System Operator
determined by it to be reliable, including information from
Participants or from a single Participant's representative, (ii) an
alternate form of financial assurance is provided as set forth below,
(iii) the group members agree to allocate amongst themselves
responsibility for payment of group member charges on a percentage
basis in a manner acceptable to NEPOOL, with additional financial
assurance to be provided by those members, if any, that do not satisfy
the minimum corporate debt rating, or (iv) the group members when
evaluated as a whole (at their expense by one of the above rating
agencies) satisfy the minimum corporate debt rating requirement set
forth above and, in addition, provide a corporate guaranty from a
parent or other responsible affiliate, which parent or affiliate
satisfies the minimum corporate debt rating. For the fourth type of
consolidated Participant, NEPOOL will conduct a financial assurances
review based on the credit rating of only the rated members of the
group.
For the purposes of these financial assurance provisions, the term
"Participant" shall, in the case of a group of members that are
treated as a single Participant pursuant to Section 4.1 of the
Restated NEPOOL Agreement, be deemed to refer to the group of members
as a whole unless the group members have affirmatively indicated to
NEPOOL, and NEPOOL has agreed, that they are to be treated pursuant to
options (i) or (iii) above, in which case the term "Participant" shall
be deemed to refer to each individual group member and not to the
aggregate of such group; and the terms "charges" and fees" shall,
likewise, be deemed to refer to the charges and fees allocable to the
individual group member as opposed to the aggregate of such group.
PROOF OF FINANCIAL VIABILITY
Each Applicant must with its application submit proof of financial
viability, as described below, satisfying NEPOOL requirements to
demonstrate the Applicant's ability to meet its obligations, or must
provide prior to its membership becoming effective financial assurance
in the form of a cash deposit, letter of credit or performance bond as
set forth below. An Applicant that chooses to provide a cash deposit,
letter of credit or performance bond will not be required to provide
financial information to NEPOOL.
Generally, each Applicant must submit a current rating agency report,
which report must indicate an investment grade rating by either
Standard & Poor's, Moody's, Duff & Phelps, or Fitch for the Applicant
to be considered as a candidate for NEPOOL membership without
furnishing additional financial assurances as described below.
Current Participants must also provide a current rating agency report
by the Second Effective Date, as well as any of the financial
statements and information set forth below if and as requested by
NEPOOL within ten (10) days of such request. Those Participants that
do not satisfy the rating requirement as set forth above must provide
instead on the Second Effective Date one form of the financial
assurances set forth below. A Participant's failure to meet these
requirements may result in termination proceedings by NEPOOL.
FINANCIAL STATEMENTS
Each Applicant must submit, if and as requested by NEPOOL and within
ten (10) days of such request, audited financial statements for at
least the immediately preceding three years, or the period of its
existence, if shorter, including, but not limited to, the following
information:
Balance Sheets
Income Statements
Statements of Cash Flows
Notes to Financial Statements
Additionally, the following information for at least the immediately
preceding three years, if available, must be submitted if and as
requested by NEPOOL and within ten (10) days of such request:
Annual and Quarterly Reports
10-K, 10-Q and 8-K Reports
Where the above financial statements are available on the Internet,
the Applicant may provide instead a letter to NEPOOL stating where
such statements may be located and retrieved by NEPOOL.
Each Applicant may also be required to provide at least one bank
reference and three (3) Utility credit references. In those cases
where an Applicant does not have three (3) Utility credit references,
three (3) trade payable vendor references may be substituted.
Each Applicant may also be required to include information as to any
known or anticipated material lawsuits, as well as any prior
bankruptcy declarations by the Applicant, or by its predecessor(s), if
any.
In the case of certain Applicants, some of the above financial
submittals may not be applicable, and alternate requirements may be
specified by NEPOOL.
ONGOING FINANCIAL REVIEW
Each Participant that has not provided a cash deposit, letter of
credit, performance bond, or corporate guaranty must submit at least
annually its current rating agency report promptly upon its issuance,
and 8-K Reports promptly upon their issuance.
In addition, each Participant is responsible for informing NEPOOL in
writing within ten (10) business days of any material change in its
financial status. A material change in financial status includes, but
is not limited to, the following: a downgrade of long or short term
debt rating by a major rating agency, being placed on credit watch
with negative implication by a major rating agency, a bankruptcy
filing, insolvency, a report of a significant quarterly loss or
decline of earnings, the resignation of key officer(s), and/or the
filing of a material lawsuit that could materially adversely impact
current or future financial results. A Participant's failure to
provide this information may result in termination proceedings by
NEPOOL.
If there is a material adverse change in the financial condition of
the Participant, NEPOOL may require the Participant to provide one of
the forms of other financial assurances set forth below. If the
Participant fails to do so, NEPOOL may initiate termination
proceedings in accordance with the procedure set forth in Section
21.2(d) of the Restated NEPOOL Agreement.
OTHER FINANCIAL ASSURANCES
Applicants or Participants that do not satisfy the rating requirement
or NEPOOL's credit review process must submit instead one of the
following additional financial assurances, depending on the type of
transactions they anticipate engaging in as Participants.
In general, Participants must provide additional financial assurance
in the following amounts, based on their average or expected monthly
charges for interchange and transmission service under the Tariff
(which would include charges for Regional Network Service or Through
or Out Service) and the Restated NEPOOL Agreement (which would include
energy and other services received through NEPOOL) and NEPOOL expenses
for services, including amounts owed to ISO New England Inc. under its
tariff (collectively the "NEPOOL Charges"):
MONTHLY NEPOOL CHARGES FINANCIAL ASSURANCE REQUIREMENT
$0 - $15,000 0 months' NEPOOL Charges
$15,001 - $30,000 1 month's NEPOOL Charges
$30,001 - $50,000 2 months' NEPOOL Charges
$50,001 or more 3 1/2 months' NEPOOL Charges
The three and one-half months is based on the time required for a FERC
filing made by NEPOOL to suspend service to be effective.
Therefore, a Participant with $32,000 in monthly NEPOOL Charges that
does not satisfy the rating requirement or NEPOOL credit review
process must provide additional financial assurances in the amount of
$64,000 to NEPOOL.
In the case of new Participants, the additional financial assurance
requirement will be based on estimated monthly NEPOOL Charges, which
estimate NEPOOL has the right to adjust in light of subsequent
experience as to actual monthly NEPOOL Charges.
CASH DEPOSIT
A cash deposit for the full value of the Financial Assurance
Requirement based on actual or anticipated NEPOOL Charges, as
determined by NEPOOL, provides an acceptable form of financial
assurance to NEPOOL.
If it is necessary to use all or a portion of the deposit to pay the
Participant's obligation, the deposit must be promptly replenished to
the required level; otherwise, termination proceedings may be
initiated. In the event that actual NEPOOL Charges exceed those
anticipated, the anticipated charges will be increased accordingly and
the Participant must augment its cash deposit to reach the required
level.
The cash deposit will be invested by NEPOOL in investments as may be
designated by the Participant in direct obligations of the United
States or its agencies and interest earned will be paid to the
Participant. NEPOOL may sell or otherwise liquidate such investments
at its discretion to meet the Participant's obligations to NEPOOL.
The requirement to continue the deposit may be reviewed by NEPOOL
after one year. Consideration will be given to replacing the cash
deposit with a corporate guaranty if certain conditions are met, as
discussed below in the Corporate Guaranty section.
LETTER OF CREDIT
An unconditional and irrevocable standby letter of credit for the full
value of the Financial Assurance Requirement based on actual or
anticipated NEPOOL Charges, as determined by NEPOOL, provides an
acceptable form of financial assurance to NEPOOL. The letter of
credit will renew automatically unless the issuing bank provides
notice to NEPOOL at least ninety (90) days prior to the letter of
credit's expiration of the bank's decision not to renew the letter of
credit.
If the letter of credit amount falls below the required level because
of a drawing, it must be replenished immediately; otherwise,
termination proceedings may be initiated by NEPOOL. If actual NEPOOL
Charges exceed those anticipated, the Participant must obtain a
substitute letter of credit that equals the actual NEPOOL Charges.
The form, substance, and provider of the letter of credit must all be
acceptable to NEPOOL. The letter of credit should clearly state the
full names of the "Issuer," "Account Party" and "Beneficiary"
(NEPOOL), the dollar amount available for drawings, and should include
a statement required on the drawing certificate and other terms and
conditions that should apply. It should also specify that funds will
be disbursed, in accordance with the instructions, within one (1)
business day after due presentation of the drawing certificate. The
bank issuing the letter of credit must have a minimum corporate debt
rating of an "A-" by Standard & Poor's, or "A3" by Moody's, or "A-" by
Duff & Phelps, or "A-" by Fitch, or an equivalent short term debt
rating by one of these agencies.
Please refer to Attachment 1, which provides an example of a generally
acceptable sample "clean" letter of credit. All costs associated with
obtaining financial security and meeting the Policy provisions are the
responsibility of the Applicant or Participant.
The requirement to continue to provide a letter of credit may be
reviewed by NEPOOL after one year. Consideration will be given to
replacing the letter of credit with a corporate guaranty if certain
conditions are met, as discussed below in the Corporate Guaranty
section.
PERFORMANCE BOND
A performance bond complying with the requirements set forth herein
provides an acceptable form of financial assurance to NEPOOL. The
penal sum of such performance bond shall be in an amount equal to the
full value of the Financial Assurance Requirement based on actual or
anticipated NEPOOL charges, as determined by NEPOOL, and shall
automatically be adjusted to reflect any adjustment in such Financial
Assurance Requirement. The bond shall permit suit thereunder until
two years after the date that all of the Applicant's or Participant's
obligations to NEPOOL expire.
If the amount of penal sum of the performance bond available to NEPOOL
falls below the required level because of a payment thereon, it must
be increased to the required level immediately; otherwise, termination
proceedings may be initiated by NEPOOL. If actual NEPOOL Charges
exceed those anticipated, the Participant must either cause the penal
sum of such performance bond to be increased accordingly or must
obtain a substitute performance bond in the appropriate amount.
The form, substance and provider of the performance bond must be
acceptable to NEPOOL. The performance bond should clearly state the
full names of the "Principal," the "Surety" and the "Obligee" (NEPOOL)
and the penal sum and should include a clear statement that the surety
will promptly and faithfully perform the Participant's obligations to
NEPOOL if the Participant fails to do so. The insurance company
issuing the performance bond must be rated "A" or better by A.M. Best
& Co.
Please refer to Attachment 2, which provides an example of a generally
acceptable sample performance bond. All costs associated with
obtaining financial security and meeting the Policy provisions,
including without limitation the cost of the premiums for such
performance bond, are the responsibility of the Applicant or
Participant.
The requirement to continue to provide a performance bond may be
reviewed by NEPOOL after one year. Consideration will given to
replacing the performance bond with a corporate guaranty if certain
conditions are met, as discussed below in the Corporate Guaranty
section.
WEEKLY PAYMENTS
A Participant that does not satisfy the rating requirement may request
that, in lieu of providing one of the additional financial assurances
set forth above, a weekly billing schedule be implemented for it.
NEPOOL may, in its discretion, agree to such a request.
If NEPOOL agrees to implement a weekly billing schedule for a
Participant, the Participant shall be billed weekly in arrears on an
estimated basis for all amounts owed to NEPOOL and the System Operator
for the week, with an adjustment for each month as part of the regular
NEPOOL monthly billing to reflect any under or over collection for the
month. The Participant shall be obligated to pay each such weekly
bill within five business days after it is received.
If a weekly billing schedule is implemented for a Participant in lieu
of requiring the Participant to provide an additional financial
assurance, the Participant may be required to provide an additional
financial assurance at any time if the Participant fails to pay when
due any weekly bill.
USE OF TRANSACTION SETOFFS
Under certain conditions, NEPOOL may be obligated to make payments to
a Participant. In this event, the amount of the cash deposit, letter
of credit or performance bond required for financial assurance for the
contemplated transactions may be reduced ("setoff") by an amount equal
to NEPOOL's unpaid balance or expected billing under the other
transactions. The terms and the amount of the setoff must be approved
by NEPOOL.
CORPORATE GUARANTY
An unconditional and irrevocable corporate guaranty obtained from a
Participant's affiliated company ("Guarantor") for the full value of
the Financial Assurance Requirement based on actual or anticipated
NEPOOL Charges, as determined by NEPOOL, may provide an acceptable
form of financial assurance to NEPOOL.
If actual NEPOOL Charges exceed those anticipated, the Participant
must provide a substitute corporate guaranty that equals the actual
NEPOOL Charges.
A Participant for which a letter of credit, performance bond or cash
deposit was initially required may have the opportunity to substitute
a corporate guaranty if the following conditions are met:
1. NEPOOL determines that the Participant has satisfactorily met its
payment obligations in NEPOOL for at least one-year, which one-year
period may in whole or in part pre-date the Second Effective Date;
2. NEPOOL determines that the financial condition of the Guarantor
meets the requirements of this Policy; and
3. The form and substance of the corporate guaranty are acceptable to
NEPOOL.
Upon NEPOOL's written authorization, the Participant may substitute a
corporate guaranty that is issued by the Guarantor for a cash deposit, bank
letter of credit or performance bond when it has satisfied the conditions
stipulated above. The corporate guaranty is considered to be a lesser form
of financial assurance than a cash deposit, letter of credit or performance
bond, and therefore is allowed as an acceptable form of financial assurance
only to those Participants that have satisfied their payment obligations to
NEPOOL in a timely manner for at least one year.
The corporate guaranty may only be used if the Participant is affiliated
with a Guarantor that has greater financial assets, a strong balance sheet
and income statements, and at minimum an investment grade rating by either
Standard & Poor's, Moody's, Duff & Phelps, or Fitch.
The corporate guaranty should clearly state the identities of the
"Guarantor," "Beneficiary" and "Obligor," and the relationship between the
Guarantor and the Participant Obligor. The corporate guaranty must be duly
authorized by the Guarantor, must be signed by an officer of the Guarantor,
and must be furnished with either an opinion satisfactory to NEPOOL of the
Guarantor's counsel with respect to the enforceability of the guaranty or
accompanied by a certificate of corporate guarantee that includes a seal of
the corporation with signature of the corporate secretary. Additionally,
adequate documentation regarding the signature authority of the person
signing the corporate guaranty must be provided with the corporate
guaranty.
A corporate guaranty must also obligate the Guarantor to submit at least
annually a current rating agency report promptly upon its issuance, to
submit 8-K Reports promptly upon their issuance, to submit financial
reports if and as requested by NEPOOL within ten (10) days of such request,
and to inform NEPOOL in writing within ten (10) business days of any
material change in its financial status. A material change in financial
status includes, but is not limited to, the following: a downgrade of long
or short term debt by a major rating agency, being placed on credit watch
with negative implication by a major rating agency, a bankruptcy filing,
insolvency, a report of a significant quarterly loss or decline of
earnings, the resignation of key officer(s), and/or the filing of a
material lawsuit that could materially adversely impact current or future
financial results. A Guarantor's failure to provide this information may
result in proceedings by NEPOOL to terminate the Participant Obligor. If
there is a material adverse change in the financial condition of the
Guarantor, NEPOOL may require the Participant Obligor to provide another
form of financial assurance, either a cash deposit or a letter of credit or
a performance bond.
NON-PAYMENT OF AMOUNTS DUE
If a Participant does not pay amounts billed when due and as a result a
letter of credit or cash deposit is drawn down or a performance bond is
paid on, then the Participant must immediately replenish the letter of
credit or cash deposit to the required amount or cause the penal sum of the
performance bond to be increased to equal the required amount plus all
amounts paid thereunder. If a Participant fails to do so, NEPOOL may
initiate termination proceedings against the Participant in accordance with
the procedure set forth in Section 21.2(d) of the Restated NEPOOL
Agreement.
In order to encourage prompt payment by Participants of amounts owed to
NEPOOL and the ISO, if a Participant is delinquent two or more times within
any period of twelve months in paying on time its NEPOOL Charges, the
Participant shall pay, in addition to interest on each late payment, a late
payment charge for its second failure to pay on time, and for each
subsequent failure to pay on time, within the same twelve-month period, in
an amount equal to the greater of (i) two percent (2%) of the total amount
of such late payment and (ii) $250.00.
In the case of a former Participant that applies again for membership in
NEPOOL, a determination of delinquency shall be based on the Participant's
history of payment of its NEPOOL Charges in its last twelve (12) months of
membership.
**FOOTNOTES**
1 The System Operator will act as NEPOOL's agent in managing and
enforcing this Policy with the exception of termination of membership
issues, which are specifically reserved to the NEPOOL Participants and will
be addressed by the NEPOOL Executive Committee Membership Subcommittee,
subject to appeal to the Management Committee. Accordingly, all financial
information required pursuant to this Policy is to be provided to the
System Operator, which will keep all such information confidential in
accordance with the provisions of Section 2 of NEPOOL Criteria, Rules and
Standards No. 45.
<PAGE>
ATTACHMENT D
RULE 13
Imposition of Sanctions by the ISO
13.1 Purpose.
(a) This Rule sets forth the procedures and standards under which the
ISO can impose sanctions for certain violations of Participants'
obligations under the NEPOOL Agreement, the Interim Independent System
Operator Agreement dated July 1, 1997 between the Participants and the ISO
(as amended and supplemented, the "ISO Agreement"), the NEPOOL Tariff and
NEPOOL Rules (collectively, "Participant Obligations"). The NEPOOL Rules
embody procedures and standards of conduct that are intended to assure
Short-Term Reliability and the competitiveness and efficiency of the
markets. The ISO's ability to impose sanctions under this rule is intended
to deter noncompliance by Participants with Participant Obligations that
(i) materially impairs or threatens to materially impair Short-Term
Reliability, (ii) materially impairs or threatens to materially impair the
competitiveness or efficiency of the markets, (iii) involves unexcused
failure to follow certain ISO instructions, or (iv) involves unexcused
failure to provide to the ISO in certain circumstances accurate and timely
information required and requested by the ISO.
(b) When in the course of the conduct of system operations or its
normal monitoring of the competitiveness and efficiency of the markets, the
ISO identifies potentially Sanctionable Behavior, the ISO will make inquiry
of the Participant, express the ISO's concerns and allow the Participant to
explain its actions and the circumstances. If, following its inquiry, the
ISO reasonably concludes that the actions constitute Sanctionable Behavior,
it may (but is not required to) impose sanctions pursuant to this Rule.
(c) If the NEPOOL Rules are inadequate to assure Short-Term
Reliability and the efficiency and competitiveness of markets, the ISO is
authorized, with the Regional Market Operations Committee or unilaterally
to the extent permitted under the ISO Agreement, to promulgate new or
changed rules to address the problem. The sanctions set forth in this Rule
are intended to assure compliance by the Participants with NEPOOL Rules
from time to time in effect, and are not a substitute for the appropriate
modification of NEPOOL Rules. Where a NEPOOL Rule is ambiguous, it is
expected that the ISO will seek clarification of the rule, and will not
impose sanctions on behavior that a Participant could reasonably believe
was in compliance with Participant Obligations. Behavior not constituting
a violation by a Participant of its Participant Obligations, and not
otherwise specifically made subject to sanction by another rule, is not
Sanctionable Behavior under this Rule.
(d) It is an objective of the NEPOOL Agreement to provide for
equitable sharing of the responsibilities, benefits and costs resulting
from the establishment of markets and the maintenance of proper standards
of reliability for the NEPOOL Control Area. Each Participant is entitled
to expect performance by other Participants of their Participant
Obligations. Pursuant to the ISO Agreement, and with the approval of the
FERC, the Participants have delegated to the ISO certain authority to
interpret and implement the NEPOOL Rules on behalf of the Participants.
This Rule is intended to create an efficient deterrent to noncompliance by
Participants of their Participant Obligations. The ISO will not impose
sanctions if it believes that the consequences of Sanctionable Behavior in
the markets are a sufficient deterrent.
(e) In order for this Rule to be an effective deterrent, the
application by the ISO of this Rule must be consistent and non-
discriminatory.
(f) This Rule is not intended to sanction any failure by a
Participant to perform any Participant Obligation which occurs
notwithstanding the good faith efforts of the Participants to perform.
Neither this Rule nor the ISO's failure to impose sanctions is intended to
excuse performance by Participants of Participant Obligations.
(g) The remaining provisions of this Rule shall be interpreted and
applied consistently with this Section 13.l.
13.2 Definitions.
13.2.1 Each of the following capitalized terms used in this Rule has
the meaning given to it in Section 1.1 of Market Rule 1 (Market Information):
Automatic Low Limit
Desired Dispatch Point
Dispatchable Load
Generator
High Operating Limit
Installed Capability
Load Available for Interruption
NEPOOL Control Area
Operable Capability
Operable Capability Entitlement
Operating Reserve
Participant
Redeclaration
Scheduled Dispatch Period
Settlement
Settlement Period
TMSR or Ten-Minute Spinning Reserve
TMNSR or Ten-Minute Non-Spinning Reserve
TMOR or Thirty-Minute Operating Reserve
13.2.2 Each of the following capitalized terms used in this Rule is
defined as set forth below:
(a) ADR and alternate dispute resolution means the dispute
resolution process described in Section 13.7 or a substitute
process referred to in Section 13.7.7.
(b) ADR Neutral means a person selected and serving pursuant to
Subsection 13.7.6.3.
(c) Administrative Sanction has the meaning set forth in
paragraph 13.5.1(b).
(d) Affiliate means, with respect to any person or entity, a
person or entity that controls, is controlled by, or is
under common control with such person or entity.
(e) Bid has the meaning set forth in Market Rule 3 (Bidding
Process) or any successor Rule thereto.
(f) Bid Parameter has the meaning set forth in Market Rule 14
(Resource Performance Monitoring) and any successor Rule
thereto.
(g) FERC means the Federal Energy Regulatory Commission.
(h) Force Majeure means any act of God, labor disturbance, act
of the public enemy, war, insurrection, riot, fire, storm or
flood, explosion, breakage or accident to machinery or
equipment not due to lack of proper care or maintenance, any
order, regulation or restriction imposed by a court or
governmental military or lawfully established civilian
authorities, or any other cause or condition beyond a
party's reasonable control.
(i) Formal Warning has the meaning set forth in paragraph
13.5.l(a).
(j) Formula-Based Sanctions has the meaning set forth in
paragraph 13.5.l(c).
(k) Good Utility Practice means any practice, method, or act
engaged in or approved by a significant portion of the
electric utility industry during the relevant time period,
or any practice, method, or act which, in the exercise of
reasonable judgment in light of the facts known at the time
the decision was made, could have been expected to
accomplish the desired result at a reasonable cost
consistent with good business practices, reliability, safety
and expedition. Good Utility Practice is not limited to a
single, optimum practice, method or act to the exclusion of
others, but rather is intended to include acceptable
practices, methods, or acts generally accepted in the
region.
(l) ISO Tariff means the ISO New England Inc. FERC Tariff for
Transmission Dispatch and Power Administration Service.
(m) NEPOOL Agreement means the Restated New England Power Pool
Agreement as restated as of December 1, 1996 among the
Participants, as amended from time to time.
(n) Market Rule means any one of the Market Rules & Procedures
adopted by NEPOOL to govern the operation of the NEPOOL
markets for energy, reserves and capability, as amended from
time to time.
(o) NEPOOL Rules and Rules mean all NEPOOL rules, including the
Market Rules and the System Rules and Procedures (as defined
in the ISO Agreement).
(p) NEPOOL Tariff means the NEPOOL Open Access Transmission
Tariff, as amended from time to time.
(q) Participant Obligations has the meaning set forth in
paragraph 13.l(a).
(r) Resource has the meaning set forth in Market Rule 14
(Resource Performance Monitoring) or any successor Rule
thereto.
(s) Sanctionable Behavior has the meaning set forth in Section
13.4.
(t) Short-Term Reliability means real-time preservation of
system security of the NEPOOL Control Area while minimizing
involuntary load shedding for the current Scheduled Dispatch
Period or at any time during the next two weeks.
(u) System Emergency means any period (i) during which the ISO
is taking actions to preserve Short-Term Reliability under
NEPEX Operating Procedure No. 4 (Action During a Capacity
Deficiency) (actions 9 through 15), or NEPEX Operating
Procedure No. 7 (Action in an Emergency), or NEPEX Operating
Procedure No. 14 (Action During Extremely Light Load
Conditions) or to preserve transmission security under
emergency conditions pursuant to CRS 19 (Transmission
Operations) or any successor Rules thereto or any new
emergency Rule whether the NEPOOL emergency condition is a
result of a response to conditions in the NEPOOL Control
Area or another control area. When the need to take
emergency action is confined to a portion of the NEPOOL
Control Area, and there is no system-wide emergency,
behavior of a Participant with respect to Resources located
in the affected area will be considered as occurring during
a System Emergency.
(v) Voting Shares has the meaning set forth in the NEPOOL
Agreement.
13.3 Application of Sanctions.
13.3.1 General Rule.
The ISO may impose sanctions on any Participant that directly
engages in Sanctionable Behavior.
13.3.2 Control of Resources.
With respect to a Resource, sanctions may be imposed on the
Participant with operating control of the Resource or Bid authority for the
Resource, as appropriate. A Participant that has Bid authority with
respect to a Resource as to which its non-Participant Affiliate has
operating control will be deemed to have operating control of such Resource
for purposes of this rule. An Entitlement that does not provide a right to
operating control or Bid authority for a Resource shall not serve as a
basis for imposition of sanctions except as set forth in Section 13.3.3.
13.3.3 Special Rule for Contract Rights.
With respect to (i) a Resource that is a contract
Entitlement for a Generator or Type 3 or 4 Dispatchable Load within the
NEPOOL Control Area that is not subject to the operating control of a
Participant or (ii) a Resource that is an External Contract:
(a) The Participant with Bid authority for such a
Resource is entitled to rely in good faith on Bid Parameters and
information as to Resource availability, capability and operating
conditions supplied by the person with operating control of the Resource
unless the Participant knew, or would have known if it had exercised the
degree of diligence required by Good Utility Practice, that such Bid
Parameters or information as to Resource availability, capability and
operating condition were inaccurate.
(b) A Participant that, 30 days or more after this
Rule is submitted to the FERC, enters into a contract or new transaction
under an existing service agreement which is structured in a way that
provides such Participant Bid authority for such a Resource shall include
in such contract or a supplement thereto the language with respect to
contracts of the type entered into set forth in Appendix B to this Rule.
(c) The Participant with Bid authority for such a
Resource shall use its reasonable efforts to ensure operation of such
Resource in accordance with NEPOOL Rules, consistent with its rights under
its contract. The Participant with Bid authority shall be subject to
sanction as if it were the Participant with operating control of such
Resource if (i) the person with operating control is not a Participant and
engages in conduct that would be sanctionable if such person were a
Participant and (ii) the Participant with Bid authority fails to use
reasonable efforts, consistent with its rights under its contract, to
prevent operation that would otherwise be sanctionable.
13.3.4 Transmission Facilities.
To the extent identified in this Rule, a Participant with
operating control of transmission facilities may be subject to sanction
with respect to operation of such facilities.
13.4 Sanctionable Behavior.
An act or omission described in any of Sections 13.4.l.1 through
13.4.1.3, 13.4.2.1 through 13.4.2.3, 13.4.3.1 through 13.4.4.5 and 13.4.5
(any such act or omission being referred to as "Sanctionable Behavior") is
subject to sanction under this Rule pursuant to the process and subject to
the standards, exclusions and evaluative factors set forth in Sections 13.4
through 13.6.
13.4.1 Failure to Perform in Markets.
13.4.1.1 Failure to Provide Energy.
Failure to provide Energy means (i) a shortfall, by
more than the permitted deviation provided for in Appendix 14-A
to Market Rule 14, in attaining within the time intervals
provided in Appendix 14-A to Market Rule 14, in response to
instructions from the ISO, a Generator's High Operating Limit Bid
Parameter, or (ii) a shortfall, as measured in a manner
consistent with Appendix 14-K to Market Rule 14, by more than the
permitted deviation provided for in Appendix 14-K to Market Rule
14, in attaining, in response to instruction from the ISO, a Type
3 or 4 Dispatchable Load's Load Available for Interruption Bid
Parameter that, in either case, is intentional and is not excused
under the provisions of Subsection 13.4.1.4 or 13.4.1.5 or
Section 13.4.6.
13.4.1.2 Failure to Provide Services.
Failure to provide services means a failure, in
response to instructions from the ISO (i) to begin to move a
Resource that is on line and operating at or above its Low
Operating Limit to a new Desired Dispatch Point within the time
limit specified in Appendix 14-I to Market Rule 14, or (ii) to
provide AGC by failing, by more than the permitted deviation
provided for in Appendix 14-C to Market Rule 14, to attain within
the intervals provided for in Appendix 14-C to Market Rule 14, a
Resource's Automatic Low Limit or its Automatic High Limit in
response to AGC signals or by failing to provide AGC Services in
response to AGC signals at the Automatic Response Rate by more
than the permitted deviation and within the intervals provided
for in Appendix 14-D to Market Rule 14 that, in either case, is
intentional and is not excused under the provisions of Subsection
13.4.1.4 or 13.4.1.5 or Section 13.4.6.
13.4.1.3 Failure to Respond to Dispatch Instructions.
Failure to Respond to Dispatch Instructions means a
departure, by more than the permitted deviation provided for in
the applicable Appendix to Rule 14, in meeting, in response to
instructions from the ISO, the operating response Bid Parameter
time for a Resource (i) in starting up a Generator, (ii) in
shutting down a Generator, (iii) in interrupting a Type 3 or 4
Dispatchable Load or (iv) in turning on a Type 3 or 4
Dispatchable Load that, in each case, is intentional and is not
excused under the provisions of Subsection 13.4.1.4 or 13.4.1.5
or Section 13.4.6.
13.4.1.4 Relationship to Rule 14.
(a) Failure to perform in markets may be determined
based on Market Rule 14 audits or on other suitable information
available to the ISO.
(b) Failure to perform in markets is not subject to
sanction if a Participant makes a timely Redeclaration as
permitted under Market Rule 14 and performs in accordance with
such Redeclaration, but if a Participant's Redeclaration
constitutes a misrepresentation of a Resource's ability to
perform, this may be subject to sanction under Section 13.4.2.
13.4.1.5 Other Facility Failures Excluded.
Failure to perform in markets does not include the
effect of any failure or other unavailability of transmission,
distribution or communications facilities so long as such failure
or other unavailability is outside the reasonable control of the
Participant.
13.4.2 Inaccurate Bid or Operating Information.
13.4.2.1 Understatement of High Operating Limit.
(a) Understatement of High Operating Limit means the
submission of a High Operating Limit Bid Parameter, including any
Redeclaration of the High Operating Limit, in circumstances where
the Participant knew or should have known that the Resource could
currently attain a High Operating Limit consistent with Good
Utility Practice that is at least five percent (or 25 MW,
whichever is less) greater than the High Operating Limit Bid
Parameter submitted by the Participant, and which submission is
not excused under the provisions of paragraph (b) of this
Subsection or Subsection 13.4.2.4 or 13.4.2.5 or Section 13.4.6.
(b) The ability of a Resource to perform for short
periods during System Emergencies may vary from the long-run
performance to be expected in accordance with Good Utility
Practice. The demonstration that a Resource is capable of
higher output on a short-term basis during System Emergencies
shall not be evidence of the Resource's long-run performance.
13.4.2.2 Misrepresentation Regarding Operating Conditions.
A misrepresentation regarding operating conditions
means the making by a Participant of any statement to the ISO
regarding inability or restricted ability of its Resource to
perform, or the unavailability or restricted availability of its
transmission facilities, including any statement as to the
existence of a forced outage, Force Majeure or System Emergency
affecting its facilities, in circumstances where the Participant
knew or should have known the statement to be materially
inaccurate and such misrepresentation is not excused under the
provisions of Subsection 13.4.2.4 or 13.4.2.5 or Section 13.4.6.
13.4.2.3 Misrepresentation of Resource Availability.
Misrepresentation with respect to Resource availability
means (i) a failure by a Participant to advise the ISO as soon as
reasonably practical that a Resource or Type 3 or 4 Dispatchable
Load which the Participant has Bid for Operating Reserve could
not respond upon request in accordance with the Bid Parameters
submitted by the Participant for TMSR, TMNSR, or TMOR, in
circumstances where the Participant knew or should have known
such Resource's inability to respond, unless such failure is
excused under the provisions of Subsection 13.4.2.4 or 13.4.2.5
or Section 13.4.6, or (ii) a failure by a Participant to advise
the ISO as soon as reasonably practical that one or more of its
Resources for which the Participant will receive credit or a
payment for an hour is not available, in whole or in part, and
therefore does not meet the criteria for an Operable Capability
Entitlement in circumstances where the Participant knew or should
have known that such Resource or Resources fail to meet Operable
Capability criteria unless such failure to meet Operable
Capability criteria is excused under the provisions of Subsection
13.4.2.4 or 13.4.2.5 or Section 13.4.6.
13.4.2.4 Excuse for Good Faith Description.
(a) Resource performance and availability are subject
to, among other factors, climatic variations and emissions,
license and other limitations. A good faith effort to describe
in a Bid the technical abilities of equipment in expected
operating conditions is not subject to sanction if actual
operating conditions vary. However, a Participant is still
expected to provide an appropriate Redeclaration if operating
conditions vary materially from an applicable Bid.
(b) A Participant shall be deemed to have satisfied its
obligation to deliver accurate information as to operating
conditions or Resource availability if it had made a good faith
effort to supply accurate, responsive information; inadvertent
errors or omissions shall not be Sanctionable Behavior.
13.4.2.5 Certain Economic Decisions Excused.
Participants may make decisions affecting the
availability of a Resource for reasons relating to the economics
of operating that Resource. Such decisions may include, but are
not limited to, sale of gas available to the Participant as fuel
for such Resource, reducing output temporarily to defer
maintenance in response to unanticipated operating difficulties
or refueling, or shutting down a Resource during a period when
the Participant does not reasonably expect the Resource-specific
NEPOOL market revenues to justify operation of the Resource in
that period. For such decisions, the Participant shall not be
subject to sanction under Subsection 13.4.2.1 or 13.4.2.2 so long
as it provides to the ISO timely information that accurately
describes the nature of the Participant's decision and result of
such decision on the performance of such Resource and otherwise
acts in accordance with the applicable provisions of NEPOOL
Operating Procedure 5 (Unit Outages) or any other rule that
provides for the coordination required to minimize the impact of
Resource unavailability on Short-Term Reliability, including
obtaining permission to the extent required by Operating
Procedure 5 or such other rule. It is not the intent of this
Subsection's reference to Operating Procedure 5 or other rules to
require a Participant to provide services from all or a portion
of a Resource where the Resource-specific NEPOOL market revenues
derived from the provision of such service do not justify the
associated operating costs or lost opportunity costs of providing
such service from such Resource. It is also not the intent of
this Subsection to provide a basis for a Participant to
circumvent the Market Power Mitigation Rule or any other NEPOOL
Rule.
13.4.3 Failure to Follow ISO Instructions.
13.4.3.1 Failure to Follow Scheduling Procedures.
Failure to comply with applicable NEPOOL Rules for
scheduling or rescheduling Resource maintenance, including
failure to follow an established schedule without rescheduling,
which failure is intentional on the part of the Participant and
is not excused under the provisions of Section 13.4.6.
13.4.3.2 Failure to Follow Transmission Instructions.
Failure to follow transmission instructions means (i)
failure to follow routine ISO transmission dispatch instructions,
or (ii) failure to follow ISO operating instructions during a
System Emergency with respect to transmission facilities or (iii)
failure to comply with applicable NEPOOL Rules for scheduling or
rescheduling transmission maintenance, including failure to
follow an established schedule without rescheduling, which
failure, in any such case, is intentional on the part of the
Participant and is not excused under the provisions of Section
13.4.6.
13.4.4 Failure to Provide Information.
13.4.4.1 Routine Reports.
Failure to provide timely, accurate routine scheduled
reports, which is not excused by Subsection 13.4.4.6 or Section
13.4.6.
13.4.4.2 Emergencies or System Disturbances.
Failure to provide timely, accurate information in
response to ISO inquiries about System Emergencies or
disturbances in the NEPOOL Control Area, which is not excused by
Subsection 13.4.4.6(b) or Section 13.4.6.
13.4.4.3 Special Information Requests.
Failure by a Participant to meet an agreed schedule to
provide information that the ISO needs to perform its obligations
under the ISO Agreement, for purposes other than current
operations, that is not contained in routine scheduled reports,
or to work in good faith to establish such a schedule that is
reasonable based on the complexity of the information request and
the urgency of the ISO's need for the information that, in either
case, is not excused by Subsection 13.4.4.6 or Section 13.4.6.
13.4.4.4 Market Settlement Information.
Failure to provide timely or accurate billing or
metering information or similar information used in Settlement,
which is not excused by Subsection 13.4.4.6(b) or Section 13.4.6.
13.4.4.5 Resource Information
Failure to provide, in response to an ISO inquiry,
pertinent information that a Participant knew or should have
known about the ability of its Resource to perform, which failure
is not excused under the provisions of Subsection 13.4.4.6(b) or
Section 13.4.6.
13.4.4.6 Timeliness and Accuracy.
(a) If a Participant, for good cause, requests an
extension of time to deliver information subject to a routine
scheduled report or a special information request, the ISO shall
grant a reasonable extension, and failure to provide information
by the original delivery date shall not be Sanctionable Behavior.
(b) A Participant shall be deemed to have satisfied its
obligation to deliver accurate information if it has made a good
faith effort to supply accurate, responsive information;
inadvertent errors or omissions shall not be Sanctionable
Behavior.
13.4.5 Relationship with and Failure to Comply with Market Mitigation
Rule
(a) Certain Participant conduct may be both Sanctionable
Behavior and among the Participant actions identified by the ISO as a basis
for imposing a mitigation remedy under the Market Power Mitigation Rule.
Provided that the ISO makes the necessary findings and follows the
applicable procedures under this Rule, the ISO may impose sanctions under
this Rule for Sanctionable Behavior without regard to whether the ISO also
imposes or seeks to impose any mitigation remedy on the Participant for the
same conduct under the Market Power Mitigation Rule. In addition, provided
that the ISO makes the necessary findings and follows the applicable
procedures under the Market Power Mitigation Rule, the ISO may impose one
or more mitigation remedies under the Market Power Mitigation Rule without
regard to whether the ISO seeks to impose or imposes sanctions under this
Rule for Sanctionable Behavior that forms the basis for a mitigation
remedy.
(b) To the extent that compliance with a Market Power
Mitigation Rule remedy requires specific actions by a Participant, and such
mitigation remedy is not currently the subject of ADR review under that
Rule and has not been removed as the result of ADR review, the ISO may
sanction a Participant under this Rule for a failure by that Participant to
comply with such mitigation remedy whether or not such failure is
intentional, unless such failure is excused under the provisions of Section
13.4.6.
13.4.6 Certain Behavior Excused.
13.4.6.1 Force Majeure.
No failure by a Participant to perform Participant
Obligations shall be Sanctionable Behavior to the extent and for
the period that the Participant's inability to perform is caused
by an event or condition of Force Majeure affecting the
Participant; provided that the Participant gives notice to the
ISO of the event or condition as promptly as possible after it
knows of the event or condition and makes all reasonable efforts
to cure, mitigate or remedy the effects of the Force Majeure
event or condition.
13.4.6.2 Safety, Licensing or Other Requirements.
No failure by a Participant to perform Participant
Obligations shall be Sanctionable Behavior if the Participant is
acting in good faith to preserve the safety of persons or the
safety or integrity of equipment subject to Dispatch Instructions
or to comply with facility licensing, environmental or other
requirements of law.
13.4.6.3 Emergencies.
No failure by a Participant to perform Participant
Obligations shall be Sanctionable Behavior if the Participant is
acting in good faith and consistent with Good Utility Practice to
preserve system reliability in a System Emergency or other system
disturbance; provided that a Participant shall not override
direct ISO instructions except in cases described in Subsection
13.4.6.2.
13.4.6.4 Conflicting Directives.
To the extent that any action or omission by a
Participant is specifically required by the NEPOOL Rules or by
ISO instructions, such action or omission shall not be
Sanctionable Behavior.
13.4.6.5 Time Limitation.
No failure by a Participant to perform Participant
Obligations shall be subject to sanction if the Participant's
failure occurred more than six months prior to the ISO providing
written notice to the Participant pursuant to Section 13.6.1 of
the ISO's belief that such failure may constitute Sanctionable
Behavior.
13.4.7 Interpretation.
13.4.7.1 Intent.
Where any subsection of Section 13.4 requires that
behavior be intentional to constitute Sanctionable Behavior, the
ISO may make a finding that behavior is intentional if it finds
(i) direct evidence of intent, (ii) evidence of reckless
endangerment of Short-Term Reliability or (iii) evidence of a
pattern of unexcused behavior or circumstances from which the ISO
may reasonably infer that the behavior was intentional. In
making an inference as to intent pursuant to clause (iii) above,
the ISO shall consider the financial benefits or detriments to
the Participant of its behavior and the adequacy of any
alternative explanation provided by the Participant for its
behavior. Actions taken by a Participant in good faith shall not
be viewed as part of a pattern of unexcused behavior or otherwise
serve as the basis of a finding of intent. The ISO shall also
consider the degree to which the Participant's behavior
materially impaired or threatened to materially impair Short-Term
Reliability or the competitiveness or efficiency of the markets
and shall not infer intent pursuant to clause (iii) above unless
the ISO finds that the Participant's behavior materially impaired
or threatened to materially impair Short-Term Reliability or the
competitiveness or efficiency of the markets. Small variations
from permitted deviations or specified time limits provided in
the applicable Appendices to Rule 14 shall be presumed to be
inadvertent unless there is specific evidence to the contrary.
Behavior that would materially impair Short-Term Reliability or
the competitiveness or efficiency of the markets if it were
engaged in on a widespread basis by other Participants to the
same degree and at the same time as by the Participant engaging
in the behavior, shall be deemed to threaten to materially impair
Short-Term Reliability or the competitiveness or efficiency of
the markets, as the case may be.
13.4.7.2 Knowledge.
Where any subsection of Section 13.4 requires that the
ISO determine that a Participant "knew or should have known"
particular information as an element of a determination that
Sanctionable Behavior has occurred, the ISO may only make a
finding based on evidence that the Participant's operating
personnel, other persons responsible for communicating such
information to the ISO, or management personnel supervising such
persons (i) knew the relevant information, (ii) had the relevant
information readily available to them in normal control room
displays or operating records or (iii) failed to obtain the
relevant information, and such information was readily available
to them from third parties, but only to the extent that failure
to obtain such third-party information constitutes reckless
endangerment of Short-Term Reliability. Failure of a Resource to
attain one or more Bid Parameters on one or more occasions does
not constitute evidence that a Participant knew or should have
known that the Resource could not subsequently attain such Bid
Parameters. The ISO may consider a Participant's efforts (or
lack of efforts) to investigate a Resource's failure to perform,
its efforts to correct any deficiencies and the Participant's
conclusions as to whether they have been corrected. Failure to
obtain information that is readily available as described in
clauses (ii) or (iii) above is excused during the continuance of
the circumstances described in Sections 13.4.6.1 through
13.4.6.3.
13.5 Sanctions.
13.5.1 Amount and Nature.
Appendix A to this Rule sets forth the maximum applicable
sanctions with respect to each category of Sanctionable Behavior set forth
in Section 13.4 subject to potential increase under Section 13.5.3 in
certain circumstances. In most cases the ISO may impose three categories
of sanctions:
(a) FORMAL WARNING. A Formal Warning consists of written
notification from the ISO to a Participant stating that Sanctionable
Behavior has occurred and directing the Participant not to engage in
further Sanctionable Behavior.
(b) ADMINISTRATIVE SANCTIONS. Administrative Sanctions consist
of fixed, per-event monetary charges set forth in Appendix A imposed on
Sanctionable Behavior.
(c) FORMULA-BASED SANCTIONS. Formula-Based Sanctions are
monetary charges determined by a formula set forth in Appendix A imposed on
Sanctionable Behavior.
In imposing an Administrative Sanction or a Formula-Based
Sanction, the ISO may impose the sanction in a lesser amount than that
specified in Appendix A if it determines that the lesser amount will have a
sufficient deterrent effect.
13.5.2 Cumulative Effect.
(a) Sanctions imposed under this Rule are in addition to (i) any
consequences for Settlement set forth in Rule 14 and (ii) any mitigation
remedies available to the ISO under the Market Power Mitigation Rule.
(b) The ISO may impose both an Administrative Sanction and a
Formula-Based Sanction with respect to the same Sanctionable Behavior if it
believes both sanctions are necessary for appropriate deterrence.
(c) If a single event is sanctionable under two different
sections or subsections of this Rule, the ISO may only impose a sanction
under one of such sections or subsections; provided that if an event is
sanctionable under one or more sections or subsections and is also
sanctionable under Section 13.4.5, the ISO may impose Administrative
Sanctions under Section 13.4.5 and a sanction under one other section or
subsection. For purposes of this Rule an "event" means the facts and
circumstances constituting a single occurrence of behavior, or multiple
occurrences of the same sanctionable behavior within a day, sanctionable
under this rule. While the ISO may review a pattern of behavior, for
example, to make a finding of intent under Subsection 13.4.7.1, the pattern
of behavior may consist of multiple events, each one of which is subject to
sanction once a finding of intent is made. With respect to operating
behavior, an event relates to a single operating action. For example, if
the ISO gives an instruction to ramp up a Resource and the Participant
fails to ramp up, that failure is a single event even if it continues over
several hours and despite repeated instructions. However, providing
inaccurate information about the Resource to the ISO in response to
questions about the failure to ramp up is a separate event as is failure of
the same Resource to ramp down later in the day. Failure to provide
information relates to a particular report or a particular request for
information, and separate inaccuracies in the same report or in response to
the same information request are not separate events.
13.5.3 Increased Sanctions.
The ISO may increase Administrative Sanctions and Formula-
Based Sanctions to an amount up to triple the base amount of the sanction
in the following circumstances:
(a) If Sanctionable Behavior occurs during a System Emergency; or
(b) If the ISO determines that the Sanctionable Behavior is part
of a continuing pattern of Sanctionable Behavior for which one or more
monetary sanctions have previously been imposed upon the Participant; or
(c) If the Sanctionable Behavior is a failure by a Participant
to comply with any market mitigation remedy the ISO has imposed on such
Participant pursuant to the Market Power Mitigation Rule that is not
currently the subject of ADR review under that Rule and has not been
removed as the result of such ADR review.
13.5.4 Costs.
In addition to applicable sanctions, if a monetary sanction
is imposed, the ISO may charge to the sanctioned Participant the reasonable
costs of the ISO's investigation of the Sanctionable Behavior. Such costs
will be payable after the deadline for requesting ADR has passed and any
requested ADR proceedings are complete and the ADR decision in any such
proceeding sustains the imposition of a monetary sanction.
13.5.5 Disclosure.
Except as provided in this Section 13.5.5, the ISO will not
disclose the imposition of particular sanctions on a particular
Participant, but will make periodic reports of sanctions imposed and the
Sanctionable Behavior upon which such sanctions were imposed that do not
identify Participants by name or provide a basis for identifying such
Participants. However, the ISO may make disclosure of monetary sanctions
imposed on a particular Participant if in the ISO's judgment such
disclosure is warranted by the nature of the Sanctionable Behavior and
monetary sanctions previously imposed on the Participant have been
unsuccessful in deterring repeated Sanctionable Behavior. The ISO shall
notify the Participant before making disclosure, and the Participant shall
be entitled to obtain ADR review of the proposed disclosure. No disclosure
of a monetary sanction will be made until after the deadlines for
requesting ADR with respect to the sanction and proposed disclosure have
passed and any requested ADR proceedings are complete and the ADR decision
sustains the ISO's actions.
13.6 Process for Imposing Sanctions.
13.6.1 Observation and Communication.
If, in the conduct of system operations or Settlement, in
auditing Resource performance under Rule 14, in making inquiry of
Participants about operating problems, in monitoring the competitiveness
and efficiency of the markets, or otherwise in the receipt of information
relevant to the performance of its duties, the ISO discovers behavior that
it believes may constitute Sanctionable Behavior, the ISO shall:
(a) make a record of the information leading to ISO's belief
that Sanctionable Behavior may have occurred; and
(b) contact the Participant whose behavior is in question,
inform the Participant of the information leading to the ISO's belief that
Sanctionable Behavior may have occurred, and provide the Participant the
opportunity to discuss the behavior observed or documented by the ISO and
to offer additional facts or explanation of circumstances (i) that tend to
show that no Sanctionable Behavior occurred or (ii) that should be weighed
in determining whether to impose a sanction and, if so, what level of
sanction to impose.
The ISO may make use of information provided by third parties in
forming the basis for an inquiry to a Participant about possible
Sanctionable Behavior, and is not required to reveal the identity or
existence of such third parties. However, unsubstantiated statements by
third parties may not serve as the basis for the imposition of sanctions.
13.6.2 Consideration by ISO.
13.6.2.1 Occurrence of Sanctionable Behavior.
Based upon information in its possession and
information provided by the Participant, the ISO shall first
determine if Sanctionable Behavior has occurred. To conclude
that Sanctionable Behavior has occurred under any specific
subsection of Section 13.4, the ISO must make (i) a written
finding with respect to each element of such Sanctionable
Behavior, as set forth in the relevant subsection, including the
basis of any finding as to intent or state of knowledge under
Section 13.4.7, (ii) a written finding with respect to the
duration of the Sanctionable Behavior and (iii) a written finding
that the Sanctionable Behavior is not excused by any specific
provision of Section 13.4;
13.6.2.2 Level of Sanction.
(a) If the ISO determines that Sanctionable Behavior
has occurred, the ISO may impose a sanction under Section 13.5.
In determining which sanction or sanctions to apply, the ISO
shall consider:
o The nature of the Sanctionable Behavior and the degree of
impact on Short-Term Reliability or the competitiveness and
efficiency of markets;
o The Participant's past history of Sanctionable Behavior
and the nature of sanctions previously imposed; and
o The promptness and effectiveness of the Participant's
response in correcting the Sanctionable Behavior.
(b) Ordinarily, the ISO will issue a Formal Warning
before imposing a monetary sanction for similar behavior.
However, in cases of Sanctionable Behavior that materially
impairs Short-Term Reliability or the competitiveness or
efficiency of markets, or reflects the sanctioned Participant's
unexcused failure to obey ISO instructions, the ISO may directly
impose a monetary sanction. The ISO has no obligation to
consider a Formal Warning with respect to sanctions imposed under
Section 13.4.5. The ISO will select the level of sanction based
on its determination of the need for effective deterrence and
consistency with sanctions imposed in similar circumstances.
(c) The ISO shall make (i) a written finding with
respect to the level of sanction imposed and the factors
considered by it pursuant to Subsection 13.6.2.2(a), (ii) a
written finding with respect to the basis of any increased
sanction pursuant to Section 13.5.3, (iii) a calculation of the
amount of any monetary sanction, and (iv), if disclosure of a
sanction is proposed, a written finding as to why disclosure of
the sanction is appropriate.
13.6.3 Notice and Payments.
The ISO shall give written notice to the Participant of the
imposition of any sanction, together with its written findings as required
under Section 13.6.1 and 13.6.2. The ISO's invoice for the amount of a
sanction will be sent to the sanctioned Participant with the notice of the
sanction. Payments of sanctions received shall be reflected as a credit to
Schedule 3 charges under the ISO Tariff (allocated on a Voting Share basis)
for Participants other than the sanctioned Participant. The Participant
shall pay the amount of the sanction to the ISO or post a bond for the
amount of the sanction if the Participant is seeking review of such
sanction under the ADR process of Section 13.7 within 30 days of the date
of the ISO's invoice.
13.6.4 No Limitations on Other Rights of the ISO.
Nothing contained in this Rule shall limit the ability of
the ISO to collect information from Participants or to institute new rules
pursuant to Section 6.17 of the ISO Agreement.
13.7 ADR Review of Sanctions.
13.7.1 Actions That Can Be Reviewed.
(a) A Participant may obtain prompt ADR review of any
sanction (other than a formal warning) imposed by the ISO on that
Participant and any proposed disclosure of a sanction. Actions subject to
review are:
o Imposition of a sanction;
o Level of sanction imposed;
o Increase of a sanction under Section 13.5.3;
o Basis of calculation of a Formula-Based Sanction; and
o Proposed disclosure of a sanction.
The Participant must make a written request for ADR review
within 30 days of the delivery of the ISO's notice of imposition of the
sanction and a bill for the amount of the sanction, or the delivery of the
ISO's notice of proposed disclosure of a sanction, if the Participant
proposes to seek ADR review.
(b) A Participant may not obtain ADR review of the issuance of a
Formal Warning. It may, however, deliver to the ISO within 30 days of the
issuance of the Formal Warning a written statement of its reasons for
disputing the imposition of the Formal Warning. The ISO shall retain any
such written statement with its record of the imposition of the Formal
Warning. If the ISO relies on its prior imposition of the Formal Warning
as a basis for imposing a more severe sanction for subsequent Sanctionable
Behavior, the written statement shall also be made part of the record in
any ADR proceeding relating to the subsequent Sanctionable Behavior. The
ISO may, but is not obligated to, reconsider its decision to issue the
Formal Warning upon receipt of the written statement. If the ISO
determines to withdraw the Formal Warning, it shall so notify the
Participant in writing, and the Formal Warning shall not be referred to in
any subsequent proceeding or report or made the basis for any subsequent
action.
(c) A Participant may seek ADR review of the actions described
in Section 13.7.1(a), and any request for ADR review will be deemed to be
properly and timely made, if the Participant (i) timely pays the full
amount of the sanction imposed or (ii) timely posts a bond with the ISO
assuring payment in full of the sanction. Unless such timely payment or
posting of a bond occurs, the Participant may not obtain ADR review of the
imposition of a monetary sanction. If the Participant makes payment in
full of the sanction amount, it may, by notice accompanying its payment,
state that it is paying subject to the outcome of the ADR review. The ISO
will hold in escrow and invest any payment accompanied by such a notice
pending the outcome of the ADR process, and will refund any amount by which
the sanction is reduced or refund the entire amount if the sanction is
removed, in either case, together with interest at the rate specified in
the NEPOOL Tariff, within 30 days of the decision rendered by the ADR
Neutral.
13.7.2 Factual Basis for ADR Review; Preliminary Meeting.
(a) In connection with its request for ADR review, the
Participant shall deliver to the ISO any information that it believes is
pertinent to the ISO's decision that it wishes to submit to the ADR
Neutral. The ISO will deliver to the Participant within ten business days
thereafter a listing of all information on which it relied in making its
decision and any other information that it intends to provide to the ADR
Neutral, together with copies of any of such information not previously
supplied to the Participant. The ISO shall provide, together with its
listing of information, a notice setting a date not sooner than five
working days after the date of the notice, for a meeting between the
Participant and the ISO to discuss their differences. The Participant may
supply prior to the date of the meeting additional information in response
to any new information delivered by the ISO. If the parties are unable to
resolve their differences at the meeting, an ADR Neutral shall be selected
as provided in Section 13.7.6.3 and the written information from both
parties shall be forwarded to the ADR Neutral.
(b) The written record for the ADR review will consist of (i)
all information provided by the Participant to the ISO up to the date of
the meeting held pursuant to paragraph (a) above and identified by the
Participant as relevant to the action of the ISO under review, and (ii) all
information furnished by the ISO to the Participant that supports its prior
written determination, and (iii) position statements by the Participant and
the ISO. The Participant's statement of position shall include a brief
written statement of its disagreement with the determination of the ISO and
the specific relief that it requests. The ISO's statement of position may
supplement its written notice given pursuant to Section 13.6.3 and may
specify any change in its position from that notice. Each party shall
provide the other with copies of all material submitted by it to the ADR
Neutral.
13.7.3 Nature of Review.
On the basis of the written record and the presentations of
the ISO and the Participant, the ADR Neutral shall review the facts and
circumstances which relate to the ISO decision and the sanction imposed by
the ISO including any proposed disclosure. The ADR Neutral shall remove or
reduce the ISO's sanction or prohibit the disclosure if it concludes that
the ISO could not reasonably make its findings with respect to the
occurrence of Sanctionable Behavior pursuant to Section 13.6.2.1 or the
level of the sanction and the appropriateness of a proposed disclosure
pursuant to Section 13.6.2.2 in light of the entire factual record
presented to the ADR Neutral and applicable law. The ADR Neutral shall
separately consider the ISO's findings as to (i) the occurrence and
duration of the Sanctionable Behavior, (ii) the level of the sanction
imposed, (iii) the basis for an increased sanction imposed pursuant to
Section 13.5.3, (iv) the basis of calculation of any monetary sanction and
(v) the appropriateness of disclosure.
13.7.4 Parties to ADR Review.
The ADR review is confidential. The only parties to an ADR
review are the ISO and the Participant or Participants upon whom the
disputed sanction is imposed. The ADR review and any record are not open
to nonparties.
13.7.5 Remedies and Standard of Review.
(a) The ADR Neutral shall either affirm, reduce or remove a
sanction and affirm or prohibit disclosure of a sanction. The ADR Neutral
shall remove the ISO's sanction or prohibit the disclosure if it concludes
that the ISO could not reasonably make its findings with respect to the
occurrence of the Sanctionable Behavior pursuant to Section 13.6.2.1(i) or
(ii) or the appropriateness of a proposed disclosure pursuant to Section
13.5.5 in light of the entire factual record presented to the ADR Neutral
and applicable law. The ADR Neutral shall reduce a sanction if it
concludes that the ISO could not reasonably make its findings in light of
the entire factual record presented to the ADR Neutral and applicable law
with respect to (i) the duration of the Sanctionable Behavior pursuant to
Section 13.6.2.1(ii), or (ii) the level of the sanction imposed pursuant to
Section 13.6.2.2, or (iii) the basis of any increased sanction pursuant to
Section 13.5.3, or (iv) the calculation of a monetary sanction. The ADR
Neutral may not compromise or reduce a sanction without a specific
determination respecting one of the four factors above, and any reduction
in the sanction shall specifically identify each finding that could not
reasonably be made in light of the entire factual record presented to the
ADR Neutral and applicable law. In reaching its decision, the ADR Neutral
shall be entitled to consider the level of sanctions imposed in similar
circumstances as set forth in the ISO's periodic reports.
(b) The decision of the ADR Neutral shall be included as a part
of any file or record the ISO maintains concerning the imposition of a
sanction or the disclosure of a sanction for so long as the ISO maintains
such file or record.
13.7.6 Procedure.
13.7.6.1 Object.
It is the intent of the ADR process that disputes be
resolved as expeditiously as possible.
13.7.6.2 Confidentiality.
All information disclosed in the course of ADR review
shall be subject to confidentiality protections that satisfy the
requirements of the NEPOOL Information Policy.
13.7.6.3 Selection and Compensation of Neutrals.
(a) NEPOOL and the ISO shall identify not fewer than
three persons who they mutually agree would be appropriate to
serve as ADR Neutral under this Rule and shall obtain the advance
consent of such persons to serve as ADR Neutrals for the ADR
procedure described in this Section. An appropriate retainer may
be paid to such persons in return for their agreement to serve,
which retainer shall be made a part of the ISO's budget. The ISO
and NEPOOL may from time to time mutually select additional
persons to fill vacancies or expand the roster of ADR Neutrals as
needed. Each ADR Neutral shall enter into a confidentiality
agreement with NEPOOL and the ISO.
(b) When an ADR Neutral is to be selected from the
roster pursuant to Section 13.7.2(a), such selection shall be
made within five business days using the following procedure:
o Except as otherwise provided for in Section 13.7.6.7
below, ADR processes shall be assigned to the ADR Neutral
whose most recent ADR process handled under this Section
13.7 was longest ago.
o If the schedule of such member of the roster does not
permit meeting the required schedule for the ADR process,
that ADR process shall be assigned to the member whose most
recent ADR process was next longest ago and so forth.
o If two or more members of the roster have not handled at
least one ADR process or handled ADR processes as to which
hearings were held on the same day, the ADR process shall be
assigned among such members by lot.
The ADR Neutral shall have no financial interest in the
proceeding and no affiliation with any party that would tend to
create a conflict of interest.
13.7.6.4 Hearing.
(a) The ADR Neutral who is assigned to an ADR process
shall receive the complete written record at the time of
assignment. The ADR Neutral, in consultation with the parties,
shall schedule a hearing to be held not later than ten business
days after the ADR Neutral is selected. The schedule may be
altered either by consent of all parties or, if it is clearly not
possible to provide a fair review within the schedule given the
complexity of the record, at the direction of the ADR Neutral.
(b) After reviewing the written record, the ADR Neutral
may pose questions in writing or in a conference call with
representatives of both parties that he or she would like to have
addressed at the hearing. All parties shall be copied on any
written communications between the ADR Neutral and any other
party. There shall be no oral communications between the ADR
Neutral and any party unless all parties have been given notice
and an opportunity to participate, other than as necessary for
administrative purposes.
(c) At the hearing, each party will have up to four
hours to present its views regarding the written record and
applicable law. A party may, subject to such limitations as the
ADR Neutral may impose, pose questions to the other party;
provided that the time spent in responding to questions shall be
counted against the time limit of the party asking the question.
A party may reserve time for rebuttal. There will be no
witnesses or cross examination, but a party may choose to have
experts or counsel make all or a portion of its presentation.
The ADR Neutral is free to question any presenter.
(d) The hearing shall be held in Springfield,
Massachusetts, or such other location as the parties and the ADR
Neutral may agree.
13.7.6.5 Decision.
The ADR Neutral shall render a reasoned decision in
writing, stating whether the sanction is affirmed, reduced or
removed or the proposed disclosure may be made and setting forth
a statement of reasons for the decision, within five business
days of the hearing. Any party may request a meeting with the
ADR Neutral to discuss the ADR Neutral's decision.
13.7.6.6 Costs.
The costs of the ADR process (including any fees for
the participation of the ADR Neutral in the specific proceeding
but not including any retainer for the ADR Neutral) shall be
assessed to the Participant if the sanction is affirmed, to the
ISO if the sanction is removed, and apportioned by the ADR
Neutral among the parties if the sanction is reduced. Costs
assessed to the ISO shall be automatically included in the ISO's
budget.
13.7.6.7 Related ADR Review.
ADR reviews involving the same Resource or Resources or
Participant or Participants may be determined by the same ADR
Neutral and may, in appropriate cases, with the consent of all
parties, be consolidated subject to appropriate confidentiality
requirements.
13.7.6.8 Effect of ADR Process, Other Proceedings.
The decision of the ADR Neutral is binding on the ISO
and the Participant except as specifically provided in this
Section 13.7.6.8. The ISO may appeal the removal or reduction of
a sanction to the FERC. A Participant may appeal the imposition
of a sanction to the FERC whether or not it has requested an ADR
process. Except for this ADR process, a Participant may not seek
removal or reduction of the sanction in any forum other than the
FERC. The ISO may not contest the removal or reduction of a
sanction in any forum other than the FERC.
13.7.7 Superseding Agreement.
The provisions of Section 13.7 of this Rule shall cease to
be in effect at such time as the ISO and the Participants have in effect an
amendment to the ISO Agreement, or an agreement which replaces the ISO
Agreement, which includes ADR provisions and provides that those provisions
are to supersede Section 13.7.
<PAGE>
APPENDIX A
SANCTIONABLE EVENTS
<TABLE>
<CAPTION>
Sanctionable Event Administrative Formula-Based Sanction*
Sanction
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
I. Failure to Perform in Markets as Defined in Section 13.4.1:
A. Failure to Provide Energy as defined in Subsection 13.4.1.1:
Attain High Operating Limit $1000/Event MW Dev. * 1/2 ECP * Hrs.
Attain Loan Available for Interruption $1000/Event MW Dev. * 1/2 ECP * Hrs.
B. Failure to Provide Services as defined in Subsection 13.4.1.2:
Failure to Move to Desired Dispatch Point $1000/Event MW Dev. * 1/2 ECP * Hrs.
Activate Operating Reserve $1500/Event MW Dev. * TMNSR CP * Hrs.
AGC: $500/Event
- Automatic High Limit MW Dev. * 1/2 ECP * Hrs.
- Automatic Low Limit -----
- Automatic Response Rate Reg. Dev. * AGC CP * Hrs.
C. Failure to Respond to Dispatch Instructions as defined in
Subsection 13.4.1.3:
Start-up Generator $500/Event MW Dev. * TMNSR CP * Hrs.
Shut-down Generator $500/Event -----
Interrupt Dispatchable Load $500/Event MW Dev. * TMNSR CP * Hrs.
Turn-On Dispatchable Load $500/Event MW Dev. * TMNSR CP * Hrs.
</TABLE>
<PAGE>
APPENDIX A
SANCTIONABLE EVENTS
<TABLE>
<CAPTION>
Sanctionable Event Administrative Formula-Based Sanction*
Sanction
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
II. Inaccurate Bid or Operating Information as Defined in
Section 13.4.2:
A. Understatement of High Operating Limit as defined in
Subsection 13.4.2.1:
On Bid $1000/Event MW Dev. * 1/2 ECP * Hrs.
On Redeclaration $2000/Event MW Dev. * 1/2 ECP * Hrs.
B. Misrepresentation of Operating Conditions as defined in
Subsection 13.4.2.2: $5000/Event MW Dev. * 1/2 ECP * Hrs.
C. Misrepresentation of Resource Availability as defined in
Subsection 13.4.2.3: $1000/Event MW Dev. * 1/2 CP * Hrs.
III. Failure to Follow ISO Instructions as Defined in Section 13.4.3:
A. Failure to Follow Scheduling Procedures as defined in
Subsection 13.4.3.1:
Maintenance Scheduling Procedures $1000/Event -----
B. Failure to Follow Transmission Instructions as defined in
Subsection 13.4.3.2:
Routine Dispatch $1000/Event -----
During System Emergency $5000/Event -----
Maintenance Scheduling Procedures $1000/Event -----
</TABLE>
<PAGE>
APPENDIX A
SANCTIONABLE EVENTS
<TABLE>
<CAPTION>
Sanctionable Event Administrative Formula-Based Sanction*
Sanction
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
IV. Failure to Provide Information as Defined in Section 13.4.4: N/A
A. Routine, Scheduled Reports as defined in Subsection 13.4.4.1:
Late $500/Event
Inaccurate $1000/Event
B. Emergencies or System Disturbances as defined in Subsection
13.4.4.2: $2000/Event
C. Special Information Requests as defined in Subsection 13.4.4.3: $1000/Event
D. Market Settlement Information as defined in Subsection 13.4.4.4:
Late $2000/day
Inaccurate $2000/Event
E. Resource Information as defined in Section 13.4.4.5 $1500/Event
V. Disregard of Mitigation Remedies as Defined in Section 13.4.5 $1500/day
</TABLE>
<PAGE>
* As used in this Appendix A, capitalized terms that are defined in Section
1.1 of Rule 1 (Market Information) are used as defined therein. The following
capitalized terms or abbreviations used in this Appendix are defined as set
forth below:
MW DEV. - (i) for purposes of Section 13.4.1, the difference in megawatts
between the value fixed by the Participant's Bid for the applicable Resource
and the comparable value actually achieved by the Resource in response to ISO
instructions; (ii) for the purposes of Subsection 13.4.2.1, the difference in
megawatts between the value fixed by a Participant's Bid for the High Operating
Limit of a Resource and the actual High Operating Limit; (iii) for purposes of
Subsection 13.4.2.3, clause (i), the difference in megawatts between the Bid
Parameter fixed by a Participant's Bid for TMSR, TMNSR or TMOR for a Resource
and the actual amount of TMSR, TMNSR or TMOR which the Resource can provide;
and (iv) for purposes of Subsection 13.4.2.3, clause (ii), the number of
megawatts of Operable Capability claimed for an Operable Capability Entitlement
which cannot meet the criteria for an Operable Capability Entitlement.
REG. DEV. - the difference in Reg (a quantity used to represent a Generator's
regulating capability) between the value fixed by the Participant's Bid for the
applicable Resource to provide Automatic Generation Control (AGC) and the
comparable value actually achieved by the Resource.
ECP - the Energy Clearing Price during the hour in which the Sanctionable
Behavior occurs.
CP - the Clearing Price for the applicable market, other than Energy, during
the hour in which the Sanctionable Behavior occurs.
TMNSR CP - the Clearing Price for 10-Minute Non-Spinning Reserve during the
hour in which Sanctionable Behavior occurs.
AGC CP - the Clearing Price for AGC during the hour in which the Sanctionable
Behavior occurs.
HRS. - the number of hours (or fraction thereof) during which Sanctionable
Behavior occurs over a period not earlier than six months prior to the date the
ISO provides written notice to the Participant pursuant to Section 6.1(b).
EVENT - has the meaning specified in Subsection 5.2(c).
<PAGE>
APPENDIX B
Participants shall include language substantially as follows in contracts
for services from entities who are not NEPOOL participants:
"Article X. Compliance with NEPOOL Market Rules
Seller agrees that it is familiar with the applicable NEPOOL Market Rules
relating to the bidding of its resources into the NEPOOL markets. Seller
further agrees to comply in all respects with these Rules, and to exercise
the degree of diligence required by Good Utility Practice to assure that
Bid Parameters or information provided to Buyer as to Resource
availability, capability and operating conditions are accurate. Seller
acknowledges that market settlement consequences and sanctions may be
imposed on Buyer by ISO New England for Seller's failure to meet Bid
Parameters or to respond to operating instructions in accordance with
Section 14 of the market Rules and for Seller's actions that would
constitute Sanctionable Behavior, as defined in Section 13 of the Market
Rules, respectively. Seller agrees to comply with NEPOOL dispatch
instructions and to provide such information as ISO New England reasonably
requests in order for ISO New England to maintain Short Term Reliability
and determine whether Seller's resource is in compliance with its bid
parameters or whether a Sanctionable Behavior has occurred.
<PAGE>
ATTACHMENT E
Policy Statement
POLICY STATEMENT FOR THE FINANCIAL ASSURANCE REQUIREMENTS AND
ADMINISTRATION THEREOF FOR NEPOOL OPEN ACCESS TARIFF:
Section 11 of the above Tariff provides that each Transmission Customer
which is not a signatory of the NEPOOL Agreement ("NON-PARTICIPANT") may be
subject to a reasonable credit review by NEPOOL to assure that it has the
financial ability to pay for services provided under the Tariff. In
addition, Section 31.3 of the Tariff sets forth SPECIFIC REQUIREMENTS FOR
DEPOSITS FOR FIRM POINT-TO-POINT TRANSMISSION SERVICE to be provided at the
time of application regardless of an entity's demonstration to NEPOOL of
its financial ability to pay for services under the Tariff.
The purpose of this policy is (i) to establish for NEPOOL commercially
reasonable credit review procedures to assess the financial ability of a
Non-Participant to pay for services under the Tariff (ii) to set forth
requirements for alternative forms of security that will be deemed
acceptable to NEPOOL and consistent with commercial practices established
by the Uniform Commercial Code that protects the Participants against the
risk of non-payment by Non-Participants, and (iii) to set forth the
conditions under which NEPOOL will conduct business so as to avoid the
possibility of failure of payment for services rendered under the Tariff.
The following procedures and requirements will apply to all Non-
Participants. Generally, any such Non-Participant whose long-term debt is
not rated at least "A-" or its equivalent by Standard & Poor's (or, if such
debt is not rated by Standard & Poor's, by another nationally recognized
credit rating agency acceptable to NEPOOL), will be required to provide
additional financial assurances, which additional financial assurances may
be in the form of prepayments, cash deposits, letters of credit and
corporate guaranties, as described in detail below. The requirement to
continue the prepayment, cash deposit or letter or credit may be reviewed
by NEPOOL after one year of providing service to such Non-Participant.
FINANCIAL STATEMENTS
Each Non-Participant applicant for service under the Tariff should submit
proof of financial viability to NEPOOL's satisfaction with its application
to demonstrate the applicant's ability to meet its obligations.
Applicants for Tariffs or their parent company (if applicable) should
submit audited financial statements for at least the immediately preceding
three years including, but not limited to, the following information:
Balance Sheets
Income Statements
Statements of Cash Flows
Notes to Financial Statements
Additionally, the following information for at least the immediately
preceding three years, if available, should be included in the application:
Annual and Quarterly Reports
10-K, 10-Q, and 8-K Reports
Non-Participants should also include at least one back reference and three
(3) Utility credit references. In those cases where a Non-Participant does
not have three (3) Utility credit references, up to three (3) trade payable
vendor references may be substituted.
Non-Participants must also include any information as to any known or
anticipated material lawsuits, as well as any prior bankruptcy declarations
by the Non-Participant, or by its predecessor(s), if any.
In the case of certain municipals, public power entities or privately owned
companies, some of the above financial submittals may not be applicable.
CHANGE OF FINANCIAL STATUS
Each Non-Participant receiving service under the Tariff is responsible for
informing NEPOOL in writing, within ten (10) business days, of any material
change in its financial status during the period that the Tariff is in
effect. A material change in financial status includes, but it not limited
to the following: a downgrade of long or short term debt by a major rating
agency, a bankruptcy filing, insolvency, a report of a significant
quarterly loss or decline of earnings, the resignation of key officer(s),
and/or the filing of a material lawsuit that could materially impact
current or future financial results. NEPOOL will use this information to
evaluate whether a change to the financial assurance requirements is
necessary.
PREPAYMENT
For the Tariff listed above, prepayment of anticipated Tariff charges
provides an acceptable form of financial assurance to NEPOOL. The
prepayment must be wire transferred to the account of NEPOOL prior to the
start of the transaction. No interest will be credited by NEPOOL on the
prepayment and any overpayment in excess of the actual billed amount will
be returned. In the absence of a prepayment, service under the Tariff will
be suspended unless another acceptable form of financial assurance is
provided, as described below.
CASH DEPOSIT
For the Tariff listed above, a cash deposit provides an acceptable form of
financial assurance to NEPOOL. If the transaction is for three (3) months
or less, the amount of the deposit should equal the contemplated charges
for the transaction. If the transaction is for greater than three (3)
months, the amount of the deposit must equal at least three and one-half
consecutive months of contemplated charges. The three and one-half months
is based on the time lag between when service is initially provided and
when NEPOOL can prepare the required FERC filing to suspend service. If
the deposit amount falls below the required level, it must be replenished;
otherwise, service under the Tariff will be suspended. For a long-term
contract (greater than one year), the minimum length of time that the
deposit will be required is one year plus three and one-half months
following the effective date of the Tariff agreement. The requirement to
continue the deposit may be reviewed by NEPOOL after one year of providing
service. Consideration will be given to replacing the cash deposit with a
corporate guaranty if certain conditions are met, as discussed below in the
Corporate Guaranty section.
LETTER OF CREDIT
An unconditional and irrevocable standby letter of credit may be provided
in lieu of a prepayment or cash deposit for receipt of service under the
Tariff, but is subject to the same conditions as stated above in the
paragraph addressing cash deposits. A single letter of credit may be
established to provide financial assurance for a customer under multiple
tariffs that are in effect.
Depending on the conditions of the transaction, the duration of the letter
of credit may vary. For transactions of relatively short duration (i.e., 3
months or less), a separate renewable letter of credit may be prepared for
each transaction. For transactions of longer duration, the letter of
credit must equal at least three and one-half consecutive months of
anticipated charges for the transaction (for the same reasons stated above
under "Cash Deposit"). In either case, the letter of credit will expire
only when full payment has been received by NEPOOL and NEPOOL has provided
a written release to the financial institution that issued the letter of
credit. Consideration will be given to replacing the letter of credit with
a corporate guaranty if certain conditions are met, as discussed below in
the Corporate Guaranty section.
The form, substance, and provider of the letter of credit must all be
acceptable to NEPOOL. The letter of credit should clearly state the full
names of the "Issuer," "Account Party" and "Beneficiary" (NEPOOL), the
dollar amount available for drawings, and should include a statement
required on the drawing certificate and other terms and conditions that
should apply. It should also specify that funds will be disbursed, in
accordance with the instructions, within one (1) business day after due
presentation of the drawing certificate. The financial institution issuing
the letter of credit must have a minimum of an "A-" by Standard and Poor's
or equivalent long-term debt rating by either Moody's or one other
nationally recognized rating agency. Additionally, adequate documentation
regarding the signature authority of the person signing the letter of
credit.
Please refer to Attachment 1, which provides a generally acceptable sample
Letter of Credit.
USE OF TRANSACTION SETOFFS
Under certain conditions, NEPOOL may be involved in other transactions with
a wheeling customer in which NEPOOL is the buyer. In this event, the
amount of the prepayment, cash deposit or letter of credit required for
financial assurance for the contemplated tariff transactions may be reduced
("setoff") by an amount equal to NEPOOL's unpaid balance or expected
billing under the other transaction. The terms and the amount of the
setoff must be approved by the Tariff Account Administrator. The Tariff
Account Administrator handling the tariff transaction is responsible for
monitoring the status of the setoff and ensuring that an adequate financial
assurance balance is maintained at all times until the transaction is
settle.
CORPORATE GUARANTY
A corporate guaranty as a form of financial assurance may be appropriate
for Non-Participants who are owned by a parent company ("Guarantor"). A
company for which a letter of credit, prepayment or cash deposit was
initially required may have the opportunity to substitute to a corporate
guaranty if the following conditions are met:
1. NEPOOL determines that the Non-Participant has satisfactorily met
its payment obligations for service rendered under the Tariff for
at least one-year;
2. NEPOOL determines that there has been no deterioration of the
financial condition of either the Non-Participant or its
Guarantor, based on audited financial statements; and
3. The form of the corporate guaranty is acceptable to NEPOOL.
Upon NEPOOL's written authorization, the Non-Participant may substitute a
corporate guaranty that is issued by the Guarantor for a cash deposit or
bank letter of credit when it has satisfied the conditions stipulated
above. The corporate guaranty is considered to be a lesser form of
financial assurance than a cash deposit or letter of credit, and therefore
is allowed as an acceptable form of financial assurance only to those
customers which have satisfied their payment obligations to NEPOOL in a
timely manner for at least one year.
The corporate guaranty may only be used if the customer is a direct or
indirect subsidiary of a larger corporate entity that has greater financial
assets, a strong balance sheet and income statement, and an investment
grade long-term debt rating (Standard & Poor's "A-" or better). If the
long term credit rating of the Guarantor is not considered to be at least
investment grade, the corporate guaranty may not be used to replace the
Non-Participant's required prepayment cash, deposit or letter of credit.
The corporate guaranty should clearly state the identities of the
"Guarantor," "Beneficiary," and "Obligor," and the relationship between the
Guarantor and the Non-Participant Obligor. Additionally, it should specify
the term of the guaranty and the conditions under which payment to the
Beneficiary will be made. The corporate guaranty must be signed by an
officer of the Guarantor. Additionally, adequate documentation regarding
the signature authority of the person signing the corporate guaranty must
be provided with the corporate guaranty.
<PAGE>
SAMPLE LETTER OF CREDIT
Three Riverway, Suite 1700
Houston, Texas 77056
Tel: (713) 629-8666
Fax: (713) 629-7533 April 6, 1995
Telex: 6868916, 794538, 794505
Swift: ABNAUS4H
IRREVOCABLE STANDBY LETTER OF CREDIT NO.
EXPIRY: 15IAN96 AT OUR COUNTERS
WE DO HEREBY ISSUE AN IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT
BY ORDER OF AND FOR THE ACCOUNT OF ON BEHALF OF
IN FAVOR OF SERVICE COMPANY ("NUSCO") IN AN AMOUNT
NOT EXCEEDING US$400,000.00 (UNITED STATES DOLLARS FOUR HUNDRED THOUSAND
AND 00/100) AGAINST PRESENTATION TO US OF A DRAWING CERTIFICATE SIGNED BY A
PURPORTED OFFICER OR AUTHORIZED AGENT OF NUSCO AND DATED THE DATE OF
PRESENTATION CONTAINING THE FOLLOWING STATEMENT:
"THE UNDERSIGNED HEREBY CERTIFIES TO ABN AMRO BANK N.V., HOUSTON
AGENCY ("BANK"), WITH REFERENCE TO IRREVOCABLE NON-TRANSFERABLE
STANDBY LETTER OF CREDIT NO. ISSUED BY ABN AMRO BANK N.V.,
HOUSTON AGENCY IN FAVOR OF
THAT HAS FAILED TO PAY
NUSCO IN ACCORDANCE WITH THE TERMS AND PROVISIONS OF THE 1995 POWER
PURCHASE AGREEMENT BETWEEN AND , AND THUS IS
DRAWING UPON THE LETTER OF CREDIT IN AN AMOUNT EQUAL TO $__________"
IF PRESENTATION OF ANY DRAWING CERTIFICATE IS MADE ON A BUSINESS DAY AND
SUCH PRESENTATION IS MADE ON OR BEFORE 10:00 A.M. HOUSTON TIME, THE BANK
SHALL SATISFY SUCH DRAWING REQUEST ON THE SAME BUSINESS DAY. IF THE
DRAWING CERTIFICATE IS RECEIVED AFTER 10:00 A.M. HOUSTON TIME, THE BANK
WILL SATISFY SUCH DRAWING REQUEST ON THE NEXT BUSINESS DAY. FOR THE
PURPOSES OF THIS SECTION, A BUSINESS DAY MEANS A DAY, OTHER THAN A SATURDAY
OR SUNDAY, ON WHICH COMMERCIAL BANKS ARE NOT AUTHORIZED OR REQUIRED TO BE
CLOSED IN NEW YORK, NEW YORK.
DISBURSEMENTS SHALL BE IN ACCORDANCE WITH THE INSTRUCTIONS OF
THE FOLLOWING TERMS AND CONDITIONS APPLY:
THIS LETTER OF CREDIT SHALL EXPIRE AT THE CLOSE OF BUSINESS JANUARY
15, 1996.
THE AMOUNT WHICH MAY BE DRAWN BY YOU UNDER THIS LETTER OF CREDIT SHALL
BE AUTOMATICALLY REDUCED BY THE AMOUNT OF ANY DRAWINGS HEREUNDER. ANY
NUMBER OF PARTIAL DRAWINGS ARE PERMITTED FROM TIME TO TIME HEREUNDER.
ALL COMMISSIONS AND CHARGES WILL BE BORNE BY
THIS LETTER OF CREDIT IS NOT TRANSFERABLE OR ASSIGNABLE.
THIS LETTER OF CREDIT DOES NOT INCORPORATE AND SHALL NOT BE DEEMED
MODIFIED, AMENDED OR AMPLIFIED BY REFERENCE TO ANY DOCUMENT,
INSTRUMENT OR AGREEMENT (A) THAT IS REFERRED TO HEREIN (EXCEPT FOR THE
UCP, AS DEFINED BELOW) OR (B) IN WHICH THIS LETTER OF CREDIT IS
REFERRED TO OR TO WHICH THIS LETTER OF CREDIT RELATES.
THIS LETTER OF CREDIT SHALL BE GOVERNED BY THE UNIFORM CUSTOMS AND
PRACTICE FOR DOCUMENTARY CREDITS, 1993 REVISION, INTERNATIONAL CHAMBER
OF COMMERCE PUBLICATION NO. 500 (THE "UCP"), EXCEPT TO THE EXTENT THAT
TERMS HEREOF ARE INCONSISTENT WITH THE PROVISIONS OF THE UCP,
INCLUDING BUT NOT LIMITED TO ARTICLES 13(b) AND 17 OF THE UCP, IN
WHICH CASE THE TERMS OF THE LETTER OF CREDIT SHALL GOVERN.
THIS LETTER OF CREDIT MAY NOT BE AMENDED, CHANGED OR MODIFIED WITHOUT
THE EXPRESS WRITTEN CONSENT OF NUSCO, AND ABN
AMRO BANK N.V., HOUSTON AGENCY.
WE HEREBY ENGAGE WITH YOU THAT DOCUMENTS DRAWN UNDER AND IN COMPLIANCE WITH
THE TERMS OF THIS LETTER OF CREDIT SHALL BE DULY HONORED UPON PRESENTATION
AS SPECIFIED.
PRESENTATION OF ANY DRAWING CERTIFICATE UNDER THE STANDBY LETTER OF CREDIT
MAY BE SENT TO ABN AMRO BANK BY COURIER, CERTIFIED MAIL, REGISTERED MAIL,
TELEGRAM, TELEX TO THE ADDRESS SET FORTH BELOW, OR SUCH OTHER ADDRESS AS
MAY HEREAFTER BE FURNISHED BY ABN AMRO BANK. OTHER NOTICES CONCERNING THIS
STANDBY LETTER OF CREDIT MAY BE SENT BY FACSIMILE OR SIMILAR COMMUNICATIONS
FACILITY TO ITS RESPECTIVE ADDRESS SET FORTH BELOW. ALL SUCH NOTICES AND
COMMUNICATIONS SHALL BE EFFECTIVE WHEN ACTUALLY RECEIVED BY THE INTENDED
RECIPIENT PARTY.
IF TO THE BENEFICIARY OF THIS LETTER OF CREDIT:
IF TO THE ACCOUNT PARTY:
IF TO ABN AMRO BANK N.V., HOUSTON AGENCY:
ABN AMRO BANK N.V.
THREE RIVERWAY, SUITE 1700
HOUSTON, TEXAS 77056
ATTN: LETTERS OF CREDIT DEPARTMENT
FAX: (713) 629-7533
TELEX: 794538, 794505, OR 6868916
_____________________________ _____________________________
C.A. ISELT S.J. JEBAMONY
TRADE SERVICES MANAGER TRADE SERVICES MANAGER
Exhibit 10.35.1
Northeast Utilities
Incentive Plan
Adopted by Northeast Utilities
Board of Trustees on January 13, 1998
Approved by Northeast Utilities
Shareholders on May 12, 1998
ARTICLE I
PURPOSE
The purpose of the Northeast Utilities Incentive Plan (the "Plan") is to
provide (i) designated employees of the Company (as hereinafter defined) and
(ii) non-employee members of the Board of Trustees (the "Board") of Northeast
Utilities, a Massachusetts business trust, ("NU") with the opportunity to
receive annual incentive compensation and grants of incentive stock options,
nonqualified stock options, stock appreciation rights, restricted stock and
performance units. The Company believes that the Plan will assist it in
recruiting talented employees who will contribute materially to the growth of
the Company, thereby benefitting NU's shareholders, and will align the
economic interests of the participants with those of the shareholders.
ARTICLE II
ADMINISTRATION
1. Committee. The Plan shall be administered and interpreted by the
Board's Compensation Committee, or the person or persons to which such
committee delegates any of its functions under the Plan (the "Committee").
The Committee may consist of two or more persons appointed by the Board, all
of whom shall be "outside directors" as defined under section 162(m) of the
Internal Revenue Code of 1986, as amended (the "Code") and related Treasury
regulations and "non-employee directors" as defined under Rule 16b-3 under
the Securities Exchange Act of 1934, as amended (the "Exchange Act").
However, the Board may ratify or approve any grants as it deems appropriate
or as are submitted by the Committee.
2. Committee Authority. The Committee shall have the sole authority
to (i) establish, and review the Company's and the Grantee's, as defined
below, performance against, annual goals for purpose of the annual incentives
to be distributed and determine the individuals to whom grants shall be made
under the Plan, (ii) determine the type, size and terms of the grants to be
made to each such individual, (iii) determine the time when the grants will
be made and the duration of any applicable exercise or restriction period,
including the criteria for exercisability and the acceleration of
exercisability and (iv) deal with any other matters arising under the Plan.
3. Committee Determinations. The Committee shall have full power and
authority to administer and interpret the Plan, to make factual
determinations and to adopt or amend such rules, regulations, agreements and
instruments for implementing the Plan and for the conduct of its business as
it deems necessary or advisable, in its sole discretion. The Committee's
interpretations of the Plan and all determinations made by the Committee
pursuant to the powers vested in it hereunder shall be conclusive and binding
on all persons having any interest in the Plan or in any awards granted
hereunder. All powers of the Committee shall be executed in its sole
discretion, in the best interest of the Company, not as a fiduciary, and in
keeping with the objectives of the Plan and need not be uniform as to
similarly situated individuals.
ARTICLE III
ANNUAL INCENTIVE AWARDS
1. Eligibility for Participation. Each employee of the Company
classified as a Vice President or higher (an "Executive Employee") shall be
eligible to receive an annual incentive award (an "Award") under the Plan.
2. Annual Awards.
(a) As soon as practicable after the start of each fiscal year of NU,
but in any event within 90 days, the Committee shall set the financial target
for the Company which shall be the basis for determining the Awards to be
paid to each Executive Employee for such fiscal year. The financial target
shall be based on the growth of NU's stock price, earnings per share, net
earnings, operating earnings, return on assets, shareholder return, return on
equity, growth in assets, unit volume, sales, market share, or strategic
business criteria consisting of one or more objectives based on meeting
specified revenue goals, market penetration goals, geographic business
expansion goals, cost targets or goals relating to acquisitions or
divestitures and the Committee shall communicate the target and the
percentages (including minimums and maximums) for each Executive Employee
applicable to each level of achievement against the target set. In no event
may an individual Award for an Executive Employee exceed $3,500,000.
(b) The maximum amount of an Award for an Executive Employee shall be
based upon the Company's performance compared against the financial target
set for that fiscal year. The actual amount of the Award for any Executive
Employee may be reduced by the Committee if the Executive Employee does not
satisfy one or more of the individual financial or nonfinancial objectives
set by the Committee for that Executive Employee as of the beginning of the
relevant fiscal year. Any such objectives for an Executive Employee shall be
set by the Committee and announced to the affected Executive Employee no
later than 90 days after the commencement of the relevant fiscal year of NU.
(c) The Committee shall certify and announce the Awards that will be
paid by the Company to each Executive Employee as soon as practicable
following the final determination of the Company's financial results for the
relevant fiscal year. Payment shall normally be made, in cash, or in shares
of Company Stock (as hereinafter defined) or Options (as hereinafter defined)
the value of which shall equal the amount to be distributed, all as
determined by the Committee, within 90 days following the end of such fiscal
year, provided that the Executive Employee has not separated from employment
by the Company prior to the date that payment is due except as otherwise
specifically provided in a contract between the Company and the Executive
Employee. If an Executive Employee's employment terminated for Retirement
(as hereinafter defined), death or Disability (as hereinafter defined) a full
Award shall be paid (unless such event occurred during the fiscal year for
which the Award is earned, in which case the Award will be pro-rated as of
the date of termination) when all other payments are made in accordance with
the first sentence of this Section.
ARTICLE IV
STOCK-BASED GRANTS
1. Grants. Grants under the Plan may consist of grants of incentive stock
options ("Incentive Stock Options") or nonqualified stock options
("Nonqualified Stock Options")(Incentive Stock Options and Nonqualified Stock
Options are collectively referred to as "Options"), restricted stock
(Restricted Stock"), stock appreciation rights ("SARs"), and/or performance
units ("Performance Units") (hereinafter collectively referred to as
"Grants"). All Grants shall be subject to the terms and conditions set forth
herein and to such other terms and conditions consistent with this Plan as
the Committee deems appropriate and as are specified in writing by the
Committee to the individual in a grant instrument or an amendment to the
grant instrument (the "Grant Instrument"). The Committee shall approve the
form and provisions of each Grant Instrument. Grants under a particular
Section of the Plan need not be uniform as among the Grantees, as defined
below.
2. Eligibility for Participation.
(a) Eligible Persons. All employees of the Company ("Employees"),
including Employees who are officers or members of the Board, contractors of
the Company ("Contractors"), and members of the Board who are not Employees
("Non-Employee Trustees") shall be eligible to receive Grants under the Plan.
Contractors shall be eligible to receive Grants only of Nonqualified Stock
Options. Non-Employee Trustees shall be eligible to receive Grants only
under Article V of the Plan.
(b) Selection of Grantees. The Committee shall select the Employees
and Contractors to receive Grants and shall determine the number of shares of
Company Stock subject to a particular Grant in such manner as the Committee
determines. Employees, Contractors and Non-Employee Trustees who receive
Grants under this Plan shall hereinafter be referred to as "Grantees".
(c) Collective Bargaining Employees. Anything to the contrary in this
Plan notwithstanding, no Employee whose terms and conditions of employment
are subject to negotiation with a collective bargaining agent shall be
eligible to receive Grants under this Plan until the agreement between the
Company and such collective bargaining agent with respect to the Employee
provides for participation in the Plan.
3. Granting of Options.
(a) Number of Shares. The Committee shall determine the number of
shares of Company Stock that will be subject to each Grant of Options to
Employees and Contractors subject to the overall limits of Article IX.
(b) Type of Option and Price.
(i) The Committee may grant Incentive Stock Options that are
intended to qualify as "incentive stock options" within the meaning of
section 422 of the Code or Nonqualified Stock Options that are not intended
so to qualify or any combination of Incentive Stock Options and Nonqualified
Stock Options, all in accordance with the terms and conditions set forth
herein. Incentive Stock Options may be granted only to Employees.
Nonqualified Stock Options may be granted to Employees, Contractors and Non-
Employee Trustees.
(ii) The purchase price (the "Exercise Price") of Company Stock
subject to an Option shall be determined by the Committee and shall be equal
to or greater than the Fair Market Value (as defined below) of a share of
Company Stock on the date the Option is granted; provided, however, that an
Incentive Stock Option may not be granted to an Employee who, at the time of
grant, owns stock possessing more than 10 percent of the total combined
voting power of all classes of stock of the Company or any parent or
subsidiary of the Company, unless the Exercise Price per share is not less
than 110% of the Fair Market Value of Company Stock on the date of grant.
(iii) If the Company Stock is publicly traded, then the Fair
Market Value per share shall be the closing price of the Company Stock as
reported in the Wall Street Journal as composite transactions for the
relevant date (or the latest date for which such price was reported if such
date is not a business day), or if not available, determined as follows: (x)
if the principal trading market for the Company Stock is the New York Stock
Exchange, the last reported sale price thereof on the relevant date or (if
there were no trades on that date) the latest preceding date upon which a
sale was reported, (y) if the principal trading market for the Company Stock
is a national securities exchange other than the New York Stock Exchange or
is the Nasdaq National Market, the last reported sale price thereof on the
relevant date or (if there were no trades on that date) the latest preceding
date upon which a sale was reported, or (z) if the Company Stock is not
principally traded on such exchange or market, the mean between the last
reported "bid" and "asked" prices of Company Stock on the relevant date, as
reported on Nasdaq or, if not so reported, as reported by the National Daily
Quotation Bureau, Inc. or as reported in a customary financial reporting
service, as applicable and as the Committee determines. If the Company Stock
is not publicly traded or, if publicly traded, is not subject to reported
transactions or "bid" or "asked" quotations as set forth above, the Fair
Market Value per share shall be as determined by the Committee.
(c) Option Term. The Committee shall determine the term of each
Option. The term of any Option shall not exceed ten years from the date of
grant. However, an Incentive Stock Option that is granted to an Employee
who, at the time of grant, owns stock possessing more than 10 percent of the
total combined voting power of all classes of stock of the Company, or any
parent or subsidiary of the Company, may not have a term that exceeds five
years from the date of grant.
(d) Exercisability of Options. Options shall become exercisable in
accordance with such terms and conditions, consistent with the Plan, as may
be determined by the Committee and specified in the Grant Instrument. The
Committee may accelerate the exercisability of any or all outstanding Options
at any time for any reason.
(e) Termination of Employment, Retirement, Disability or Death.
(i) Except as provided below, an Option may only be exercised
while the Grantee is employed by, or providing service to, the Company as an
Employee, a Contractor, or a member of the Board. In the event that a
Grantee ceases to be employed by, or provide service to, the Company for any
reason other than a "Retirement," "Disability," death, or termination for
"Cause" (as hereinafter defined), any Option which is otherwise exercisable
by the Grantee shall terminate unless exercised within 90 days after the date
on which the Grantee ceases to be employed by, or provide service to, the
Company (or within such other period of time as may be specified by the
Committee), but in any event no later than the date of expiration of the
Option term. Any of the Grantee's Options that are not otherwise exercisable
as of the date on which the Grantee ceases to be employed by, or provide
service to, the Company shall terminate as of such date.
(ii) In the event the Grantee ceases to be employed by, or provide
service to, the Company on account of a termination for Cause by the Company,
any Option held by the Grantee shall terminate as of the date the Grantee
ceases to be employed by, or provide service to, the Company.
(iii) In the event the Grantee ceases to be employed by, or
provide service to, the Company because the Grantee Retires or is Disabled,
any Option which is otherwise exercisable by the Grantee shall terminate
unless exercised within one year after the date on which the Grantee ceases
to be employed by, or provide service to, the Company (or within such other
period of time as may be specified by the Committee), but in any event no
later than the date of expiration of the Option term. Any of the Grantee's
Options which are not otherwise exercisable as of the date on which the
Grantee ceases to be employed by, or provide service to, the Company shall
terminate as of such date.
(iv) If the Grantee dies while employed by, or providing service
to, the Company or within 90 days after the date on which the Grantee ceases
to be employed or provide service on account of a termination specified in
Section 5(e)(i) above (or within such other period of time as may be
specified by the Committee), any Option that is otherwise exercisable by the
Grantee shall terminate unless exercised within one year after the date on
which the Grantee ceases to be employed by, or provide service to, the
Company (or within such other period of time as may be specified by the
Committee), but in any event no later than the date of expiration of the
Option term. Any of the Grantee's Options that are not otherwise exercisable
as of the date on which the Grantee ceases to be employed by, or provide
service to, the Company shall terminate as of such date.
(v) For purposes of this Plan:
(A) "Cause" shall mean, except to the extent specified
otherwise by the Committee acting on behalf of the Company, (i) the Grantee's
conviction of a felony, (ii) in the reasonable determination of the
Committee, the Grantee's (x) commission of an act of fraud, embezzlement, or
theft in connection with the Grantee's duties in the course of the Grantee's
employment with the Company, (y) acts or omissions causing intentional,
wrongful damage to the property of the Company or intentional and wrongful
disclosure of confidential information of the Company, or (z) engaging in
gross misconduct or gross negligence in the course of the Grantee's
employment with the Company, or (iii) the Grantee's material breach of his or
her obligations under any written agreement with the Company if such breach
shall not have been remedied within 30 days after receiving written notice
from the Committee specifying the details thereof. For purposes of this
Program, an act or omission on the part of a Grantee shall be deemed
"intentional" only if it was not due primarily to an error in judgment or
negligence and was done by Grantee not in good faith and without reasonable
belief that the act or omission was in the best interest of the Company. In
the event a Grantee's employment or service is terminated for cause, in
addition to the immediate termination of all Grants, the Grantee shall
automatically forfeit all shares underlying any exercised portion of an
Option for which the Company has not yet delivered the share certificates,
upon refund by the Company of the Exercise Price paid by the Grantee for such
shares.
(B) "Disability" shall mean a Grantee's becoming disabled
within the meaning of the Company's long-term disability plan.
(C) "Employed by, or provide service to, the Company" shall
mean employment or service as an Employee, Contractor or member of the Board
(so that, for purposes of exercising Options and SARs and satisfying
conditions with respect to Restricted Stock and Performance Units, a Grantee
shall not be considered to have terminated employment or service until the
Grantee ceases to be an Employee, Contractor and member of the Board), unless
the Committee determines otherwise.
(D) "Retired" shall mean a termination of employment from the
Company on or after attaining age 65 or eligibility for normal or early
retirement under any retirement plan maintained by the Company.
(f) Exercise of Options. A Grantee may exercise an Option that has
become exercisable, in whole or in part, by delivering a notice of exercise
to the Company with payment of the Exercise Price. The Grantee shall pay the
Exercise Price for an Option as specified by the Committee (x) in cash, (y)
with the approval of the Committee, by delivering shares of Company Stock
owned by the Grantee (including Company Stock acquired in connection with the
exercise of an Option or Restricted Stock, as defined below, granted under
this Plan, subject to such restrictions as the Committee deems appropriate
including placing the same restrictions on the shares of Company Stock
obtained through the exchange of the Restricted Stock) and having a Fair
Market Value on the date of exercise equal to the Exercise Price or (z) by
such other method as the Committee may approve, including payment through a
broker in accordance with procedures permitted by Regulation T of the Federal
Reserve Board. Shares of Company Stock used to exercise an Option shall have
been held by the Grantee for the requisite period of time to avoid adverse
accounting consequences to the Company with respect to the Option. The
Grantee shall pay the Exercise Price and the amount of any withholding tax
due at the time of exercise.
(g) Limits on Incentive Stock Options. Each Incentive Stock Option
shall provide that, if the aggregate Fair Market Value of the stock on the
date of the grant with respect to which Incentive Stock Options are
exercisable for the first time by a Grantee during any calendar year, under
the Plan or any other stock option plan of the Company exceeds $100,000, then
the option, as to the excess, shall be treated as a Nonqualified Stock
Option. An Incentive Stock Option shall not be granted to any person who is
not an Employee of the Company.
ARTICLE V
STOCK OPTION GRANTS TO NON-EMPLOYEE TRUSTEES
1. Formula Option Grants to Non-Employee Trustees. A Non-Employee
Trustee shall be entitled to receive Nonqualified Stock Options in accordance
with this Article V.
(a) Initial Grant. Each Non-Employee Trustee who first becomes a
member of the Board after the effective date of this Plan shall receive, on
the date as of which he or she first becomes a member of the Board, a grant
of a Nonqualified Stock Option to purchase 2,500 shares of Company Stock.
(b) Annual Grants. On each date that NU holds its annual meeting of
shareholders, commencing with the 1998 annual meeting, each Non-Employee
Trustee who is in office immediately after the annual election of directors
(other than a director who is first elected to the Board at such meeting)
shall receive a grant of a Nonqualified Stock Option to purchase 2,500 shares
of Company Stock. The date of grant of each such annual Grant shall be the
date of the annual meeting of the Company's shareholders.
(c) Exercise Price. The Exercise Price per share of Company Stock
subject to an Option granted under this Article shall be equal to the Fair
Market Value of a share of Company Stock on the date of grant.
(d) Option Term and Exercisability. The term of each Option granted
pursuant to this Article shall be 10 years. Options granted under this
Article shall vest one-half on the date of grant and the other one-half on
the first anniversary of the date of grant if the Non-Employee Trustee is
still a member of the Board on each such date. Options shall be exercisable
in accordance with the provisions of Article IV, Section 3(e) except that
only the provisions of subsections (e)(i), (iii) where the Non-Employee
Trustee ceases to serve on the Board on or after age 70 and (iv) shall be
applicable.
(e) Payment of Exercise Price.
(i) The Non-Employee Trustee shall pay the Exercise Price for an
Option (x) in cash, (y) by delivering shares of Company Stock owned by the
Non-Employee Trustee and having a Fair Market Value on the date of exercise
equal to the Exercise Price or (z) by payment through a broker in accordance
with procedures permitted by Regulation T of the Federal Reserve Board.
Shares of Company Stock used to exercise an Option shall have been held by
the Grantee for the requisite period of time to avoid adverse accounting
consequences to the Company with respect to the Option. The Non-Employee
Trustee shall pay the Exercise Price at the time of exercise. Shares of
Company Stock shall not be issued upon exercise of an Option until the
Exercise Price is fully paid.
(ii) A Grantee may exercise an Option granted under this Article by
delivering to the Committee a notice of exercise as described below, with
accompanying payment of the Exercise Price in accordance with Subsection (i)
above. The notice of exercise may instruct the Company to deliver shares of
Company Stock due upon the exercise of the Option to any registered broker or
dealer designated by the Committee in lieu of delivery to the Grantee, and
shall designate the account into which the shares are to be deposited.
(f) Applicability of Plan Provisions. Except as otherwise provided in
this Article, Nonqualified Stock Options granted to Non-Employee Trustees
shall be subject to the provisions of this Plan applicable to Nonqualified
Stock Options granted to other persons, provided however that (i) if an event
described in Article IV, Section 3(b) occurs, appropriate adjustments, as
described in that Section, shall be made automatically, (ii) with respect to
the provisions of Article IV, Section 3(e), the Committee shall not have
discretion to modify the terms of such provisions in the Grant Instrument,
and (iii) in the event of a Change of Control (as defined in Article XI), the
provisions of Article XI, Section 2 shall apply to Options granted pursuant
to this Article, except that the Committee shall not have discretion under
subsection (c) thereof to modify the automatic provisions of that Section.
(g) Administration. The provisions of this Article are intended to
operate automatically and not require administration. To the extent that any
administrative determinations are required, any determinations with respect
to the provisions of this Article shall be made by the members of the Board
who are not eligible to receive Grants under this Article, but in no event
shall such determinations affect the eligibility of Grantees, the
determination of the Exercise Price, the timing of the Grants or the number
of shares subject to Options granted hereunder. If at any time there are not
sufficient shares available under the Plan to permit an automatic Grant as
described in this Article, the Grant shall be reduced pro rata (to zero, if
necessary) so as not to exceed the number of shares then available under the
Plan.
ARTICLE VI
RESTRICTED STOCK GRANTS
1. Restricted Stock Grants. The Committee may issue or transfer
shares of Company Stock to an Employee with such restrictions as the
Committee deems appropriate ("Restricted Stock"). The following provisions
are applicable to Restricted Stock:
(a) General Requirements. Shares of Company Stock issued or
transferred pursuant to Restricted Stock Grants may be issued or transferred
in exchange for services performed or to
be performed. The Committee may establish conditions under which
restrictions on shares of Restricted Stock shall lapse over a period of time
or according to such other criteria as the Committee deems appropriate. The
period of time during which the Restricted Stock will remain subject to
restrictions will be designated in the Grant Instrument as the "Restriction
Period."
(b) Number of Shares. The Committee shall determine the number of
shares of Company Stock to be issued or transferred pursuant to a Restricted
Stock Grant and the restrictions applicable to such shares, subject to the
limitations contained in Article IX.
(c) Requirement of Employment or Service. If the Grantee ceases to be
employed by, or provide service to, the Company during a period designated in
the Grant Instrument as the Restriction Period, or if other specified
conditions are not met, the Restricted Stock Grant shall terminate as to all
shares covered by the Grant as to which the restrictions have not lapsed, and
those shares of Company Stock must be immediately returned to the Company.
The Committee may, however, provide for complete or partial exceptions to
this requirement as it deems appropriate.
(d) Restrictions on Transfer and Legend on Stock Certificate. During
the Restriction Period, a Grantee may not sell, assign, transfer, pledge or
otherwise dispose of the shares of Restricted Stock except to a Successor
Grantee, as defined below. Each certificate for a share of Restricted Stock
shall contain a legend giving appropriate notice of the restrictions in the
Grant. The Grantee shall be entitled to have the legend removed from the
stock certificate covering the shares subject to restrictions when all
restrictions on such shares have lapsed. The Committee may determine that
the Company will not issue certificates for shares of Restricted Stock until
all restrictions on such shares have lapsed, or that the Company will retain
possession of certificates for shares of Restricted Stock until all
restrictions on such shares have lapsed.
(e) Right to Vote and to Receive Dividends. Unless the Committee
determines otherwise, during the Restriction Period, the Grantee shall have
the right to vote shares of Restricted Stock and to receive any dividends or
other distributions paid on such shares, subject to any restrictions deemed
appropriate by the Committee.
(f) Lapse of Restrictions. All restrictions imposed on Restricted
Stock shall lapse upon the expiration of the applicable Restriction Period
and the satisfaction of all conditions imposed by the Committee. The
Committee may determine, as to any or all Restricted Stock Grants, that the
restrictions shall lapse without regard to any Restriction Period.
ARTICLE VII
STOCK APPRECIATION RIGHTS
1. Stock Appreciation Rights.
(a) General Requirements. The Committee may grant stock appreciation
rights ("SARs") to an Employee separately or in tandem with any Option (for
all or a portion of the applicable Option). Tandem SARs may be granted
either at the time the Option is granted or at any time thereafter while the
Option remains outstanding; provided, however, that, in the case of an
Incentive Stock Option, SARs may be granted only at the time of the Grant of
the Incentive Stock Option. The Committee shall establish the base amount of
the SAR at the time the SAR is granted. Unless the Committee determines
otherwise, the base amount of each SAR shall be equal to the per share
Exercise Price of the related Option or, if there is no related Option, the
Fair Market Value of a share of Company Stock as of the date of Grant of the
SAR.
(b) Tandem SARs. In the case of tandem SARs, the number of SARs
granted to a Grantee that shall be exercisable during a specified period
shall not exceed the number of shares of Company Stock that the Grantee may
purchase upon the exercise of the related Option during such period. Upon
the exercise of an Option, the SARs relating to the Company Stock covered by
such Option shall terminate. Upon the exercise of SARs, the related Option
shall terminate to the extent of an equal number of shares of Company Stock.
(c) Exercisability. An SAR shall be exercisable during the period
specified by the Committee in the Grant Instrument and shall be subject to
such vesting and other restrictions as may be specified in the Grant
Instrument. The Committee may accelerate the exercisability of any or all
outstanding SARs at any time for any reason. SARs may only be exercised
while the Grantee is employed by the Company or during the applicable period
after termination of employment as described in Article IV, Section 3(e). A
tandem SAR shall be exercisable only during the period when the Option to
which it is related is also exercisable.
(d) Value of SARs. When a Grantee exercises SARs, the Grantee shall
receive in settlement of such SARs an amount equal to the value of the stock
appreciation for the number of SARs exercised, payable in cash, Company Stock
or a combination thereof. The stock appreciation for an SAR is the amount by
which the Fair Market Value of the underlying Company Stock on the date of
exercise of the SAR exceeds the base amount of the SAR as described in
Subsection (a).
(e) Form of Payment. The Committee shall determine whether the
appreciation in an SAR shall be paid in the form of cash, shares of Company
Stock, or a combination of the two, in such proportion as the Committee deems
appropriate. For purposes of calculating the number of shares of Company
Stock to be received, shares of Company Stock shall be valued at their Fair
Market Value on the date of exercise of the SAR. If shares of Company Stock
are to be received upon exercise of an SAR, cash shall be delivered in lieu
of any fractional share.
ARTICLE VIII
PERFORMANCE UNITS
1. Performance Units.
(a) General Requirements. The Committee may grant performance units
("Performance Units") to an Employee. Each Performance Unit shall represent
the right of the Grantee to receive an amount based on the value of the
Performance Unit, if performance goals established by the Committee are met.
A Performance Unit shall be based on the Fair Market Value of a share of
Company Stock or on such other measurement base as the Committee deems
appropriate. The Committee shall determine the number of Performance Units
to be granted and the requirements applicable to such Units, subject to the
limitations contained in Article IX.
(b) Performance Period and Performance Goals. When Performance Units
are granted, the Committee shall establish the performance period during
which performance shall be measured (the "Performance Period"), performance
goals applicable to the Units ("Performance Goals") and such other conditions
of the Grant as the Committee deems appropriate. Performance Goals may
relate to the financial performance of the Company or its operating units,
the performance of Company Stock, individual performance, or such other
criteria as the Committee deems appropriate.
(c) Payment with respect to Performance Units. At the end of each
Performance Period, the Committee shall determine to what extent the
Performance Goals and other conditions of the Performance Units are met and
the amount, if any, to be paid with respect to the Performance Units.
Payments with respect to Performance Units shall be made in cash, in Company
Stock, or in a combination of the two, as determined by the Committee.
(d) Requirement of Employment or Service. If the Grantee ceases to be
employed by, or provide service to, the Company (as defined in Article IV,
Section 3(e)) during a Performance Period, or if other conditions established
by the Committee are not met, the Grantee's Performance Units shall be
forfeited. The Committee may, however, provide for complete or partial
exceptions to this requirement as it deems appropriate.
(e) Designation as Qualified Performance-Based Compensation. The
Committee may determine that Performance Units granted to an Employee shall
be considered "qualified performance-based compensation" under Section 162(m)
of the Code. The provisions of this subsection (e) shall apply to Grants of
Performance Units that are to be considered "qualified performance-based
compensation" under Section 162(m) of the Code.
(i) Performance Goals. When Performance Units that are to be
considered "qualified performance-based compensation" are Granted, the
Committee shall establish in writing (i) the objective performance goals that
must be met in order for amounts to be paid under the Performance Units, (ii)
the Performance Period during which the performance goals must be met, (iii)
the threshold, target and maximum amounts that may be paid if the performance
goals are met, and (iv) any other conditions, including without limitation
provisions relating to death, disability, other termination of employment or
Change of Control, that the Committee deems appropriate and consistent with
the Plan and Section 162(m) of the Code. The performance goals may relate to
the Employee's business unit or the performance of the Company and its
subsidiaries as a whole, or any combination of the foregoing. The Committee
shall use objectively determinable performance goals based on one or more of
the following criteria: stock price, earnings per share, net earnings,
operating earnings, return on assets, shareholder return, return on equity,
growth in assets, unit volume, sales, market share, or strategic business
criteria consisting of one or more objectives based on meeting specified
revenue goals, market penetration goals, geographic business expansion goals,
cost targets or goals relating to acquisitions or divestitures.
(ii) Establishment of Goals. The Committee shall establish the
performance goals in writing either before the beginning of the Performance
Period or during a period ending no later than the earlier of (i) 90 days
after the beginning of the Performance Period or (ii) the date on which 25%
of the Performance Period has been completed, or such other date as may be
required or permitted under applicable regulations under Section 162(m) of
the Code. The performance goals shall satisfy the requirements for
"qualified performance-based compensation," including the requirement that
the achievement of the goals be substantially uncertain at the time they are
established and that the goals be established in such a way that a third
party with knowledge of the relevant facts could determine whether and to
what extent the performance goals have been met. The Committee shall not
have discretion to increase the amount of compensation that is payable upon
achievement of the designated performance goals.
(iii) Maximum Payment. If Performance Units measured with
respect to the fair market value of Company Stock, are granted, not more than
25% of the total number of shares of Company Stock subject to the Plan in the
aggregate may be granted to an Employee under the Performance Units for any
Performance Period. If Performance Units are measured with respect to other
criteria, the maximum amount that may be paid to an Employee with respect to
a Performance Period is $3,500,000.
(iv) Announcement of Grants. The Committee shall certify and
announce the results for each Performance Period to all Grantees immediately
following the announcement of the Company's financial results for the
Performance Period. If and to the extent that the Committee does not so
certify that the performance goals have been met, the grants of Performance
Units for the Performance Period shall be forfeited.
ARTICLE IX
AUTHORIZED SHARES
1. Shares Subject to the Plan.
(a) Shares Authorized. Subject to the adjustment specified below, the
aggregate number of common shares of NU, par value $5.00, ("Company Stock")
that may be subject to Grants of Options, or transferred on account of other
Grants or Awards, under the Plan in any fiscal year of NU is one percent of
the total number of shares of Company Stock outstanding as of the first day
of such fiscal year; provided, however, that sum of the total number of
shares of Company Stock that may be granted as Restricted Stock plus the
number of Performance Units that may be granted, in any fiscal year, shall
not exceed 30% of the total number of shares of Company Stock available under
the Plan for such year; and provided, further, that the aggregate number of
shares of Common Stock that may be issued or transferred under the Plan
subject to Incentive Stock Options is 10% of the number of shares of Company
Stock outstanding as of December 31, 1997. The shares may be authorized but
unissued shares of Company Stock or reacquired shares of Company Stock,
including shares purchased by the Company on the open market for purposes of
the Plan. If and to the extent (i) less than the full number of shares
available for use under the Plan, as set forth above, are made the subject of
Grants or Awards in any year, or (ii) Options or SARs granted under the Plan
terminate, expire, or are canceled, forfeited, exchanged or surrendered
without having been exercised, or (iii) any shares of Restricted Stock or
Performance Units are forfeited, then the shares not made the subject of
Grants and Awards, and the shares subject to such terminated, expired,
canceled, forfeited, exchanged or surrendered Grants and Awards shall again
be available for purposes of the Plan in addition to the number of shares of
Company Stock otherwise available for Grants and Awards. No Grantee under
the Plan may receive aggregate Grants in excess of 2.5% of the total number
of shares of Company Stock outstanding as of December 31, 1997.
(b) Adjustments. If there is any change in the number or kind of
shares of Company Stock outstanding (i) by reason of a stock dividend,
spinoff, recapitalization, stock split, or combination or exchange of shares,
(ii) by reason of a merger, reorganization or consolidation in which NU is
the surviving entity, (iii) by reason of a reclassification or change in par
value, or (iv) by reason of any other extraordinary or unusual event
affecting the outstanding Company Stock as a class without NU's receipt of
consideration, or if the value of outstanding shares of Company Stock is
substantially reduced as a result of a spinoff or NU's payment of an
extraordinary dividend or distribution, the maximum number of shares of
Company Stock available for Grants, the maximum number of shares of Company
Stock that any individual participating in the Plan may be granted in any
year, the number of shares covered by outstanding Grants, the kind of shares
issued under the Plan, and the price per share or the applicable market value
of such Grants shall be appropriately adjusted by the Committee to reflect
any increase or decrease in the number of, or change in the kind or value of,
issued shares of Company Stock to preclude, to the extent practicable, the
enlargement or dilution of rights and benefits under such Grants; provided,
however, that any fractional shares resulting from such adjustment shall be
eliminated. Any adjustments determined by the Committee shall be final,
binding and conclusive.
ARTICLE X
OPERATING RULES
1. Withholding of Taxes. All Grants under the Plan shall be subject
to applicable federal (including FICA), state and local tax withholding
requirements. The Company shall have the right to deduct from all Grants
paid in cash, or from other wages paid to the Grantee, any federal, state or
local taxes required by law to be withheld with respect to such Grants. In
the case of Options and other Grants paid in Company Stock, the Company may
require the Grantee or other person receiving such shares to pay to the
Company the amount of any such taxes that the Company is required to withhold
with respect to such Grants, or the Company may deduct from other wages paid
by the Company the amount of any withholding taxes due with respect to such
Grants. If the Committee so permits, a Grantee may elect to satisfy the
Company's income tax withholding obligation with respect to an Option, SAR,
Restricted Stock or Performance Units paid in Company Stock by having shares
withheld up to an amount that does not exceed the Grantee's minimum
applicable withholding tax rate for federal (including FICA), state and local
tax liabilities. The election must be in a form and manner prescribed by the
Committee.
2. Transferability of Grants.
(a) Nontransferability of Grants. Except as provided below, only the
Grantee may exercise rights under a Grant during the Grantee's lifetime. A
Grantee may not transfer those rights except by will or by the laws of
descent and distribution or, with respect to Grants other than Incentive
Stock Options, if permitted in any specific case by the Committee, pursuant
to a domestic relations order (as defined under the Code or Title I of the
Employee Retirement Income Security Act of 1974, as amended, or the
regulations thereunder). When a Grantee dies, the personal representative or
other person entitled to succeed to the rights of the Grantee ("Successor
Grantee") may exercise such rights. A Successor Grantee must furnish proof
satisfactory to the Company of his or her right to receive the Grant under
the Grantee's will or under the applicable laws of descent and distribution.
(b) Transfer of Nonqualified Stock Options. Notwithstanding the
foregoing, the Committee may provide, in a Grant Instrument, that a Grantee
may transfer Nonqualified Stock Options to family members, one or more trusts
for the benefit of family members, or one or more partnerships of which
family members are the only partners, according to such terms as the
Committee may determine; provided that the Grantee receives no consideration
for the transfer of an Option and the transferred Option shall continue to be
subject to the same terms and conditions as were applicable to the Option
immediately before the transfer.
3. Requirements for Issuance or Transfer of Shares. No Company Stock
shall be issued or transferred in connection with any Grant hereunder unless
and until all legal requirements applicable to the issuance or transfer of
such Company Stock have been complied with to the satisfaction of the
Committee. The Committee shall have the right to condition any Grant made to
any Grantee hereunder on such Grantee's undertaking in writing to comply with
such restrictions on his or her subsequent disposition of such shares of
Company Stock as the Committee shall deem necessary or advisable as a result
of any applicable law, regulation or official interpretation thereof, and
certificates representing such shares may be legended to reflect any such
restrictions. Certificates representing shares of Company Stock issued or
transferred under the Plan will be subject to such stop-transfer orders and
other restrictions as may be required by applicable laws, regulations and
interpretations, including any requirement that a legend be placed thereon.
4. Funding of the Plan. This Plan shall be unfunded. The Company
shall not be required to establish any special or separate fund or to make
any other segregation of assets to assure the payment of any Grants under
this Plan. In no event shall interest be paid or accrued on any Grant,
including unpaid installments of Grants.
5. Rights of Participants. Nothing in this Plan shall entitle any
Employee or Non-Employee Director or other person to any claim or right to
be granted a Grant under this Plan except as provided in Article V. Neither
this Plan nor any action taken hereunder shall be construed as giving any
individual any rights to be retained by or in the employ of the Company or
any other employment rights.
6. No Fractional Shares. No fractional shares of Company Stock shall
be issued or delivered pursuant to the Plan or any Grant. The Committee
shall determine whether cash, other awards or other property shall be issued
or paid in lieu of such fractional shares or whether such fractional shares
or any rights thereto shall be forfeited or otherwise eliminated.
7. Headings. Section headings are for reference only. In the event
of a conflict between a title and the content of a Section, the content of
the Section shall control.
8. Effective Date of the Plan. Subject to approval by NU's
shareholders, the Plan shall be effective on January 1, 1998.
9. Definition of Company. "Company" means NU and any Affiliate which
is authorized by the Board to adopt the Plan and cover its eligible employees
and whose designation as such has become effective upon acceptance of such
status by the board of directors of the Affiliate. An Affiliate may revoke
its acceptance of such designation at any time, but until such acceptance has
been revoked, all the provisions of the Plan, including the authority of the
Board and the Committee, and amendments thereto shall apply to the eligible
employees of the Affiliate. In the event the designation is revoked by the
board of directors of an Affiliate, the Plan shall be deemed terminated only
with respect to such Affiliate. For the purposes hereof, "Affiliate" means
each direct and indirect affiliated company that directly or through one or
more intermediaries, controls, is controlled by, or is under common control
with NU.
ARTICLE XI
CHANGE OF CONTROL OF NU
1. Change of Control of NU.
As used herein, a "Change of Control" shall be deemed to have occurred:
(i) When any "person," as such term is used in Sections 13(d)
and 14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), other
than the Company, its affiliates, or any Company or NU employee benefit plan
(including any trustee of such plan acting as trustee), is or becomes the
"beneficial owner" (as defined in Rule 13d-3 under the Exchange Act),
directly or indirectly, of securities of NU representing more than 20% of the
combined voting power of either (i) the then outstanding common shares of NU
(the "Outstanding Common Shares") or (ii) the then outstanding voting
securities of NU entitled to vote generally in the election of directors (the
"Voting Securities"); or
(ii) Individuals who, as of the beginning of any twenty-four
month period, constitute the Trustees (the "Incumbent Trustees") cease for
any reason to constitute at least a majority of the Trustees or cease to be
able to exercise the powers of the majority of the Trustees, provided that
any individual becoming a trustee subsequent to the beginning of such period
whose election or nomination for election by the Company's stockholders was
approved by a vote of at least a majority of the trustees then comprising the
Incumbent Trustees shall be considered as though such individual were a
member of the Incumbent Trustees, but excluding, for this purpose, any such
individual whose initial assumption of office is in connection with an actual
or threatened election contest relating to the election of the Trustees of NU
(as such terms are used in Rule 14a-11 of Regulation 14A promulgated under
the Exchange Act); or
(iii) Consummation by NU of a reorganization, merger or
consolidation (a "Business Combination"), in each case, with respect to which
all or substantially all of the individuals and entities who were the
respective beneficial owners of the Outstanding Common Shares and Voting
Securities immediately prior to such Business Combination do not, following
consummation of all transactions intended to constitute part of such Business
Combination, beneficially own, directly or indirectly, more than 75% of,
respectively, the then outstanding shares of common stock and the combined
voting power of the then outstanding voting securities entitled to vote
generally in the election of directors, as the case may be, of the
corporation, business trust or other entity resulting from or being the
surviving entity in such Business Combination in substantially the same
proportion as their ownership immediately prior to such Business Combination
of the Outstanding Common Shares and Voting Securities, as the case may be;
or
(iv) Consummation of a complete liquidation or dissolution of
NU or sale or other disposition of all or substantially all of the assets of
NU other than to a corporation, business trust or other entity with respect
to which, following consummation of all transactions intended to constitute
part of such sale or disposition, more than 75% of, respectively, the then
outstanding shares of common stock and the combined voting power of the then
outstanding voting securities entitled to vote generally in the election of
directors, as the case may be, is then owned beneficially, directly or
indirectly, by all or substantially all of the individuals and entities who
were the beneficial owners, respectively, of the Outstanding Common Shares
and Voting Securities immediately prior to such sale or disposition in
substantially the same proportion as their ownership of the Outstanding
Common Shares and Voting Securities, as the case may be, immediately prior to
such sale or disposition.
2. Consequences of a Change of Control.
(a) Notice and Acceleration. Upon a Change of Control, unless the
Committee determines otherwise, (i) the Company shall provide each Grantee
with outstanding Grants written notice of such Change of Control, (ii) all
outstanding Options and SARs shall automatically accelerate and become fully
exercisable, (iii) the restrictions and conditions on all outstanding
Restricted Stock shall immediately lapse, and (iv) Grantees holding
Performance Units shall receive a payment in settlement of such Performance
Units, in an amount determined by the Committee, based on the Grantee's
target payment for the Performance Period and the portion of the Performance
Period that precedes the Change of Control.
(b) Assumption of Grants. Upon a Change of Control where the Company
is not the surviving corporation (or survives only as a subsidiary of another
corporation), unless the Committee determines otherwise, all outstanding
Options and SARs that are not exercised shall be assumed by, or replaced with
comparable options or rights by, the surviving corporation.
(c) Other Alternatives. Notwithstanding the foregoing, subject to
subsection (d) below, in the event of a Change of Control, the Committee may
take one or both of the following actions: the Committee may (i) require that
Grantees surrender their outstanding Options and SARs in exchange for a
payment by the Company, in cash or Company Stock as determined by the
Committee, in an amount equal to the amount by which the then Fair Market
Value of the shares of Company Stock subject to the Grantee's unexercised
Options and SARs exceeds the Exercise Price of the Options or the base
amount of the SARs, as applicable, or (ii) after giving Grantees an
opportunity to exercise their outstanding Options and SARs, terminate any or
all unexercised Options and SARs at such time as the Committee deems
appropriate. Such surrender or termination shall take place as of the date
of the Change of Control or such other date as the Committee may specify.
(d) Committee. The Committee making the determinations under this
Article XI, Section 2(d) following a Change of Control must comprise the same
members as those on the Committee immediately before the Change of Control.
If the Committee members do not meet this requirement, the automatic
provisions of Subsections (a) and (b) shall apply, and the Committee shall
not have discretion to vary them.
(e) Limitations. Notwithstanding anything in the Plan to the contrary,
in the event of a Change of Control, the Committee shall not have the right
to take any actions described in the Plan (including without limitation
actions described in Subsection (c) above) that would make the Change of
Control ineligible for pooling of interests accounting treatment or that
would make the Change of Control ineligible for desired tax treatment if, in
the absence of such right, the Change of Control would qualify for such
treatment and the Company intends to use such treatment with respect to the
Change of Control.
ARTICLE XII
AMENDMENT AND TERMINATION
1. Amendment and Termination of the Plan.
(a) Amendment. The Board may amend or terminate the Plan at any time;
provided, however, that the Board shall not amend the Plan without
shareholder approval if such approval is required by section 422 of the Code
or section 162(m) of the Code.
(b) Termination of Plan. The Plan shall terminate on the day
immediately preceding the tenth anniversary of its effective date, unless the
Plan is terminated earlier by the Board or is extended by the Board with the
approval of the shareholders.
(c) Termination and Amendment of Outstanding Grants. A termination or
amendment of the Plan that occurs after a Grant is made shall not materially
impair the rights of a Grantee unless the Grantee consents or unless the
Committee acts under Article XI, Section 2(c). The termination of the Plan
shall not impair the power and authority of the Committee with respect to an
outstanding Grant.
(d) Governing Document. The Plan shall be the controlling document.
No other statements, representations, explanatory materials or examples, oral
or written, may amend the Plan in any manner. The Plan shall be binding upon
and enforceable against the Company and its successors and assigns.
ARTICLE XIII
MISCELLANEOUS
1. Grants in Connection with Corporate Transactions and Otherwise.
Nothing contained in this Plan shall be construed to (i) limit the right
of the Committee to make Grants under this Plan in connection with the
acquisition, by purchase, lease, merger, consolidation or otherwise, of the
business or assets of any corporation, firm or association, including Grants
to employees thereof who become Employees of the Company, or for other proper
corporate purposes, or (ii) limit the right of the Company to grant stock
options or make other awards outside of this Plan. Without limiting the
foregoing, the Committee may make a Grant to an employee of another
corporation who becomes an Employee by reason of a corporate merger,
consolidation, acquisition of stock or property, reorganization or
liquidation involving the Company or any of its subsidiaries in substitution
for a stock option or restricted stock grant made by such corporation. The
terms and conditions of the substitute grants may vary from the terms and
conditions required by the Plan and from those of the substituted stock
incentives. The Committee shall prescribe the provisions of the substitute
grants.
2. Compliance with Law. The Plan, the exercise of Options and SARs
and the obligations of the Company to issue or transfer shares of Company
Stock under Grants shall be subject to all applicable laws and to approvals
by any governmental or regulatory agency as may be required. With respect to
persons subject to section 16 of the Exchange Act, it is the intent of the
Company that the Plan and all transactions under the Plan comply with all
applicable provisions of Rule 16b-3 or its successors under the Exchange Act.
In addition, it is the intent of the Company that the Plan and applicable
Grants under the Plan comply with the applicable provisions of sections
162(m) and 422 of the Code. To the extent that any legal requirement of
section 16 of the Exchange Act or section 162(m) or 422 of the Code as set
forth in the Plan ceases to be required under section 16 of the Exchange Act
or section 162(m) or 422 of the Code, that Plan provision shall cease to
apply. The Committee may revoke any Grant if it is contrary to law or modify
a Grant to bring it into compliance with any valid and mandatory government
regulation. The Committee may also adopt rules regarding the withholding of
taxes on payments to Grantees. The Committee may, in its sole discretion,
agree to limit its authority under this Section.
3. Governing Law. The validity, construction, interpretation and
effect of the Plan and Grant Instruments issued under the Plan shall
exclusively be governed by and determined in accordance with the law of the
State of Connecticut.
4. Disclaimer of Liability. The Declaration of Trust of NU provides
that no shareholder of NU shall be held to any liability whatever for the
payment of any sum of money, or for damages or otherwise under any contract,
obligation or undertaking made, entered into or issued by the Board or by any
officer, agent or representative elected or appointed by the Board, and no
such contract, obligation or undertaking shall be enforceable against the
Board or any of them in their or his or her individual capacities or capacity
and all such contracts, obligations and undertakings shall be enforceable
only against the Board as such, and every person or entity, having any claim
or demand arising out of any such contract, obligation or undertaking shall
look only to the trust estate for the payment or satisfaction thereof.
Exhibit 10.35.1.1
AMENDMENT NO. 1 TO NORTHEAST UTILITIES INCENTIVE PLAN
Adopted by Northeast Utilities Board of Trustees - February 23, 1999
The Northeast Utilities Incentive Plan is amended, effective February 23,
1999, as follows:
A. By deleting Article V and inserting the following in its place:
ARTICLE V
STOCK-BASED GRANTS TO NON-EMPLOYEE TRUSTEES
1. Non-Employee Trustees shall be eligible to receive Grants as set
forth in Article IV; provided, that the number of shares of Company Stock
subject to each Grant of Options, as well as the terms of all Grants, to Non-
Employee Trustees shall be approved by the Board, in accordance with Article
(9) of the Declaration of Trust of Northeast Utilities, as amended.
2. The words "age 65" in the definition of "Retired" in Section
3(e)(v)(D) of Article IV shall be read as "age 70" with respect to Non-
Employee Trustees.
B. By changing the words "an Employee" to "a Grantee" in each of Sections 1
of Article VI, 1(a) of Article VII, 1(a) and 1(e) of Article VIII,
C. By changing the word "Director" to "Trustee" in Section 5 of Article X.
Exhibit 10.37
As approved and adopted by subsidiaries of Northeast Utilities on June 9,
1997 and modified effective January 13, 1998 pursuant to action of the Board
of Trustees on January 13, 1998 and approved by subsidiaries of Northeast
Utilities on July 15, 1998.
SPECIAL SEVERANCE PROGRAM
FOR OFFICERS OF NORTHEAST UTILITIES SYSTEM COMPANIES
I. Purpose
The purpose of this Special Severance Program for Officers of Northeast
Utilities System Companies (the "Program") is to provide certain executives
with severance payments and benefits in the event of "Termination upon a
Change of Control", as hereinafter defined. The Program is not intended to
meet the qualification requirements of Section 401 of the Code or to be an
"employee pension benefit plan" as defined in ERISA. The Program is not
intended to affect eligibility for or payment of any other compensation or
benefits in accordance with the terms of any applicable plans or programs of
the Company.
II. Definitions
When used herein with initial capital letters, each of the following
terms shall have the corresponding meaning set forth below unless a different
meaning is plainly required by the context in which the term is used:
"Administrator" shall mean the Senior Vice President and Chief
Administrative Officer of NUSCO.
"Affiliate" shall mean an "affiliate" as defined in Rule 12b-2 of the
General Rules and Regulations under the Exchange Act.
"Base Compensation" for any Participant shall mean the Participant's
annualized base rate of salary plus all short-term incentive compensation at
the target level for the Participant specified under compensation programs
established by the Company for its officers generally, received by the
Participant in all capacities with the Company, as would be reported for
federal income tax purposes on Form W-2, together with any and all salary
reduction authorized amounts under any of the Company's benefit plans or
programs, for the most recent full calendar year immediately preceding the
calendar year in which occurs Participant's Termination Date or preceding the
Change of Control, if higher. "Base Compensation" shall not include the
value of any stock options, stock appreciation rights, restricted stock, or
restricted stock units granted to Participant by the Company.
"Board" shall mean the Board of Trustees of Northeast Utilities.
"Cause" with respect to the Termination of Employment of a Participant
shall mean (i) the Participant's conviction of a felony, (ii) in the
reasonable determination of the Board, the Participant's (x) commission of an
act of fraud, embezzlement, or theft in connection with Participant's duties
in the course of Participant's employment with the Company, (y) acts or
omissions causing intentional, wrongful damage to the property of the Company
or intentional and wrongful disclosure of Confidential Information, or (z)
engaging in gross misconduct or gross negligence in the course of the
Participant's employment with the Company, or (iii) the Participant's
material breach of his or her obligations under any written agreement with
the Company if such breach shall not have been remedied within 30 days after
receiving written notice from the Administrator specifying the details
thereof. For purposes of this Program, an act or omission on the part of a
Participant shall be deemed "intentional" only if it was not due primarily to
an error in judgment or negligence and was done by Participant not in good
faith and without reasonable belief that the act or omission was in the best
interest of the Company.
"Change of Control" shall mean the happening of any of the following:
(i) Any "person," as such term is used in Sections 13(d) and 14(d) of
the Exchange Act, other than Northeast Utilities, its Affiliates, or any
Company employee benefit plan (including any trustee of such plan acting as
trustee), is or becomes the "beneficial owner" (as defined in Rule 13d-3
under the Exchange Act), directly or indirectly, of securities of Northeast
Utilities representing more than 20% of the combined voting power of either
(i) the Outstanding Common Shares or (ii) the Voting Securities; or
(ii) Individuals who, as of the beginning of any twenty-four month
period, constitute the trustees of NU (the "Incumbent Board") cease for any
reason to constitute at least a majority of the Board or cease to be able to
exercise the powers of the majority of the Board, provided that any
individual becoming a trustee subsequent to the beginning of such period
whose election or nomination for election by the common shareholders of
Northeast Utilities was approved by a vote of at least a majority of the
trustees then comprising the Incumbent Board shall be considered as though
such individual were a member of the Incumbent Board, but excluding, for this
purpose, any such individual whose initial assumption of office is in
connection with an actual or threatened election contest relating to the
election of the trustees of Northeast Utilities (as such terms are used in
Rule 14a-11 of Regulation 14A promulgated under the Exchange Act); or
(iii) Consummation by Northeast Utilities of a reorganization,
merger or consolidation (a "Business Combination"), in each case, with
respect to which all or substantially all of the individuals and entities who
were the respective beneficial owners of the Outstanding Common Shares and
Voting Securities immediately prior to such Business Combination do not,
following consummation of all transactions intended to constitute part of
such Business Combination, beneficially own, directly or indirectly, more
than 75% of, respectively, the then outstanding shares of common stock and
the combined voting power of the then outstanding voting securities entitled
to vote generally in the election of directors, as the case may be, of the
corporation, business trust or other entity resulting from or being the
surviving entity in such Business Combination in substantially the same
proportion as their ownership immediately prior to such Business Combination
of the Outstanding Common Shares and Voting Securities, as the case may be;
or
(iv) Consummation of a complete liquidation or dissolution of Northeast
Utilities or sale or other disposition of all or substantially all of the
assets of Northeast Utilities other than to a corporation, business trust or
other entity with respect to which, following consummation of all
transactions intended to constitute part of such sale or disposition, more
than 75% of, respectively, the then outstanding shares of common stock and
the combined voting power of the then outstanding voting securities entitled
to vote generally in the election of directors, as the case may be, is then
owned beneficially, directly or indirectly, by all or substantially all of
the individuals and entities who were the beneficial owners, respectively, of
the Outstanding Common Shares and Voting Securities immediately prior to such
sale or disposition in substantially the same proportion as their ownership
of the Outstanding Common Shares and Voting Securities, as the case may be,
immediately prior to such sale or disposition.
"Code" shall mean the Internal Revenue Code of 1986, as amended.
"Committee" shall mean the Committee on Organization, Compensation and
Board Affairs that has been established by the Board, or any subsequent
committee of the Board that has primary responsibility for compensation
policies. In the absence of such a committee, "Committee" shall mean the
Board or any committee of the Board designated by the Board to perform the
functions of the Committee under the Program.
"Company" includes, individually and/or collectively as the context
requires, Northeast Utilities, NUSCO, and all other entities that have
approved and adopted this Program pursuant to Article VII, whether or not an
individual such entity directly compensates the Participant or the
Participant appears on the payroll of such entity.
"Disability" shall mean the inability of a Participant substantially to
perform his or her duties and responsibilities to the full extent required by
the Board, by reason of illness, injury or incapacity for six consecutive
months, or for more than six months in the aggregate during any period of
twelve calendar months.
"ERISA" shall mean the Employee Retirement Income Security Act of 1974,
as amended.
"Exchange Act" shall mean the Securities Exchange Act of 1934, as
amended.
"Notice of Termination" means a written notice given in accordance with
Section 3(d) which (i) indicates the specific termination provision in this
Program relied upon, (ii) briefly summarizes the facts and circumstances
deemed to provide a basis for a Termination of Employment and the applicable
provision hereof, and (iii) if the Termination Date is other than the date of
receipt of such notice, specifies the Termination Date (which date shall not
be more than 15 days after the giving of such notice).
"NUSCO" shall mean Northeast Utilities Service Company, its successors
and assigns.
"Outstanding Common Shares" at any time shall mean the then outstanding
common shares of Northeast Utilities.
"Participant" at any time shall mean each person then holding the
office of vice president or higher level of the Company, not including
assistant officers, who (a) has signed a non-competition agreement with the
Company in the form of Annex 1 hereto or in such form as has been approved by
the Administrator for this purpose from time to time, and (b) is not a party
to a then effective separate written agreement with the Company which has
been adopted by the Board and expressly provides benefits following a change
of control of Northeast Utilities (unless such agreement expressly provides
for participation in this Program).
"Termination Date" with respect to any Participant shall mean the date
of any action by the Company constituting a Termination upon a Change of
Control of such Participant.
"Termination of Employment" of a Participant shall mean the termination
of the Participant's actual employment relationship with the Company
occasioned by the Company's action.
"Termination upon a Change of Control" of a Participant shall mean a
Termination of Employment upon or within two years after a Change of Control
either (i) initiated by the Company for any reason other than (w) Disability,
(x) death, (y) retirement on or after attaining age 65, or (z) Cause, or (ii)
initiated by the Participant (A) upon any significant reduction by the
Company of the authority, duties or responsibilities of Participant, any
reduction of the Participant's compensation or benefits other than a
reduction applicable to all employees generally, or the assignment to
Participant of duties which are materially inconsistent with the duties of
Participant's position with the Company, or (B) if Participant is
transferred, without Participant's written consent, to a location that is
more than 50 miles from Participant's principal place of business immediately
preceding the Change of Control.
"Voting Securities" at any time shall mean the then outstanding voting
securities of Northeast Utilities entitled to vote generally in the election
of trustees of Northeast Utilities.
III. Benefits
(a) Benefits Following Termination Upon a Change of Control. So long
as a Participant executes a written release substantially in the form of
Annex 2 hereto, upon such Participant's Termination upon a Change of Control,
(i) the Company will pay to Participant, in a single cash payment within 30
days after the later of the Termination Date and the date the Participant
executes such release, an amount equal to two times the Participant's Base
Compensation, (ii) each of the Participant, his or her eligible spouse and
dependents shall be eligible for a continuation of all employee health plan
benefits as then in effect for such persons, as if the Participant had
remained actively employed by the Company, such benefits to continue until
the earlier of two years following the Termination Date or the date such
person has coverage through another group health plan or plans and to count
as "continuation coverage" pursuant to the requirements of Section 4980B of
the Code, and (iii) on such Participant's Termination Date, all performance
share units, stock options or restricted shares previously granted to the
Participant, to the extent not already vested prior to the Termination Date,
shall be fully vested and exercisable or paid as if the Participant had
remained actively employed by the Company, including the right of exercise,
where appropriate, within 36 months after the Termination Date; provided,
however, that the performance share units shall be paid as if the Company had
met all performance targets during the applicable performance period.
(b) Certain Reduction of Payments.
(i) Anything in this Program to the contrary notwithstanding, in
the event that it shall be determined that any payment or distribution by the
Company to or for the benefit of a Participant, whether paid or payable or
distributed or distributable pursuant to the terms of this Program or
otherwise (the "Payment"), would constitute an "excess parachute payment"
within the meaning of Section 280G of the Internal Revenue Code of 1986, as
amended (the "Code"), and that such Participant would receive a greater net
amount if the Payment to Participant were reduced to avoid the taxation of
excess parachute payments under Section 4999 of the Code, the aggregate
present value of amounts payable or distributable to or for the benefit of
Participant pursuant to this Program (such payments or distributions pursuant
to this Program are hereinafter referred to as "Program Payments") shall be
reduced (but not below zero) to the Reduced Amount. The "Reduced Amount"
shall be an amount expressed in present value which maximizes the aggregate
present value of Program Payments without causing any Payment to be subject
to the taxation under Section 4999 of the Code. For purposes of this Section
3(b), present value shall be determined in accordance with Section 280G(d)(4)
of the Code.
(ii) All determinations to be made under this Section 3(b) shall be
made by the Company's independent public accountant immediately prior to the
Change of Control (the "Accounting Firm"), which firm shall provide its
determinations and any supporting calculations both to the Company and the
affected Participant within 10 days of the Termination Date of such
Participant. Any such determination by the Accounting Firm shall be binding
upon the Company and the Participant; provided, however, that Participant
shall, in his or her sole discretion, determine whether, which and how much
of the Program Payments shall be eliminated or reduced consistent with the
requirements of this Section 3(b). Within five days after the Participant's
determination, the Company shall pay (or cause to be paid) or distribute (or
cause to be distributed) to or for the benefit of the Participant such
amounts as are then due to the Participant under this Program.
(iii) As a result of the uncertainty in the application of
Section 280G of the Code at the time of the initial determination by the
Accounting Firm hereunder, it is possible that Program Payments will have
been made by the Company which should not have been made ("Overpayment") or
that additional Program Payments which have not been made by the Company
could have been made ("Underpayment"), in each case, consistent with the
calculations required to be made hereunder. Within two years after the
Termination of Employment of any Participant, the Accounting Firm shall
review the determination made by it pursuant to Section 3(b)(ii). In the
event that the Accounting Firm determines that an Overpayment has been made,
any such Overpayment shall be treated for all purposes as a loan to the
Participant which the Participant shall repay to the Company together with
interest at the applicable Federal rate provided for in Section 7872(f)(2) of
the Code (the "Federal Rate"); provided, however, that no amount shall be
payable by the Participant to the Company if and to the extent such payment
would not increase the net amount which is payable to the Participant after
taking into account the provisions of Section 4999 of the Code. In the event
that the Accounting Firm determines that an Underpayment has occurred, any
such Underpayment shall be promptly paid by the Company to or for the benefit
of the Participant together with interest at the Federal Rate.
(iv) All of the fees and expenses of the Accounting Firm in
performing the determinations referred to in subsections 3(b)(ii) and
3(b)(iii) above shall be borne solely by the Company. The Company agrees to
indemnify and hold harmless the Accounting Firm of and from any and all
claims, damages and expenses resulting from or relating to its determinations
pursuant to subsections 3(b)(ii) and 3(b)(iii) above, except for claims,
damages or expenses resulting from the gross negligence or wilful misconduct
of the Accounting Firm.
(b) Vesting. A Participant shall be vested and shall have a
nonforfeitable right with respect to the benefits to be provided hereunder
from and after the Termination Date. The respective rights and obligations
of the Company and the Participant under this Program shall survive any
termination of Participant's employment to the extent necessary to the
intended preservation of such rights and obligations.
(c) Non-Exclusivity of Rights. Nothing in this Program shall prevent
or limit any Participant's continuing or future participation in or rights
under any benefit, bonus, incentive or other plan or program provided by the
Company and for which such Participant may qualify; provided, however, that
if such Participant becomes entitled to and receives all of the payments
provided for in this Program, the Participant hereby waives his or her right
to receive payments under any severance plan or similar program applicable to
employees of the Company generally.
(d) Notice of Termination. No Termination upon a Change of Control
shall be effective unless accompanied or preceded by a Notice of Termination.
IV. Funding
Benefits payable under this Program shall be unfunded, as that term is used
in Sections 201(2), 301(a)(3), 401(a)(1) and 4021(a)(6) of ERISA, with
respect to unfunded plans maintained primarily for the purpose of providing
deferred compensation to a select group of management or highly compensated
employees, and the Administrator shall administer this Program in a manner
that will ensure that benefits are unfunded and that Participants will not be
considered to have received a taxable economic benefit prior to the time at
which benefits are actually payable hereunder. Accordingly, the Company shall
not be required to segregate or earmark any of its assets for the benefit of
Participants or their spouses or other beneficiaries, and each such person
shall have only a contractual right against the Company for benefits
hereunder. The Company may from time to time establish a trust and deposit
with the trustee thereof funds to be held in trust for the payment of
benefits hereunder; provided, that the use of such funds for such purpose
shall be subject to the claims of the Company's general creditors as set
forth in the agreement establishing any such trust. The rights and interests
of a Participant under this Program shall not be subject in any manner to
anticipation, alienation, sale, transfer, assignment, pledge or encumbrance
by a Participant or any person claiming under or through a Participant, nor
shall they be subject to the debts, contracts, liabilities or torts of a
Participant or anyone else prior to payment. The Treasurer of NUSCO may from
time to time appoint an investment manager or managers for the funds held in
any such trust.
V. Administration
The Program shall be operated under the direction of the Committee and
administered by the Administrator. The calculation of all benefits payable
under the Program shall be performed by the Administrator, subject to the
review of the Committee.
VI. Claims Procedure
All claims for benefits under this Program shall be determined under the
claims procedure in effect under the Northeast Utilities Service Company
Retirement Plan on the date that such claims are submitted, except that the
Administrator shall make initial determinations with respect to claims
hereunder and the Committee shall decide appeals of such determinations. In
the event that any dispute under the provisions of this Program is not
resolved to the satisfaction of the affected Participant, other than a
dispute in which the primary relief sought is an equitable remedy such as an
injunction, the parties shall be required to have the dispute, controversy or
claim settled by arbitration in the City of Hartford, Connecticut in
accordance with National Rules for the Resolution of Employment Disputes then
in effect of the American Arbitration Association, before a panel of three
arbitrators, two of whom shall be selected by the Company and the affected
Participant, respectively, and the third of whom shall be selected by the
other two arbitrators. Any award entered by the arbitrators shall be final,
binding and nonappealable (except as provided in Section 52-418 of the
Connecticut General Statutes) and judgment may be entered thereon by either
party in accordance with applicable law in any court of competent
jurisdiction. This arbitration provision shall be specifically enforceable.
The arbitrators shall have no authority to modify any provision of this
Program or to award a remedy for a dispute involving this Program other than
a benefit specifically provided under or by virtue of the Program. If a
Participant prevails on any material issue which is the subject of any such
arbitration or lawsuit, the Company shall be responsible for all of the fees
of the American Arbitration Association and the arbitrators and any expenses
relating to the conduct of the arbitration (including the Company's and the
Participant's reasonable attorneys' fees and expenses). Otherwise, each
party shall be responsible for its own expenses relating to the conduct of
the arbitration (including reasonable attorneys' fees and expenses) and shall
share the fees of the American Arbitration Association.
VII. Adoption by Company: Obligations of Company.
(a) At the earliest feasible time or times, Northeast Utilities shall
cause each entity in which it now or hereafter holds, directly or indirectly,
more than a 50 percent voting interest to approve and adopt this Program and,
by such approval and adoption, to be bound by the terms hereof.
(b) Benefits under this Program shall, in the first instance, be paid
and satisfied by NUSCO. If NUSCO shall be dissolved or for any other reason
shall fail to pay and satisfy such benefits, each individual entity referred
to in (a) above shall pay and satisfy its share of such benefits, such share
to be the ratio of the Participant's Base Compensation charged to such entity
during the three calendar years immediately preceding the Participant's
Termination Upon a Change of Control to the total of the Participant's Base
Compensation charged to all such entities during the same period.
(c) The Declaration of Trust of Northeast Utilities provides that no
shareholder of Northeast Utilities shall be held to any liability whatever
for the payment of any sum of money, or for damages or otherwise under any
contract, obligation or undertaking made, entered into or issued by the
trustees of Northeast Utilities or by any officer, agent or representative
elected or appointed by the trustees and no such contract, obligation or
undertaking shall be enforceable against the trustees or any of them in their
or his individual capacities or capacity and all such contracts, obligations
and undertakings shall be enforceable only against the trustees as such and
every person, firm, association, trust and corporation having any claim or
demand arising out of any such contract, obligation or undertaking shall look
only to the trust estate for the payment or satisfaction thereof. Any
liability for benefits under this Program incurred by Northeast Utilities
shall be subject to the foregoing provisions of this Section 7 (c).
VIII. Miscellaneous
(a) Amendment or Termination. Prior to the occurrence of a Change of
Control, the Board may amend or discontinue this Program at any time, on at
least two (2) years prior written notice to each Participant of the Board's
intention to do so and specifying the changes to be made. Upon and following
a Change of Control, this Program may not be amended or terminated in any way
that would eliminate or reduce the payments and benefits owing to
Participants under the Program.
(b) Headings. Headings are included in the Program for convenience
only and are not substantive provisions of the Program.
(c) Applicable Law. The interpretation of the provisions and the
administration of the Program shall be governed by the laws of the State of
Connecticut without giving effect to any conflict of laws provisions, and to
the extent applicable, the United States of America.
(d) Mitigation. No Participant shall be required to mitigate the
amount of any payment or benefit provided for in this Program by seeking
other employment or otherwise and there shall be no offset against amounts
due any Participant under this Program on account of any remuneration
attributable to any subsequent employment that may be obtained.
(e) Notices. All notices and other communications required or
permitted under this Program or necessary or convenient in connection
herewith shall be in writing and shall be deemed to have been given when hand
delivered or mailed by registered or certified mail to the last known address
of the Company or the Participant, as the case may be, reflected upon Company
records. Notices to the Company shall be addressed to:
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT 06141-0270
Attention: Senior Vice President and Chief Administrative Officer
(f) Binding Effect; Successors and Assigns. All of the terms and
provisions of this Program shall be binding upon and inure to the benefit of
and be enforceable by the respective heirs, executors, administrators, legal
representatives, successors and assigns of the parties hereto, except that
the duties and responsibilities of the Participants under this Program are of
a personal nature and shall not be assignable or delegatable in whole or in
part by the Participants. The Company shall require any successor (whether
direct or indirect, by purchase, merger, consolidation, reorganization or
otherwise) to all or substantially all of the business or assets of the
Company, by agreement in form and substance satisfactory to the Participants,
expressly to assume and agree to perform this Plan in the same manner and to
the extent the Company would be required to perform if no such succession had
taken place.
(g) Severability. If any provision of this Program or application
thereof to anyone or under any circumstances is adjudicated to be invalid or
unenforceable in any jurisdiction, such invalidity or unenforceability shall
not affect any other provision or application of this Program which can be
given effect without the invalid or unenforceable provision or application
and shall not invalidate or render unenforceable such provision or
application in any other jurisdiction. If any provision is held void,
invalid or unenforceable with respect to particular circumstances, it shall
nevertheless remain in full force and effect in all other circumstances.
(h) Remedies Cumulative; No Waiver. No remedy conferred upon a party
by this Program is intended to be exclusive of any other remedy, and each and
every such remedy shall be cumulative and shall be in addition to any other
remedy given under this Program or now or hereafter existing at law or in
equity. No delay or omission by a party in exercising any right, remedy or
power under this Program or existing at law or in equity shall be construed
as a waiver thereof, and any such right, remedy or power may be exercised by
such party from time to time and as often as may be deemed expedient or
necessary by such party in its sole discretion.
(i) Beneficiaries/References. Each Participant shall be entitled, to
the extent permitted under any applicable law, to select and change a
beneficiary or beneficiaries to receive any compensation or benefit payable
under this Program following his or her death by giving the Company written
notice thereof. In the event of a Participant's death or a judicial
determination of a Participant's incompetence, reference in this Program to
"Participant" shall be deemed, where appropriate, to refer to such
Participant's beneficiary, estate or other legal representative.
(j) Withholding. The Company may withhold from any payments under this
Program all federal, state and local taxes as the Company is required to
withhold pursuant to any law or governmental rule or regulation. Each
Participant shall bear all expense of, and be solely responsible for, all
federal, state and local taxes due with respect to any payment received under
this Program.
.
(k) Establishment of Trust. The Company may establish an irrevocable
trust fund pursuant to a trust agreement to hold assets to satisfy any of its
obligations under this Program. Funding of such trust fund shall be subject
to the Board's discretion, as set forth in the agreement pursuant to which
the fund will be established.
Exhibit 10.37.1
AMENDMENT TO SPECIAL SEVERANCE PROGRAM
FOR OFFICERS OF NORTHEAST UTILITIES SYSTEM COMPANIES
The definition of "Termination upon a Change of Control" set forth in Article
II of the Special Severance Program for Officers of Northeast Utilities
System Companies is amended to read in its entirety as follows, effective
February 23, 1999:
"Termination upon a Change of Control" of a Participant shall mean a
Termination of Employment during the period beginning on the earlier of (a)
approval by the shareholders of Northeast Utilities of a Change of Control or
(b) consummation of a Change of Control and, in either case, ending on the
second anniversary of the consummation of the transaction that constitutes
the Change of Control (or if such period started on shareholder approval and
after such shareholder approval the Board abandons the transaction, on the
date the Board abandoned the transaction) either:
(i) initiated by the Company for any reason other than (w) Disability, (x)
death, (y) retirement on or after attaining age 65, or (z) Cause, or
(ii) initiated by the Participant (A) upon any significant reduction by the
Company of the authority, duties or responsibilities of Participant, any
reduction of the Participant's compensation or benefits other than a
reduction applicable to all employees generally, or the assignment to
Participant of duties which are materially inconsistent with the duties of
Participant's position with the Company, or (B) if Participant is
transferred, without Participant's written consent, to a location that is
more than 50 miles from Participant's principal place of business immediately
preceding such approval or consummation.
Approved in accordance with resolutions of the Board of Trustees of Northeast
Utilities adopted on February 23, 1999.
Cheryl W. Grise
Senior Vice President, Secretary and General Counsel
I waive the two-year notice period of a change to the Special Severance
Program provided for in Section VIII(a) thereof:
Name:
Date:
Exhibit 10.39.1
AMENDMENT TO EMPLOYMENT AGREEMENT
This Amendment to Employment Agreement, dated as of February 23, 1999, amends
the Employment Agreement, dated as of August 20, 1997, between Northeast
Utilities ("NU") and Michael G. Morris, as follows:
A. The phrase "a Termination upon Change of Control, as defined in Section
6.1(f)" in Section 1.9 of the Employment Agreement is amended to read "a
Change of Control, as defined in Section 6.1(c)".
B. Section 6.1(f) is amended to read in its entirety as follows:
(f) "Termination upon a Change of Control" shall mean a Termination of
Employment during the period beginning on the earlier of (a) approval by the
shareholders of NU of a Change of Control or (b) consummation of a Change of
Control and, in either case, ending on the second anniversary of the
consummation of the transaction that constitutes the Change of Control (or if
such period started on shareholder approval and after such shareholder
approval the Board abandons the transaction, on the date the Board abandoned
the transaction) either:
(i) initiated by the Company for any reason other than Executive's (w)
disability, as described in Section 5.1 hereof, (x) death, (y) retirement on
or after attaining age 65, or (z) "cause," as defined in Section 5.3 hereof,
or
(ii) initiated by Executive (A) upon any failure of the Company materially to
comply with and satisfy any of the terms of this Agreement, including any
significant reduction by the Company of the authority, duties or
responsibilities of Executive, any reduction of Executive's compensation or
benefits due hereunder, or the assignment to Executive of duties which are
materially inconsistent with the duties of Executive's position as defined in
Section 1.2 above, or (B) if Executive is transferred, without Executive's
written consent, to a location that is more than 50 miles from Executive's
principal place of business immediately preceding such approval or
consummation; provided, that the imposition on Executive following a Change
of Control of a limitation of Executive's scope of authority such that
Executive's responsibilities relate primarily to a company or companies whose
common equity is not publicly held shall be considered a "significant
reduction by the Company of the authority, duties or responsibilities of
Executive" for purposes hereof.
C. Section 6.4(c) of the Employment Agreement is deleted, and the following
paragraph is added at the beginning of Section 6.4:
Upon the occurrence of a Change of Control, unless the Compensation Committee
of the Northeast Utilities Board of Trustees is comprised of the same members
as those on the Committee immediately before the Change of Control and
determines otherwise, (i) the Option and any subsequent stock option grants
previously granted to Executive, to the extent not already vested prior to
such occurrence, shall be fully vested and immediately exercisable as if
Executive had satisfied all requirements as to exercise, including the right
of exercise where appropriate within 36 months of such occurrence, and if the
Change of Control results in the Voting Securities of NU ceasing to be traded
on a national securities exchange or through the national market system of
the National Association of Securities Dealers Inc., the price at which the
Option shall be exercised shall be the average of the closing prices for the
five trading days preceding the day such Voting Securities cease trading; and
(ii) if the Company is not the surviving corporation (or survives only as a
subsidiary of another corporation), that portion of the Option that has not
been exercised shall be assumed by, or replaced with comparable options or
rights by, the surviving corporation. Notwithstanding the foregoing, such
Committee (if comprised of the same members as those on the Committee
immediately before the Change of Control) may require Executive to surrender
the remainder of the Option in exchange for a payment by the Company, in cash
or common shares as determined by the Committee, in an amount equal to the
amount by which the then fair market value of the common shares subject to
the Option exceeds $9.625 per share, or, after giving Executive an
opportunity to exercise the Option, terminate the Option at such time as the
Committee deems appropriate.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Amendment as of the day and year first above written.
NORTHEAST UTILITIES
/s/Michael G. Morris
By/s/Cheryl Grise
Senior Vice President, Secretary
and General Counsel
3/3/99 3/3/99
Exhibit 10.41.1
AMENDMENT TO EMPLOYMENT AGREEMENT
This Amendment to Employment Agreement, dated as of January 13, 1998, amends
the Employment Agreement, dated as of February 25, 1997, between Northeast
Utilities Service Company and Bruce D. Kenyon.
1. Section 3.1(a) is amended to read in its entirety as follows:
During his employment by the Company and for a period of two years after
Executive's termination of employment for any reason, within the Company's
"service area," as defined below, Executive will not, except with the prior
written consent of the Board, directly or indirectly, own, manage, operate,
join, control, finance or participate in the ownership, management,
operation, control or financing of, or be connected as an officer, director,
employee, partner, principal, agent, representative, consultant or otherwise
with, or use or permit his name to be used in connection with, any business
or enterprise which is engaged in any business that is competitive with any
business or enterprise in which the Company is engaged. For the purposes of
this Section, "service area" shall mean the geographic area within the states
of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and
Vermont, or any other state in which the Company, in the aggregate, generates
25% or more of its revenues in the fiscal year of NU in which Executive's
termination of employment occurs. Executive acknowledges that the listed
service area is the area in which the Company presently does business.
2. Section 6.1(c) is amended to read in its entirety as follows:
"Change of Control" shall mean the happening of any of the following:
(i) When any "person," as such term is used in Sections 13(d) and 14(d)
of the Securities Exchange Act of 1934 (the "Exchange Act"), other than the
Company, its Affiliates, or any Company or NU employee benefit plan
(including any trustee of such plan acting as trustee), is or becomes the
"beneficial owner" (as defined in Rule 13d-3 under the Exchange Act),
directly or indirectly, of securities of NU representing more than 20% of the
combined voting power of either (i) the then outstanding common shares of NU
(the "Outstanding Common Shares") or (ii) the Voting Securities; or
(ii) Individuals who, as of the beginning of any twenty-four month
period, constitute the Trustees (the "Incumbent Trustees") cease for any
reason to constitute at least a majority of the Trustees or cease to be able
to exercise the powers of the majority of the Trustees, provided that any
individual becoming a trustee subsequent to the beginning of such period
whose election or nomination for election by the Company's shareholders was
approved by a vote of at least a majority of the trustees then comprising the
Incumbent Trustees shall be considered as though such individual were a
member of the Incumbent Trustees, but excluding, for this purpose, any such
individual whose initial assumption of office is in connection with an actual
or threatened election contest relating to the election of the Trustees of NU
(as such terms are used in Rule 14a-11 of Regulation 14A promulgated under
the Exchange Act); or
(iii) Consummation by NU of a reorganization, merger or
consolidation (a "Business Combination"), in each case, with respect to which
all or substantially all of the individuals and entities who were the
respective beneficial owners of the Outstanding Common Shares and Voting
Securities immediately prior to such Business Combination do not, following
consummation of all transactions intended to constitute part of such Business
Combination, beneficially own, directly or indirectly, more than 75% of,
respectively, the then outstanding shares of common stock and the combined
voting power of the then outstanding voting securities entitled to vote
generally in the election of directors, as the case may be, of the
corporation, business trust or other entity resulting from or being the
surviving entity in such Business Combination in substantially the same
proportion as their ownership immediately prior to such Business Combination
of the Outstanding Common Shares and Voting Securities, as the case may be;
or
(iv) Consummation of a complete liquidation or dissolution of NU or sale
or other disposition of all or substantially all of the assets of NU other
than to a corporation, business trust or other entity with respect to which,
following consummation of all transactions intended to constitute part of
such sale or disposition, more than 75% of, respectively, the then
outstanding shares of common stock and the combined voting power of the then
outstanding voting securities entitled to vote generally in the election of
directors, as the case may be, is then owned beneficially, directly or
indirectly, by all or substantially all of the individuals and entities who
were the beneficial owners, respectively, of the Outstanding Common Shares
and Voting Securities immediately prior to such sale or disposition in
substantially the same proportion as their ownership of the Outstanding
Common Shares and Voting Securities, as the case may be, immediately prior to
such sale or disposition.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Agreement as of the day and year first above written.
NORTHEAST UTILITIES
SERVICE COMPANY
/s/Bruce D. Kenyon By: /s/Cheryl Grise
Executive Senior Vice President
6/25/98 6/26/98
Exhibit 10.41.2
AMENDMENT TO EMPLOYMENT AGREEMENT
This Amendment to Employment Agreement, dated as of February 23, 1999, amends
Section 6.1(f) of the Employment Agreement, dated as of August 21, 1996,
between Northeast Utilities Service Company and Bruce D. Kenyon, to read as
follows:
(f) "Termination upon a Change of Control" shall mean a Termination of
Employment during the period beginning on the earlier of (a) approval by the
shareholders of NU of a Change of Control or (b) consummation of a Change of
Control and, in either case, ending on the second anniversary of the
consummation of the transaction that constitutes the Change of Control (or if
such period started on shareholder approval and after such shareholder
approval the Board abandons the transaction, on the date the Board abandoned
the transaction) either:
(i) initiated by the Company for any reason other than Executive's (w)
disability, as described in Section 5.1 hereof, (x) death, (y) retirement on
or after attaining age 65, or (z) "cause," as defined in Section 5.3 hereof,
or
(ii) initiated by Executive (A) upon any failure of the Company materially to
comply with and satisfy any of the terms of this Agreement, including any
significant reduction by the Company of the authority, duties or
responsibilities of Executive, any reduction of Executive's compensation or
benefits due hereunder, or the assignment to Executive of duties which are
materially inconsistent with the duties of Executive's position as defined in
Section 1.2 above, or (B) if Executive is transferred, without Executive's
written consent, to a location that is more than 50 miles from Executive's
principal place of business immediately preceding such approval or
consummation; provided, that the imposition on Executive following a Change
of Control of a limitation of Executive's scope of authority such that
Executive's responsibilities relate primarily to a company or companies whose
common equity is not publicly held shall be considered a "significant
reduction by the Company of the authority, duties or responsibilities of
Executive" for purposes hereof.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Amendment as of the day and year first above written.
NORTHEAST UTILITIES SERVICE COMPANY
/s/Bruce D. Kenyon
3/5/99
By /s/Cheryl Grise
Senior Vice President, Secretary
and General Counsel
3/4/99
Exhibit 10.42.1
AMENDMENT TO EMPLOYMENT AGREEMENT
This Amendment to Employment Agreement, dated as of January 13, 1998, amends
the Employment Agreement, dated as of February 25, 1997, between Northeast
Utilities Service Company and John H. Forsgren.
1. Section 3.1(a) is amended to read in its entirety as follows:
During his employment by the Company and for a period of two years after
Executive's termination of employment for any reason, within the Company's
"service area," as defined below, Executive will not, except with the prior
written consent of the Board, directly or indirectly, own, manage, operate,
join, control, finance or participate in the ownership, management,
operation, control or financing of, or be connected as an officer, director,
employee, partner, principal, agent, representative, consultant or otherwise
with, or use or permit his name to be used in connection with, any business
or enterprise which is engaged in any business that is competitive with any
business or enterprise in which the Company is engaged. For the purposes of
this Section, "service area" shall mean the geographic area within the states
of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and
Vermont, or any other state in which the Company, in the aggregate, generates
25% or more of its revenues in the fiscal year of NU in which Executive's
termination of employment occurs. Executive acknowledges that the listed
service area is the area in which the Company presently does business.
2. Section 6.1(c) is amended to read in its entirety as follows:
"Change of Control" shall mean the happening of any of the following:
(i) When any "person," as such term is used in Sections 13(d) and 14(d)
of the Securities Exchange Act of 1934 (the "Exchange Act"), other than the
Company, its Affiliates, or any Company or NU employee benefit plan
(including any trustee of such plan acting as trustee), is or becomes the
"beneficial owner" (as defined in Rule 13d-3 under the Exchange Act),
directly or indirectly, of securities of NU representing more than 20% of the
combined voting power of either (i) the then outstanding common shares of NU
(the "Outstanding Common Shares") or (ii) the Voting Securities; or
(ii) Individuals who, as of the beginning of any twenty-four month
period, constitute the Trustees (the "Incumbent Trustees") cease for any
reason to constitute at least a majority of the Trustees or cease to be able
to exercise the powers of the majority of the Trustees, provided that any
individual becoming a trustee subsequent to the beginning of such period
whose election or nomination for election by the Company's shareholders was
approved by a vote of at least a majority of the trustees then comprising the
Incumbent Trustees shall be considered as though such individual were a
member of the Incumbent Trustees, but excluding, for this purpose, any such
individual whose initial assumption of office is in connection with an actual
or threatened election contest relating to the election of the Trustees of NU
(as such terms are used in Rule 14a-11 of Regulation 14A promulgated under
the Exchange Act); or
(iii) Consummation by NU of a reorganization, merger or
consolidation (a "Business Combination"), in each case, with respect to which
all or substantially all of the individuals and entities who were the
respective beneficial owners of the Outstanding Common Shares and Voting
Securities immediately prior to such Business Combination do not, following
consummation of all transactions intended to constitute part of such Business
Combination, beneficially own, directly or indirectly, more than 75% of,
respectively, the then outstanding shares of common stock and the combined
voting power of the then outstanding voting securities entitled to vote
generally in the election of directors, as the case may be, of the
corporation, business trust or other entity resulting from or being the
surviving entity in such Business Combination in substantially the same
proportion as their ownership immediately prior to such Business Combination
of the Outstanding Common Shares and Voting Securities, as the case may be;
or
(iv) Consummation of a complete liquidation or dissolution of NU or sale
or other disposition of all or substantially all of the assets of NU other
than to a corporation, business trust or other entity with respect to which,
following consummation of all transactions intended to constitute part of
such sale or disposition, more than 75% of, respectively, the then
outstanding shares of common stock and the combined voting power of the then
outstanding voting securities entitled to vote generally in the election of
directors, as the case may be, is then owned beneficially, directly or
indirectly, by all or substantially all of the individuals and entities who
were the beneficial owners, respectively, of the Outstanding Common Shares
and Voting Securities immediately prior to such sale or disposition in
substantially the same proportion as their ownership of the Outstanding
Common Shares and Voting Securities, as the case may be, immediately prior to
such sale or disposition.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Agreement as of the day and year first above written.
NORTHEAST UTILITIES
SERVICE COMPANY
/s/John H. Forsgren By: /s/Cheryl Grise
Executive Senior Vice President
6/25/98 6/26/98
Exhibit 10.42.2
AMENDMENT TO EMPLOYMENT AGREEMENT
This Amendment to Employment Agreement, dated as of February 23, 1999, amends
Section 6.1(f) of the Employment Agreement, dated as of February 1, 1996,
between Northeast Utilities Service Company and John H. Forsgren, to read as
follows:
(f) "Termination upon a Change of Control" shall mean a Termination of
Employment during the period beginning on the earlier of (a) approval by the
shareholders of NU of a Change of Control or (b) consummation of a Change of
Control and, in either case, ending on the second anniversary of the
consummation of the transaction that constitutes the Change of Control (or if
such period started on shareholder approval and after such shareholder
approval the Board abandons the transaction, on the date the Board abandoned
the transaction) either:
(i) initiated by the Company for any reason other than Executive's (w)
disability, as described in Section 5.1 hereof, (x) death, (y) retirement on
or after attaining age 65, or (z) "cause," as defined in Section 5.3 hereof,
or
(ii) initiated by Executive (A) upon any failure of the Company materially to
comply with and satisfy any of the terms of this Agreement, including any
significant reduction by the Company of the authority, duties or
responsibilities of Executive, any reduction of Executive's compensation or
benefits due hereunder, or the assignment to Executive of duties which are
materially inconsistent with the duties of Executive's position as defined in
Section 1.2 above, or (B) if Executive is transferred, without Executive's
written consent, to a location that is more than 50 miles from Executive's
principal place of business immediately preceding such approval or
consummation; provided, that the imposition on Executive following a Change
of Control of a limitation of Executive's scope of authority such that
Executive's responsibilities relate primarily to a company or companies whose
common equity is not publicly held shall be considered a "significant
reduction by the Company of the authority, duties or responsibilities of
Executive" for purposes hereof.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Amendment as of the day and year first above written.
NORTHEAST UTILITIES SERVICE COMPANY
/s/John H. Forsgren /s/Cheryl Grise
3/8/99 Senior Vice President, Secretary and
General Counsel
3/4/99
Exhibit 10.43.1
AMENDMENT TO EMPLOYMENT AGREEMENT
This Amendment to Employment Agreement, dated as of January 13, 1998, amends
the Employment Agreement, dated as of February 25, 1997, between Northeast
Utilities Service Company and Hugh C. MacKenzie.
1. Section 3.1(a) is amended to read in its entirety as follows:
During his employment by the Company and for a period of two years after
Executive's termination of employment for any reason, within the Company's
"service area," as defined below, Executive will not, except with the prior
written consent of the Board, directly or indirectly, own, manage, operate,
join, control, finance or participate in the ownership, management,
operation, control or financing of, or be connected as an officer, director,
employee, partner, principal, agent, representative, consultant or otherwise
with, or use or permit his name to be used in connection with, any business
or enterprise which is engaged in any business that is competitive with any
business or enterprise in which the Company is engaged. For the purposes of
this Section, "service area" shall mean the geographic area within the states
of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and
Vermont, or any other state in which the Company, in the aggregate, generates
25% or more of its revenues in the fiscal year of NU in which Executive's
termination of employment occurs. Executive acknowledges that the listed
service area is the area in which the Company presently does business.
2. Section 6.1(c) is amended to read in its entirety as follows:
"Change of Control" shall mean the happening of any of the following:
(i) When any "person," as such term is used in Sections 13(d) and 14(d)
of the Securities Exchange Act of 1934 (the "Exchange Act"), other than the
Company, its Affiliates, or any Company or NU employee benefit plan
(including any trustee of such plan acting as trustee), is or becomes the
"beneficial owner" (as defined in Rule 13d-3 under the Exchange Act),
directly or indirectly, of securities of NU representing more than 20% of the
combined voting power of either (i) the then outstanding common shares of NU
(the "Outstanding Common Shares") or (ii) the Voting Securities; or
(ii) Individuals who, as of the beginning of any twenty-four month
period, constitute the Trustees (the "Incumbent Trustees") cease for any
reason to constitute at least a majority of the Trustees or cease to be able
to exercise the powers of the majority of the Trustees, provided that any
individual becoming a trustee subsequent to the beginning of such period
whose election or nomination for election by the Company's shareholders was
approved by a vote of at least a majority of the trustees then comprising the
Incumbent Trustees shall be considered as though such individual were a
member of the Incumbent Trustees, but excluding, for this purpose, any such
individual whose initial assumption of office is in connection with an actual
or threatened election contest relating to the election of the Trustees of NU
(as such terms are used in Rule 14a-11 of Regulation 14A promulgated under
the Exchange Act); or
(iii) Consummation by NU of a reorganization, merger or
consolidation (a "Business Combination"), in each case, with respect to which
all or substantially all of the individuals and entities who were the
respective beneficial owners of the Outstanding Common Shares and Voting
Securities immediately prior to such Business Combination do not, following
consummation of all transactions intended to constitute part of such Business
Combination, beneficially own, directly or indirectly, more than 75% of,
respectively, the then outstanding shares of common stock and the combined
voting power of the then outstanding voting securities entitled to vote
generally in the election of directors, as the case may be, of the
corporation, business trust or other entity resulting from or being the
surviving entity in such Business Combination in substantially the same
proportion as their ownership immediately prior to such Business Combination
of the Outstanding Common Shares and Voting Securities, as the case may be;
or
(iv) Consummation of a complete liquidation or dissolution of NU or sale
or other disposition of all or substantially all of the assets of NU other
than to a corporation, business trust or other entity with respect to which,
following consummation of all transactions intended to constitute part of
such sale or disposition, more than 75% of, respectively, the then
outstanding shares of common stock and the combined voting power of the then
outstanding voting securities entitled to vote generally in the election of
directors, as the case may be, is then owned beneficially, directly or
indirectly, by all or substantially all of the individuals and entities who
were the beneficial owners, respectively, of the Outstanding Common Shares
and Voting Securities immediately prior to such sale or disposition in
substantially the same proportion as their ownership of the Outstanding
Common Shares and Voting Securities, as the case may be, immediately prior to
such sale or disposition.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Agreement as of the day and year first above written.
NORTHEAST UTILITIES
SERVICE COMPANY
/s/Hugh C. MacKenzie By: /s/Cheryl Grise
Executive Senior Vice President
6/25/98 6/26/98
Exhibit 10.43.2
AMENDMENT TO EMPLOYMENT AGREEMENT
This Amendment to Employment Agreement, dated as of February 23, 1999, amends
Section 6.1(f) of the Employment Agreement, dated as of February 25, 1997,
between Northeast Utilities Service Company and Hugh C. MacKenzie
("Executive"), to read as follows:
(f) "Termination upon a Change of Control" shall mean a Termination of
Employment during the period beginning on the earlier of (a) approval by the
shareholders of NU of a Change of Control or (b) consummation of a Change of
Control and, in either case, ending on the second anniversary of the
consummation of the transaction that constitutes the Change of Control (or if
such period started on shareholder approval and after such shareholder
approval the Board abandons the transaction, on the date the Board abandoned
the transaction) either:
(i) initiated by the Company for any reason other than Executive's (w)
disability, as described in Section 5.1 hereof, (x) death, (y) retirement on
or after attaining age 65, or (z) "cause," as defined in Section 5.3 hereof,
or
(ii) initiated by Executive (A) upon any failure of the Company materially to
comply with and satisfy any of the terms of this Agreement, including any
significant reduction by the Company of the authority, duties or
responsibilities of Executive, any reduction of Executive's compensation or
benefits due hereunder, or the assignment to Executive of duties which are
materially inconsistent with the duties of Executive's position as defined in
Section 1.2 above, or (B) if Executive is transferred, without Executive's
written consent, to a location that is more than 50 miles from Executive's
principal place of business immediately preceding such approval or
consummation.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Amendment as of the day and year first above written.
/s/Hugh C. MacKenzie NORTHEAST UTILITIES SERVICE COMPANY
Executive /s/Cheryl Grise
3/5/99 Senior Vice President, Secretary
and General Counsel
3/4/99
Exhibit 10.44
EMPLOYMENT AGREEMENT
THIS EMPLOYMENT AGREEMENT (the "Agreement") entered into as of February 25,
1997, by and between Northeast Utilities Service Company, a Connecticut
corporation (the "Company"), with its principal office in Berlin,
Connecticut, and Cheryl W. Grise, a resident of West Hartford, Connecticut
("Executive").
WHEREAS, Executive is currently employed as the Senior Vice President and
Chief Administrative Officer of the Company and both parties desire to enter
into an agreement to reflect Executive's contribution to the Company's
business in Executive's executive capacities and to provide for Executive's
continued employment by the Company, upon the terms and conditions set forth
herein:
NOW, THEREFORE, the parties hereto, intending to be legally bound, hereby
agree as follows:
1. Employment. The Company hereby agrees to continue the employment of
Executive, and Executive hereby accepts such employment and agrees to perform
Executive's duties and responsibilities, in accordance with the terms,
conditions and provisions hereinafter set forth.
1.1. Employment Term. The term of Executive's employment under this
Agreement shall commence as of the date hereof (the "Effective Date") and
shall continue until December 31, 1998, unless sooner terminated in
accordance with Section 5 or Section 6 hereof, and shall automatically renew
for periods of one year unless one party gives written notice to the other,
at least six months prior to December 31, 1998 or at least six months prior
to the end of any one-year renewal period, that the Agreement shall not be
further extended. The period commencing as of the Effective Date and ending
on the date on which the term of Executive's employment under the Agreement
shall terminate is hereinafter referred to as the "Employment Term".
1.2. Duties and Responsibilities. Executive shall serve in such senior
positions as directed by the Company's Board of Directors (the "Board") or
the Board of Trustees (the "Trustees") of Northeast Utilities ("NU") that
provide Executive with duties and compensation that are substantially
equivalent to Executive's current position in terms of duties and
responsibilities. During the Employment Term, Executive shall perform all
duties and accept all responsibilities incident to such positions as may be
assigned to Executive by the Board.
1.3. Extent of Service. During the Employment Term, Executive agrees to use
Executive's best efforts to carry out Executive's duties and responsibilities
under Section 1.2 hereof and, consistent with the other provisions of this
Agreement, to devote substantially all Executive's business time, attention
and energy thereto. Except as provided in Section 3 hereof, the foregoing
shall not be construed as preventing Executive from making minority
investments in other businesses or enterprises provided that Executive agrees
not to become engaged in any other business activity which, in the reasonable
judgment of the Board, is likely to interfere with Executive's ability to
discharge Executive's duties and responsibilities to the Company.
1.4. Base Salary. For all the services rendered by Executive hereunder, the
Company shall pay Executive a base salary ("Base Salary"), commencing on the
Effective Date, at the annual rate then being paid to Executive by the
Company, payable in installments at such times as the Company customarily
pays its other senior level executives (but in any event no less often than
monthly). Executive's Base Salary shall be reviewed annually for appropriate
adjustment (but shall not be reduced below that in effect on the Effective
Date without Executive's written consent) by the Trustees pursuant to its
normal performance review policies for senior level executives.
1.5. Retirement and Benefit Coverages. During the Employment Term, Executive
shall be entitled to participate in all (a) employee pension and retirement
plans and programs ("Retirement Plans") and (b) welfare benefit plans and
programs ("Benefit Coverages"), in each case made available to the Company's
senior level executives as a group or to its employees generally, as such
Retirement Plans or Benefit Coverages may be in effect from time to time,
including, without limitation, the Company's Supplemental Executive
Retirement Plan for Officers (the "Supplemental Plan"), both as to the Make-
Whole Benefit and the Target Benefit.
1.6. Reimbursement of Expenses; Vacation. Executive shall be provided with
reimbursement of expenses related to Executive's employment by the Company on
a basis no less favorable than that which may be authorized from time to time
for senior level executives as a group, and shall be entitled to vacation and
holidays in accordance with the Company's normal personnel policies for
senior level executives.
1.7. Short-Term Incentive Compensation. If the Employment Term has not
previously terminated, beginning on January 1, 1999, Executive shall be
entitled to participate in any short-term incentive compensation programs
established by the Company for its senior level executives generally
depending upon achievement of certain annual individual or business
performance objectives specified and approved by the Trustees (or a Committee
thereof) in its sole discretion; provided, however, that Executive's "target
opportunity" and "maximum opportunity" under any such program shall be at
least at the same level as in effect for Executive on January 1, 1996.
Executive's short-term incentive compensation, either in shares of NU or
cash, as applicable from time to time, shall be paid to Executive, subject
to the Board's or the Trustee's reasonable discretion, not later than such
payments are made to the Company's senior level executives generally.
1.8. Long-Term Incentive Compensation. On and after the Effective Date and
until December 31, 1998, Executive shall participate in the NU Stock Price
Recovery Plan, in accordance with the terms adopted by the Trustees and NU's
Organization, Compensation and Board Affairs Committee on December 21, 1996.
If the Employment Term has not previously terminated, beginning on January 1,
1999, Executive shall also be entitled to participate in any long-term
incentive compensation programs established by the Company for its senior
level executives generally depending upon achievement of certain business
performance objectives specified and approved by the Trustees (or a Committee
thereof) in its sole discretion; provided, however, that Executive's "target
opportunity" and "maximum opportunity" under any such program shall be at
least at the same level as in effect for Executive on January 1, 1996.
Executive's long-term incentive compensation, either in shares of NU or cash,
as applicable from time to time, shall be paid to Executive, subject to the
Board's or the Trustee's reasonable discretion, not later than such payments
are made to the Company's senior level executives generally.
2. Confidential Information. Executive recognizes and acknowledges that by
reason of Executive's employment by and service to the Company before, during
and, if applicable, after the Employment Term Executive has had and will
continue to have access to certain confidential and proprietary information
relating to the business of the Company, which may include, but is not
limited to, trade secrets, trade "know-how", customer information, supplier
information, cost and pricing information, marketing and sales techniques,
strategies and programs, computer programs and software and financial
information (collectively referred to as "Confidential Information").
Executive acknowledges that such Confidential Information is a valuable and
unique asset of the Company and Executive covenants that Executive will not,
unless expressly authorized in writing by the Board, at any time during the
course of Executive's employment use any Confidential Information or divulge
or disclose any Confidential Information to any person, firm or corporation
except in connection with the performance of Executive's duties for the
Company and in a manner consistent with the Company's policies regarding
Confidential Information. Executive also covenants that at any time after
the termination of such employment, directly or indirectly, Executive will
not use any Confidential Information or divulge or disclose any Confidential
Information to any person, firm or corporation, unless such information is in
the public domain through no fault of Executive or except when required to do
so by a court of law, by any governmental agency having supervisory authority
over the business of the Company or by any administrative or legislative body
(including a committee thereof) with apparent jurisdiction to order
Executive to divulge, disclose or make accessible such information, in which
case Executive will inform the Company in writing promptly of such required
disclosure, but in any event at least two business days prior to disclosure.
All written Confidential Information (including, without limitation, in any
computer or other electronic format) which comes into Executive's possession
during the course of Executive's employment shall remain the property of the
Company. Except as required in the performance of Executive's duties for the
Company, or unless expressly authorized in writing by the Board, Executive
shall not remove any written Confidential Information from the Company's
premises, except in connection with the performance of Executive's duties for
the Company and in a manner consistent with the Company's policies regarding
Confidential Information. Upon termination of Executive's employment,
Executive agrees immediately to return to the Company all written
Confidential Information in Executive's possession. For the purposes of
this Section 2, the term "Company" shall be deemed to include NU and the
Affiliates, as defined in Section 6.1(a), of NU and the Company.
3. Non-Competition; Non-Solicitation.
(a) During Executive's employment by the Company and for a period of two
years after Executive's termination of employment for any reason, within the
Company's "service area," as defined below, Executive will not, except with
the prior written consent of the Board, directly or indirectly, own, manage,
operate, join, control, finance or participate in the ownership, management,
operation, control or financing of, or be connected as an officer, director,
employee, partner, principal, agent, representative, consultant or otherwise
with, or use or permit Executive's name to be used in connection with, any
business or enterprise which is engaged in any business that is competitive
with any business or enterprise in which the Company is engaged. For the
purposes of this Section, "service area" shall mean the geographic area
within the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode
Island, and Vermont, or any other geographic area in which, at the time of
Executive's termination of employment from the Company, the Company is doing
business. Executive acknowledges that the listed service area is the area in
which the Company presently does business.
(b) The foregoing restrictions shall not be construed to prohibit the
ownership by Executive of less than five percent (5%) of any class of
securities of any corporation which is engaged in any of the foregoing
businesses having a class of securities registered pursuant to the Securities
Exchange Act of 1934 (the "Exchange Act"), provided that such ownership
represents a passive investment and that neither Executive nor any group of
persons including Executive in any way, either directly or indirectly,
manages or exercises control of any such corporation, guarantees any of its
financial obligations, otherwise takes any part in its business, other than
exercising Executive's rights as a shareholder, or seeks to do any of the
foregoing.
(c) Executive further covenants and agrees that during Executive's
employment by the Company and for the period of two years thereafter,
Executive will not, directly or indirectly, (i) solicit, divert, take away,
or attempt to solicit, divert or take away, any of the Company's "Principal
Customers," defined for the purposes hereof to include any customer of the
Company, from which $100,000 or more of annual gross revenues are derived at
such time, or (ii) encourage any Principal Customer to reduce its patronage
of the Company.
(d) Executive further covenants and agrees that during Executive's
employment by the Company and for the period of two years thereafter,
Executive will not, directly or indirectly, solicit or hire, or encourage the
solicitation or hiring of, any person who was a managerial or higher level
employee of the Company at any time during the term of Executive's employment
by the Company by any employer other than the Company for any position as an
employee, independent contractor, consultant or otherwise. The foregoing
covenant of Executive shall not apply to any person after 12 months have
elapsed subsequent to the date on which such person's employment by the
Company has terminated.
(e) Nothing in this Section 3 shall be construed to prohibit Executive, if
Executive is a lawyer, from being connected as a partner, principal,
shareholder, associate, counsel or otherwise with another lawyer or a law
firm which performs services for clients engaged in any business or
enterprise that is competitive with any business or enterprise in which the
Company is engaged, provided that Executive is not personally involved,
directly or indirectly, in performing services for any such clients during
the period specified in Section 3(a) and provided further that such lawyer or
law firm takes reasonable precautions to screen Executive from participating
for the period specified in Section 3(a) in the representation of any such
clients. The parties agree that any such personal performance of services by
Executive for any such clients during such period would create an
unreasonable risk of violation by Executive of the provisions of Section 2 of
this Agreement, and Executive agrees (and the Company may elect) to notify in
writing any lawyer or law firm with which Executive may be connected during
the period specified in Section 3(a) of Executive's Agreement as set forth
herein. The parties further agree that, in addition to the nondisclosure
obligations of Section 2 of this Agreement, Executive remains subject to all
ethical obligations relating to confidentiality of information to the extent
that Executive acted as a lawyer for the Company, but Executive's knowledge
of such confidential information shall not be imputed to such other lawyer or
law firm with which Executive subsequently may become connected. Executive
agrees to notify the Company in writing in advance of the precautions to be
taken by such lawyer or law firm to screen Executive from any representation
of such competing client of such lawyer or law firm.
(f) For the purposes of this Section 3, the term "Company" shall be deemed
to include NU and the Affiliates, as defined in Section 6.1(a), of NU and the
Company.
4. Equitable Relief.
(a) Executive acknowledges and agrees that the restrictions contained in
Sections 2 and 3 are reasonable and necessary to protect and preserve the
legitimate interests, properties, goodwill and business of the Company, that
the Company would not have entered into this Agreement in the absence of such
restrictions and that irreparable injury will be suffered by the Company
should Executive breach any of the provisions of those Sections. Executive
represents and acknowledges that (i) Executive has been advised by the
Company to consult Executive's own legal counsel in respect of this
Agreement, and (ii) that Executive has had full opportunity, prior to
execution of this Agreement, to review thoroughly this Agreement with
Executive's counsel.
(b) Executive further acknowledges and agrees that a breach of any of the
restrictions in Sections 2 and 3 cannot be adequately compensated by monetary
damages. Executive agrees that the Company shall be entitled to preliminary
and permanent injunctive relief, without the necessity of proving actual
damages, as well as an equitable accounting of all earnings, profits and
other benefits arising from any violation of Sections 2 or 3 hereof, which
rights shall be cumulative and in addition to any other rights or remedies to
which the Company may be entitled. In the event that any of the provisions
of Sections 2 or 3 hereof should ever be adjudicated to exceed the time,
geographic, service, or other limitations permitted by applicable law in any
jurisdiction, it is the intention of the parties that the provision shall be
amended to the extent of the maximum time, geographic, service, or other
limitations permitted by applicable law, that such amendment shall apply only
within the jurisdiction of the court that made such adjudication and that the
provision otherwise be enforced to the maximum extent permitted by law.
(c) If Executive breaches any of Executive's obligations under Sections 2 or
3 hereof, and such breach constitutes "Cause," as defined in Section 5.3
hereof, or would constitute Cause if it had occurred during the Employment
Term, the Company shall thereafter have no Target Benefit obligation pursuant
to the Supplemental Plan, but shall remain obligated for the Make-Whole
Benefit under the Supplemental Plan, but only to the extent not modified by
the terms of this Agreement, and compensation and other benefits provided in
any plans, policies or practices then applicable to Executive in accordance
with the terms thereof.
(d) Executive irrevocably and unconditionally (i) agrees that any suit,
action or other legal proceeding arising out of Sections 2 or 3 hereof,
including without limitation, any action commenced by the Company for
preliminary and permanent injunctive relief and other equitable relief, may
be brought in the United States District Court for the District of
Connecticut, or if such court does not have jurisdiction or will not accept
jurisdiction, in any court of general jurisdiction in Hartford, Connecticut,
(ii) consents to the non-exclusive jurisdiction of any such court in any such
suit, action or proceeding, and (iii) waives any objection which Executive
may have to the laying of venue of any such suit, action or proceeding in any
such court. Executive also irrevocably and unconditionally consents to the
service of any process, pleadings, notices or other papers in a manner
permitted by the notice provisions of Section 10 hereof.
(e) Executive agrees that for a period of five years following the
termination of Executive's employment by the Company Executive will provide,
and that at all times after the date hereof the Company may similarly
provide, a copy of Sections 2 and 3 hereof to any business or enterprise (i)
which Executive may directly or indirectly own, manage, operate, finance,
join, control or participate in the ownership, management, operation,
financing, or control of, or (ii) with which Executive may be connected as an
officer, director, employee, partner, principal, agent, representative,
consultant or otherwise, or in connection with which Executive may use or
permit Executive's name to be used; provided, however, that this provision
shall not apply in respect of Section 3 hereof after expiration of the time
periods set forth therein.
(f) For the purposes of this Section 4, the term "Company" shall be deemed
to include NU and the Affiliates, as defined in Section 6.1(a), of NU and the
Company.
5. Termination. The Employment Term shall terminate upon the occurrence of
any one of the following events:
5.1. Disability. The Company may terminate the Employment Term if Executive
is unable substantially to perform Executive's duties and responsibilities
hereunder to the full extent required by the Board by reason of illness,
injury or incapacity for six consecutive months, or for more than six months
in the aggregate during any period of twelve calendar months; provided,
however, that the Company shall continue to pay Executive's Base Salary until
the Company acts to terminate the Employment Term. In addition, Executive
shall be entitled to receive (i) any amounts earned, accrued or owing but not
yet paid under Section 1 above and (ii) any other benefits in accordance with
the terms of any applicable plans and programs of the Company. Otherwise,
the Company shall have no further liability or obligation to Executive for
compensation under this Agreement. Executive agrees, in the event of a
dispute under this Section 5.1, to submit to a physical examination by a
licensed physician selected by the Board.
5.2. Death. The Employment Term shall terminate in the event of Executive's
death. In such event, the Company shall pay to Executive's executors, legal
representatives or administrators, as applicable, an amount equal to the
installment of Executive's Base Salary set forth in Section 1.4 hereof for
the month in which Executive dies. In addition, Executive's estate shall be
entitled to receive (i) any other amounts earned, accrued or owing but not
yet paid under Section 1 above and (ii) any other benefits in accordance
with the terms of any applicable plans and programs of the Company.
Otherwise, the Company shall have no further liability or obligation under
this Agreement to Executive's executors, legal representatives,
administrators, heirs or assigns or any other person claiming under or
through Executive.
5.3. Cause. The Company may terminate the Employment Term, at any time, for
"cause" upon written notice, in which event all payments under this Agreement
shall cease, except for Base Salary to the extent already accrued, and no
Target Benefit shall be due under the Supplemental Plan, but Executive shall
remain entitled to the Make-Whole Benefit under the Supplemental Plan, but
only to the extent not modified by the terms of this Agreement, and any other
benefits in accordance with the terms of any applicable plans and programs of
the Company. For purposes of this Agreement, Executive's employment may be
terminated for "cause" if (i) Executive is convicted of a felony, (ii) in the
reasonable determination of the Board, Executive has (x) committed an act of
fraud, embezzlement, or theft in connection with Executive's duties in the
course of Executive's employment with the Company, (y) caused intentional,
wrongful damage to the property of the Company or intentionally and
wrongfully disclosed Confidential Information, or (z) engaged in gross
misconduct or gross negligence in the course of Executive's employment with
the Company or (iii) Executive materially breached Executive's obligations
under this Agreement and shall not have remedied such breach within 30 days
after receiving written notice from the Board specifying the details thereof.
For purposes of this Agreement, an act or omission on the part of Executive
shall be deemed "intentional" only if it was not due primarily to an error in
judgment or negligence and was done by Executive not in good faith and
without reasonable belief that the act or omission was in the best interest
of the Company.
5.4. Termination Without Cause and Non-Renewal.
(a) The Company may remove Executive, at any time, without cause from the
position in which Executive is employed hereunder (in which case the
Employment Term shall be deemed to have ended) upon not less than 60 days'
prior written notice to Executive; provided, however, that, in the event that
such notice is given, Executive shall be under no obligation to render any
additional services to the Company and, subject to the provisions of Section
3 hereof, shall be allowed to seek other employment. Upon any such removal
or if the Company informs Executive that the Agreement will not be renewed
after December 31, 1998 or at the end of any subsequent renewal period,
Executive shall be entitled to receive, as liquidated damages for the failure
of the Company to continue to employ Executive, only the amount due to
Executive under the Company's then current severance pay plan for employees.
No other payments or benefits shall be due under this Agreement to Executive,
but Executive shall be entitled to any other benefits in accordance with the
terms of any applicable plans and programs of the Company. Notwithstanding
anything in this Agreement to the contrary, on or after Executive attains age
65, no action by the Company shall be treated as a removal from employment or
non-renewal if on the effective date of such action Executive satisfies all
of the requirements for the executive or high policy-making exception to
applicable provisions of state and federal age discrimination legislation.
(b) Notwithstanding the foregoing, in the event that Executive executes a
written release upon such removal or non-renewal, substantially in the form
attached hereto as Annex 1, (the "Release"), of any and all claims against
the Company and all related parties with respect to all matters arising out
of Executive's employment by the Company (other than any entitlements under
the terms of this Agreement or under any other plans or programs of the
Company in which Executive participated and under which Executive has accrued
a benefit), or the termination thereof, Executive shall be entitled to
receive, in lieu of the payment described in subsection (a) hereof, which
Executive agrees to waive,
(i) as liquidated damages for the failure of the Company to continue to
employ Executive, a single cash payment, within 30 days after the effective
date of the removal or non-renewal, equal to Executive's Base Compensation,
as defined in Section 6.1(a) below, which shall not constitute a "severance
benefit" to Executive for purposes of the Target Benefit under the
Supplemental Plan;
(ii) for a period of two years following the end of the Employment Term,
Executive and Executive's spouse and dependents shall be eligible for a
continuation of those Benefit Coverages, as in effect at the time of such
termination or removal, and as the same may be changed from time to time, as
if Executive had been continued in employment during said period or to
receive cash in lieu of such benefits or premiums, as applicable, where such
Benefit Coverages may not be continued (or where such continuation would
adversely affect the tax status of the plan pursuant to which the Benefit
Coverage is provided) under applicable law or regulations;
(iii) any other amounts earned, accrued or owing but not yet paid under
Section 1 above;
(iv) any other benefits in accordance with the terms of any applicable plans
and programs of the Company and a payment equal to any unused vacation;
(v) as additional consideration for the non-competition and non-solicitation
covenant contained in Section 3, a single cash payment, within 30 days after
the effective date of the removal or non-renewal, equal to Executive's Base
Compensation, as defined in Section 6.1(a) below, which shall not constitute
a "severance benefit" to Executive for purposes of the Target Benefit under
the Supplemental Plan;
(vi) Executive's years of service with the Company through the 24th month
following the Termination Date shall be taken into account in determining the
amount of, and eligibility for, the Target Benefit and Make-Whole Benefit
under the Supplemental Plan and 24 months shall be added to Executive's age
for purposes of determining Executive's eligibility for both such Benefits
and the actuarial reduction under the Plan; and
(vii) All stock appreciation rights and restricted stock units granted to
Executive under NU's Stock Price Recovery Plan or stock options or restricted
shares previously granted to Executive, to the extent not already vested
prior to the removal or non-renewal, shall be fully vested and exercisable or
paid as if Executive had remained actively employed by the Company, including
the right of exercise, where appropriate, within 36 months after the removal
or non-renewal; provided, however, that the stock appreciation rights and
restricted stock units shall be paid on a pro rata basis for the number of
completed months in the applicable period for any such stock appreciation
rights or restricted stock units during which Executive was employed by the
Company.
5.5. Voluntary Termination. Executive may voluntarily terminate the
Employment Term upon 30 days' prior written notice for any reason. In such
event, after the effective date of such termination, no further payments
shall be due under this Agreement except that Executive shall be entitled to
any benefits due in accordance with the terms of any applicable plan and
programs of the Company.
6. Payments Upon a Change in Control.
6.1. Definitions. For all purposes of this Section 6, the following terms
shall have the meanings specified in this Section 6.1 unless the context
otherwise clearly requires:
(a) "Affiliate" shall mean an "affiliate" as defined in Rule 12b-2 of the
General Rules and Regulations under the Exchange Act.
(b) "Base Compensation" shall mean Executive's annualized Base Salary and
all short-term incentive compensation at the target level for Executive (but
in no event less than the target level for Executive in effect on January 1,
1996), specified under programs established by the Company for its senior
level executives generally, received by Executive in all capacities with the
Company, as would be reported for federal income tax purposes on Form W-2,
together with any and all salary reduction authorized amounts under any of
the Company's benefit plans or programs, for the most recent full calendar
year immediately preceding the calendar year in which occurs Executive's
Termination Date or preceding the Change of Control, if higher. "Base
Compensation" shall not include the value of any stock appreciation rights or
restricted stock units granted to Executive under NU's Stock Price Recovery
Plan.
(c) "Change of Control" shall mean the happening of any of the following:
(i) When any "person," as such term is used in Sections 13(d) and 14(d) of
the Securities Exchange Act of 1934 (the "Exchange Act"), other than the
Company, its Affiliates, or any Company or NU employee benefit plan
(including any trustee of such plan acting as trustee), is or becomes the
"beneficial owner" (as defined in Rule 13d-3 under the Exchange Act),
directly or indirectly, of securities of NU representing more than 20% of the
combined voting power of either (i) the then outstanding shares of common
stock of NU (the "Outstanding Common Stock") or (ii) the then outstanding
voting securities of NU entitled to vote generally in the election of
directors (the "Voting Securities"); or
(ii) Individuals who, as of the beginning of any twenty-four month period,
constitute the Trustees (the "Incumbent Board") cease for any reason to
constitute at least a majority of the Trustees or cease to be able to
exercise the powers of the majority of the Board, provided that any
individual becoming a trustee subsequent to the beginning of such period
whose election or nomination for election by the Company's stockholders was
approved by a vote of at least a majority of the trustees then comprising the
Incumbent Board shall be considered as though such individual were a member
of the Incumbent Board, but excluding, for this purpose, any such individual
whose initial assumption of office is in connection with an actual or
threatened election contest relating to the election of the Trustees of NU
(as such terms are used in Rule 14a-11 of Regulation 14A promulgated under
the Exchange Act); or
(iii) Consummation by NU of a reorganization, merger or consolidation (a
"Business Combination"), in each case, with respect to which all or
substantially all of the individuals and entities who were the respective
beneficial owners of the Outstanding Common Stock and Voting Securities
immediately prior to such Business Combination do not, following such
Business Combination, beneficially own, directly or indirectly, more than 75%
of, respectively, the then outstanding shares of common stock and the
combined voting power of the then outstanding voting securities entitled to
vote generally in the election of directors, as the case may be, of the
corporation, business trust or other entity resulting from or being the
surviving entity in such Business Combination in substantially the same
proportion as their ownership immediately prior to such Business Combination
of the Outstanding Common Stock and Voting Securities, as the case may be; or
(iv) Consummation of a complete liquidation or dissolution of NU or sale or
other disposition of all or substantially all of the assets of NU other than
to a corporation, business trust or other entity with respect to which,
following such sale or disposition, more than 75% of, respectively, the then
outstanding shares of common stock and the combined voting power of the then
outstanding voting securities entitled to vote generally in the election of
directors, as the case may be, is then owned beneficially, directly or
indirectly, by all or substantially all of the individuals and entities who
were the beneficial owners, respectively, of the Outstanding Common Stock and
Voting Securities immediately prior to such sale or disposition in
substantially the same proportion as their ownership of the Outstanding
Common Stock and Voting Securities, as the case may be, immediately prior to
such sale or disposition.
(d) "Termination Date" shall mean the date of receipt of a Notice of
Termination of this Agreement or any later date specified therein.
(e) "Termination of Employment" shall mean the termination of Executive's
actual employment relationship with the Company, including a failure to renew
the Agreement after December 31, 1998 or at the end of any subsequent renewal
period, in either case occasioned by the Company's action.
(f) "Termination upon a Change of Control" shall mean a Termination of
Employment upon or within two years after a Change of Control either:
(i) initiated by the Company for any reason other than Executive's (w)
disability, as described in Section 5.1 hereof, (x) death, (y) retirement on
or after attaining age 65, or (z) "cause," as defined in Section 5.3 hereof,
or (ii) initiated by Executive (A) upon any failure of the Company materially
to comply with and satisfy any of the terms of this Agreement, including any
significant reduction by the Company of the authority, duties or
responsibilities of Executive, any reduction of Executive's compensation or
benefits due hereunder, or the assignment to Executive of duties which are
materially inconsistent with the duties of Executive's position as defined in
Section 1.2 above, or (B) if Executive is transferred, without Executive's
written consent, to a location that is more than 50 miles from Executive's
principal place of business immediately preceding the Change of Control.
6.2. Notice of Termination. Any Termination upon a Change of Control shall
be communicated by a Notice of Termination to the other party hereto given in
accordance with Section 10 hereof. For purposes of this Agreement, a "Notice
of Termination" means a written notice which (i) indicates the specific
termination provision in this Agreement relied upon, (ii) briefly summarizes
the facts and circumstances deemed to provide a basis for a Termination of
Employment and the applicable provision hereof, and (iii) if the Termination
Date is other than the date of receipt of such notice, specifies the
Termination Date (which date shall not be more than 15 days after the giving
of such notice).
6.3. Payments upon Termination. Subject to the provisions of Sections 6.6
and 6.7 hereof, in the event of Executive's Termination upon a Change of
Control, the Company agrees (a) in the event Executive executes the Release
required by Section 5.4(b), to pay to Executive, in a single cash payment,
within thirty days after the Termination Date, two multiplied by Executive's
Base Compensation and, in addition, all amounts, benefits and Benefit
Coverages described in Section 5.4(b)(ii), (iii), (iv) and (v), provided that
in (ii) Benefit Coverages shall continue for three years instead of two, or
(b) in the event Executive fails or refuses to execute the Release required
by Section 5.4(b), to pay to Executive, in a single cash payment, within
thirty days after the Termination Date, the amount due under Section 5.4(a)
above and, in addition, all other amounts and benefits described in Section
5.4(a).
6.4. Other Payments, Supplemental Plan, Stock Option and Stock Grants, etc.
Subject to the provisions of Sections 6.6 and 6.7 hereof, in the event of
Executive's Termination upon a Change of Control, and the execution of the
Release required by Section 5.4(b):
(a) Under the Supplemental Plan, Executive shall be entitled to a Target
Benefit and a Make-Whole Benefit commencing as provided below with an
actuarial reduction in the event the Target Benefit and Make-Whole Benefit
commence prior to age 65 (age 60 if Executive has attained age 60 and
completed at least 30 years of service at the Termination Date), whether or
not Executive is then age 60 and notwithstanding the Plan's requirement that
a participant retire on or after age 60 and be entitled to a vested benefit
under the Company's Retirement Plan. The actuarial reduction shall be 2% for
each year younger than age 65 to age 60, if applicable, 3% for each year
younger than age 60 to age 55 and a full actuarial reduction, as determined
by the enrolled actuary for the Retirement Plan, for each year younger than
55. Executive's years of service with the Company through the 36th month
following the Termination Date shall be taken into account in determining the
amount of the Target Benefit and Make-Whole Benefit and 36 months shall be
added to Executive's age for purposes of determining Executive's eligibility
for both such Benefits and the actuarial reduction under the Plan as modified
herein. Executive shall determine the form of payment in which the Target
Benefit and Make-Whole Benefit shall be paid, in accordance with the terms of
the Supplemental Plan or may elect to receive a single sum payment equal to
the then actuarial present value (computed using the 1983 GAM (50%/Male/50%/
Female) Mortality Table and at an interest rate equal to the discount rate
used in the Retirement Plan's previous year's FASB 87 accounting) of the
amount of the Target Benefit and Make-Whole Benefit as determined in
accordance with the first three sentences of this subsection (a). Payment
shall commence or be made within 30 days after the Termination Date or on any
date thereafter, as specified by Executive in a written election. Such
election may be made at any time and amended at any time but any election or
amendment, other than one made within 30 days of the Effective Date, shall be
ineffective if made within six months prior to the Termination Date. In the
absence of any election or determination provided for herein, the terms of
the Supplemental Plan shall govern the form and time of payment.
(b) Executive's years of service with the Company through the 36th month
following the Termination Date shall be taken into account in determining
Executive's eligibility for, but not amount of cost sharing under, the
Company's retiree health plan and, in addition, 36 months shall be added to
Executive's age for this purpose.
(c) On Executive's Termination Date, all stock appreciation rights and
restricted stock units granted to Executive under NU's Stock Price Recovery
Plan or stock options or restricted shares previously granted to Executive,
to the extent not already vested prior to the Termination Date, shall be
fully vested and exercisable or paid as if Executive had remained actively
employed by the Company, including the right of exercise, where appropriate,
within 36 months after the Termination Date and, if the Change of Control
results in the Voting Securities of NU ceasing to be traded on a national
securities exchange or though the national market system of the National
Association of Securities Dealers Inc., the price at which the rights or
units may be exercised shall be the average of the closing prices for the
five trading days preceding the day such Voting Securities cease trading.
6.5. Non-Exclusivity of Rights. Nothing in this Agreement shall prevent or
limit Executive's continuing or future participation in or rights under any
benefit, bonus, incentive or other plan or program provided by the Company
and for which Executive may qualify; provided, however, that if Executive
becomes entitled to and receives all of the payments provided for in this
Agreement, Executive hereby waives Executive's right to receive payments
under any severance plan or similar program applicable to all employees of
the Company.
6.6. Certain Increase in Payments.
(a) Anything in this Agreement to the contrary notwithstanding, in the event
that it shall be determined that any payment or distribution by the Company
to or for the benefit of Executive, whether paid or payable or distributed or
distributable pursuant to the terms of this Agreement or otherwise (the
"Payment"), would constitute an "excess parachute payment" within the meaning
of Section 280G of the Internal Revenue Code of 1986, as amended (the
"Code"), Executive shall be paid an additional amount (the "Gross-Up
Payment") such that the net amount retained by Executive after deduction of
any excise tax imposed under Section 4999 of the Code, and any federal, state
and local income and employment tax and excise tax imposed upon the Gross-Up
Payment shall be equal to the Payment. For purposes of determining the
amount of the Gross-Up Payment, Executive shall be deemed to pay federal
income tax and employment taxes at the highest marginal rate of federal
income and employment taxation in the calendar year in which the Gross-Up
Payment is to be made and state and local income taxes at the highest
marginal rate of taxation in the state and locality of Executive's residence
on the Termination Date, net of the maximum reduction in federal income taxes
that may be obtained from the deduction of such state and local taxes.
(b) All determinations to be made under this Section 6 shall be made by the
Company's independent public accountant immediately prior to the Change of
Control (the "Accounting Firm"), which firm shall provide its determinations
and any supporting calculations both to the Company and Executive within 10
days of the Termination Date. Any such determination by the Accounting Firm
shall be binding upon the Company and Executive. Within five days after the
Accounting Firm's determination, the Company shall pay (or cause to be paid)
or distribute (or cause to be distributed) to or for the benefit of Executive
such amounts as are then due to Executive under this Agreement.
(c) In the event that upon any audit by the Internal Revenue Service, or by
a state or local taxing authority, of the Payment or Gross-Up Payment, a
change is finally determined to be required in the amount of taxes paid by
Executive, appropriate adjustments shall be made under this Agreement such
that the net amount which is payable to Executive after taking into account
the provisions of Section 4999 of the Code shall reflect the intent of the
parties as expressed in subsection (a) above, in the manner determined by the
Accounting Firm.
(d) All of the fees and expenses of the Accounting Firm in performing the
determinations referred to in subsections (b) and (c) above shall be borne
solely by the Company. The Company agrees to indemnify and hold harmless the
Accounting Firm of and from any and all claims, damages and expenses
resulting from or relating to its determinations pursuant to subsections (b)
and (c) above, except for claims, damages or expenses resulting from the
gross negligence or wilful misconduct of the Accounting Firm.
6.7 Changes to Sections 6.3 and 6.4. The payments, benefits and other
compensation provided under Sections 6.3 and 6.4 may be revised, in the sole
discretion of the Board, after the expiration of two years following written
notice to Executive of the Board's intention to do so and the changes to be
made; provided, however, that no revision may be made that would reduce the
payments, benefits and other compensation below those provided under Section
5.4 in the event Executive's employment is terminated without cause or this
Agreement is not renewed; and provided, further, that no such notice may be
given and no such revision may become effective following a Change of
Control. Notice under this Section 6.7 shall not constitute a non-renewal or
removal of Executive, nor shall any such actual revision be grounds for a
determination that this Agreement is not being renewed or that Executive has
been removed, for purposes of Section 5.4.
7. Survivorship. The respective rights and obligations of the parties
under this Agreement shall survive any termination of Executive's employment
to the extent necessary to the intended preservation of such rights and
obligations.
8. Mitigation. Executive shall not be required to mitigate the amount of
any payment or benefit provided for in this Agreement by seeking other
employment or otherwise and there shall be no offset against amounts due
Executive under this Agreement on account of any remuneration attributable to
any subsequent employment that Executive may obtain.
9. Arbitration; Expenses. In the event of any dispute under the provisions
of this Agreement other than a dispute in which the primary relief sought is
an equitable remedy such as an injunction, the parties shall be required to
have the dispute, controversy or claim settled by arbitration in the City of
Hartford, Connecticut in accordance with National Rules for the Resolution of
Employment Disputes then in effect of the American Arbitration Association,
before a panel of three arbitrators, two of whom shall be selected by the
Company and Executive, respectively, and the third of whom shall be selected
by the other two arbitrators. Any award entered by the arbitrators shall be
final, binding and nonappealable (except as provided in Section 52-418 of the
Connecticut General Statutes) and judgment may be entered thereon by either
party in accordance with applicable law in any court of competent
jurisdiction. This arbitration provision shall be specifically enforceable.
The arbitrators shall have no authority to modify any provision of this
Agreement or to award a remedy for a dispute involving this Agreement other
than a benefit specifically provided under or by virtue of the Agreement. If
Executive prevails on any material issue which is the subject of such
arbitration or lawsuit, the Company shall be responsible for all of the fees
of the American Arbitration Association and the arbitrators and any expenses
relating to the conduct of the arbitration (including the Company's and
Executive's reasonable attorneys' fees and expenses). Otherwise, each party
shall be responsible for its own expenses relating to the conduct of the
arbitration (including reasonable attorneys' fees and expenses) and shall
share the fees of the American Arbitration Association.
10. Notices. All notices and other communications required or permitted
under this Agreement or necessary or convenient in connection herewith shall
be in writing and shall be deemed to have been given when hand delivered or
mailed by registered or certified mail, as follows (provided that notice of
change of address shall be deemed given only when received):
If to the Company, to:
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT 06141-0270
Attention: Vice President, Secretary and General Counsel
With a required copy to:
Morgan, Lewis & Bockius
2000 One Logan Square
Philadelphia, PA 19103-6993
Attention: Robert J. Lichtenstein, Esquire
If to Executive, to:
With a required copy to:
Shipman & Goodwin
One American Row
Hartford, CT 06103-2819
Attention: Brian Clemow, Esquire
or to such other names or addresses as the Company or Executive, as the case
may be, shall designate by notice to each other person entitled to receive
notices in the manner specified in this Section.
11. Contents of Agreement; Amendment and Assignment.
(a) This Agreement sets forth the entire understanding between the parties
hereto with respect to the subject matter hereof and cannot be changed,
modified, extended or terminated except upon written amendment approved by
the Board and executed on its behalf by a duly authorized officer and by
Executive.
(b) All of the terms and provisions of this Agreement shall be binding upon
and inure to the benefit of and be enforceable by the respective heirs,
executors, administrators, legal representatives, successors and assigns of
the parties hereto, except that the duties and responsibilities of Executive
under this Agreement are of a personal nature and shall not be assignable or
delegatable in whole or in part by Executive. The Company shall require any
successor (whether direct or indirect, by purchase, merger, consolidation,
reorganization or otherwise) to all or substantially all of the business or
assets of the Company, by agreement in form and substance satisfactory to
Executive, expressly to assume and agree to perform this Agreement in the
same manner and to the extent the Company would be required to perform if no
such succession had taken place.
12. Severability. If any provision of this Agreement or application thereof
to anyone or under any circumstances is adjudicated to be invalid or
unenforceable in any jurisdiction, such invalidity or unenforceability shall
not affect any other provision or application of this Agreement which can be
given effect without the invalid or unenforceable provision or application
and shall not invalidate or render unenforceable such provision or
application in any other jurisdiction. If any provision is held void,
invalid or unenforceable with respect to particular circumstances, it shall
nevertheless remain in full force and effect in all other circumstances.
13. Remedies Cumulative; No Waiver. No remedy conferred upon a party by
this Agreement is intended to be exclusive of any other remedy, and each and
every such remedy shall be cumulative and shall be in addition to any other
remedy given under this Agreement or now or hereafter existing at law or in
equity. No delay or omission by a party in exercising any right, remedy or
power under this Agreement or existing at law or in equity shall be construed
as a waiver thereof, and any such right, remedy or power may be exercised by
such party from time to time and as often as may be deemed expedient or
necessary by such party in its sole discretion.
14. Beneficiaries/References. Executive shall be entitled, to the extent
permitted under any applicable law, to select and change a beneficiary or
beneficiaries to receive any compensation or benefit payable under this
Agreement following Executive's death by giving the Company written notice
thereof. In the event of Executive's death or a judicial determination of
Executive's incompetence, reference in this Agreement to Executive shall be
deemed, where appropriate, to refer to Executive's beneficiary, estate or
other legal representative.
15. Miscellaneous. All section headings used in this Agreement are for
convenience only. This Agreement may be executed in counterparts, each of
which is an original. It shall not be necessary in making proof of this
Agreement or any counterpart hereof to produce or account for any of the
other counterparts.
16. Withholding. The Company may withhold from any payments under this
Agreement all federal, state and local taxes as the Company is required to
withhold pursuant to any law or governmental rule or regulation. Executive
shall bear all expense of, and be solely responsible for, all federal, state
and local taxes due with respect to any payment received under this
Agreement.
17. Governing Law. This Agreement shall be governed by and interpreted
under the laws of the State of Connecticut without giving effect to any
conflict of laws provisions.
18. Adoption by Affiliates; Obligations. The obligations under this
Agreement shall, in the first instance, be paid and satisfied by the Company;
provided, however, that the Company will use its best efforts to cause NU and
each entity in which NU (or its successors or assigns) now or hereafter
holds, directly or indirectly, more than a 50 percent voting interest and
that has at least fifty (50) employees on its direct payroll (an "Employer")
to approve and adopt this Agreement and, by such approval and adoption, to be
bound by the terms hereof as though a signatory hereto. If the Company shall
be dissolved or for any other reason shall fail to pay and satisfy the
obligations, each individual Employer shall thereafter shall be jointly and
severally liable to pay and satisfy the obligations to Executive.
19. Establishment of Trust. The Company may establish an irrevocable trust
fund pursuant to a trust agreement to hold assets to satisfy any of its
obligations under this Agreement. Funding of such trust fund shall be
subject to the Board's discretion, as set forth in the agreement pursuant to
which the fund will be established.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Agreement as of the date first above written.
NORTHEAST UTILITIES
SERVICE COMPANY
/s/Cheryl Grise /s/Bernard Fox
Executive 2/25/97
2/23/97
Exhibit 10.44.1
AMENDMENT TO EMPLOYMENT AGREEMENT
This Amendment to Employment Agreement, dated as of January 13, 1998, amends
the Employment Agreement, dated as of February 25, 1997, between Northeast
Utilities Service Company and Cheryl W. Grise.
1. Section 3.1(a) is amended to read in its entirety as follows:
During his employment by the Company and for a period of two years after
Executive's termination of employment for any reason, within the Company's
"service area," as defined below, Executive will not, except with the prior
written consent of the Board, directly or indirectly, own, manage, operate,
join, control, finance or participate in the ownership, management,
operation, control or financing of, or be connected as an officer, director,
employee, partner, principal, agent, representative, consultant or otherwise
with, or use or permit his name to be used in connection with, any business
or enterprise which is engaged in any business that is competitive with any
business or enterprise in which the Company is engaged. For the purposes of
this Section, "service area" shall mean the geographic area within the states
of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and
Vermont, or any other state in which the Company, in the aggregate, generates
25% or more of its revenues in the fiscal year of NU in which Executive's
termination of employment occurs. Executive acknowledges that the listed
service area is the area in which the Company presently does business.
2. Section 6.1(c) is amended to read in its entirety as follows:
"Change of Control" shall mean the happening of any of the following:
(i) When any "person," as such term is used in Sections 13(d) and 14(d)
of the Securities Exchange Act of 1934 (the "Exchange Act"), other than the
Company, its Affiliates, or any Company or NU employee benefit plan
(including any trustee of such plan acting as trustee), is or becomes the
"beneficial owner" (as defined in Rule 13d-3 under the Exchange Act),
directly or indirectly, of securities of NU representing more than 20% of the
combined voting power of either (i) the then outstanding common shares of NU
(the "Outstanding Common Shares") or (ii) the Voting Securities; or
(ii) Individuals who, as of the beginning of any twenty-four month
period, constitute the Trustees (the "Incumbent Trustees") cease for any
reason to constitute at least a majority of the Trustees or cease to be able
to exercise the powers of the majority of the Trustees, provided that any
individual becoming a trustee subsequent to the beginning of such period
whose election or nomination for election by the Company's shareholders was
approved by a vote of at least a majority of the trustees then comprising the
Incumbent Trustees shall be considered as though such individual were a
member of the Incumbent Trustees, but excluding, for this purpose, any such
individual whose initial assumption of office is in connection with an actual
or threatened election contest relating to the election of the Trustees of NU
(as such terms are used in Rule 14a-11 of Regulation 14A promulgated under
the Exchange Act); or
(iii) Consummation by NU of a reorganization, merger or
consolidation (a "Business Combination"), in each case, with respect to which
all or substantially all of the individuals and entities who were the
respective beneficial owners of the Outstanding Common Shares and Voting
Securities immediately prior to such Business Combination do not, following
consummation of all transactions intended to constitute part of such Business
Combination, beneficially own, directly or indirectly, more than 75% of,
respectively, the then outstanding shares of common stock and the combined
voting power of the then outstanding voting securities entitled to vote
generally in the election of directors, as the case may be, of the
corporation, business trust or other entity resulting from or being the
surviving entity in such Business Combination in substantially the same
proportion as their ownership immediately prior to such Business Combination
of the Outstanding Common Shares and Voting Securities, as the case may be;
or
(iv) Consummation of a complete liquidation or dissolution of NU or sale
or other disposition of all or substantially all of the assets of NU other
than to a corporation, business trust or other entity with respect to which,
following consummation of all transactions intended to constitute part of
such sale or disposition, more than 75% of, respectively, the then
outstanding shares of common stock and the combined voting power of the then
outstanding voting securities entitled to vote generally in the election of
directors, as the case may be, is then owned beneficially, directly or
indirectly, by all or substantially all of the individuals and entities who
were the beneficial owners, respectively, of the Outstanding Common Shares
and Voting Securities immediately prior to such sale or disposition in
substantially the same proportion as their ownership of the Outstanding
Common Shares and Voting Securities, as the case may be, immediately prior to
such sale or disposition.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Agreement as of the day and year first above written.
NORTHEAST UTILITIES
SERVICE COMPANY
/s/Cheryl Grise /s/Robert Wax
Executive Senior Vice President, Secretary
6/23/98 and General Counsel
7/7/98
Exhibit 10.44.2
AMENDMENT TO EMPLOYMENT AGREEMENT
This Amendment to Employment Agreement, dated as of February 23, 1999, amends
Section 6.1(f) of the Employment Agreement, dated as of February 25, 1997,
between Northeast Utilities Service Company and Cheryl W. Grise, to read as
follows:
(f) "Termination upon a Change of Control" shall mean a Termination of
Employment during the period beginning on the earlier of (a) approval by the
shareholders of NU of a Change of Control or (b) consummation of a Change of
Control and, in either case, ending on the second anniversary of the
consummation of the transaction that constitutes the Change of Control (or if
such period started on shareholder approval and after such shareholder
approval the Board abandons the transaction, on the date the Board abandoned
the transaction) either:
(i) initiated by the Company for any reason other than Executive's (w)
disability, as described in Section 5.1 hereof, (x) death, (y) retirement on
or after attaining age 65, or (z) "cause," as defined in Section 5.3 hereof,
or
(ii) initiated by Executive (A) upon any failure of the Company materially to
comply with and satisfy any of the terms of this Agreement, including any
significant reduction by the Company of the authority, duties or
responsibilities of Executive, any reduction of Executive's compensation or
benefits due hereunder, or the assignment to Executive of duties which are
materially inconsistent with the duties of Executive's position as defined in
Section 1.2 above, or (B) if Executive is transferred, without Executive's
written consent, to a location that is more than 50 miles from Executive's
principal place of business immediately preceding such approval or
consummation; provided, that the imposition on Executive following a Change
of Control of a limitation of Executive's scope of authority such that
Executive's responsibilities relate primarily to a company or companies whose
common equity is not publicly held shall be considered a "significant
reduction by the Company of the authority, duties or responsibilities of
Executive" for purposes hereof.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have
executed this Amendment as of the day and year first above written.
/s/Cheryl Grise /s/Michael G. Morris
3/4/99 Chairman, President and CEO
3/4/99
Exhibit 10.49.1
As of September 29, 1998
The CL&P Receivables Corporation
107 Selden Street
Berlin, Connecticut 06037
Ladies and Gentlemen:
Reference is made to the Receivables Purchase and Sale Agreement (the
"Agreement"), dated as of September 30, 1997, among CL&P Receivables
Corporation, The Connecticut Light and Power Company, Corporate Asset Funding
Company, Inc., Citibank, N.A., and Citicorp North America, Inc., as Agent.
Unless otherwise defined herein, terms used herein are used with the meanings
specified in the Agreement. This letter modifies certain terms of the
Agreement and the Fee Agreement executed and delivered in connection
therewith.
1. Clause (a) of the definition of "Commitment Termination Date" in Article
I of the Agreement is hereby amended by substituting "September 28, 1999" for
"September 29, 1998"; provided, that it shall be a condition precedent to the
effectiveness of this amendment that the Originator shall have filed an
application for the approval of the Connecticut Department of Public Utility
Control (the "PUC") described in paragraph 2 below.
2. Item 4 of the second paragraph (relating to the Liquidity Fee) and the
third paragraph of the Fee Agreement, dated as of September 30, 1997, are
hereby amended in their entirety to read as follows:
Second Paragraph - Item 4
The Seller shall pay to the Agent for the benefit of the Banks providing
Bank Commitments a Liquidity Fee on the aggregate Purchase Limit in effect
from time to time at the per annum rate of 0.375 percent.
Third Paragraph
All fees are payable in arrears on each Settlement Date during the term
of the Receivables Purchase Agreement until the later of the Facility
Termination Date or the date on which the Capital and Yield of all Receivable
Interests have been paid in full. The Seller shall pay such fees to the
Agent by deposit of the appropriate amounts in a special account (account
number 4063-6695) maintained with Citibank at its address specified on the
signature page to the Receivables Purchase Agreement.
Provided that such amendment shall only be effective at such time as the
approval of the PUC is obtained, at which point such amendment shall be
effective retroactive to September 29, 1998, with a payment to be made for
the difference between 0.375 percent and the period prior to approval. The
Seller agrees that it, or the Originator on its behalf, will uses its best
efforts to obtain the approval of the PUC, but that, in any event, failure to
obtain such approval by November 30, 1998 shall constitute an Event of
Termination.
Except as modified herein, the Agreement and all documents executed and
delivered thereunder shall continue in full force and effect. This letter
shall be governed by the laws of the State of New York.
Very truly yours,
CITICORP NORTH AMERICA, INC.,
as Agent
By:
Name: /s/Robert P. DiLeo
Title: Vice President
Agreed and accepted as of the date first above written:
CL&P RECEIVABLES CORPORATION
By:
Name: /s/Randy Shoop
Title: Assistant Treasurer
THE CONNECTICUT LIGHT AND POWER COMPANY
By:
Name: /s/Randy Shoop
Title: Assistant Treasurer
CORPORATE ASSET FUNDING, INC.
By: Citicorp North American, Inc.
as Attorney-in-Fact
By:
Name: /s/Robert P. DiLeo
Title: Vice President
CITIBANK, N.A.
By:
Name: /s/Robert P. DiLeo
Title: Attorney-in-Fact
FINANCIAL AND STATISTICAL
TABLE OF CONTENTS
12 Management's Discussion and Analysis
20 Company Report
20 Report of Independent Public Accountants
21 Consolidated Financial Statements
29 Notes to Consolidated Financial Statements
and related schedules
11
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MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
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OVERVIEW
Northeast Utilities' (NU) financial outlook improved in 1998 despite retail
rate decreases for each of the company's regulated subsidiaries. The improved
outlook is a result of the successful restart of the Millstone 3 nuclear power
plant, significant progress toward the restart of Millstone 2 and significant
reductions in operating expenses.
NU lost $1.12 a share in 1998, compared with a loss of $1.01 a share in 1997
and a profit of $0.30 a share in 1996. The loss was greater in 1998 as a result
of significant write-offs of The Connecticut Light and Power Company's (CL&P)
investment in the retired Millstone 1 nuclear power plant and the accelerated
amortization of regulatory assets as ordered by Connecticut state regulators in
CL&P's February 1999 retail rate decision.
Operation and maintenance (O&M) costs at Millstone Station declined to $392
million in 1998 from $551 million in 1997. That decline was driven primarily by
the decision to retire Millstone 1 and the return to service of Millstone 3.
Aside from Millstone, nonfuel O&M costs totaled $984 million in 1998,
compared with $1,055 million in 1997. That reduction continued a two-year trend
of declining costs at NU. In 1996, nonfuel O&M costs, not including Millstone
costs, totaled $1,170 million.
Partially offsetting the benefits from lower O&M was a 2 percent drop in
total revenues, which fell to $3.77 billion in 1998 from $3.83 billion in 1997.
The fall in revenues occurred, despite a 1.9 percent increase in retail
kilowatt-hour sales for the year, as a result of a series of retail rate
decreases implemented by regulators in the three states served by the NU system.
CL&P's annual revenues were reduced by a total of $68 million in 1998 as a
result of the removal of the Millstone units from rate base. A 10 percent
reduction in Western Massachusetts Electric Company (WMECO) rates occurred in
two steps in 1998, and a 6.87 percent reduction in Public Service Company of New
Hampshire (PSNH) base rates went into effect December 1, 1997.
Also offsetting the lower O&M were significant increases in certain noncash
expenses. Primarily as a result of Connecticut regulatory decisions,
amortization of regulatory assets totaled $203 million, up from $124 million in
1997.
NU's ability to improve its financial performance in 1999 will depend
primarily on its success in bringing Millstone 2 back on line and further
reducing its operating costs to help offset continued downward pressure on
retail revenues. CL&P will continue to be negatively affected by the $232
million reduction in revenue requirements ordered by Connecticut state
regulators in February 1999. WMECO's financial performance will be affected by
the carryover of 1998 rate reductions, plus another 5 percent rate reduction,
adjusted for inflation, that is scheduled to take effect September 1, 1999. A
final decision in PSNH's rate case and the resolution of New Hampshire
restructuring could have substantial impacts on both NU and PSNH if completed in
1999.
NU's financial performance also will be affected by the performance of
Select Energy, Inc. (Select), NU's unregulated marketing subsidiary. In December
1998, Select began serving two contracts covering a 13-month period with Boston
Edison that will provide approximately $300 million in revenues through December
31, 1999. Select has a number of other contracts in effect in 1999 with other
retail and wholesale customers. Select expects total revenues to exceed $600
million in 1999.
NU also expects that 1999 will be a pivotal year in implementing the
company's strategy of becoming one of the leading energy providers in the
Northeast United States. During the first quarter of 1999, NU established three
new subsidiaries: NU Enterprises, Inc., Northeast Generation Company and
Northeast Generation Services Company. These entities will engage in a variety
of energy-related activities, including the acquisition and management of
non-nuclear generating plants. The scope and success of NU's strategy, however,
will depend on many factors, including the outcome and timing of restructuring
decisions or settlements, its ability to successfully bid in auctions and to
finance the activities of its unregulated businesses and other factors affecting
the energy market that cannot be estimated at this time.
CL&P and WMECO are in the process of auctioning approximately 4,000
megawatts (MW) of fossil and hydroelectric generating capacity. Management also
hopes in 1999 to begin the process of securitizing stranded costs, a means of
monetizing the NU system companies' regulatory assets and certain other stranded
costs. The companies intend to use most of the proceeds from asset sales and
securitization to repay outstanding debt and preferred securities.
Management expects a relatively modest portion of those proceeds to be used
to reduce common equity investment in the subsidiaries through payment of
special dividends to the parent company. Proceeds received by the parent company
could be used to repurchase common shares or to invest further in regulated
energy delivery businesses, unregulated generation or marketing ventures. In
1998, the Board of Trustees approved the repurchase of up to 10 million shares
through July 1, 2000.
12
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RESTRUCTURING
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Although the NU system companies continue to operate under cost-of-service based
regulation, future rates and the recovery of stranded costs are issues under
various restructuring plans in each of the NU system companies' service
territories. Stranded costs are expenditures or commitments that have been made
to meet public service obligations with the expectation that they would be
recovered from customers. However, under certain circumstances these costs might
not be recoverable from customers in a fully competitive electric utility
industry (i.e., the costs may result in above-market energy prices).
The NU system has exposure to stranded costs for its investments in
high-cost nuclear generating plants, state-mandated purchased-power obligations
and significant regulatory assets. As of December 31, 1998, the system
companies' net investment in nuclear generating plants, excluding its investment
in certain regional nuclear companies, was approximately $2.9 billion ($1.9
billion for CL&P, $83 million for PSNH, $365 million for WMECO and $591 million
for North Atlantic Energy Corporation [NAEC]) and its regulatory assets were
approximately $2.3 billion ($1.4 billion for CL&P, $610 million for PSNH and
$322 million for WMECO).
The NU system's financial strength and resulting ability to compete in a
restructured environment will be negatively affected if the NU system companies
are unable to recover their past investments and commitments.
CONNECTICUT
In April 1998, Connecticut enacted comprehensive electric utility restructuring
legislation. The act provides for rates to be capped at December 31, 1996,
levels until December 31, 1999. Retail choice will be phased in over six months
beginning January 1, 2000, and will extend to all retail customers by July 2000.
Customers not choosing an alternate supplier can continue to receive service
until January 2004 at a rate that is at least 10 percent less than 1996 rates.
The law allows for recovery of all prudently incurred stranded costs and
mandates the functional separation of competitive and regulated businesses. To
qualify for stranded cost recovery, CL&P must auction off all fossil and
hydroelectric generating facilities prior to January 2000 and its nuclear
generating assets prior to January 2004. CL&P also received regulatory approval
to auction any of its purchased-power contracts which cannot be renegotiated by
March 1999.
The Connecticut legislation allows the use of securitization after January
1, 2000, to further reduce the costs of the transition to a competitive
marketplace. The use of securitization is limited, however, to non-nuclear
generation-related regulatory assets and costs associated with the renegotiation
of purchased-power contracts. CL&P may not securitize nuclear stranded costs.
The Connecticut Department of Public Utility Control (DPUC) will initiate an
investigation into CL&P's stranded costs in the spring of 1999 with a final
decision expected before the end of the year.
As a result of the corporate unbundling and divestiture proposals, CL&P will
redefine itself as a distribution company under the restructuring legislation,
and will provide generation services only to the extent necessary to provide
standard offer, backup and default services as required by customers who have
not chosen an alternate energy supplier.
NEW HAMPSHIRE
Restructuring efforts in New Hampshire have resulted in numerous proceedings
within the federal and state court systems. The New Hampshire Public Utilities
Commission's (NHPUC) 1997 restructuring orders have been prevented from being
implemented as a result of various court actions pending the outcome of a full
trial in the U.S. District Court. The 1997 orders would have forced PSNH and
NAEC to write off substantially all of their regulatory assets. A trial is
expected to begin in mid to late 1999.
The litigation has caused New Hampshire to fall behind several other
Northeast states in implementing industry restructuring. PSNH believes that a
negotiated resolution of outstanding restructuring and rate issues would be in
the best interests of the state, PSNH and customers.
MASSACHUSETTS
In November 1997, Massachusetts enacted comprehensive electric utility industry
restructuring legislation. As required by that legislation, WMECO instituted a
10 percent rate reduction in 1998 and continues to work with the Massachusetts
Department of Telecommunications and Energy (DTE) on implementing WMECO's
restructuring plan. In September 1999, WMECO must institute another
5 percent rate reduction, adjusted for inflation.
In January 1999, WMECO announced the sale of approximately 290 MW of fossil
and hydroelectric generating capacity to Consolidated Edison Energy, Inc. for
$47 million. The sale price is approximately 3.8 times greater than the assets'
1997 book value of $12.5 million. WMECO hopes to close on that transaction in
midsummer and expects to use the majority of the proceeds to repay outstanding
debt. The sale of these assets and future asset sales will be used to reduce
WMECO's stranded costs. WMECO will auction another 270 MW of pumped storage and
conventional hydroelectric plant later in 1999. WMECO has notified the DTE that
it will seek to auction its ownership in the Millstone units.
The rate reductions caused WMECO's annual revenues to decline to $393
million in 1998 from $426 million in 1997. WMECO's ability to improve financial
performance in 1999 will be driven by containing operating costs and using the
proceeds from asset sales and securitization to reduce financing costs. WMECO
expects to seek approval to securitize up to $500 million in stranded costs.
Following the sale of its generating assets, WMECO will continue to operate
and maintain the transmission and local distribution network and deliver
electricity to its customers.
13
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RATE MATTERS
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CONNECTICUT
In February 1999, the DPUC issued a final order in CL&P's retail rate proceeding
reducing CL&P's revenue requirements by approximately $232 million retroactive
to September 28, 1998. To implement that reduction, the DPUC ordered CL&P to
reduce its retail base rates by approximately $96 million annually and to
increase its amortization of regulatory assets by $136 million annually. The
rate order allowed CL&P to earn a return on equity of 10.3 percent. The DPUC
also said it would allow CL&P to recover only $126 million of its investment in
Millstone 1 undepreciated plant and related assets. As a result of this
decision, CL&P reflected in 1998 a one-time pretax charge of $116.5 million and
began amortizing its remaining Millstone 1 investment over three years.
In a February 1998 decision, the DPUC removed Millstone 2 from CL&P's rate
base effective May 1, 1998, and Millstone 3 effective July 1, 1998. On July 18,
1998, Millstone 3 returned to rate base. Millstone 1 previously had been removed
from CL&P's rate base effective March 1, 1998, with customers receiving a
temporary credit of approximately 1.4 percent, or $30 million annually, on their
bills.
The removal of Millstone 2 reduced CL&P's noncash revenues by approximately
$3 million a month. This reduction was increased in the 1999 rate order to
nearly $6.6 million per month to reflect lower fuel costs. Actual fuel costs
are subject to true-up in the Energy Adjustment Clause.
NEW HAMPSHIRE
In May 1998, the NHPUC approved slightly more than a 1 percent net increase in
PSNH's fuel and purchased-power adjustment clause (FPPAC) rate for the period
June through November 1998. As part of this proceeding, PSNH agreed to offset in
base rates the scheduled reduction in acquisition premium amortization with the
scheduled amortization of the Seabrook deferred return.
On December 1, 1998, the NHPUC approved a Stipulation and Settlement
executed by PSNH, the NHPUC staff, and the Governor's Office of Energy and
Community Services. They recommended that PSNH's currently effective FPPAC rate
be continued for another six-month period -- December 1, 1998, through May 31,
1999. The FPPAC rate currently in effect will produce an estimated $80 million
underrecovery as of May 31, 1999. All other FPPAC costs are being recovered on a
current basis.
A PSNH rate case has been pending at the NHPUC since May 1997 but was
delayed in connection with various restructuring proceedings. In November 1997,
the NHPUC ordered a temporary rate reduction of 6.87 percent effective December
1, 1997. A final rate case decision currently is scheduled to be issued by June
1, 1999, the same date when PSNH's FPPAC rate is scheduled to be set for the
second half of 1999. The final decision will be reconciled to July 1, 1997.
PSNH's ongoing settlement negotiations with the state of New Hampshire could
resolve both the rate case and FPPAC issues discussed above.
MILLSTONE NUCLEAR UNITS
- --------------------------------------------------------------------------------
The NU system owns 100 percent of Millstone 2 and approximately 68 percent of
Millstone 3. NU's poor financial performance from 1996 through 1998 was due
primarily to the lengthy outages at Millstone. Costs peaked in 1997 when
replacement power costs and operation and maintenance costs totaled nearly $900
million. In 1998, Millstone-related costs fell significantly as Millstone 3
returned to service and Millstone 1 began to prepare for decommissioning.
After a 27-month outage, Millstone 3 received Nuclear Regulatory Commission
(NRC) permission to restart in June 1998 and reached full power in July. The
unit achieved a capacity factor of approximately 70 percent in the second half
of 1998. NU's share of the operation, maintenance and replacement power costs
associated with Millstone 3 totaled approximately $164 million in 1998, down
from $304 million in 1997. The unit remains on the NRC's watch list with a
Category 2 designation, which means that it will continue to be subject to
heightened NRC oversight. A refueling and maintenance outage is scheduled to
begin in May 1999.
Millstone 2 remains on the NRC watch list with a Category 3 designation,
meaning that NRC commissioners must formally vote to allow restart. Key steps
before restart include final verification that the unit is in conformance with
its design and licensing basis; that management processes support safe and
conservative operations; and that the employees are effective at identifying and
correcting deficiencies at the unit. Millstone 2 is on schedule for a spring
1999 restart following final NRC review and approval. Millstone 2's return is
expected to restore $6.6 million a month in noncash revenues to CL&P, reduce
fuel and purchased-power expense by approximately $8 million a month, and
significantly reduce the unit's operation and maintenance expenses, which
totaled $220 million in 1998. In a July 1998 filing with the DPUC, management
concluded that Millstone 2 had over $400 million of economic value over the 17
years remaining on its license life. In its February rate decision, the DPUC
concurred that the unit was economic for customers and ordered it to be restored
to CL&P rate base once it operates at 75 percent or more power for 100
consecutive hours.
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SEABROOK
The NU system owns 40 percent of the Seabrook nuclear unit. Seabrook's capacity
factor was 82.8 percent in 1998. The unit operated well, except for two
unplanned outages, one in late 1997 through early 1998 and the other in
mid-1998, to repair the control building's air-conditioning system. Seabrook is
scheduled to begin a refueling outage in March 1999.
LIQUIDITY
- --------------------------------------------------------------------------------
The NU system successfully refinanced more than $1 billion in expiring debt
obligations and bank commitments in 1998 despite a significant reported loss.
CL&P, PSNH and WMECO converted a total of $535 million variable-rate tax exempt
debt to fixed-rate tax exempt debt carrying interest rates of 5.85 to 6.0
percent. Niantic Bay Fuel Trust (NBFT), which finances CL&P's and WMECO's
nuclear fuel at Millstone, converted $180 million of maturing notes and bank
lines to five-year 8.59 percent notes. Also, PSNH successfully extended $190
million in credit ($75 million in bank credit lines and $115 million in letters
of credit).
The success in refinancing the NU system obligations was due primarily to
the progress shown in 1998 by returning Millstone 3 to service and improved cash
flows. Net cash flows from operations totaled approximately $689 million in
1998, up sharply from $377 million in 1997. Approximately $321 million of net
cash flow was used for investment activities, including construction
expenditures and investments in nuclear decommissioning trusts, compared with
$330 million in 1997. Another $26 million was used to pay preferred dividends,
compared with $62 million in common and preferred dividends in 1997. The
majority of the balance of cash used for financing activities, approximately
$351 million, was used to pay off long-term debt, short-term debt and preferred
stock, a significant shift from 1997 when net debt and preferred stock levels
were reduced by only $43 million.
The return to service of Millstone 3 and resulting reduction in costs
stabilized the NU system's credit ratings in mid-1998 after repeated downgrades
in 1996 and 1997. Moody's Investors Service, which had downgraded CL&P, WMECO
and NU debt in April 1998, upgraded those same ratings in July 1998 and
established a "positive" outlook. Also in July, Standard & Poor's (S&P) removed
the NU system from "CreditWatch--negative" for the first time in more than two
years. In September 1998, S&P upgraded CL&P, WMECO and PSNH first mortgage
bonds.
The rating agency actions also were due in part to the NU system's success
in 1998 in maintaining access to its various credit lines. Key covenants on a
$313.75 million revolving credit line primarily serving CL&P and WMECO were
adjusted in the fall. The CL&P rate decision resulted in the need for a waiver
of the revolver's equity test in the fourth quarter, which was negotiated with
banks in March 1999. PSNH renegotiated a one-year extension of a $75 million
revolving credit line in April 1998 and NU currently is seeking to extend a $25
million credit line that expires in March 1999.
The $313.75 million revolving credit line will expire on November 21, 1999.
As of February 23, 1999, CL&P and WMECO had $165 million and $60 million,
respectively, outstanding under that line. CL&P met a $140 million bond maturity
on February 1, 1999. Management expects those borrowings to increase in the
first half of 1999 as CL&P pays off a $74 million bond issue that matures July
1, 1999, and WMECO pays off a $40 million issue that matures March 1, 1999. In
1999, the NU system faces nearly $400 million of maturities and sinking-fund
payments, all of which it expects to meet through cash on hand, operating cash
flows and borrowings through its short-term facilities.
PSNH's $75 million revolving credit agreement expires on April 22, 1999, and
the company currently does not intend to renew it. PSNH will fund its needs
through operating cash flows or other short-term credit arrangements which may
be negotiated later in the year. PSNH has had no borrowings under that line
since October 1998. PSNH expects to renew the bank letters of credit that
support nearly $110 million of taxable variable-rate pollution control bonds.
Those letters of credit also expire April 22, 1999.
CL&P and WMECO also have arranged financing agreements through the sale of
their accounts receivables. CL&P can finance up to $200 million and WMECO up to
$40 million through these facilities. As of December 31, 1998, CL&P had
financed $105 million through its accounts receivable line and WMECO had
financed $20 million.
CL&P is party to an operating lease with General Electric Capital
Corporation related to the use of four turbine generators having an installed
cost of approximately $70 million and a stipulated loss value of $59 million.
CL&P must meet certain financial covenants that are substantially similar to the
revolving credit line. CL&P has received a waiver of these tests for the fourth
quarter of 1998 as a result of the CL&P rate decision.
The permanent shutdown of Millstone 1 in July 1998 could require CL&P and
WMECO to immediately repay the NBFT approximately $80 million of capital lease
obligations. The companies are seeking consents from the note holders to amend
the lease so that they will not be obligated to make this payment. As
consideration for the note holders' consent, the companies intend to issue an
additional $80 million of first mortgage bonds in mid-1999.
NU has provided credit assurance in the form of guarantees of a letter of
credit, performance guarantees and other assurances for the financial and
performance obligations of certain of its unregulated subsidiaries. NU currently
is limited by the Securities and Exchange Commission (SEC) to an aggregate of
$75 million of such credit assurance arrangements. It is expected that NU will
seek to increase this limitation in the future.
15
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NUCLEAR DECOMMISSIONING
- --------------------------------------------------------------------------------
The staff of the SEC has questioned certain current accounting practices of the
electric utility industry regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating units in the
financial statements. In response to these questions, the Financial Accounting
Standards Board (FASB) had agreed to review the accounting for closure and
removal costs, including decommissioning. If current electric utility industry
accounting practices for nuclear power plant decommissioning are changed, the
annual provision for decommissioning could increase relative to 1998, and the
estimated cost for decommissioning could be recorded as a liability (rather than
as accumulated depreciation), with recognition of an increase in the cost of the
related nuclear power plant. As management believes decommissioning costs will
continue to be recovered through rates, changes to the accounting practices will
not affect net income.
MILLSTONE 1
CL&P and WMECO have ownership interests of 81 percent and 19 percent,
respectively, in Millstone 1. Based on a continued unit operation study filed
with the Connecticut DPUC in July 1998, CL&P and WMECO decided to retire
Millstone 1 and begin decommissioning activities. Subsequently, Millstone 1 was
removed from the NRC's watch list.
The total estimated decommissioning costs for Millstone 1, which have been
updated to reflect the early shutdown of the unit, are approximately $692.0
million in December 1998 dollars. CL&P and WMECO use external trusts to fund the
decommissioning costs. In 1998, CL&P recorded a charge of approximately $143.2
million for the write-off of its investment in Millstone 1 as a result of the
February 1999 rate decision and an earlier settlement with the Connecticut
Municipal Electric Energy Cooperative (CMEEC). At December 31, 1998, the NU
system had unrecovered plant and related assets for Millstone 1 of $190 million
and an unrecovered decommissioning obligation of $386 million. These amounts
have been recorded as a regulatory asset, while decommissioning and closure
obligations have been recorded as a liability. CL&P has been allowed to recover
its remaining investment in Millstone 1 over three years beginning October 1998.
The rate decision also stated that CL&P would be allowed to recover its
decommissioning costs and could defer pre-decommissioning costs commencing July
1, 1999, for future recovery. Management expects the DTE to decide on the
recovery of WMECO's share of Millstone 1 investment and decommissioning
liability as part of the ongoing restructuring docket.
YANKEE COMPANIES
The NU system has a 49 percent ownership interest in the Connecticut Yankee
Atomic Power Company (CYAPC), a 38.5 percent ownership interest in Yankee Atomic
Electric Company (YAEC), a 20 percent ownership interest in Maine Yankee Atomic
Power Company (MYAPC) and a 16 percent ownership interest in Vermont Yankee
Nuclear Power Corporation (VYNPC). The nuclear plants owned by YAEC, CYAPC and
MYAPC were shut down permanently on February 26, 1992, December 4, 1996, and
August 6, 1997, respectively.
At December 31, 1998, the NU system's share of its estimated remaining
contract obligations, including decommissioning, amounted to approximately
$418.8 million: $244.3 million for CYAPC, $143.0 million for MYAPC and $31.5
million for YAEC. Under the terms of the contracts with the Yankee companies,
CL&P, PSNH and WMECO are responsible for their proportionate share of the costs
of the units including decommissioning. Management expects to recover these
costs from customers. Accordingly, NU system companies have recognized these
costs as regulatory assets, with corresponding obligations on their balance
sheets.
The NU system companies have exposure for their investment in CYAPC as a
result of an initial decision at the Federal Energy Regulatory Commission
(FERC). Additionally, in January 1999, MYAPC filed an offer of settlement
which, if accepted by the FERC, will resolve all the issues in the FERC
decommissioning rate case proceeding. NU management cannot predict the ultimate
outcome of the FERC proceedings at this time, but believes that the associated
regulatory assets are probable of recovery. For further information on Yankee
companies see "Notes to Consolidated Financial Statements," Note 7B.
The NU system's ownership share of estimated costs, in year-end 1998
dollars, of decommissioning the nuclear plant owned by VYNPC is approximately
$84.8 million.
MILLSTONE 2, 3 AND SEABROOK 1
NU's estimated cost to decommission its shares of Millstone 2, Millstone 3 and
Seabrook 1 is approximately $974 million in year-end 1998 dollars. These costs
are being recognized over the lives of the respective units with a portion
currently being recovered through rates. As of December 31, 1998, the market
value of the contributions already made to the decommissioning trusts, including
their investment returns, was approximately $350 million. See the "Notes to
Consolidated Financial Statements," Note 2, for further information on nuclear
decommissioning.
YEAR 2000 ISSUES
- --------------------------------------------------------------------------------
The NU system has established an action plan by which identified processes must
be completed by certain dates in order to ensure its operating systems,
including nuclear systems, and reporting systems are able to properly recognize
the year 2000. This action plan has three phases: the inventory phase, the
detailed assessment phase and the remediation phase. The inventory phase, which
has been completed, identified operating and reporting systems which may need
to be fixed. The detailed assessment phase, which has been completed,
determined exactly what needed to be done in order to ensure that the systems
identified
16
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during the inventory phase are able to recognize properly and process the year
2000. The final phase is the remediation phase. By the end of this phase,
mission critical systems (systems that are related to safety, keeping the lights
on, regulatory requirements, and other systems that could have a significant
financial impact) will be year 2000 ready; that is, these systems will perform
their business functions properly in the year 2000. This phase includes making
modifications, testing and validating changes and verifying that the year 2000
issues have been resolved.
Although the identification and detailed assessment phases are complete,
newly identified items, such as new software purchases, are added to the
inventory as they are identified and are subject to detailed assessment and, if
needed, remediation. NU system purchasing policies require newly purchased
software and devices to be year 2000 compliant. None of these newly identified
items are expected to materially impact completion of the remediation phase.
The NU system has identified and inventoried 2,497 computer systems
(software) and over 24,000 devices (hardware) broken down into 3,450 device
types containing date-sensitive computer chips. As of December 31, 1998, 73
percent of the software systems and 81 percent of the hardware were year 2000
ready, as follows:
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Percentage Complete Software Hardware
- --------------------------------------------------------------------------------
Generation
Fossil/Hydro 58% 86%
Millstone Nuclear 76% 85%
Seabrook Nuclear 77% 81%
Transmission/Distribution 84% 70%
Other Business Systems 56% 92%
- --------------------------------------------------------------------------------
The remaining items are in various stages of modification or testing.
Management anticipates the remediation phase for mission critical systems to be
completed by mid-1999.
In addition, the NU system has been contacting its key suppliers and
business partners to determine their ability to manage the year 2000 problem
successfully. The NU system is adjusting its inventories, working with suppliers
to provide backup inventories, and changing suppliers as needed to provide for
an adequate supply of materials needed to conduct business into the year 2000.
The NU system also has worked actively with the Independent System Operator
(ISO) New England, the operator of the New England power grid, and with the
North American Electric Reliability Council to provide for the year 2000
readiness of the New England power grid.
The NU system has utilized both internal and external resources to identify,
assess, test and reprogram or replace the computer systems for year 2000
readiness. The current projected total cost of the Year 2000 Program is $30
million. The total estimated remaining cost is $18 million, which is being
funded through operating cash flows. The majority of these costs will be
expensed as incurred in 1999. Since 1996, the NU system has incurred and
expensed approximately $12 million related to year 2000 readiness efforts. Total
expenditures related to the year 2000 are not expected to have a material effect
on the operations or financial condition of the NU system.
The costs of the project and the date on which the NU system plans to
complete the year 2000 modifications are based on management's best estimates,
which were derived utilizing numerous assumptions of future events, including
the continued availability of certain resources, third-party modification plans
and other factors. However, there can be no guarantee that these estimates will
be achieved, and actual results could differ materially from those plans. If the
NU system's remediation plans or those of third parties are not successful,
there could be a significant disruption of the NU system's operations. The most
likely worst case scenario is a limited number of localized interruptions to
electric service which can be restored within a few hours. As a precautionary
measure, NU is formulating contingency plans that will evaluate alternatives
that could be implemented if our remediation efforts are not successful. The
contingency plans are being developed by enhancing existing emergency operating
procedures to include year 2000 issues. In addition, the NU system plans to have
staff available to respond to any year 2000 situations that might arise. The
contingency plan is expected to be available by July 30, 1999.
The NU system is committed to assuring that adequate resources are available
in order to implement any changes necessary for its nuclear and other operations
to be compatible with the new millennium.
RISK-MANAGEMENT INSTRUMENTS
- --------------------------------------------------------------------------------
The following discussion about the NU system's risk-management activities
includes forward looking statements that involve risks and uncertainties. Actual
results could differ materially from those projected in the forward looking
statements.
This analysis presents the hypothetical loss in earnings related to the NU
system's fuel price and interest rate market risks at December 31, 1998. The NU
system uses swaps and collars to manage the market risk exposures associated
with changes in fuel prices and variable interest rates. The NU system uses
these instruments to reduce risk by essentially creating offsetting market
exposures. Based on the derivative instruments which currently are being
utilized by NU system companies to hedge some of their fuel price and interest
rate risks, there will be an impact on earnings upon adoption of Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities, which management cannot estimate at this time. For more
information on NU's use of risk-management instruments, see the "Notes to
Consolidated Financial Statements," Notes 1N and 8.
17
<PAGE>
FUEL-PRICE RISK-MANAGEMENT INSTRUMENTS
In the generation of electricity, the most significant segment of the variable
cost component is the cost of fuel. Typically, most of CL&P's fuel purchases are
protected by a regulatory fuel price adjustment clause. However, for a
specific, well-defined volume of fuel that is excluded from the fuel price
adjustment clause, CL&P employs fuel-price risk-management instruments to
protect itself against the risk of rising fuel prices, thereby limiting fuel
costs and protecting its profit margins. These risks are primarily created by
the sale of long-term, fixed-price electricity contracts to wholesale
customers.
At December 31, 1998, CL&P had outstanding fuel-price management instrument
agreements with a total notional value of approximately $422 million and a
negative mark-to-market position of approximately $45 million. A hypothetical 10
percent decrease in average 1998 fuel prices during 1999 may result in a $10
million decrease in the fair value of the fuel-price risk-management
instruments. Because these instruments are used to hedge the fuel price risk
created by the sale of long-term, fixed-price electricity contracts, it is
expected that the hypothetical decrease in fuel prices during 1999 would result
in a corresponding increase in the fair value of these contracts.
This analysis is based on the assumption that the amount of fuel-price
risk-management instruments and the amount of long-term, fixed-price
electricity sales contracts to wholesale customers will not fluctuate during
1999. This analysis is subject to change as these assumptions change.
INTEREST-RATE RISK-MANAGEMENT INSTRUMENTS
Several NU subsidiaries hold variable-rate long-term debt, exposing the NU
system to interest rate risk. In order to hedge some of this risk, interest-rate
risk-management instruments have been entered into on NAEC's $200 million
variable-rate note, effectively fixing the interest on this note at 7.823
percent. As of December 31, 1998, NAEC had outstanding agreements with a total
notional value of approximately $200 million and a negative mark-to-market
position of approximately $2.3 million. The remaining variable-rate debt is
unhedged.
At December 31, 1998, NU had $210 million of long-term, variable-rate debt
which is not hedged and is subject to actual market rates for 1999. A 10 percent
increase in market interest rates above the 1998 weighted average variable rate
during 1999 would result in an immaterial impact on interest expense. The
difference is no longer material, primarily as a result of converting $535
million variable-rate debt to fixed-rate debt during 1998.
See the "Notes to Consolidated Financial Statements," Note 10, for the fair
value of NU's financial instruments.
ENVIRONMENTAL MATTERS
NU's subsidiaries are potentially liable for environmental cleanup costs at a
number of sites inside and outside their service territories. To date, the
future estimated environmental remediation liability has not been material with
respect to the earnings or financial position of the NU system. At December 31,
1998, NU's subsidiaries had recorded an environmental reserve of approximately
$21.5 million. See the "Notes to Consolidated Financial Statements," Note 7D,
for further information on environmental matters.
RESULTS OF OPERATIONS
- --------------------------------------------------------------------------------
The components of significant income statement variances for the past two years
are provided in the table below. The relative magnitude of how revenues earned
in 1998 were used by NU's continuing operations in 1998 is illustrated in the
chart on page 19.
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------------
Income Statement Variances
(Millions of Dollars)
- --------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
1998 over/(under) 1997 1997 over/(under) 1996
---------------------- ----------------------
Amount Percent Amount Percent
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $(67) (2)% $ 43 1%
Fuel, purchased and net interchange power 3 -- 154 13
Other operation (127) (12) 10 1
Maintenance (103) (20) 86 21
Depreciation (22) (6) (5) (1)
Amortization of regulatory assets, net 79 64 1 1
Federal and state income taxes 4 (a) (94) (98)
Millstone 1 unrecoverable costs (143) (100) -- --
Other income, net 19 50 (69) (a)
Net loss (17) (13) (169) (a)
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) Percentage greater than 100.
18
<PAGE>
OPERATING REVENUES
Retail revenues decreased by $199 million in 1998 due to retail rate reductions
for CL&P, PSNH and WMECO and the accounting impact of Millstone 2 and Millstone
3 being removed from CL&P's rates. Wholesale revenues decreased by $32 million
primarily as a result of the terminated contract with CMEEC. Other revenues
decreased approximately $50 million due to lower billings to outside companies
for reimbursable costs and price differences among customer classes. These
decreases were partially offset by higher fuel recoveries and higher retail
sales volumes. Fuel recoveries increased by $166 million primarily due to higher
fuel revenues for PSNH as a result of a higher FPPAC rate. Retail kilowatt-hour
sales were 1.9 percent higher and contributed $48 million to nonfuel revenues in
1998 primarily as a result of economic growth in all three states.
Total operating revenues increased in 1997, primarily due to higher fuel
recoveries and higher conservation recoveries. Fuel recoveries increased $32
million, primarily due to higher fuel revenues for CL&P as a result of a lower
fuel rate in 1996. Conservation recoveries increased by $17 million, primarily
due to a 1996 reserve for overrecoveries of CL&P demand-side management costs.
Retail kilowatt-hour sales were 0.3 percent lower in 1997 as a result of mild
winter weather.
FUEL, PURCHASED AND NET INTERCHANGE POWER
The change in fuel, purchased and net interchange power expense in 1998 was not
significant.
Fuel, purchased and net interchange power expense increased in 1997,
primarily due to replacement power costs associated with the Millstone outages
and the expensing in 1997 of replacement power costs incurred in 1996.
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance expenses decreased in 1998, primarily due to
lower costs at the Millstone nuclear units ($159 million), lower costs at the
Seabrook and Yankee nuclear units ($50 million), the recognition of
environmental insurance proceeds ($27 million), and lower administrative and
general expenses ($26 million). These decreases were offset partially by higher
recognition of nuclear refueling outage costs primarily as a result of the 1996
CL&P rate settlement ($29 million).
Other operation and maintenance expenses increased in 1997, primarily due to
higher costs associated with the Millstone restart effort ($216 million), higher
costs as a result of Seabrook outages ($23 million) and higher capacity charges
from MYAPC ($16 million). These were partially offset by lower recognition of
nuclear refueling outage costs primarily as a result of the 1996 CL&P rate
settlement ($72 million), lower capacity charges from CYAPC ($35 million)
primarily as a result of a property tax refund, and lower administrative and
general expenses ($41 million) primarily due to lower pension and benefit costs,
and lower storm expenses.
DEPRECIATION
Depreciation decreased in 1998, primarily due to the retirement of Millstone 1.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased in 1998, primarily due to
accelerated amortizations in accordance with regulatory decisions for CL&P, the
amortization of NAEC's Seabrook deferred return and the beginning of the
amortization of CL&P's Millstone 1 investment. These increases were partially
offset by the lower amortization of the PSNH acquisition premium.
Amortization of regulatory assets, net increased in 1997, primarily due to
the completion of the CL&P cogeneration deferrals in 1996, increased
amortization in 1997, and the beginning of the amortization of NAEC's Seabrook
deferred return in December 1997. This was partially offset by the completion of
CL&P's Seabrook amortization and WMECO's Millstone 3 amortization in 1996.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes increased in 1998, primarily due to higher book
taxable income, partially offset by an increase in income tax credits primarily
due to the Millstone 1 write-off of unrecoverable costs as a result of the
February 1999 CL&P rate decision.
Federal and state income taxes decreased in 1997, primarily due to lower
book taxable income.
MILLSTONE 1 UNRECOVERABLE COSTS
Millstone 1 unrecoverable costs represents the write-off of the Millstone 1
entitlement formerly held by CMEEC and the write-off of unrecoverable costs as
a result of the February 1999 CL&P rate decision.
OTHER INCOME, NET
Other income, net increased in 1998, primarily due to the proceeds resulting
from the shareholder derivative suit.
Other income, net decreased in 1997, primarily due to a $25 million reserve
for anticipated losses on the sale of investments by Charter Oak Energy (COE),
equity losses on COE investments, costs associated with the accounts receivable
facility, nonutility marketing and advertising costs and lower miscellaneous
income.
1998 USE OF REVENUE AND RETAINED EARNINGS
- --------------------------------------------------------------------------------
[GRAPHIC OMITTED]
TAXES 7%
DEPRECIATION, AMORITIZATION AND OTHER EXPENSES 17%
WAGES AND BENEFITS 12%
INTEREST CHARGES AND PREFERRED DIVIDENDS 8%
NONFUEL OPERATION AND MAINTENANCE EXPENSES 23%
ENERGY COSTS 33%
19
<PAGE>
COMPANY REPORT
The consolidated financial statements of Northeast Utilities and subsidiaries
and other sections of this Annual Report were prepared by the company. These
financial statements, which were audited by Arthur Andersen LLP, were prepared
in accordance with generally accepted accounting principles using estimates and
judgment, where required, and giving consideration to materiality.
The company has endeavored to establish a control environment that
encourages the maintenance of high standards of conduct in all of its business
activities. The company maintains a system of internal controls over financial
reporting which is designed to provide reasonable assurance to the company's
management and Board of Trustees regarding the preparation of reliable,
published financial statements. The system is supported by an organization of
trained management personnel, policies and procedures, and a comprehensive
program of internal audits. Through established programs, the company regularly
communicates to its management employees their internal control responsibilities
and policies prohibiting conflict of interest.
The Audit Committee of the Board of Trustees is composed entirely of outside
trustees. This committee meets periodically with management, the internal
auditors and the independent auditors to review the activities of each and to
discuss audit matters, financial reporting and the adequacy of internal
controls.
Because of inherent limitations in any system of internal controls, errors
or irregularities may occur and not be detected. The company believes, however,
that its system of internal accounting controls and control environment provide
reasonable assurance that its assets are safeguarded from loss or unauthorized
use and that its financial records, which are the basis for the preparation of
all financial statements, are reliable.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Trustees and
Shareholders of Northeast Utilities:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Northeast Utilities (a Massachusetts trust) and
subsidiaries as of December 31, 1998 and 1997, and the related consolidated
statements of income, comprehensive income, shareholders' equity, cash flows
and income taxes for each of the three years in the period ended December 31,
1998. 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 in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Northeast Utilities and
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
/s/ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 23, 1999
20
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
(Thousands of Dollars, except share information) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES...................................................... $ 3,767,714 $ 3,834,806 $ 3,792,148
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
- --------------------------------------------------------------------------------------------------------------------------------
Operation --
Fuel, purchased and net interchange power........................... 1,296,480 1,293,518 1,139,848
Other............................................................... 977,139 1,104,479 1,094,078
Maintenance............................................................. 399,165 501,693 415,532
Depreciation............................................................ 332,807 354,329 359,507
Amortization of regulatory assets, net.................................. 203,132 123,718 122,573
Federal and state income taxes (See Consolidated........................
Statements of Income Taxes)......................................... 82,332 12,650 94,363
Taxes other than income taxes........................................... 251,932 253,637 257,577
- --------------------------------------------------------------------------------------------------------------------------------
Total operating expenses............................................ 3,542,987 3,644,024 3,483,478
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME........................................................ 224,727 190,782 308,670
- --------------------------------------------------------------------------------------------------------------------------------
OTHER (LOSS)/INCOME:
Deferred nuclear plants return -- other funds........................... 6,896 7,288 8,988
Equity in earnings of regional nuclear generating
and transmission companies.......................................... 12,420 11,306 13,155
Millstone 1 -- unrecoverable costs (Note 1M)............................ (143,239) -- --
Other, net.............................................................. (19,121) (38,473) 30,932
Minority interest in income of subsidiary............................... (9,300) (9,300) (9,300)
Income taxes............................................................ 76,393 10,702 (1,747)
- --------------------------------------------------------------------------------------------------------------------------------
Other (loss)/ income, net........................................... (75,951) (18,477) 42,028
- --------------------------------------------------------------------------------------------------------------------------------
Income before interest charges...................................... 148,776 172,305 350,698
- --------------------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt.............................................. 273,824 282,095 285,463
Other interest.......................................................... 7,808 3,561 7,649
Deferred nuclear plants return -- borrowed funds........................ (12,543) (13,675) (15,119)
- --------------------------------------------------------------------------------------------------------------------------------
Interest charges, net............................................... 269,089 271,981 277,993
- --------------------------------------------------------------------------------------------------------------------------------
(Loss)/income after interest charges................................ (120,313) (99,676) 72,705
PREFERRED DIVIDENDS OF SUBSIDIARIES..................................... 26,440 30,286 33,776
- --------------------------------------------------------------------------------------------------------------------------------
NET (LOSS)/INCOME....................................................... $ (146,753) $ (129,962) $ 38,929
================================================================================================================================
(LOSS)/EARNINGS PER COMMON SHARE -- BASIC AND DILUTED................... $ (1.12) $ (1.01) $ 0.30
================================================================================================================================
COMMON SHARES OUTSTANDING (AVERAGE)..................................... 130,549,760 129,567,708 127,960,382
================================================================================================================================
</TABLE>
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
(Thousands of Dollars) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
NET (LOSS)/INCOME....................................................... $ (146,753) $ (129,962) $ 38,929
- --------------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Foreign currency translation adjustments................................ -- (499) 433
Unrealized gains on securities.......................................... 2,019 -- --
Minimum pension liability adjustments................................... (613) -- --
Other comprehensive income, net of tax (Note 12)................... 1,406 (499) 433
- --------------------------------------------------------------------------------------------------------------------------------
COMPREHENSIVE (LOSS)/INCOME............................................. $ (145,347) $ (130,461) $ 39,362
================================================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
21
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
UTILITY PLANT, AT COST:
Electric........................................................................... $9,570,547 $ 9,869,561
Other.............................................................................. 195,325 186,130
- --------------------------------------------------------------------------------------------------------------------------------
9,765,872 10,055,691
Less: Accumulated provision for depreciation....................................... 4,224,416 4,330,599
- --------------------------------------------------------------------------------------------------------------------------------
5,541,456 5,725,092
PSNH acquisition costs................................................................. 352,855 402,285
Construction work in progress.......................................................... 143,159 141,077
Nuclear fuel, net...................................................................... 133,411 194,704
- --------------------------------------------------------------------------------------------------------------------------------
Total net utility plant............................................................ 6,170,881 6,463,158
- --------------------------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS:
Nuclear decommissioning trusts, at market.............................................. 619,143 502,749
Investments in regional nuclear generating companies, at equity........................ 85,791 86,955
Investments in transmission companies, at equity....................................... 17,692 19,635
Other, at cost......................................................................... 136,812 95,352
- --------------------------------------------------------------------------------------------------------------------------------
859,438 704,691
- --------------------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents.............................................................. 136,155 143,403
Investments in securitizable assets.................................................... 182,118 230,905
Receivables, less accumulated provision for uncollectible
accounts of $2,416 in 1998 and $2,052 in 1997...................................... 237,207 214,914
Accrued utility revenues............................................................... 42,145 36,885
Fuel, materials and supplies, at average cost.......................................... 202,661 212,721
Recoverable energy costs, net -- current portion....................................... 67,181 59,959
Prepayments and other.................................................................. 65,440 71,896
- --------------------------------------------------------------------------------------------------------------------------------
932,907 970,683
- --------------------------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Regulatory assets (Note 1H)............................................................ 2,328,949 2,173,278
Unamortized debt expense............................................................... 40,416 38,758
Other.................................................................................. 54,790 63,844
- --------------------------------------------------------------------------------------------------------------------------------
2,424,155 2,275,880
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS........................................................................... $10,387,381 $10,414,412
================================================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
22
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION: (See Consolidated Statements of Capitalization)
Common shareholders' equity (See Note (a) -- Consolidated Statements of
Shareholders' Equity):
Common shares, $5 par value -- authorized 225,000,000 shares; 137,031,264
shares issued and 130,954,740 shares outstanding in 1998 and 136,842,170
shares issued and 130,182,736 shares outstanding in 1997........................ $ 685,156 $ 684,211
Capital surplus, paid in............................................................ 940,661 932,494
Deferred contribution plan -- employee stock ownership plan (ESOP).................. (140,619) (154,141)
Retained earnings................................................................... 560,769 707,522
Accumulated other comprehensive income (Note 12).................................... 1,405 (1)
- --------------------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity................................................... 2,047,372 2,170,085
Preferred stock not subject to mandatory redemption..................................... 136,200 136,200
Preferred stock subject to mandatory redemption......................................... 167,539 245,750
Long-term debt.......................................................................... 3,282,138 3,645,659
- --------------------------------------------------------------------------------------------------------------------------------
Total capitalization................................................................ 5,633,249 6,197,694
- --------------------------------------------------------------------------------------------------------------------------------
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES.......................................... 100,000 100,000
- --------------------------------------------------------------------------------------------------------------------------------
OBLIGATIONS UNDER CAPITAL LEASES (Note 4)............................................... 88,423 30,427
- --------------------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Notes payable to banks.................................................................. 30,000 50,000
Long-term debt and preferred stock -- current portion................................... 397,153 274,810
Obligations under capital leases -- current portion..................................... 120,856 177,304
Accounts payable........................................................................ 338,612 402,870
Accrued taxes........................................................................... 50,755 46,016
Accrued interest........................................................................ 51,044 30,786
Accrued pension benefits................................................................ 33,034 77,186
Other................................................................................... 106,333 88,396
- --------------------------------------------------------------------------------------------------------------------------------
1,127,787 1,147,368
- --------------------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS:
Accumulated deferred income taxes....................................................... 1,848,694 1,984,513
Accumulated deferred investment tax credits............................................. 143,369 158,837
Decommissioning obligation -- Millstone 1 (Note 2)...................................... 692,000 --
Deferred contractual obligations (Note 2)............................................... 418,760 525,076
Other................................................................................... 335,099 270,497
- --------------------------------------------------------------------------------------------------------------------------------
3,437,922 2,938,923
- --------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES.................................................... $10,387,381 $10,414,412
================================================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
23
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
(Thousands of Dollars) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
(Loss)/income before preferred dividends of subsidiaries.................. $(120,313) $(99,676) $ 72,705
Adjustments to reconcile to net cash from operating activities:
Depreciation.......................................................... 332,807 354,329 359,507
Deferred income taxes and investment tax credits, net................. 23,502 26,435 71,832
Deferred nuclear plants return........................................ (19,439) (20,963) (24,107)
Amortization of nuclear plants return................................. 50,386 -- --
Amortization of demand-side management costs, net..................... 42,085 38,029 26,941
Amortization/(deferral) of recoverable energy costs................... 38,356 (54,102) (14,289)
Amortization of PSNH acquisition costs................................ 49,431 89,424 89,744
Amortization of regulatory asset -- income taxes...................... 68,684 19,379 22,266
Amortization of cogeneration deferral................................. 29,559 37,338 28,162
Amortization of regulatory liability -- PSNH.......................... (32,860) (32,860) (32,860)
Amortization of other regulatory assets............................... 37,932 10,437 15,261
Millstone 1 -- unrecoverable costs (Note 1M).......................... 143,239 -- --
Other sources of cash................................................. 181,591 77,248 186,173
Other uses of cash.................................................... (81,271) (86,202) (41,589)
Changes in working capital:
Receivables and accrued utility revenues, net......................... (62,553) 262,384 (31,992)
Fuel, materials and supplies.......................................... 10,060 (1,307) (10,834)
Accounts payable...................................................... (64,258) (104,269) 188,101
Accrued taxes......................................................... 4,739 38,966 (68,168)
Sale of receivables and accrued utility revenues...................... 35,000 90,000 --
Investments in securitizable assets................................... 48,787 (230,905) --
Other working capital (excludes cash)................................. (26,714) (36,464) (21,383)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flows from operating activities.................................. 688,750 377,221 815,470
- --------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES:
Issuance of common shares................................................. 2,659 6,502 10,622
Issuance of long-term debt................................................ 275 260,000 222,150
Net (decrease)/increase in short-term debt................................ (20,000) 11,250 (60,250)
Reacquisitions and retirements of long-term debt.......................... (269,555) (288,793) (248,142)
Reacquisitions and retirements of preferred stock......................... (62,211) (25,000) (36,500)
Cash dividends on preferred stock......................................... (26,440) (30,286) (33,776)
Cash dividends on common shares........................................... -- (32,134) (176,277)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flows used for financing activities.............................. (375,272) (98,461) (322,173)
- --------------------------------------------------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES:
Investment in plant:
Electric and other utility plant...................................... (217,009) (233,399) (222,829)
Nuclear fuel.......................................................... (17,026) (6,852) (14,529)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flows used for investments in plant.............................. (234,035) (240,251) (237,358)
Investment in nuclear decommissioning trusts.............................. (75,551) (61,046) (65,716)
Other investment activities, net.......................................... (11,140) (28,257) (25,064)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flows used for investments....................................... (320,726) (329,554) (328,138)
- --------------------------------------------------------------------------------------------------------------------------------
NET (DECREASE)/INCREASE IN CASH FOR THE PERIOD............................ (7,248) (50,794) 165,159
Cash and cash equivalents -- beginning of period.......................... 143,403 194,197 29,038
- --------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS -- END OF PERIOD................................ $136,155 $143,403 $ 194,197
================================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized...................................... $238,990 $291,335 $ 268,129
================================================================================================================================
Income taxes.............................................................. $ 19,454 $(26,387) $ 64,189
================================================================================================================================
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases....................... $ 5,064 $ 3,475 $ 3,524
================================================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
24
<PAGE>
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
Accumulated
Other
Deferred Comprehensive
Common Capital Surplus Contribution Retained Income
(Thousands of Dollars) Shares (a) Paid In Plan -- ESOP Earnings (b) (Note 12) Total
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Balance as of January 1, 1996............. $678,056 $936,197 $(198,152) $1,007,340 $ 65 $2,423,506
- --------------------------------------------------------------------------------------------------------------------------------
Net income for 1996................... 38,929 38,929
Cash dividends on common shares --
$1.38 per share................... (176,277) (176,277)
Loss on retirement of preferred stock. (374) (374)
Issuance of 440,772 common shares,
$5 par value...................... 2,204 8,418 10,622
Allocation of benefits -- ESOP........ (8,103) 22,061 13,958
Capital stock expenses, net........... 3,077 3,077
Other comprehensive income............ 433 433
- --------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1996........... 680,260 939,589 (176,091) 869,618 498 2,313,874
- --------------------------------------------------------------------------------------------------------------------------------
Net loss for 1997 .................... (129,962) (129,962)
Cash dividends on common shares --
$0.25 per share................... (32,134) (32,134)
Issuance of 790,232 common shares,
$5 par value...................... 3,951 2,551 6,502
Allocation of benefits -- ESOP........ (12,238) 21,950 9,712
Capital stock expenses, net........... 2,592 2,592
Other comprehensive income............ (499) (499)
- --------------------------------------------------------------------------------------------------------------------------------
BALANCE AS OF DECEMBER 31, 1997........... 684,211 932,494 (154,141) 707,522 (1) 2,170,085
- --------------------------------------------------------------------------------------------------------------------------------
Net loss for 1998 .................... (146,753) (146,753)
Issuance of 189,094 common shares,
$5 par value...................... 945 1,714 2,659
Allocation of benefits -- ESOP........ (4,769) 13,522 8,753
Unearned stock compensation........... (537) (537)
Capital stock expenses, net........... 3,560 3,560
Gain on equity investment............. 8,140 8,140
Gain on repurchase of preferred stock. 59 59
Other comprehensive income............ 1,406 1,406
- --------------------------------------------------------------------------------------------------------------------------------
BALANCE AS OF DECEMBER 31, 1998........... $685,156 $940,661 $(140,619) $ 560,769 $1,405 $2,047,372
================================================================================================================================
</TABLE>
(a) NU issued 8,430,910 warrants as part of its acquisition of PSNH. These
warrants, which expired on June 5, 1997, entitled the holder to purchase one
share of NU common stock at an exercise price of $24 per share. As of June
5, 1997, 464,678 shares had been purchased through the exercise of warrants.
(b) Certain consolidated subsidiaries have dividend restrictions imposed by
their long-term debt agreements. These restrictions also limit the amount of
retained earnings available for NU common dividends. At December 31, 1998,
these restrictions totaled approximately $832.2 million.
The accompanying notes are an integral part of these financial statements.
25
<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
COMMON SHAREHOLDERS' EQUITY (See Consolidated Balance Sheets) ............................. $2,047,372 $2,170,085
- --------------------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$25 par value - authorized 36,600,000 shares at December 31, 1998 and 1997;
3,780,000 shares outstanding in 1998 and 4,840,000 shares outstanding in
1997
$50 par value - authorized 9,000,000 shares at December 31, 1998 and 1997;
4,709,774 shares outstanding in 1998 and 5,424,000 shares outstanding in
1997
$100 par value - authorized 1,000,000 shares at December 31, 1998 and 1997;
200,000 shares outstanding in 1998 and 1997
- --------------------------------------------------------------------------------------------------------------------------------
Dividend Rates Current Redemption Prices (a) Current Shares Outstanding
- --------------------------------------------------------------------------------------------------------------------------------
NOT SUBJECT TO MANDATORY REDEMPTION:
$50 par value -- $1.90 to $3.28 $50.50 to $54.00 2,324,000..... 116,200 116,200
$100 par value -- $7.72 $103.51 200,000..... 20,000 20,000
- --------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock Not Subject to Mandatory Redemption.................................. 136,200 136,200
- --------------------------------------------------------------------------------------------------------------------------------
SUBJECT TO MANDATORY REDEMPTION: (b)
$25 par value -- $1.90 to $2.65 $25.00 to $25.51 3,780,000..... 94,500 121,000
$50 par value -- $2.65 to $3.615 $50.67 to $52.17 2,385,774..... 119,289 155,000
- --------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock Subject to Mandatory Redemption...................................... 213,789 276,000
Less: Preferred Stock to be redeemed within one year...................................... 46,250 30,250
- --------------------------------------------------------------------------------------------------------------------------------
Preferred Stock Subject to Mandatory Redemption, net....................................... 167,539 245,750
- --------------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT (c)
First Mortgage Bonds --
Maturity Interest Rates
- --------------------------------------------------------------------------------------------------------------------------------
1998 6.50% to 9.17%............................................................ -- 199,800
1999 5.50% to 7.25%............................................................ 254,000 279,000
2000 5.75% to 6.875%........................................................... 260,000 260,000
2001 7.375% to 7.875%.......................................................... 220,000 220,000
2002 7.75% to 9.05%............................................................ 560,000 580,000
2004 6.125%.................................................................... 140,000 140,000
2019-2023 7.375% to 7.50%........................................................... 120,000 120,000
2024-2025 7.375% to 8.50%........................................................... 430,000 430,000
- --------------------------------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds............................................................. 1,984,000 2,228,800
- --------------------------------------------------------------------------------------------------------------------------------
Other Long-Term Debt -- (d)
Pollution Control Notes and Other Notes --
2000 Adjustable Rate (e) and 7.67%............................................. 212,022 218,033
2005-2006 8.38% to 8.58%............................................................ 177,000 194,000
2013-2018 Adjustable Rate and 5.90% (d)............................................. 33,400 33,400
2020 Adjustable Rate........................................................... 15,300 15,300
2021-2022 5.85% to 7.65% and Adjustable Rate (d).................................... 552,485 552,485
2028 5.85% to 5.95% (d)........................................................ 369,300 369,300
2031 Adjustable Rate........................................................... 62,000 62,000
- --------------------------------------------------------------------------------------------------------------------------------
Total Pollution Control Notes and Other Notes.......................................... 1,421,507 1,444,518
Fees and interest due for spent nuclear fuel disposal costs (Note 7E)...................... 216,377 205,502
Other...................................................................................... 17,043 18,513
- --------------------------------------------------------------------------------------------------------------------------------
Total Other Long-Term Debt................................................................. 1,654,927 1,668,533
- --------------------------------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net...................................................... (5,886) (7,113)
- --------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt....................................................................... 3,633,041 3,890,220
Less: Amounts due within one year......................................................... 350,903 244,561
- --------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt, net........................................................................ 3,282,138 3,645,659
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION....................................................................... $5,633,249 $6,197,694
================================================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
26
<PAGE>
NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
(a) Each of these series is subject to certain refunding limitations for the
first five years after issuance. Redemption prices reduce in future years.
(b) Changes in Preferred Stock Subject to Mandatory Redemption:
- --------------------------------------------------------------------------------
(Thousands of Dollars)
- --------------------------------------------------------------------------------
Balance at December 31, 1995................ $304,000
Reacquisitions and Retirements............ (3,000)
- --------------------------------------------------------------------------------
Balance at December 31, 1996................ 301,000
Reacquisitions and Retirements............ (25,000)
- --------------------------------------------------------------------------------
Balance at December 31, 1997................ 276,000
Reacquisitions and Retirements............ (62,211)
- --------------------------------------------------------------------------------
Balance at December 31, 1998................ $213,789
================================================================================
The minimum sinking-fund requirements of the series subject each year to
mandatory redemption aggregate approximately $46.3 million each year in 1999,
2000 and 2001; $21.3 million in 2002 and $7.7 million in 2003. In case of
default on sinking-fund payments, no payments may be made on any junior stock by
way of dividends or otherwise (other than in shares of junior stock) so long as
the default continues. If a subsidiary is in arrears in the payment of
dividends on any outstanding shares of preferred stock, the subsidiary is
prohibited from redeeming or purchasing less than all of the outstanding
preferred stock.
(c) Long-term debt maturities and cash sinking-fund requirements, excluding fees
and interest due for spent nuclear fuel disposal costs, on debt outstanding at
December 31, 1998, for the years 1999 through 2003 are approximately $350.9
million, $557.8 million, $313.2 million, $375.4 million and $25.6 million,
respectively.
In addition, there are annual one percent sinking- and improvement-fund
requirements of approximately $1.5 million for 1999 and 2000, $900,000 for 2001
and 2002, and no requirements for 2003 for certain series of Western
Massachusetts Electric Company (WMECO) first mortgage bonds which expire in
2003. The WMECO sinking- and improvement-fund requirements may be satisfied by
the deposit of cash or bonds or by certification of property additions.
Essentially all utility plant of The Connecticut Light and Power Company (CL&P),
Public Service Company of New Hampshire (PSNH), WMECO and North Atlantic Energy
Corporation (NAEC) is subject to the liens of each company's respective first
mortgage bond indenture. NAEC's first mortgage bonds also are secured by
payments made to NAEC by PSNH under the terms of the Seabrook Power Contracts.
CL&P and WMECO have secured $369.3 million of pollution control notes with
second mortgage liens on Millstone 1, junior to the liens of their respective
first mortgage bond indentures.
CL&P and WMECO have issued $225 million and $80 million, respectively, of
first mortgage bonds as collateral to enable them to borrow under a three-year
revolving credit agreement. At December 31, 1998, CL&P and WMECO had $10 million
and $20 million, respectively, in borrowings under this agreement. PSNH's
Revolving Credit Facility is secured by $75 million of first mortgage bonds and
substantially all of PSNH's accounts receivable. At December 31, 1998, PSNH had
no borrowings under the Revolving Credit Facility. See Note 3, "Short-Term
Debt," for further information.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs)
with bond insurance secured by first mortgage bonds and a liquidity facility.
Concurrent with the issuance of PSNH's Series A and B first mortgage bonds,
PSNH entered into financing arrangements with the Business Finance Authority
(BFA) of the state of New Hampshire. Pursuant to these arrangements, the BFA
issued seven series of PCRBs and loaned the proceeds to PSNH. At December 31,
1998, $516.5 million of the PCRBs were outstanding. PSNH's obligation to repay
each series of PCRBs is secured by first mortgage bonds. Each such series of
first mortgage bonds contains similar terms and provisions as the applicable
series of PCRBs. For financial reporting purposes, these bonds would not be
considered outstanding unless PSNH failed to meet its obligations under the
PCRBs.
(d) The average effective interest rates on the variable-rate pollution control
notes ranged from 3.1 percent to 5.6 percent for 1998 and 3.4 percent to 5.6
percent for 1997.
During 1998, approximately $535 million of adjustable-rate debt was
converted to fixed-rate debt at rates ranging from 5.85 percent to 6.0 percent.
At December 31, 1998 and 1997, adjustable-rate debt totaled $410 million and
$945 million, respectively.
(e) Interest-rate swaps effectively fix the interest rate of NAEC's $200
million variable-rate bank note at 7.823 percent. For further information, see
Note 8, "Interest-Rate and Fuel-Price Risk-Management."
27
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME TAXES
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
(Thousands of Dollars) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
The components of the federal and state income tax provisions charged to
operations are:
Current income taxes:
Federal................................................................ $(13,660) $(22,760) $ 13,500
State.................................................................. (3,903) (1,727) 10,778
- --------------------------------------------------------------------------------------------------------------------------------
Total current.............................................................. (17,563) (24,487) 24,278
- --------------------------------------------------------------------------------------------------------------------------------
Deferred income taxes, net:
Federal................................................................ 51,913 46,871 90,093
State.................................................................. (12,948) (10,841) (8,667)
- --------------------------------------------------------------------------------------------------------------------------------
Total deferred............................................................. 38,965 36,030 81,426
- --------------------------------------------------------------------------------------------------------------------------------
Investment tax credits, net................................................ (15,463) (9,595) (9,594)
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE................................................... $ 5,939 $ 1,948 $ 96,110
- --------------------------------------------------------------------------------------------------------------------------------
The components of total income tax expense are classified as follows:
Income taxes charged to operating expenses ............................ $82,332 $12,650 $ 94,363
Other income taxes .................................................... (76,393) (10,702) 1,747
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE .................................................. $ 5,939 $ 1,948 $ 96,110
================================================================================================================================
Deferred income taxes are comprised of the tax effects of temporary differences
as follows:
Deferred tax asset associated with net operating losses................ $69,212 $ -- $ 96,756
Depreciation, leased nuclear fuel, settlement credits
and disposal costs................................................... 16,217 32,932 18,401
Energy adjustment clauses.............................................. (22,308) 5,916 (8,268)
Nuclear plant deferrals................................................ (2,291) 13,989 (15,549)
Bond redemptions....................................................... (2,809) (4,260) (4,685)
Amortization of New Hampshire regulatory settlement.................... 11,501 11,501 11,501
Demand-side management................................................. (13,688) (12,169) (14,954)
State net operating loss carryforward.................................. 1,150 (7,670) --
Millstone revenue out of rate base..................................... (18,080) -- --
Other ................................................................. 61 (4,209) (1,776)
- --------------------------------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES, NET................................................. $38,965 $36,030 $ 81,426
================================================================================================================================
A reconciliation between income tax expense and the expected tax expense at 35
percent of pretax income:
Expected federal income tax................................................ $(40,031) $(34,205) $ 59,085
Tax effect of differences:
Depreciation........................................................... 27,630 20,566 22,537
Deferred nuclear plants return......................................... (2,414) (2,551) (3,146)
Amortization of regulatory assets...................................... 30,740 5,498 7,910
Amortization of PSNH acquisition costs................................. 17,301 31,298 31,410
Seabrook intercompany gains and losses................................. 630 (3,898) (7,503)
Investment tax credit amortization and write-off....................... (15,463) (9,595) (9,594)
State income taxes, net of federal benefit............................. (4,759) (7,839) 1,372
Nondeductible penalties................................................ 3,589 648 846
Adjustment for prior years' taxes...................................... (15,369) (1,712) (962)
Employee stock ownership plan.......................................... (1,670) (4,648) (4,007)
Dividends received deduction........................................... (3,218) (1,563) (3,027)
Loss reserve on sale of investment..................................... 7,000 8,750 --
Other, net............................................................. 1,973 1,199 1,189
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE................................................... $ 5,939 $ 1,948 $ 96,110
================================================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
28
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. ABOUT NORTHEAST UTILITIES
Northeast Utilities (NU or the company) is the parent company of the Northeast
Utilities system (the NU system). The NU system furnishes franchised retail
electric service in Connecticut, New Hampshire and western Massachusetts through
three wholly owned subsidiaries: CL&P, PSNH and WMECO. Another wholly owned
subsidiary, NAEC, sells all of its entitlement to the capacity and output of the
Seabrook nuclear power plant (Seabrook 1 or Seabrook) to PSNH under two
life-of-unit, full cost recovery contracts. A fifth wholly owned subsidiary,
Holyoke Water Power Company (HWP), also is engaged in the production and
distribution of electric power. The NU system also furnishes firm and other
wholesale electric services to various municipalities and other utilities, and
participates in limited retail access programs, providing off-system retail
electric service. The NU system serves in excess of 30 percent of New England's
electric needs and is one of the 24 largest electric utility systems in the
country as measured by revenues.
NU is registered with the Securities and Exchange Commission (SEC) as a
holding company under the Public Utility Holding Company Act of 1935 (1935 Act).
NU and its subsidiaries are subject to the provisions of the 1935 Act.
Arrangements among the NU system companies, outside agencies and other utilities
covering interconnections, interchange of electric power and sales of utility
property are subject to regulation by the Federal Energy Regulatory Commission
(FERC) and/or the SEC. The operating subsidiaries are subject to further
regulation for rates, accounting and other matters by the FERC and/or applicable
state regulatory commissions.
Several wholly owned subsidiaries of NU provide support services for the NU
system companies and, in some cases, for other New England utilities. Northeast
Utilities Service Company (NUSCO) provides centralized accounting,
administrative, information resources, engineering, financial, legal,
operational, planning, purchasing and other services to the NU system companies.
Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system
companies and other New England utilities in operating the Millstone nuclear
generating facilities. North Atlantic Energy Service Corporation (NAESCO) has
operational responsibility for Seabrook. Three other subsidiaries construct,
acquire or lease some of the property and facilities used by the NU system
companies. In addition, CL&P and WMECO each have established a special purpose
subsidiary whose business consists of the purchase and resale of receivables.
Select Energy, Inc. (Select), HEC Inc. (HEC), Mode 1 Communications, Inc.
(Mode 1), and Charter Oak Energy, Inc. (COE) are other NU system companies which
engage in a variety of activities. During 1998, revenues from these four
subsidiaries accounted for approximately one percent of consolidated revenues.
Currently, Select serves as a vehicle for participation in other retail
pilot competition programs and open-access retail and wholesale electric markets
in the Northeast and other areas of the country as appropriate. In addition,
Select develops and markets energy-related products and services in order to
enhance its core electric service and customer relationships. Select has taken
steps to establish strategic alliances with other companies in various
energy-related fields including fuel supply and management, power quality,
energy efficiency and load management services.
HEC provides energy management services for the NU system's and other
utilities' commercial, industrial and institutional electric customers. Mode 1
is a wholly owned subsidiary of NU which develops and invests in
telecommunications and related activities.
COE has an investment in a foreign utility company as permitted under the
Energy Policy Act of 1992 (Energy Act). This investment is accounted for on the
equity basis based upon COE's level of participation. NU has put COE up for
sale.
During the first quarter of 1999, NU established three new subsidiaries: NU
Enterprises, Inc., Northeast Generation Company and Northeast Generation
Services Company. Directly or through multiple subsidiaries, these entities will
engage in a variety of energy-related activities, including the acquisition and
management of non-nuclear generating plants.
B. PRESENTATION
The consolidated financial statements of the NU system include the accounts of
all wholly owned subsidiaries. Significant intercompany transactions have been
eliminated in consolidation.
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
disclosure of contingent 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.
Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
C. NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued two new accounting
standards during 1998: Statement of Financial Accounting Standards (SFAS) 132,
"Employers' Disclosures About Pensions and Other Postretirement Benefits," and
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities."
SFAS 132 revises employers' disclosures about pension and other
postretirement benefit plans, but it does not change the measurement or
recognition of those plans. See
29
<PAGE>
Note 5A, "Pension Benefits and Postretirement Benefits Other Than Pensions," for
further information on the NU system's pension and postretirement benefits
disclosures.
SFAS 133 establishes accounting and reporting standards for derivative
instruments and hedging activities. This statement becomes effective for the NU
system companies on January 1, 2000, and will require derivative instruments
used by the NU system companies to be recognized on the balance sheets as assets
or liabilities at fair value. The NU system uses derivative instruments for
hedging purposes. The accounting for these hedging instruments will depend on
which hedging classification each derivative instrument falls under, as
defined by SFAS 133, offset by any changes in the market value of the hedged
item.
Based on the derivative instruments which currently are being utilized by NU
system companies to hedge some of their fuel price and interest rate risks,
there will be an impact on earnings upon adoption of SFAS 133 which management
cannot estimate at this time. For further information regarding derivative
instruments, see Note 1N, "Interest-Rate and Fuel-Price Risk-Management."
In November 1998, the Emerging Issues Task Force (EITF) reached a final
consensus on EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities." The Task Force determined in its
consensus that when an operation's activities are considered to be trading
activities, its energy trading and risk-management contracts should be marked to
market with the gains and losses included in earnings. The consensus on this
Issue is effective for financial statements issued for years beginning after
December 15, 1998. Management has determined that EITF 98-10 currently has no
effect on its financial statements.
During June 1997, the FASB issued SFAS 131, "Disclosures about Segments of
an Enterprise and Related Information." SFAS 131 determines the standards for
reporting and disclosing qualitative and quantitative information about a
company's operating segments. More specifically, it requires financial
information to be disclosed for segments whose operating results are received by
the chief operating officer for decisions on resource allocation. It also
requires related disclosures about products and services, geographic areas and
major customers. The NU system currently evaluates management performance using
a cost-based budget, and the information required by SFAS 131 is not available.
As a result of the changes the NU system and the industry are undergoing,
the company will implement business segment reporting in 1999. This reporting
will provide management with revenue and expense information at the business
segment level. Management has identified significant segments to include
transmission, distribution, generation-related and energy marketing.
The NU system's revenues primarily are derived from residential, commercial
and industrial customers. A breakdown of revenues by class of customers is shown
on the Consolidated Sales Statistics table.
D. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock of
four regional nuclear generating companies (Yankee companies) which are
accounted for on the equity basis due to the NU system companies' ability to
exercise significant influence over their operating and financial policies.
The NU system's equity investments and ownership interests in the Yankee
companies at December 31, 1998, are:
- --------------------------------------------------------------------------------
(Thousands of Dollars, except for percentages)
- --------------------------------------------------------------------------------
Connecticut Yankee Atomic
Power Company (CYAPC)............. $51,685 49.0%
Yankee Atomic Electric
Company (YAEC).................... 7,632 38.5
Maine Yankee Atomic
Power Company (MYAPC)............. 17,342 20.0
Vermont Yankee Nuclear
Power Corporation (VYNPC)......... 9,132 16.0
- --------------------------------------------------------------------------------
Total Equity Investment............. $85,791
================================================================================
Each Yankee company owns a single nuclear generating unit. YAEC's, CYAPC's and
MYAPC's nuclear power plants were shut down permanently on February 26, 1992,
December 4, 1996, and August 6, 1997, respectively. For further information on
the Yankee companies, see Note 2, "Nuclear Decommissioning and Plant Closure
Costs."
Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a
660 megawatt (MW) nuclear generating unit and Millstone 2, a 870 MW nuclear
generating unit. CL&P, PSNH and WMECO together have a 68.02 percent joint
ownership interest in Millstone 3, a 1,154 MW nuclear generating unit. During
the third quarter of 1998, CL&P and WMECO decided to retire Millstone 1 and
prepare for final decommissioning. For further information on the Millstone 1
closure, see Note 2, "Nuclear Decommissioning and Plant Closure Costs," and
Management's Discussion and Analysis (MD&A). For further information on
Millstone 2 and 3, see Note 2, "Nuclear Decommissioning and Plant Closure
Costs," Note 7C, "Commitments and Contingencies -- Nuclear Performance," and the
MD&A.
Seabrook 1: CL&P and NAEC together have a 40.04 percent joint ownership
interest in Seabrook 1, a 1,148 MW nuclear generating unit. NAEC sells all of
its share of the power generated by Seabrook 1 to PSNH under two long-term
contracts (the Seabrook Power Contracts).
30
<PAGE>
Plant-in-service and the accumulated provision for depreciation for the NU
system's share of the three Millstone units and Seabrook 1 are as follows:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
(Millions of Dollars) 1998 1997
- --------------------------------------------------------------------------------
Plant-in-service
Millstone 1........................ $ -- $ 478.7
Millstone 2........................ 936.8 857.1
Millstone 3........................ 2,407.4 2,404.3
Seabrook 1......................... 895.5 897.5
Accumulated provision
for depreciation
Millstone 1........................ $ -- $ 212.1
Millstone 2........................ 379.6 306.7
Millstone 3........................ 765.9 695.1
Seabrook 1......................... 170.0 150.0
================================================================================
The NU system's share of Millstone and Seabrook 1 expenses are included in
operating expenses on the accompanying Consolidated Statements of Income.
Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling
approximately $17.7 million, in two companies that transmit electricity imported
from the Hydro-Quebec system in Canada.
E. DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on estimated remaining lives of depreciable utility plant-in-service,
adjusted for salvage value and removal costs, as approved by the appropriate
regulatory agency. Except for major facilities, depreciation rates are applied
to the average plant-in-service during the period. Major facilities are
depreciated from the time they are placed in service. When plant is retired from
service, the original cost of plant, including cost of removal, less salvage, is
charged to the accumulated provision for depreciation. The costs of closure and
removal of non-nuclear facilities are accrued over the life of the plant as a
component of depreciation. The depreciation rates for the several classes of
electric plant-in-service are equivalent to a composite rate of 3.3 percent in
1998 and 3.8 percent for 1997 and 1996, respectively. See Note 2, "Nuclear
Decommissioning and Plant Closure Costs," for information on nuclear plant
decommissioning.
At December 31, 1998 and 1997, the accumulated provision for depreciation
included approximately $88.4 million and $83.2 million, respectively, accrued
for the cost of removal, net of salvage, for non-nuclear generation property.
F. REVENUES
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, commercial and industrial customers and limited retail access
programs, utility revenues are based on authorized rates applied to each
customer's use of electricity. In general, rates can be changed only through a
formal proceeding before the appropriate regulatory commission. Regulatory
commissions also have authority over the terms and conditions of nontraditional
ratemaking arrangements. At the end of each accounting period, CL&P, PSNH and
WMECO accrue an estimate for the amount of energy delivered but unbilled.
For information on rate proceedings and their potential impact on CL&P and
PSNH, see Note 7B, "Commitments and Contingencies -- Rate Matters."
G. PSNH ACQUISITION COSTS
The PSNH acquisition costs represent the aggregate value placed by the 1989 rate
agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in
excess of the net book value of PSNH's non-Seabrook assets, plus the $700
million value assigned to Seabrook by the Rate Agreement, as part of the
bankruptcy resolution on June 5, 1992 (Acquisition Date). The Rate Agreement
provides for the recovery through rates, with a return, of the PSNH acquisition
costs. The unrecovered balance was approximately $352.9 million at December 31,
1998, and is being recovered ratably over a 20-year period through May 1, 2011,
in accordance with the Rate Agreement. Through December 31, 1998, $640.0 million
has been collected.
H. REGULATORY ACCOUNTING AND ASSETS
The accounting policies of the utility operating companies and the accompanying
consolidated financial statements conform to generally accepted accounting
principles applicable to rate-regulated enterprises and reflect the effects of
the ratemaking process in accordance with SFAS 71, "Accounting for the Effects
of Certain Types of Regulation." Assuming a cost-of-service based regulatory
structure, regulators may permit incurred costs, normally treated as expenses,
to be deferred and recovered through future revenues. Through their actions,
regulators also may reduce or eliminate the value of an asset, or create a
liability. If any of the operating companies were no longer subject to the
provisions of SFAS 71, the company would be required to write off all of its
related regulatory assets and liabilities unless there is a formal transition
plan which provides for the recovery, through established rates, for the
collection of these costs through a portion of the business which would remain
regulated on a cost-of-service basis. At the time of transition, the operating
companies also would be required to determine any impairment to the carrying
costs of deregulated plant and inventory assets.
Restructuring programs are being implemented within each of the NU system
operating companies' respective jurisdictions, however, management continues to
believe the application of SFAS 71 remains appropriate at this time. Once the NU
system operating companies' respective restructuring plans have been formally
approved by the appropriate regulatory agency and management can determine the
impacts of restructuring, the NU system operating companies' generation
businesses no longer will be rate regulated on a cost-of-service basis. The
majority of the NU system operating companies' regulatory assets are related to
their respective generation business. Management expects that the transmission
and distribution business
31
<PAGE>
within each of the NU system operating companies' respective jurisdictions will
continue to be rate regulated on a cost-of-service basis and restructuring plans
will allow for the recovery of regulatory assets through this portion of the
business.
For further information on the NU system companies' respective regulatory
environments and the potential impacts of restructuring, see Note 7A,
"Commitments and Contingencies -- Restructuring" and the MD&A.
Based on a current evaluation of the various factors and conditions that are
expected to impact future cost recovery, management continues to believe it is
probable that the NU system operating companies will recover their investments
in long-lived assets, including regulatory assets. The components of the NU
system companies' regulatory assets are as follows:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------
Income taxes, net
(Note 1I)...................... $ 762,495 $ 938,564
Recoverable energy costs,
net (Note 1J).................. 279,232 324,809
Deferred costs -- nuclear
plants (Note 1K)............... 187,132 208,129
Unrecovered contractual
obligations (Note 1L).......... 407,926 515,076
Millstone 1 (Note 1M)............ 576,323 --
Other............................ 115,841 186,700
- --------------------------------------------------------------------------------
$2,328,949 $2,173,278
================================================================================
I. INCOME TAXES
The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the periods in
which they affect the determination of taxable income) is accounted for in
accordance with the ratemaking treatment of the applicable regulatory
commissions. See the Consolidated Statements of Income Taxes for the components
of income tax expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, that give rise to the
accumulated deferred tax obligation is as follows:
- --------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------
(Thousands of Dollars) 1998 1997
- --------------------------------------------------------------------------------
Accelerated depreciation and other
plant-related differences....... $1,537,903 $1,567,597
Net operating loss
carryforwards................... (33,387) (102,492)
Regulatory assets -- income
tax gross up.................... 370,029 395,619
Other............................. (25,851) 123,789
- --------------------------------------------------------------------------------
$1,848,694 $1,984,513
================================================================================
At December 31, 1998, PSNH had a federal net operating loss (NOL)
carryforward of approximately $94 million that can be used against PSNH's
federal taxable income and which if unused expires between the years 2005 and
2006. CL&P had a state of Connecticut NOL carryforward of approximately $149
million that can be used against CL&P and affiliates' combined Connecticut
taxable income and which if unused expires in the year 2002. PSNH also had
Investment Tax Credit (ITC) carryforwards of $37 million which if unused expire
between the years 1999 and 2004. The reorganization of PSNH under Chapter 11 of
the United States Bankruptcy Code limits the annual amount of PSNH ITC
carryforward that may be used. Approximately $6 million of the ITC carryforward
is subject to this limitation.
J. RECOVERABLE ENERGY COSTS
Energy Act: Under the Energy Act, CL&P, PSNH, WMECO and NAEC are assessed for
their proportionate shares of the costs of decontaminating and decommissioning
uranium enrichment plants owned by the United States Department of Energy (D&D
assessment). The Energy Act requires that regulators treat D&D assessments as a
reasonable and necessary current cost of fuel, to be fully recovered in rates
like any other fuel cost. CL&P, PSNH, WMECO and NAEC currently are recovering
these costs through rates. As of December 31, 1998, the NU system's total D&D
deferrals were approximately $57.5 million.
CL&P: CL&P has in place an energy adjustment clause under which fuel prices
above or below base-rate levels are charged or credited to customers. At
December 31, 1998, recoverable energy costs included $78.1 million of costs
previously deferred.
PSNH: The Rate Agreement includes a comprehensive fuel and purchased-power
adjustment clause (FPPAC) permitting PSNH to pass through to retail customers,
for a ten-year period that began in May 1991, the retail portion of differences
between the fuel and purchased-power costs assumed in the Rate Agreement and
PSNH's actual costs, which include the costs related to the Seabrook Power
Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are
subject to a prudence review by the New Hampshire Public Utilities Commission
(NHPUC). At December 31, 1998, PSNH had $156.3 million of noncurrent recoverable
energy costs deferred under the FPPAC.
WMECO: Prior to March 1, 1998, WMECO had in place a comprehensive fuel
adjustment clause which allowed for the collection or refund of fuel price
differences between the cost of fuel and the amounts collected. Management
expects the deferred fuel balance will be collected as part of the restructuring
proceeding.
For further information on rate matters, see Note 7B, "Commitments and
Contingencies -- Rate Matters" and the MD&A.
32
<PAGE>
K. DEFERRED COSTS -- NUCLEAR PLANTS
Under the Rate Agreement, the plant costs of Seabrook were phased into rates
over a seven-year period beginning May 15, 1991. Total costs deferred under the
phase-in plan were approximately $288 million. This plan is in compliance with
SFAS 92, "Regulated Enterprises - Accounting for Phase-In Plans." These deferred
costs are being billed to PSNH by NAEC through the Seabrook Power Contracts
beginning December 1, 1997, and will be recovered fully from PSNH's customers by
May 2001.
L. UNRECOVERED CONTRACTUAL OBLIGATIONS
Under the terms of contracts with MYAPC, CYAPC and YAEC, the shareholder-sponsor
companies, including CL&P, PSNH and WMECO, are responsible for their
proportionate share of the remaining costs of the units, including
decommissioning. As management expects that the NU system companies will be
allowed to recover these costs from their customers, the NU system companies
have recorded regulatory assets, with corresponding obligations, on their
respective balance sheets. For further information, see Note 2, "Nuclear
Decommissioning and Plant Closure Costs."
M. MILLSTONE 1
The Millstone 1 regulatory asset includes the recoverable portion of the
undepreciated plant and related balances of approximately $190.3 million, and
the regulatory asset associated with the decommissioning and closure obligation
of $386.0 million. See Note 2, "Nuclear Decommissioning and Plant Closure
Costs," for further information.
N. INTEREST-RATE AND FUEL-PRICE RISK-MANAGEMENT
The NU system utilizes market risk-management instruments to hedge well-defined
risks associated with variable interest rates and changes in fuel prices. To
qualify for hedge treatment, the underlying hedged item must expose the company
to risks associated with market fluctuations and the market risk-management
instrument used must be designated as a hedge and must reduce the NU system's
exposure to market fluctuations throughout the period.
Amounts receivable or payable under fuel-price management instruments are
recognized in operating expenses when realized. Amounts receivable or payable
under interest-rate management instruments are accrued and offset against
interest expense. For further information, see Note 8, "Interest-Rate and
Fuel-Price Risk-Management."
O. CASH AND CASH EQUIVALENTS
Cash and cash equivalents includes cash on hand and short-term cash investments
which are highly liquid in nature and have original maturities of three months
or less.
2. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
Millstone 2 and 3 and Seabrook 1: The NU system operating nuclear power plants
have service lives that are expected to end during the years 2015 through 2026.
Upon retirement, these units must be decommissioned. Current decommissioning
studies conclude that complete and immediate dismantlement at retirement
continues to be the most viable and economic method of decommissioning the
units. Decommissioning studies are reviewed and updated periodically to reflect
changes in decommissioning requirements, costs, technology and inflation.
The estimated cost of decommissioning Millstone 2, in year-end 1998 dollars,
is $397.5 million. The NU system's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook 1 in year-end 1998 dollars is $380.6
million and $195.8 million, respectively. Millstone 2 and 3 and Seabrook 1
decommissioning costs will be increased annually by their respective escalation
rates. Nuclear decommissioning costs are accrued over the expected service lives
of the units and are included in depreciation expense on the Consolidated
Statements of Income. Nuclear decommissioning costs for these units amounted to
$27.9 million in 1998, $28.6 million in 1997 and $27.6 million in 1996. Nuclear
decommissioning, as a cost of removal, is included in the accumulated provision
for depreciation on the Consolidated Balance Sheets. At December 31, 1998 and
1997, the decommissioning balance in the accumulated provision for depreciation
amounted to $229.7 million and $202.1 million, respectively.
External decommissioning trusts have been established for the costs of
decommissioning Millstone 2 and 3. Payments for the company's portions of the
cost of decommissioning Seabrook 1 are paid to an independent decommissioning
financing fund managed by the state of New Hampshire. Funding of the estimated
decommissioning costs assumes levelized collections for the Millstone units and
escalated collections for Seabrook 1 and after-tax earnings on the Millstone and
Seabrook decommissioning funds of approximately 5.5 percent and 6.5 percent,
respectively.
As of December 31, 1998, CL&P, PSNH and WMECO collected a total of $229.7
million through rates toward the future decommissioning costs of their share of
Millstone 2 and 3 and Seabrook, of which $209.9 million has been transferred to
external decommissioning trusts. Earnings on the decommissioning trusts increase
the decommissioning trust balance and the accumulated reserve for depreciation.
Unrealized gains and losses associated with the decommissioning trusts and
financing fund also impact the balance of the trusts and the accumulated
reserve for depreciation. The fair value of the amounts in the external
decommissioning trusts was $349.9 million at December 31, 1998.
Changes in requirements or technology, the timing of funding or dismantling
or adoption of a decommissioning method other than immediate dismantlement would
change decommissioning cost estimates and the amounts required to be recovered.
CL&P, PSNH and WMECO attempt to
33
<PAGE>
recover sufficient amounts through their allowed rates to cover their expected
decommissioning costs. Only the portion of currently estimated total
decommissioning costs that has been accepted by regulatory agencies is reflected
in rates of the NU system companies. Based on present estimates and assuming its
nuclear units operate to the end of their respective license periods, the NU
system expects that the decommissioning trusts and financing fund will be
substantially funded when the units are retired from service.
Millstone 1: The total estimated decommissioning costs for Millstone 1,
which have been updated to reflect the early shutdown of the unit, are
approximately $692.0 million as of December 31, 1998. The company has recorded
the decommissioning and closure obligation as a liability. Nuclear
decommissioning costs for Millstone 1 were $19.8 million in 1998 and $20.2
million in 1997 and 1996, respectively.
In February 1999, the DPUC issued a decision on CL&P's rate case filing.
The decision allowed for recovery over a three-year period, without a return, of
$126.0 million of CL&P's remaining investment in Millstone 1. As a result, CL&P
recorded an after-tax loss of approximately $80 million, related to the
write-down of its investment in Millstone 1. The decision allowed for the
recovery of CL&P's decommissioning and closure obligations. Accordingly, CL&P
recorded a regulatory asset for its portion of the decommissioning and closure
obligation. For further information on the DPUC decision, see Note 7B,
"Commitments and Contingencies - Rate Matters" and the MD&A.
During 1998, CL&P recorded a loss of approximately $27.9 million related to
the termination of an approximate 4.3 percent entitlement contract of CL&P's
share of Millstone 1, formerly held by the Connecticut Municipal Electric Energy
Cooperative.
WMECO will seek recovery of unrecovered Millstone 1 balances of
approximately $60.8 million and decommissioning related costs of approximately
$63.3 million as part of its restructuring regulatory proceedings. Based upon
the restructuring law in Massachusetts, management believes it is probable that
WMECO will be allowed the recovery of these costs and has recorded a regulatory
asset.
CL&P and WMECO use external trusts to fund the estimated decommissioning
costs of Millstone 1. As of December 31, 1998, CL&P and WMECO had collected a
total of $182.0 million through rates toward the future decommissioning costs of
their share of Millstone 1, of which $160.1 million has been transferred to
external decommissioning trusts. At December 31, 1998, the fair market value of
the balance in the external trusts was approximately $269.2 million.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012. The NU system's ownership share of
estimated costs, in year-end 1998 dollars, of decommissioning this unit is
approximately $84.8 million.
At December 31, 1998, the remaining estimated obligation, including
decommissioning, for the Yankee companies' nuclear generating facilities which
have been shut down were:
- --------------------------------------------------------------------------------
Total NU's
(Thousands of Dollars) Obligation Share
- --------------------------------------------------------------------------------
Maine Yankee..................... $715,065 $143,013
Connecticut Yankee............... $498,557 $244,293
Yankee Atomic.................... $ 81,699 $ 31,454
================================================================================
For further information on the Yankee companies, see Note 7B, "Commitments
and Contingencies -- Rate Matters."
For information on proposed changes to the accounting for decommissioning,
see the MD&A.
3. SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by NU and the
NU system operating companies is subject to periodic approval by either the SEC
under the 1935 Act or by the respective state regulators. SEC authorization
allowed CL&P, WMECO and NAEC, as of January 1, 1999, to incur total short-term
borrowings up to a maximum of $375 million, $150 million and $60 million,
respectively. In addition, the charters of CL&P and WMECO contain preferred
stock provisions restricting the amount of unsecured debt those companies may
incur. As of December 31, 1998, CL&P's and WMECO's charters permit CL&P and
WMECO to incur an additional $466 million and $96 million, respectively, of
unsecured debt. Effective April 1998, PSNH is authorized under a NHPUC order to
incur short-term borrowings up to a maximum of $75 million.
Credit Agreements: NU, CL&P and WMECO are parties to a $313.75 million
revolving credit agreement (Credit Agreement). Under the Credit Agreement
amended on September 11, 1998, CL&P and WMECO are able to borrow, subject to the
availability of first mortgage bond collateral, up to $313.75 million and $150
million, respectively. At December 31, 1998, CL&P and WMECO have issued first
mortgage bonds to enable borrowings under this facility up to a maximum of $225
million and $80 million, respectively. NU, which cannot issue first mortgage
bonds, would be able to borrow up to $50 million if NU consolidated, CL&P and
WMECO each meet certain interest coverage tests for two consecutive quarters.
This requirement for NU has not been met. In addition, CL&P and WMECO each must
meet certain minimum quarterly financial ratios to access the Credit Agreement.
CL&P currently is in the process of obtaining a waiver of the equity financial
ratio requirement for the quarter ended December 31, 1998. WMECO satisfied
these requirements for the quarter ending December 31, 1998. In connection with
obtaining the waiver for the equity test, NU's participation in the Credit
Agreement will be terminated. The overall limit for all of the NU system
companies under the entire Credit Agreement is $313.75 million. The NU system
companies
34
<PAGE>
are obligated to pay a facility fee of .50 percent per annum of each
bank's total commitment under this Credit Agreement, which will expire in
November 1999. At December 31, 1998 and 1997, there were $30 million and $50
million, respectively, in borrowings under this Credit Agreement.
In February 1998, NU entered into a separate $25 million 364-day revolving
credit facility (Credit Facility) with one bank. NU is obligated to pay a
facility fee of .625 percent per annum on the unused commitment. At December 31,
1998, there were no borrowings under the Credit Facility. NU currently is
seeking an extension for this Credit Facility.
PSNH has access to a $75 million revolving credit agreement entered into in
April 1998 with a group of 16 banks. The borrowing level under this agreement
was reduced from a previous level of $125 million. The agreement will expire in
April 1999. Under the terms of this agreement, PSNH is obligated to pay a
facility fee of .50 percent per annum on the commitment. PSNH's borrowings under
the $75 million agreement are secured, per dollar of borrowing, by $75 million
of first mortgage bonds and substantially all of PSNH's accounts receivable.
There were no borrowings under this facility at December 31, 1998 and 1997.
On March 20, 1998, in connection with the $75 million PSNH credit agreement,
the NHPUC issued an order requiring PSNH to obtain NHPUC approval before paying
any dividends on its common stock and before investing any PSNH funds in the NU
system Money Pool during the expected 364-day term of the facilities. PSNH has
not sought such authorization.
Under the credit facilities discussed above, with the exception of the $25
million NU Credit Facility, the NU system companies may borrow funds on a
short-term revolving basis under their respective agreements, using either
fixed-rate loans or standby loans. Fixed rates are set using competitive
bidding. Standby loans are based upon several alternative variable rates. Loans
advanced under the $25 million NU Credit Facility are on a standby basis only.
The weighted average annual interest rate on the NU system companies' notes
payable to banks outstanding on December 31, 1998 and 1997, was 6.53 percent and
6.95 percent, respectively.
Maturities of short-term debt obligations were for periods of three months or
less.
For further information on NU system companies' short-term debt, see the
MD&A.
4. LEASES
CL&P and WMECO finance their nuclear fuel for Millstone 2 and their
respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel
Trust (NBFT) capital lease agreement. This lease agreement has an expiration
date of June 1, 2040. On June 5, 1998, the NBFT issued $180 million Series G
intermediate term notes (ITNs) through a private placement offering. The
five-year notes mature June 5, 2003, and will bear interest at a rate of 8.59
percent per annum, payable semiannually. At December 31, 1998, the capital lease
obligation to the NBFT was approximately $178.7 million.
The permanent shutdown of Millstone 1 in July 1998 afforded the NBFT ITN
holders the right to seek repurchase of a pro rata share of their notes based
upon the stipulated loss value of Millstone 1 fuel compared to the stipulated
loss value of all fuel then under the NBFT. This amount was approximately $80
million. The shutdown also obligates CL&P and WMECO to pay such amount to the
NBFT under the NBFT lease whether or not any ITN holders request repurchase. The
NU system companies are seeking consents from the ITN holders to amend this
lease provision so that they will not be obligated to make this payment, but
instead will issue an additional $80 million of collateral first mortgage bonds
in mid-1999.
CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel
consumed in the reactors based on a units-of-production method at rates which
reflect estimated kilowatt-hours of energy provided plus financing costs
associated with the fuel in the reactors. Upon permanent discharge from the
reactors, ownership of the nuclear fuel transfers to CL&P and WMECO. The NU
system companies also have entered into lease agreements, some of which are
capital leases, for the use of data processing and office equipment, vehicles,
gas turbines, nuclear control room simulators and office space. The provisions
of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $31.0 million
in 1998, $19.0 million in 1997 and $28.2 million in 1996. Interest included in
capital lease rental payments was $18.3 million in 1998, $13.6 million in 1997
and $14.1 million in 1996. Operating lease rental payments charged to expense
were $15.7 million in 1998, $17.3 million in 1997 and $18.3 million in 1996.
Future minimum rental payments, excluding annual nuclear fuel lease payments
and executory costs such as property taxes, state use taxes, insurance and
maintenance, under long-term noncancelable leases, as of December 31, 1998, are:
- -------------------------------------------------------------------------------
(Thousands of Dollars)
- -------------------------------------------------------------------------------
Capital Operating
Year Leases Leases
- -------------------------------------------------------------------------------
1999 ........................................... $ 8,500 $ 28,400
2000 ........................................... 8,000 26,200
2001 ........................................... 5,800 21,600
2002 ........................................... 3,400 11,600
2003 ........................................... 3,500 7,000
After 2003 ..................................... 47,700 24,200
===============================================================================
Future minimum
lease payments ............................... 76,900 $119,000
Less amount
representing interest ........................ 46,300
- -------------------------------------------------------------------------------
Present value of future
minimum lease payments
for other than nuclear fuel .................. 30,600
Present value of future
nuclear fuel lease payments .................. 178,700
- -------------------------------------------------------------------------------
Present value of future
minimum lease payments ....................... $209,300
===============================================================================
35
<PAGE>
5. EMPLOYEE BENEfiTS
A. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system subsidiaries participate in a uniform noncontributory defined
benefit retirement plan covering all regular NU system employees. Benefits are
based on years of service and the employees' highest eligible compensation
during 60 consecutive months of employment. Total pension (credit)/cost, part of
which was (credited)/charged to utility plant, approximated $(44.1) million in
1998, $(22.5) million in 1997 and $9.1 million in 1996.
Currently, the NU system subsidiaries annually fund an amount at least equal
to that which will satisfy the requirements of the Employee Retirement Income
Security Act and the Internal Revenue Code. Pension costs are determined using
market-related values of pension assets.
The NU system subsidiaries also provide certain health care benefits,
primarily medical and dental, and life insurance benefits through a benefit
plan to retired employees. These benefits are available for employees retiring
from the NU system who have met specified service requirements. For current
employees and certain retirees, the total benefit is limited to two times the
1993 per-retiree health care cost. These costs are charged to expense over the
future estimated work life of the employee. The NU system subsidiaries are
funding postretirement costs through external trusts. The NU system subsidiaries
are funding, on an annual basis, amounts that have been rate-recovered and which
also are tax deductible under the Internal Revenue Code.
Pension and trust assets are invested primarily in domestic and international
equity securities and bonds.
The following table represents the plans' beginning benefit obligation
balance reconciled to the ending benefit obligation balance, beginning fair
value of plan assets balance reconciled to the ending fair value of plan assets
balance and the respective funds' funded status reconciled to the Consolidated
Balance Sheets:
The components of net cost are:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
------------------- -----------------------
(Thousands of Dollars) 1998 1997 1998 1997
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year ............................. $(1,392,833) $(1,321,146) $(285,959) $(306,082)
Service cost ........................................................ (37,420) (34,903) (6,625) (5,746)
Interest cost ....................................................... (96,785) (98,621) (20,920) (20,556)
Transfers ........................................................... 8,510 -- -- --
Actuarial (loss)/gain ............................................... (37,656) (18,956) (16,077) 20,926
Benefits paid ....................................................... 76,951 78,188 24,393 25,499
Curtailments and settlements ........................................ -- 2,605 -- --
- --------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year ................................... $(1,479,233) $(1,392,833) $(305,188) $(285,959)
- --------------------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year ...................... $ 1,919,414 $ 1,660,404 $ 129,434 $ 105,086
Actual return on plan assets ........................................ 264,717 337,198 17,353 21,132
Employer contribution ............................................... -- -- 28,831 28,715
Benefits paid ....................................................... (76,951) (78,188) (24,393) (25,499)
Transfers ........................................................... (9,160) -- -- --
- --------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year ............................ $ 2,098,020 $ 1,919,414 $ 151,225 $ 129,434
- --------------------------------------------------------------------------------------------------------------------------------
Funded status at December 31 ........................................ $ 618,787 $ 526,581 $(153,963) $(156,525)
Unrecognized transition amount ...................................... (9,019) (10,562) 211,881 227,015
Unrecognized prior service cost ..................................... 27,620 29,711 -- --
Unrecognized net gain ............................................... (670,422) (622,916) (57,918) (70,391)
- --------------------------------------------------------------------------------------------------------------------------------
(Accrued)/prepaid benefit cost ...................................... $ (33,034) $ (77,186) $ -- $ 99
================================================================================================================================
</TABLE>
36
<PAGE>
The following actuarial assumptions were used in calculating the plans' year-end
funded status:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
At December 31,
- --------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
------------------- -----------------------
1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Discount rate ..................................................... 7.00% 7.25% 7.00% 7.25%
Compensation/progression rate ..................................... 4.25 4.25 4.25 4.25
Health care cost trend rate (a) ................................... N/A N/A 5.22 5.76
================================================================================================================================
</TABLE>
(a) The annual growth in per capita cost of covered health care benefits was
assumed to decrease to 4.40 percent by 2001.
The components of net periodic benefit cost are:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
------------------------------- -------------------------------
(Thousands of Dollars) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost ................................... $ 37,420 $ 34,903 $ 35,435 $ 6,625 $ 5,746 $ 7,457
Interest cost .................................. 96,785 98,621 94,723 20,920 20,556 22,698
Expected return on
plan assets ................................ (153,152) (135,093) (117,882) (9,871) (8,065) (3,969)
Amortization of unrecognized
transition (asset)/obligation .............. (1,543) (1,543) (1,543) 15,134 15,134 15,134
Amortization of prior
service costs .............................. 2,091 2,091 2,091 -- -- --
Amortization of
actuarial gain ............................. (25,739) (18,901) (11,526) -- -- --
Other amortization, net ........................ -- -- -- (3,879) (5,060) (2,167)
Curtailment .................................... -- (2,605) 7,771 -- -- --
- --------------------------------------------------------------------------------------------------------------------------------
Net periodic benefit (credit)/cost ............. $(44,138) $ (22,527) $ 9,069 $28,929 $28,311 $39,153
================================================================================================================================
</TABLE>
For calculating pension and postretirement benefit costs, the following
assumptions were used:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
------------------------------- -------------------------------
1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Discount rate .................................. 7.25% 7.75% 7.50% 7.25% 7.75% 7.50%
Expected long-term
rate of return ............................. 9.50 9.25 8.75 N/A N/A N/A
Compensation/
progression rate ........................... 4.25 4.75 4.75 4.25 4.75 4.75
Long-term rate of return --
Health assets, net of tax .................. N/A N/A N/A 7.75 7.50 5.25
Life assets ................................ N/A N/A N/A 9.50 9.25 8.75
================================================================================================================================
</TABLE>
37
<PAGE>
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. The effect of changing the assumed health
care cost trend rate by one percentage point in each year would have the
following effects:
- -------------------------------------------------------------------
One Percentage One Percentage
(Thousands of Dollars) Point Increase Point Decrease
- -------------------------------------------------------------------
Effect on total service and
interest cost components ........... $ 1,294 $(1,325)
Effect on postretirement
benefit obligation ................. 16,214 (16,141)
===================================================================
The trust holding the health plan assets is subject to federal income taxes at a
39.6 percent tax rate.
B. 401(K) SAVINGS PLAN
NU maintains a 401(k) Savings Plan for substantially all NU system employees.
This savings plan provides for employee contributions up to specified limits.
The company matches, with cash and company stock, employee contributions up to a
maximum of 3 percent of eligible compensation. The matching contributions made
by the company were $13.2 million for 1998, $12.0 million for 1997 and $11.8
million for 1996.
C. ESOP
NU maintains an ESOP for purposes of allocating shares to employees
participating in the NU system's 401(k) Savings Plan. Under this arrangement, NU
issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds
of which were lent to the ESOP trust for purchase of approximately 10.8 million
newly issued NU common shares (ESOP shares). The ESOP trust is obligated to make
principal and interest payments on the ESOP notes at the same rate that ESOP
shares are allocated to employees. NU makes annual contributions to the ESOP
equal to the ESOP's debt service, less dividends received by the ESOP. All
dividends received by the ESOP on unallocated shares are used to pay debt
service and are not considered dividends for financial reporting purposes.
During 1998, there were no dividends on NU stock.
In 1998 and 1997, the ESOP trust issued approximately 584,000 and 948,000 of
NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to
employees. As of December 31, 1998 and 1997, the total allocated ESOP shares
were 4,724,858 and 4,140,751, respectively, and total unallocated ESOP shares
were 6,075,327 and 6,659,434, respectively. The fair market value of unallocated
ESOP shares as of December 31, 1998 and 1997, was approximately $97.2 million
and $78.7 million, respectively.
D. STOCK BASED COMPENSATION
Employee Stock Purchase Plan: Beginning in July 1998, the NU system has an
employee stock purchase plan (ESPP) for all eligible employees. Under the ESPP,
shares of NU common stock may be purchased at six-month intervals at 85 percent
of the lower of the price on the first or last day of each six-month period.
Employees may purchase shares having a value not exceeding 25 percent of their
compensation at the beginning of the purchase period. During 1998, employees
purchased 129,471 shares at a discounted price of $13.60 per share. At December
31, 1998, 1,870,529 shares remained reserved for future issuance under the ESPP.
Incentive Plans: The NU system has long-term incentive plans authorizing
various types of stock based awards, including stock options, to be made to
eligible employees and board members. The exercise price of stock options, as
set at the time of grant, is equal to the fair market value per share at the
date of grant. Under the Northeast Utilities Incentive Plan (Incentive Plan)
approved by shareholders in May 1998, the number of shares which may be utilized
for awards granted during a given calendar year may not exceed 1 percent of the
total number of shares of NU common stock outstanding as of the first day of
that calendar year.
No stock options were granted in 1996. Stock option transactions for 1997 and
1998 are as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
Price Per Share
- --------------------------------------------------------------------------------------------------------------------------------
Weighted
Options Range Average
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Outstanding December 31, 1996 ............................................. -- -- --
Granted ................................................................... 500,000 $9.625 $ 9.625
- --------------------------------------------------------------------------------------------------------------------------------
Outstanding December 31, 1997 ............................................. 500,000 $ 9.625 $ 9.625
Granted ................................................................... 741,273 $14.875 - $16.8125 $ 16.178
Forfeited ................................................................. (7,595) $16.3125 $16.3125
- --------------------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1998 ............................................. 1,233,678 $ 9.625 - $16.8125 $13.5213
- --------------------------------------------------------------------------------------------------------------------------------
EXERCISABLE DECEMBER 31, 1998 ............................................. 232,936 $14.875 - $16.8125 $16.2972
================================================================================================================================
</TABLE>
38
<PAGE>
The vesting schedule for the options granted in 1997 is 50 percent after two
years, 75 percent after three years and 100 percent after four years. The
vesting schedule for the options granted in 1998 is one-third upon grant,
two-thirds after one year and the total award after two years.
Under the Incentive Plan, the NU system awarded 49,973 shares of restricted
stock in 1998. These shares have the same vesting schedule as the options
granted under the Incentive Plan. During 1997, certain key officers were
awarded restricted stock totaling 25,700 shares and which vest pro rata over
three years from the date of grant. During 1996, the same key officers were
awarded 43,000 shares of restricted stock which vest upon meeting specific
performance goals. The NU system also has made several small grants of
restricted stock and other incentive-based stock compensation.
During 1998, 1997 and 1996, approximately $795,000, $246,000 and $411,000,
respectively, was expensed for stock based compensation.
Had compensation cost been determined for the stock options and the ESPP
under the fair value method as opposed to the intrinsic value method followed by
the NU system, the effect on net loss and loss per share would have been as
follows:
<TABLE>
<CAPTION>
- ---------------------------------------------------------
(Thousands of Dollars,
except per share amounts) 1998 1997
- ---------------------------------------------------------
<S> <C> <C>
Net loss ........................... $149,054 $130,035
Basic and diluted loss
per share ........................ $ 1.14 $ 1.01
=========================================================
</TABLE>
The fair value of each stock option grant has been estimated on the date of
grant using the Black-Scholes option pricing model with the following weighted
average assumptions:
<TABLE>
<CAPTION>
- ---------------------------------------------------------
1998 1997
- ---------------------------------------------------------
<S> <C> <C>
Risk-free interest rate ............ 5.82% 6.41%
Expected life ...................... 10 years 10 years
Expected volatility ................ 35.05% 31.89%
Expected dividend yield ............ 5.46% 7.42%
=========================================================
</TABLE>
The weighted average grant date fair values of options granted during 1998 and
1997 were $3.98 and $1.68, respectively.
6. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES
CL&P and WMECO have entered into agreements to sell up to $200 million and $40
million, respectively, of undivided ownership interests in eligible customer
receivables and accrued utility revenues (receivables).
CL&P and WMECO each have established a special purpose, wholly owned
subsidiary whose business consists of the purchase and resale of receivables:
CL&P Receivables Corporation (CRC), and WMECO Receivables Corporation (WRC),
respectively. For receivables sold, both CL&P and WMECO have retained collection
responsibilities as agent for the purchaser under each company's respective
agreements. As collections reduce previously sold receivables, new receivables
may be sold. At December 31, 1998, approximately $105 million and $20 million
of receivables had been sold to third-party purchasers by CL&P and WMECO,
respectively. All receivables sold to CRC and WRC are not available to pay
CL&P's or WMECO's creditors.
The receivables are sold to third-party purchasers with limited recourse.
The sales agreements provide for a formula-based loss reserve in which
additional receivables may be assigned to the third-party purchasers for costs
such as bad debt. The third-party purchasers absorb the excess amount in the
event that actual loss experience exceeds the loss reserve. At December 31,
1998, approximately $11.6 million and $2.9 million were the formula-based
amounts of credit exposure and have been reserved as collateral by CRC and WRC,
respectively. Historical losses for bad debt for both CL&P and WMECO have been
substantially less.
As a result of prior period downgrades on WMECO's first mortgage bonds, the
current bond rating is at a level where the sponsor of WMECO's accounts
receivable program could take various actions at its discretion, which would
have the practical effect of limiting WMECO's ability to utilize the facility.
To date, the sponsor has not notified WMECO that it will elect to exercise
those rights and the program is functioning in its normal mode.
Concentrations of credit risk to the respective purchasers under each
company's agreements with respect to the receivables are limited due to CL&P's
and WMECO's diverse customer base within their respective service territories.
39
<PAGE>
7. COMMITMENTS AND CONTINGENCIES
A. RESTRUCTURING
Connecticut: During April 1998, the utility restructuring bill was signed into
law by the governor of the state of Connecticut. The legislation provides for
electric utilities, including CL&P, to recover stranded costs. The legislation
also allows for securitization of generation-related regulatory assets and the
costs associated with renegotiated above-market purchased-power contracts and
requires divestiture of generation-related assets through public auction.
As a result of the restructuring legislation, CL&P will sell non-nuclear
generating assets and purchased-power contracts with nonutility generators
through public auction. CL&P also will transfer its ownership interests in
Millstone 2 and 3 and Seabrook to a corporate affiliate or division, subject to
prior federal regulatory approvals, which would assume CL&P's responsibilities
related to the plants for the period prior to offering them for sale. In
February 1999, the DPUC announced the offering for sale of CL&P's fossil fuel
and hydroelectric generating facilities. Interested parties will be required to
submit nonbinding bids by April 8, 1999. A smaller field of qualified bidders
will be selected to participate in the second round of the auction and will be
invited to submit binding bids. A winning bidder will be chosen by mid-1999 and
the sale will be completed by the end of 1999. At December 31, 1998, the book
value of assets to be auctioned during 1999 was approximately $170 million.
After restructuring is complete, CL&P will be an electric transmission and
distribution company which will continue to provide transmission and
distribution services on a cost-of-service basis.
Management continues to believe that it is probable that CL&P will recover
fully its prudently incurred costs, including regulatory assets and stranded
investments.
New Hampshire: In 1996, New Hampshire enacted legislation requiring a
competitive electric industry beginning in 1998. In February 1997, the NHPUC
issued its restructuring order, which would have forced PSNH and NAEC to write
off all of their regulatory assets, and possibly to seek protection under
Chapter 11 of the bankruptcy laws. The amount of potential write-off which would
have been triggered by the order currently is estimated to be in excess of $400
million, after taxes.
Following the issuance of these orders, PSNH immediately sought declaratory
and injunctive relief on various grounds in federal district court and has
received a preliminary injunction that freezes implementation of the NHPUC's
restructuring orders. Restructuring in New Hampshire has resulted in numerous
subsequent proceedings within the federal and state legal systems.
As the court proceedings are ongoing, PSNH continues to be involved in
settlement discussions with representatives from the state of New Hampshire.
PSNH hopes to reach a settlement which would include, among other things,
recovery of regulatory assets and stranded costs, rate reductions, an auction of
PSNH's generating units and securitization of PSNH's stranded costs. If a
settlement is not reached, a trial is expected to begin in mid to late 1999.
As a result of the NHPUC decision and the potential consequences discussed
above, the reports of our auditors on the individual financial statements of
PSNH and NAEC contain explanatory paragraphs. Those explanatory paragraphs
indicate that a substantial doubt exists currently about the ability of PSNH and
NAEC to continue as going concerns. The accounts of PSNH and NAEC are included
in the accompanying consolidated financial statements on the basis of a going
concern. While the effect of the implementation of that decision would have a
material adverse impact on NU's financial position, results of operations and
cash flows, it would not in and of itself result in defaults under borrowing or
other financial agreements of NU or its other subsidiaries.
Management believes that PSNH is entitled to full recovery of its prudently
incurred costs, including regulatory assets and other stranded costs. It bases
this belief both on the general nature of public utility industry
cost-of-service based regulation and the specific circumstances of the
resolution of PSNH's previous bankruptcy proceedings and its acquisition by NU,
including the recoveries provided by the Rate Agreement and related agreements.
Massachusetts: Electric utility industry restructuring within the state of
Massachusetts became effective March 1, 1998. As required by the legislation
enacted in November 1997, WMECO will continue to operate and maintain its
transmission and local distribution network and deliver electricity to all
customers. The restructuring legislation specifically provides for the cost
recovery of generation-related assets. The legislation gives the DTE the
authority to determine the amount of stranded costs that will be eligible for
recovery by utilities. Costs which will qualify as stranded costs and be
eligible for recovery include, but are not limited to, certain above-market
costs associated with generating facilities, costs associated with long-term
commitments to purchase power at above-market prices from small-power producers
and nonutility generators (NUGs), and regulatory assets and associated
liabilities related to the generation portion of WMECO's business.
Effective March 1, 1998, WMECO's restructuring plan has been filed with the
DTE and includes a 10 percent rate reduction, divestiture of generation assets,
securitization of approximately $500 million of stranded costs and customer
choice of supplier. The DTE has not approved WMECO's plan yet and rates are
being charged under an interim order. A final decision is expected in mid-1999.
On January 22, 1999, WMECO signed an agreement to sell 290 MW of fossil and
hydroelectric generation assets to Consolidated Edison Energy, Inc. of New York
for $47 million. The sale price is approximately 3.8 times greater
40
<PAGE>
than the assets' 1997 book value of $12.5 million. WMECO did not offer its 19
percent share of the Northfield Mountain pumped storage generating facility and
associated hydroelectric facilities. WMECO's book value in Northfield Mountain
was $13.0 million at December 31, 1998. This asset will be auctioned in
conjunction with CL&P's fossil/hydroelectric auction discussed above. The net
proceeds in excess of book value received from the actual divestiture of these
units will be used to mitigate stranded costs.
Based upon the legislation and regulatory proceedings to date, management
continues to believe that the NU system companies will recover their prudently
incurred costs, including regulatory assets and generation-related investments.
However, a change in one or more of these factors could affect the recovery of
stranded costs and may result in a loss to the company.
B. RATE MATTERS
Connecticut: On February 25, 1998, the DPUC issued its decision in CL&P's
Interim Rate case. During the period from March 1, 1998, through September 28,
1998, rates were charged under an interim rate which required a $30.5 million
annual credit to customer bills to reflect the removal of Millstone 1 from
rates.
During April 1998, the DPUC issued a decision finding Millstone 2 unlikely
to restart in 1998 and ordered its removal from rate base effective May 1, 1998.
The DPUC allowed the revenue requirement reductions related to this decision to
be potentially applied against regulatory asset balances. As a result, there was
no change in rates or CL&P's cash flow from rates. CL&P has accounted for these
reductions as a reserve against revenues until such time when the regulatory
asset balances are reduced. At December 31, 1998, the amount of revenue
reductions related to this decision totaled approximately $36.4 million. The
unit will remain out of rate base until the plant is restarted.
On June 1, 1998, CL&P filed its rate application for a comprehensive rate
proceeding. On February 5, 1999, the DPUC issued its final decision in CL&P's
rate case. The DPUC concluded that CL&P's annual revenue requirements should be
reduced by approximately $232 million, or 9.68 percent, through a combination of
a 4 percent reduction to CL&P's rates and accelerated amortization of approxi-
mately $136 million of its deferred tax regulatory asset. The decision is
retroactive to September 28, 1998. The retroactive portion of the decision did
not require a base-rate decrease. It resulted in accelerated amortization of the
deferred tax regulatory asset in the amount of $27.6 million. The decision also
resulted in an after-tax write-off of approximately $80 million related to
CL&P's investment in Millstone 1. For further information, see Note 2, "Nuclear
Decommissioning and Plant Closure Costs," and the MD&A.
New Hampshire: PSNH's Rate Agreement between NU, PSNH and the state of New
Hampshire provided for seven base-rate increases of 5.5 percent per year
beginning in 1990 and provided for the FPPAC. The final base-rate increase went
into effect on June 1, 1996. The Rate Agreement contemplates that PSNH's rates
are subject to traditional rate regulation after the fixed-rate period, which
expired on May 31, 1997. The FPPAC, however, would continue through May 31,
2001, and other Rate Agreement requirements would continue in accordance with
the terms of the agreement.
A PSNH base-rate case was filed in May 1997, but was delayed in connection
with the restructuring proceedings discussed above. In November 1997, the NHPUC
ordered a temporary base-rate reduction for PSNH of 6.87 percent effective
December 1, 1997. The NHPUC also set an interim return on equity of 11 percent.
In December 1998, the base-rate case was reopened and an updated rate case was
filed. A final decision, which will be retroactive to July 1, 1997, currently
is scheduled to be issued by June 1, 1999.
Concurrently with the 6.87 percent rate reduction beginning in December
1997, the NHPUC allowed an FPPAC increase of approximately 6 percent. This rate
increase was effective for the period from December 1, 1997, through May 31,
1998. On May 29, 1998, the NHPUC approved slightly more than a 1 percent
increase in PSNH's FPPAC rate for the period June through November 1998. On
December 1, 1998, the NHPUC allowed the current FPPAC rate to remain in place
through May 31, 1999. As a result of this decision, the current portion of un-
recovered energy costs are projected to increase by approximately $17.4 million
from January 1, 1999, through May 31, 1999, to an estimated balance of
approximately $79.7 million. PSNH's ongoing restructuring settlement
negotiations with the state of New Hampshire could resolve both the base-rate
case and the FPPAC proceedings discussed above.
FERC: During November 1997, MYAPC filed an amendment to its power contracts
clarifying the obligations of its purchasing utilities following the decision to
cease power production. During January 1998, the FERC accepted the amendments
and proposed rates, subject to a refund. On January 18, 1999, MYAPC filed with
the FERC Administrative Law Judge (ALJ) an Offer of Settlement which if accepted
by the FERC, will resolve all the issues in the FERC decommissioning rate case
proceeding. The settlement provides, among other things, the following: (1)
MYAPC will collect $33.6 million annually to pay for decommissioning and spent
fuel; (2) its return on equity will be set at 6.5 percent; (3) MYAPC is
permitted full recovery of all unamortized investment in MY, including fuel, and
(4) an incentive budget for decommissioning is set at $436.3 million.
During late December 1996, CYAPC filed an amendment to its power contracts
clarifying the obligations of its purchasing utilities following the decision to
cease power production. On February 27, 1997, the FERC accepted
41
<PAGE>
CYAPC's contract amendment. The new rates became effective March 1, 1997,
subject to a refund.
On August 31, 1998, the FERC ALJ released an initial decision regarding the
December 1996 filing. The decision contained provisions which would allow for
the recovery, through rates, of the balance of the NU system companies' net
unamortized investment in CYAPC, which was approximately $51.7 million as of
December 31, 1998. The decision also called for the disallowance of the recovery
of a portion of the return on the CY investment. The ALJ's decision also stated
that decommissioning collections should continue to be based on the previously
approved estimate of $309.1 million (in 1992 dollars), with an inflation
adjustment of 3.8 percent per year, until a new, more reliable estimate has been
prepared and tested.
During October 1998, CYAPC, CL&P, PSNH and WMECO filed briefs on exceptions
to the ALJ decision. If the initial ALJ decision is upheld, CYAPC could be
required to write off a portion of the regulatory asset associated with the
plant closing.
If upheld, CYAPC's management has estimated the effect of the ALJ decision
on CYAPC's earnings would be approximately $37.5 million, of which the NU
system's share would be approximately $18.4 million. NU management cannot
predict the ultimate outcome of the hearing at this time, however, management
believes that the associated regulatory assets are probable of recovery.
C. NUCLEAR PERFORMANCE
Millstone: The three Millstone units are managed by NNECO. All three units were
placed on the NRC watch list on January 29, 1996. The units cannot be restarted
without appropriate NRC approvals. Millstone 3 has received these approvals and
resumed operation in July 1998. Restart efforts continue for Millstone 2 and it
is expected to be ready to restart in the spring of 1999. The estimated
replacement power costs are approximately $8 million per month while Millstone 2
remains out of service. In July 1998, CL&P and WMECO decided to retire Millstone
1 and prepare for final decommissioning.
Litigation: Several shareholder class-action lawsuits have been filed
against the company and certain present and former officers and employees of NU
in connection with the company's nuclear operations. Management cannot estimate
the potential outcome of these suits, but believes these suits are without merit
and intends to defend itself vigorously in all these actions.
In addition, certain of the non-NU joint owners of Millstone 3 filed
demands for arbitration with CL&P and WMECO as well as lawsuits in Massachusetts
Superior Court against NU and its current and former trustees related to the
company's operation of Millstone 3. The arbitrations and lawsuits seek to
recover compensatory damages in excess of $200 million, together with punitive
damages, treble damages and attorney's fees. Management cannot estimate the
potential outcome of these suits but believes there is no legal basis for the
claims and intends to defend against them vigorously.
D. ENVIRONMENTAL MATTERS
The NU system is subject to regulation by federal, state and local authorities
with respect to air and water quality, the handling and disposal of toxic
substances and hazardous and solid wastes, and the handling and use of chemical
products. The NU system has an active environmental auditing and training
program and believes that it is in substantial compliance with current
environmental laws and regulations. However, the NU system is subject to certain
pending enforcement actions and governmental investigations in the environmental
area. Management cannot predict the outcome of these enforcement actions and
investigations.
Environmental requirements could hinder the construction of new generating
units, transmission and distribution lines, substations and other facilities.
Changing environmental requirements could also require extensive and costly
modifications to the NU system's existing generating units and transmission and
distribution systems, and could raise operating costs significantly. As a
result, the NU system may incur significant additional environmental costs,
greater than amounts included in cost of removal and other reserves, in
connection with the generation and transmission of electricity and the storage,
transportation and disposal of byproducts and wastes. The NU system also may
encounter significantly increased costs to remedy the environmental effects of
prior waste handling activities. The cumulative long-term cost impact of
increasingly stringent environmental requirements cannot be estimated
accurately.
The NU system has recorded a liability based upon currently available
information for the estimated environmental remediation costs that the NU system
subsidiaries expect to incur. In most cases, additional future environmental
cleanup costs are not reasonably estimable due to a number of factors, including
the unknown magnitude of possible contamination, the appropriate remediation
methods, the possible effects of future legislation or regulation and the
possible effects of technological changes. At December 31, 1998, the liability
recorded by the NU system for its estimated environmental remediation costs, not
considering any possible recoveries from third parties, amounted to
approximately $21.5 million, within a range of $21.5 million to $36.4 million.
The NU system companies have received proceeds from several insurance
carriers for the settlement with certain insurance companies of all past,
present and future environmental matters. As a result of these settlements, the
NU system companies will retain the risk loss, in part, for some environmental
remediation costs.
The NU system cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought against it.
However, considering known facts, existing laws and regulatory practices,
management does not believe the matters disclosed above will have a material
effect on the NU system's financial position or future results of operations.
42
<PAGE>
E. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO and NAEC must pay
the United States Department of Energy (DOE) for the disposal of spent nuclear
fuel and high-level radioactive waste. The DOE is responsible for the selection
and development of repositories for, and the disposal of, spent nuclear fuel and
high-level radioactive waste. Fees for nuclear fuel burned on or after April 7,
1983, are billed currently to customers and paid to the DOE on a quarterly
basis. For nuclear fuel used to generate electricity prior to April 7, 1983
(prior period fuel), payment must be made prior to the first delivery of spent
fuel to the DOE. Until such payment is made, the outstanding balance will
continue to accrue interest at the three-month Treasury Bill Yield Rate. At
December 31, 1998, fees due to the DOE for the disposal of prior period fuel
were approximately $216.1 million, including interest costs of $134.0 million.
The DOE originally was scheduled to begin accepting delivery of spent fuel
in 1998. However, delays in identifying a permanent storage site continually
have postponed plans for the DOE's long-term storage and disposal site. Extended
delays or a default by the DOE could lead to consideration of costly
alternatives. The company has primary responsibility for the interim storage of
its spent nuclear fuel. Adequate storage capacity exists to accommodate all
spent nuclear fuel at Millstone 1. With the addition of new storage racks,
storage facilities for Millstone 3 are expected to be adequate for the projected
life of the unit. With the implementation of currently planned modifications,
the storage facilities for Millstone 2 are expected to be adequate to
accommodate a full-core discharge from the reactor until 2005. Fuel
consolidation, which has been licensed for Millstone 2, could provide adequate
storage capability for its projected life. Seabrook is expected to have spent
fuel storage capacity until at least 2010. Meeting spent fuel storage
requirements beyond these periods could require new and separate storage
facilities, the costs for which have not been determined.
In November 1997, the U.S. Court of Appeals for the D.C. Circuit ruled that
the lack of an interim storage facility does not excuse the DOE from meeting its
contractual obligation to begin accepting spent nuclear fuel no later than
January 31, 1998. The 1997 ruling by the appeals court said, however, that the
1982 federal law could not require the DOE to accept waste when it did not have
a suitable storage facility. The court directed the plaintiffs to pursue relief
under the terms of their contracts with the DOE. Based on this ruling, since the
DOE did not take the spent nuclear fuel as scheduled, it may have to pay
contract damages.
In May 1998, the same court denied petitions from 60 states and state
agencies, collectively, and 41 utilities, including the company, asking the
court to compel the DOE to submit a program, beginning immediately, for
disposing of spent nuclear fuel. The petitions were filed after the DOE
defaulted on its January 31, 1998 obligation to begin accepting the fuel. The
court directed the company and other plaintiffs to pursue relief under the terms
of their contracts with the DOE.
In a petition filed in August 1998, the court's May 1998 decision was
appealed to the U.S. Supreme Court. In November 1998, the Supreme Court declined
to review the lower court ruling that said utilities should go to court and seek
monetary damages from the DOE. The ultimate outcome of this legal proceeding is
uncertain at this time.
F. NUCLEAR INSURANCE CONTINGENCIES
Under certain circumstances, in the event of a nuclear incident at one of the
nuclear facilities in the country covered by the federal government's
third-party liability indemnification program, the NU system could be assessed
in proportion to its ownership interest in each of its nuclear units up to $83.9
million. The NU system's payments of this assessment would be limited to, in
proportion to its ownership interest in each of its nuclear units, $10 million
in any one year per nuclear unit. In addition, if the sum of all claims and
costs from any one nuclear incident exceeds the maximum amount of financial
protection, the NU system would be subject to an additional 5 percent or $4.2
million, in proportion to its ownership interests in each of its nuclear units.
Based upon its ownership interests in Millstone 1, 2 and 3 and in Seabrook 1,
the NU system's maximum liability, including any additional assessments, would
be $271.0 million per incident, of which payments would be limited to $30.8
million per year. In addition, through purchased-power contracts with VYNPC, the
NU system would be responsible for up to an additional $14.1 million per
incident, of which payments would be limited to $1.6 million per year.
The NRC approved CYAPC's and MYAPC's requests for withdrawal from
participation in the secondary financial protection program effective November
19, 1998, and January 17, 1999, respectively, due to their permanently shutdown
and defueled status. Therefore, neither CYAPC, MYAPC nor their sponsor companies
have any future obligations for potential assessment.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from insured
occurrences. The NU system is subject to retroactive assessments if losses
exceed the accumulated funds available to the insurer. The maximum potential
assessment against the NU system with respect to losses arising during the
current policy year is approximately $14.2 million under the primary property
insurance program.
Insurance has been purchased to cover certain extra costs incurred in
obtaining replacement power during prolonged accidental outages and the excess
cost of repair, replacement or decontamination or premature decommis-
43
<PAGE>
sioning of utility property resulting from insured occurrences. The NU system is
subject to retroactive assessments if losses exceed the accumulated funds
available to the insurer. The maximum potential assessments against the NU
system with respect to losses arising during current policy years are
approximately $6.9 million under the replacement power policies and $16.4
million under the excess property damage, decontamination and decommissioning
policies. The cost of a nuclear incident could exceed available insurance
proceeds.
Insurance has been purchased aggregating $200 million on an industry basis
for coverage of worker claims.
G. CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision by
management. The NU system companies currently forecast construction expenditures
of approximately $2.1 billion for the years 1999-2003, including $364 million
for 1999. In addition, the NU system companies estimate that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $252.2 million for the years 1999-2003, including $34.0 million
for 1999. See Note 4, "Leases," for additional information about the financing
of nuclear fuel.
H. LONG-TERM CONTRACTUAL ARRANGEMENTS
Yankee Companies: The NU system companies rely on VY for approximately 1.4
percent of their capacity under long-term contracts. Under the terms of their
agreements, the NU system companies pay their ownership (or entitlement) shares
of costs, which include depreciation, O&M expenses, taxes, the estimated cost of
decommissioning and a return on invested capital. These costs are recorded as
purchased-power expense and recovered through the companies' rates. The total
cost of purchases under contracts with VYNPC amounted to $27.3 million in 1998,
$24.2 million in 1997 and $25.5 million in 1996. CL&P, PSNH and WMECO also may
be asked to provide direct or indirect financial support for one or more of the
Yankee companies, including VYNPC.
NUGs: CL&P, PSNH and WMECO have entered into various arrangements for the
purchase of capacity and energy from NUGs. These arrangements have terms from 10
to 30 years, currently expiring in the years 1999 through 2029, and require the
companies to purchase energy at specified prices or formula rates. For the
12-month period ending December 31, 1998, approximately 13 percent of NU system
electricity requirements was met by NUGs. The total cost of purchases under
these arrangements amounted to $459.7 million in 1998, $447.6 million in 1997
and $441.6 million in 1996.
New Hampshire Electric Cooperative: PSNH entered into a buy-back agreement
to purchase the capacity and energy of the New Hampshire Electric Cooperative,
Inc.'s (NHEC) share of Seabrook 1 and to pay all of NHEC's Seabrook 1 costs for
a 10-year period, which began on July 1, 1990. The total cost of purchases under
this agreement was $29.7 million in 1998, $23.4 million in 1997 and $14.6
million in 1996. The total cost of these purchases has been collected through
the FPPAC in accordance with the Rate Agreement.
Although under the agreement NHEC agreed to continue as a firm-requirements
customer of PSNH for 15 years, it has recently received a FERC ruling allowing
it to purchase power from qualifying facilities. The ruling allows that the
price for such purchases may be determined through negotiation between NHEC and
the qualifying facility. The financial impact of this decision in the future
will vary depending upon the level of purchases made by NHEC from the qualifying
purchasers.
NHEC also is seeking to be able to purchase energy under the agreement from
competitive sources once competition has begun in its service territory. A
final FERC decision is expected by March 1999. The financial impact of this
decision in the future will depend upon the implementation of restructuring in
NHEC's service territory.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO and
HWP have entered into agreements to support transmission and terminal facilities
to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO
and HWP are obligated to pay, over a 30-year period ending in 2020, their
proportionate shares of the annual O&M and capital costs of these facilities.
Estimated Annual Costs: The estimated annual costs of the NU system's
significant long-term contractual arrangements are as follows:
- --------------------------------------------------------------
(Millions of Dollars) 1999 2000 2001 2002 2003
- --------------------------------------------------------------
VYNPC ................. $ 29.2 $ 27.0 $ 29.4 $ 30.0 $ 27.9
NUGs .................. 473.3 476.8 484.9 493.5 505.1
NHEC .................. 30.0 14.6 -- -- --
Hydro-Quebec .......... 32.2 30.9 30.0 29.3 28.5
==============================================================
8. INTEREST-RATE AND FUEL-PRICE RISK-MANAGEMENT
Interest-Rate Risk-Management: NAEC uses swap instruments with financial
institutions to hedge against interest rate risk associated with its $200
million variable-rate bank note. The interest-rate management instruments
employed eliminate the exposure associated with rising interest rates, and
effectively fix the interest rate for this borrowing arrangement. Under the
agreements, NAEC exchanges quarterly payments based on a differential between a
fixed
44
<PAGE>
contractual interest rate and the three-month LIBOR rate at a given time.
As of December 31, 1998, NAEC had outstanding agreements with a total notional
value of approximately $200 million and a negative mark-to-market position of
approximately $2.3 million.
Fuel-Price Risk-Management: CL&P uses swap instruments with financial
institutions to hedge against some of the fuel price risk created by long-term
negotiated energy contracts. These agreements minimize exposure associated with
rising fuel prices by managing a portion of CL&P's cost of producing power for
these negotiated energy contracts. As of December 31, 1998, CL&P had outstanding
agreements with a total notional value of approximately $422.2 million, and a
negative mark-to-market position of approximately $44.9 million.
The terms of the agreements require CL&P to post cash collateral with its
counterparties in the event of negative mark-to-market positions and lowered
credit ratings. The amount of the collateral is to be returned to CL&P when the
mark-to-market position becomes positive, when CL&P meets specified credit
ratings or when an agreement ends and all open positions are properly settled.
At December 31, 1998, cash collateral in the amount of $45.7 million was posted
under these terms. This amount has been recorded in Other Investments on the
accompanying Consolidated Balance Sheets.
Credit Risk: These agreements have been made with various financial
institutions, each of which is rated "A3" or better by Moody's rating group.
Each respective system company will be exposed to credit risk on their
respective market risk-management instruments if the counterparties fail to
perform their obligations. Management anticipates that the counterparties will
fully satisfy their obligations under the agreements.
9. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
CL&P Capital LP (CL&P LP, a subsidiary of CL&P) previously had issued $100
million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS),
Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner,
and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance,
CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million
capital contribution, back to CL&P in the form of an unsecured debenture. CL&P
consolidates CL&P LP for financial reporting purposes. Upon consolidation, the
unsecured debenture is eliminated, and the MIPS securities are accounted for as
minority interests.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each of the following financial instruments:
Cash and cash equivalents: The carrying amounts approximate fair value due
to the short-term nature of cash and cash equivalents.
Supplemental Executive Retirement Plan investments: SFAS 115, "Accounting
for Certain Investments in Debt and Equity Securities," requires investments in
debt and equity securities to be presented at fair value. As a result of this
requirement, the investments having a cost basis of $5.4 million held for
benefit of the Supplemental Executive Retirement Plan were recorded on the
Consolidated Balance Sheet at their fair market value at December 31, 1998, of
$8.7 million.
Nuclear decommissioning trusts: The investments held in the NU system
companies' nuclear decommissioning trusts were adjusted to market by
approximately $110.4 million as of December 31, 1998, and $69.6 million as of
December 31, 1997, with corresponding offsets to the accumulated provision for
depreciation. The amounts adjusted in 1998 and in 1997 represent cumulative net
unrealized gains. The cumulative gross unrealized holding losses were immaterial
for both 1998 and 1997.
Preferred stock and long-term debt: The fair value of the NU system's
fixed-rate securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair value
equal to their carrying value. The carrying amounts of the NU system's financial
instruments and the estimated fair values are as follows:
- ---------------------------------------------------------
At December 31, 1998
- ---------------------------------------------------------
Carrying Fair
(Thousands of Dollars) Amount Value
- ---------------------------------------------------------
Preferred stock not subject
to mandatory redemption ....... $ 136,200 $ 97,017
Preferred stock subject to
mandatory redemption .......... 213,789 205,905
Long-term debt --
First mortgage bonds .......... 1,984,000 2,003,630
Other long-term debt .......... 1,654,927 1,682,722
MIPS ............................ 100,000 102,000
=========================================================
- ---------------------------------------------------------
At December 31, 1997
- ---------------------------------------------------------
Carrying Fair
(Thousands of Dollars) Amount Value
- ---------------------------------------------------------
Preferred stock not subject
to mandatory redemption ....... $ 136,200 $ 79,141
Preferred stock subject to
mandatory redemption .......... 276,000 255,180
Long-term debt --
First mortgage bonds .......... 2,228,800 2,210,423
Other long-term debt .......... 1,668,533 1,691,362
MIPS ............................ 100,000 100,760
=========================================================
45
<PAGE>
11. EARNINGS PER SHARE
Earnings per share is computed based upon the weighted average number of common
shares outstanding during each year. Diluted earnings per share is computed on
the basis of the weighted average number of common shares outstanding plus the
potential dilution effect if certain securities are converted into common stock.
The following table sets forth the components of basic and diluted earnings
per share:
- ---------------------------------------------------------------
(Thousands of Dollars,
except per share data) 1998 1997 1996
- ---------------------------------------------------------------
(Loss)/ income after
interest charges ..... $(120,313) $ (99,676) $72,705
Preferred dividends
of subsidiaries ...... 26,440 30,286 33,776
- ---------------------------------------------------------------
Net (loss)/income ...... $(146,753) $(129,962) $38,929
===============================================================
Basic EPS common
shares outstanding
(average) ............ 130,549,760 129,567,708 127,960,382
Dilutive effect of
employee stock
options .............. --(a) --(a) 112,879
- ---------------------------------------------------------------
Diluted EPS common
shares outstanding
(average) ............ 130,549,760 129,567,708 128,073,261
===============================================================
Basic earnings
per share ............ $ (1.12) $ (1.01) $ 0.30
Diluted earnings
per share ............ $ (1.12) $ (1.01) $ 0.30
===============================================================
(a) The addition of dilutive potential common shares would be anti-dilutive for
1998 and 1997 and, therefore, are not included.
12. OTHER COMPREHENSIVE INCOME
During 1998, the NU system adopted SFAS 130, "Reporting Comprehensive Income,"
which established standards for reporting and displaying comprehensive income
and its components in a financial statement that is displayed with the same
prominence as other financial statements.
The accumulated balance for each other comprehensive income item is as
follows:
- ---------------------------------------------------------------
Current
December 31, Period DECEMBER 31,
(Thousands of Dollars) 1997 Change 1998
- ---------------------------------------------------------------
Foreign currency
translation adjustments ........ $(1) $ -- $ (1)
Unrealized gains on
securities ..................... -- 2,019 2,019
Minimum pension liability
adjustment ..................... -- (613) (613)
- ---------------------------------------------------------------
Accumulated other
comprehensive income ........... $(1) $1,406 $1,405
===============================================================
The changes in the components of other comprehensive income are reported on the
Consolidated Statements of Comprehensive Income net of the following income tax
effects:
- ---------------------------------------------------------------
(Thousands of Dollars) 1998 1997 1996
- ---------------------------------------------------------------
Foreign currency
translation
adjustments ................ $ -- $359 $(313)
Unrealized gains
on securities .............. (1,222) -- --
Minimum pension
liability
adjustment ................. 398 -- --
- ---------------------------------------------------------------
Other comprehensive
income ..................... $ (824) $359 $(313)
===============================================================
13. MODE 1
In July 1998, Mode 1's equity investments, FiveCom LLC and NECOM LLC,
reorganized along with other related companies to form a new company, NorthEast
Optic Network, Inc. ("NEON"). Mode 1's ownership interest of 40.78 percent in
the new company was equal to its combined ownership interest in FiveCom LLC and
NECOM LLC.
In August 1998, NEON issued 4,000,000 new common shares on the open market
in an initial public offering (IPO). NEON's IPO had the effect of decreasing
Mode 1's ownership interest from 40.78 percent to 30.74 percent. The shares were
issued at an amount greater than Mode 1's investment, resulting in a $13.7
million pretax increase to Mode 1's equity. NU's accounting policy is to
recognize the gain or loss from this type of change in ownership interest in net
income. Based upon new information received regarding the startup nature of
NEON's operations, this change in ownership interest was recognized in
additional paid in capital instead of net income.
In conjunction with the IPO, Mode 1 sold 217,997 NEON shares, resulting in a
pretax gain of $1.7 million and further reducing its ownership interest to 29.4
percent of the outstanding common shares of NEON.
46
<PAGE>
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA
(UNAUDITED)
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
1998 Quarter Ended (a)
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
(Thousands of Dollars, except per share data) March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------------------------------------------
Operating Revenues ........................................... $958,905 $874,809 $974,382 $ 959,618
======================================================================================================================
Operating Income ............................................. $ 40,488 $ 76,296 $ 82,675 $ 25,268
======================================================================================================================
Net (Loss)/Income ............................................ $(17,949) $ 6,273 $ (3,075)(b) $(132,002)
======================================================================================================================
Basic and Diluted (Loss)/Earnings Per Common Share ........... $ (0.14) $ 0.05 $ (0.02)(b) $ (1.01)
======================================================================================================================
- ----------------------------------------------------------------------------------------------------------------------
1997
- ----------------------------------------------------------------------------------------------------------------------
Operating Revenues ........................................... $975,368 $903,323 $977,127 $ 978,988
======================================================================================================================
Operating Income ............................................. $ 69,377 $ 23,542 $ 46,361 $ 51,502
======================================================================================================================
Net Income/(Loss) ............................................ $ 876 $(47,017) $(30,832) $ (52,989)
======================================================================================================================
Basic and Diluted Earnings/(Loss) Per Common Share ........... $ 0.01 $ (0.37) $ (0.24) $ (0.41)
======================================================================================================================
</TABLE>
CONSOLIDATED GENERATION STATISTICS
(UNAUDITED)
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
SOURCE OF ELECTRIC ENERGY: (kWh-millions)
<S> <C> <C> <C> <C> <C>
Nuclear -- Steam (c) .......................... 5,679 3,778 9,405 18,235 19,443
Fossil -- Steam ............................... 12,505 13,155 9,188 9,162 8,292
Hydro -- Conventional ......................... 1,510 1,260 1,544 1,099 1,239
Hydro -- Pumped Storage ....................... 819 959 1,217 1,209 1,195
Internal Combustion ........................... 80 184 206 37 13
Energy Used for Pumping ....................... (1,130) (1,327) (1,668) (1,674) (1,629)
- ----------------------------------------------------------------------------------------------------------------------
Net Generation ................................ 19,463 18,009 19,892 28,068 28,553
- ----------------------------------------------------------------------------------------------------------------------
Purchased and Net Interchange ................. 24,945 24,377 22,111 14,256 14,028
Company Use and Unaccounted for ............... (2,566) (2,802) (2,473) (2,706) (2,535)
- ----------------------------------------------------------------------------------------------------------------------
Net Energy Sold ............................... 41,842 39,584 39,530 39,618 40,046
======================================================================================================================
System Capability -- MW (c)(d) ................ 8,169.6 8,312.0(e) 8,894.0 8,394.8 8,494.8
System Peak Demand -- MW ...................... 6,454.7 6,455.5 5,946.9 6,358.2 6,338.5
Nuclear Capacity -- MW (c)(d) ................. 2,217.8 2,785.0(e) 3,117.8 3,239.6 3,272.6
Nuclear Contribution to
Total Energy Requirements (%)(c) .......... 19.0 13.0 28.0 52.0 54.0
Nuclear Capacity Factor (%)(e) ................ 32.8 19.6 38.0 69.9 67.5
======================================================================================================================
</TABLE>
(a) Reclassifications of prior years' data have been made to conform with the
current presentation.
(b) During the third quarter of 1998, Mode 1 classified the change in ownership
interest in NEON as a gain in net income. In the fourth quarter, the gain
was reclassified to additional paid in capital. See Note 13, "Mode 1" for
further information. Amounts previously reported for the third quarter were
net income of $4,976 and earnings per common share of $0.04.
(c) Includes the NU system's entitlements in regional nuclear generating
companies, net of capacity sales and purchases.
(d) Millstone 2 has been out of service since February 21, 1996. The NU system
hopes to return Millstone 2 to service in the spring of 1999. Millstone 3
returned to service during the third quarter of 1998 following NRC approval.
During the third quarter of 1998, CL&P and WMECO decided to retire Millstone
1 and prepare for final decommissioning.
(e) Represents the average capacity factor for the nuclear units operated by the
NU system.
47
<PAGE>
SELECTED CONSOLIDATED FINANCIAL DATA
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except percentages and per share data) 1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Net Utility Plant (a) ................................. $ 6,170,881 $ 6,463,158 $ 6,732,165 $ 7,000,837 $ 7,282,421
Total Assets .......................................... 10,387,381 10,414,412 10,741,748 10,559,574 10,584,880
Total Capitalization (b) .............................. 6,030,402 6,472,504 6,659,617 6,820,624 7,035,989
Obligations Under Capital Leases (b) .................. 209,279 207,731 206,165 230,482 239,121
- ----------------------------------------------------------------------------------------------------------------------------------
INCOME DATA:
Operating Revenues .................................... $ 3,767,714 $ 3,834,806 $ 3,792,148 $ 3,750,560 $ 3,642,742
Net (Loss)/Income ..................................... (146,753) (129,962) 38,929 282,434 286,874
- ----------------------------------------------------------------------------------------------------------------------------------
COMMON SHARE DATA:
Basic and Diluted (Loss)/Earnings
Per Share ......................................... $(1.12) $(1.01) $0.30 $2.24 $2.30
Dividends Per Share (c) ............................... $-- $0.25 $1.38 $1.76 $1.76
Number of Shares Outstanding -- Average ............... 130,549,760 129,567,708 127,960,382 126,083,645 124,678,192
Market Price -- High .................................. $17 1/4 $14 1/4 $25 1/4 $25 3/8 $25 3/4
Market Price -- Low ................................... $11 11/16 $7 5/8 $9 1/2 $21 $20 3/8
Market Price -- Closing (end of year) ................. $16 $11 13/16 $13 1/8 $24 1/4 $21 5/8
Book Value Per Share (end of year) .................... $15.63 $16.67 $18.02 $19.08 $18.47
Rate of Return Earned on Average
Common Equity (%) ................................. (7.0) (5.8) 1.6 12.0 12.7
Market-to-Book Ratio (end of year) .................... 1.0 0.7 0.7 1.3 1.2
- ----------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION:
Common Shareholders' Equity ........................... 34% 34% 35% 36% 33%
Preferred Stock (b)(d) ................................ 5 6 6 7 9
Long-Term Debt (b) .................................... 61 60 59 57 58
- ----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization .................................. 100% 100% 100% 100% 100%
==================================================================================================================================
</TABLE>
(a) Restated to include the reclassification of the PSNH acquisition costs to
net utility plant.
(b) Includes portions due within one year.
(c) On March 25, 1997, the NU Board of Trustees adopted a resolution suspending
the quarterly dividends on NU's common shares.
(d) Excludes $100 million of Monthly Income Preferred Securities.
48
<PAGE>
CONSOLIDATED SALES STATISTICS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
REVENUES: (thousands)
Residential .................................. $1,475,363 $1,499,394 $1,501,465 $1,469,988 $1,430,239
Commercial ................................... 1,273,146 1,266,449 1,246,822 1,230,608 1,173,808
Industrial ................................... 568,913 560,782 565,900 583,204 559,801
Other Utilities .............................. 336,623 329,764 315,577 303,004 330,801
Streetlighting and Railroads ................. 47,682 48,867 48,053 47,510 45,943
Nonfranchised Sales .......................... 22,479 21,476 8,360 -- --
Miscellaneous ................................ 16,429 47,446 23,513 50,353 44,140
- -------------------------------------------------------------------------------------------------------------------------
Total Electric ........................... 3,740,635 3,774,178 3,709,690 3,684,667 3,584,732
Other ........................................ 27,079 60,628 82,458 65,893 58,010
- -------------------------------------------------------------------------------------------------------------------------
Total .................................... $3,767,714 $3,834,806 $3,792,148 $3,750,560 $3,642,742
=========================================================================================================================
SALES: (kWh - millions)
Residential .................................. 12,162 12,099 12,241 12,005 12,231
Commercial ................................... 12,477 12,091 12,012 11,737 11,649
Industrial ................................... 6,948 6,801 6,820 6,842 6,729
Other Utilities .............................. 9,742 8,034 8,032 8,718 9,123
Streetlighting and Railroads ................. 320 318 319 316 314
Nonfranchised Sales .......................... 193 241 50 -- --
- -------------------------------------------------------------------------------------------------------------------------
Total .................................... 41,842 39,584 39,474 39,618 40,046
=========================================================================================================================
CUSTOMERS: (average)
Residential .................................. 1,555,013 1,535,134 1,532,015 1,526,127 1,513,987
Commercial ................................... 162,500 159,350 157,347 156,652 154,703
Industrial ................................... 7,847 7,804 7,792 7,861 7,813
Other ........................................ 3,890 3,929 3,916 3,878 3,818
- -------------------------------------------------------------------------------------------------------------------------
Total .................................... 1,729,250 1,706,217 1,701,070 1,694,518 1,680,321
=========================================================================================================================
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh) ........................... 7,799 7,898 8,005 7,880(a) 8,152
=========================================================================================================================
AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER ................................. $ 946.80 $ 978.72 $ 980.19 $ 964.88(a) $ 953.23
=========================================================================================================================
AVERAGE REVENUE PER KWH:
Residential .................................. 12.14(cent) 12.39(cent) 12.27(cent) 12.24(cent) 11.69(cent)
Commercial ................................... 10.20 10.47 10.38 10.49 10.08
Industrial ................................... 8.19 8.25 8.30 8.52 8.32
=========================================================================================================================
</TABLE>
(a) Effective January 1, 1996, the amounts shown reflect billed and unbilled
sales. 1995 has been restated to reflect this change.
49
<PAGE>
NORTHEAST UTILITIES SYSTEM OFFICERS* As of March 1, 1999
CHAIRMAN, PRESIDENT AND
CHIEF EXECUTIVE OFFICER
Michael G. Morris
GROUP PRESIDENTS
Bruce D. Kenyon
Generation Group
Hugh C. MacKenzie
Retail Business Group
EXECUTIVE VICE PRESIDENTS
Ted C. Feigenbaum
Nuclear Group
John H. Forsgren
Chief Financial Officer
SENIOR VICE PRESIDENTS
Cheryl W. Grise
Secretary and General Counsel
Leon J. Olivier
Chief Nuclear Officer
Gary D. Simon
Strategy and Development
VICE PRESIDENTS
David B. Amerine
Nuclear Technical Services
David H. Boguslawski
Energy Delivery
Michael H. Brothers
Nuclear Operations
Gregory B. Butler
Governmental Affairs
John T. Carlin
Human Services, Nuclear
Stephen J. Fabiani
Retail Sales and Marketing
Barry Ilberman
Human Resources and General Services
John B. Keane
Administration
Mary Jo Keating
Corporate Communications
Keith R. Marvin
Chief Information Officer
David R. McHale
Treasurer
William J. Nadeau
Fossil/Hydro Engineering and Operations
Raymond P. Necci
Nuclear Oversight and Regulatory Affairs
Thomas W. Philbin
Energy Services
John J. Roman
Controller
Frank C. Rothen
Nuclear Work Services
Frank P. Sabatino
Wholesale Marketing
Lisa J. Thibdaue
Rates, Regulatory Affairs
and Compliance
Dennis E. Welch
Environmental, Safety and Ethics
Roger C. Zaklukiewicz
Transmission and Distribution
ELECTRIC OPERATING COMPANY OFFICERS
William T. Frain, Jr.
President and Chief Operating Officer - PSNH
Robert G. Abair**
Vice President and Chief Administrative Officer - WMECO
Robert J. Kost
Vice President - Western Region - CL&P
Kerry J. Kuhlman
Vice President - Customer Operations - WMECO
Gary A. Long
Vice President - Customer Service and Economic Development - PSNH
Rodney O. Powell
Vice President - Central Region - CL&P
Paul E. Ramsey
Vice President - Customer Operations - PSNH
Richard L. Tower
Vice President - Eastern Region - CL&P
OTHER OFFICER
John P. Stack
Executive Director - Corporate Accounting and Taxes
ASSISTANT CONTROLLERS
Deborah L. Canyock
Management Information and Budgeting Services
Lori A. Mahler
Accounting Services
William J. Starr
Taxes
ASSISTANT TREASURERS
Robert C. Aronson
Treasury Operations
Randy A. Shoop
Finance
ASSISTANT SECRETARIES AND CLERKS
Theresa Hopkins Allsop
Robert A. Bersak - PSNH
O. Kay Comendul
Thomas V. Foley, Clerk - HWP
Patricia A. Wood, Clerk - WMECO
Margaret L. Morton
HEC INC., OFFICERS
Thomas W. Philbin
President
H. Donald Burbank
Vice President - Customer Service
David S. Dayton
Vice President
Linda A. Jensen
Vice President - Finance, Treasurer and Clerk
James B. Redden
Vice President - Operations
* All officers shown are for
Northeast Utilities Service Company,
unless otherwise indicated.
** Mr. Abair will retire effective April 1, 1999.
50
1998 Annual Report
The Connecticut Light and Power Company and Subsidiaries
Index
Contents Page
Consolidated Balance Sheets............................... 2-3
Consolidated Statements of Income......................... 4
Consolidated Statements of Comprehensive Income........... 4
Consolidated Statements of Cash Flows..................... 5
Consolidated Statements of Common Stockholder's Equity.... 6
Notes to Consolidated Financial Statements................ 7
Report of Independent Public Accountants.................. 40
Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 41
Selected Financial Data................................... 53
Statements of Quarterly Financial Data (Unaudited)........ 53
Statistics (Unaudited).................................... 54
Preferred Stockholder and Bondholder Information.......... Back Cover
PART I. FINANCIAL INFORMATION
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
At December 31, 1998 1997
- ----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at original cost:
Electric................................................ $ 6,173,871 $ 6,411,018
Less: Accumulated provision for depreciation......... 2,758,012 2,902,673
------------- -------------
3,415,859 3,508,345
Construction work in progress........................... 83,477 93,692
Nuclear fuel, net....................................... 87,867 135,076
------------- -------------
Total net utility plant............................. 3,587,203 3,737,113
------------- -------------
Other Property and Investments:
Nuclear decommissioning trusts, at market............... 452,755 369,162
Investments in regional nuclear generating
companies, at equity................................... 56,999 58,061
Other, at cost.......................................... 93,864 66,615
------------- -------------
603,618 493,838
------------- -------------
Current Assets:
Cash.................................................... 434 459
Investment in securitizable assets...................... 160,253 205,625
Notes receivable from affiliated companies.............. 6,600 -
Receivables, less accumulated provision for
uncollectible accounts of $300,000 in 1998 and 1997.... 22,186 50,671
Accounts receivable from affiliated companies........... 1,721 3,150
Taxes receivable........................................ 26,478 70,311
Fuel, materials and supplies, at average cost........... 71,982 81,878
Recoverable energy costs, net--current portion.......... - 28,073
Prepayments and other................................... 121,514 79,642
------------- -------------
411,168 519,809
------------- -------------
Deferred Charges:
Regulatory assets (Note 1G)............................. 1,415,838 1,292,818
Unamortized debt expense................................ 19,603 19,286
Other................................................... 12,768 18,359
------------- -------------
1,448,209 1,330,463
------------- -------------
Total Assets........................................ $ 6,050,198 $ 6,081,223
============= =============
</TABLE>
See accompanying notes to consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
At December 31, 1998 1997
- ------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock--$10 par value. Authorized
24,500,000 shares; outstanding 12,222,930
shares................................................... $ 122,229 $ 122,229
Capital surplus, paid in.................................. 664,156 641,333
Retained earnings......................................... 210,108 419,972
Accumulated other comprehensive income.................... 378 -
------------- -------------
Total common stockholder's equity................ 996,871 1,183,534
Preferred stock not subject to mandatory
redemption............................................... 116,200 116,200
Preferred stock subject to mandatory redemption........... 99,539 151,250
Long-term debt............................................ 1,793,952 2,023,316
------------- -------------
Total capitalization............................. 3,006,562 3,474,300
------------- -------------
Minority Interest in Consolidated Subsidiary................ 100,000 100,000
------------- -------------
Obligations Under Capital Leases............................ 68,444 18,042
------------- -------------
Current Liabilities:
Notes payable to banks.................................... 10,000 35,000
Notes payable to affiliated companies..................... - 61,300
Long-term debt and preferred stock--current
portion.................................................. 233,755 23,761
Obligations under capital leases--current
portion.................................................. 94,440 140,076
Accounts payable.......................................... 121,040 124,427
Accounts payable to affiliated companies.................. 32,758 92,963
Accrued taxes............................................. 19,396 33,017
Accrued interest.......................................... 31,409 14,650
Other..................................................... 34,872 23,495
------------- -------------
577,670 548,689
------------- -------------
Deferred Credits:
Accumulated deferred income taxes......................... 1,194,722 1,348,617
Accumulated deferred investment tax credits............... 114,457 127,713
Decommissioning obligation--Millstone 1 (Note 3).......... 560,500 -
Deferred contractual obligations.......................... 277,826 348,406
Other..................................................... 150,017 115,456
------------- -------------
2,297,522 1,940,192
------------- -------------
Commitments and Contingencies (Note 11)
Total Capitalization and Liabilities............. $ 6,050,198 $ 6,081,223
============= =============
</TABLE>
See accompanying notes to consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues................................. $2,386,864 $2,465,587 $2,397,460
----------- ----------- -----------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power..... 887,224 977,543 831,079
Other......................................... 703,971 726,420 727,674
Maintenance...................................... 271,317 355,772 300,005
Depreciation..................................... 216,509 238,667 247,109
Amortization of regulatory assets, net........... 120,884 61,648 57,432
Federal and state income taxes................... (11,642) (59,436) 957
Taxes other than income taxes.................... 170,347 172,592 174,062
----------- ----------- -----------
Total operating expenses................... 2,358,610 2,473,206 2,338,318
----------- ----------- -----------
Operating Income/(Loss)............................ 28,254 (7,619) 59,142
----------- ----------- -----------
Other Income:
Equity in earnings of regional nuclear
generating companies........................... 6,241 5,672 6,619
Millstone 1--unrecoverable costs (Note 1K)....... (143,239) - -
Other, net....................................... (6,075) (1,856) 20,710
Minority interest in income of subsidiary........ (9,300) (9,300) (9,300)
Income taxes..................................... 67,127 7,573 160
----------- ----------- -----------
Other (loss)/income, net................... (85,246) 2,089 18,189
----------- ----------- -----------
(Loss)/income before interest charges...... (56,992) (5,530) 77,331
----------- ----------- -----------
Interest Charges:
Interest on long-term debt....................... 133,192 132,127 127,198
Other interest................................... 5,541 1,940 1,001
----------- ----------- -----------
Interest charges, net...................... 138,733 134,067 128,199
----------- ----------- -----------
Net Loss........................................... $ (195,725) $ (139,597) $ (50,868)
=========== =========== ===========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Loss........................................... $ (195,725) $ (139,597) $ (50,868)
----------- ----------- -----------
Other comprehensive income, net of tax (Note 15):
Unrealized gains on securities..................... 638 - -
Minimum pension liability adjustments.............. (260) - -
----------- ----------- -----------
Other comprehensive income, net of tax........... 378 - -
----------- ----------- -----------
Comprehensive Loss $ (195,347) $ (139,597) $ (50,868)
========== =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities:
Net loss.................................................... $(195,725) $(139,597) $ (50,868)
Adjustments to reconcile to net cash
from operating activities:
Depreciation.............................................. 216,509 238,667 247,109
Deferred income taxes and investment tax credits, net..... (65,689) (10,401) (39,642)
Amortization of deferred demand-side-management costs, net 42,085 38,029 26,941
Amortization/(deferral) of recoverable energy costs....... 30,745 (9,533) (35,567)
Amortization of cogeneration deferral..................... 29,559 37,338 19,221
Amortization of regulatory asset - income taxes........... 66,027 13,927 19,349
Amortization of other regulatory asset ................... 25,298 10,383 18,862
Deferred nuclear refueling outage, net of amortization ... - (45,333) 45,643
Millstone 1--unrecoverable costs.......................... 143,239 - -
Other sources of cash..................................... 82,109 35,065 51,823
Other uses of cash........................................ (23,561) (50,417) (23,862)
Changes in working capital:
Receivables and accrued utility revenues.................. (5,086) 184,223 (22,378)
Fuel, materials and supplies.............................. 9,896 (1,941) (11,455)
Accounts payable.......................................... (63,592) (22,036) 83,951
Accrued taxes............................................. (13,621) 4,310 (23,561)
Sale of receivables and accrued utility revenues.......... 35,000 70,000 -
Investment in securitizable assets........................ 45,372 (205,625) -
Other working capital (excludes cash)..................... 30,097 (74,266) (5,385)
---------- ---------- ----------
Net cash flows from operating activities...................... 388,662 72,793 300,181
---------- ---------- ----------
Financing Activities:
Issuance of long-term debt.................................. - 200,000 222,000
Net (decrease)/increase in short-term debt.................. (86,300) 96,300 (51,750)
Reacquisitions and retirements of long-term debt............ (45,006) (204,116) (14,329)
Reacquisitions and retirements of preferred stock........... (35,711) - -
Cash dividends on preferred stock........................... (14,139) (15,221) (15,221)
Cash dividends on common stock.............................. - (5,989) (138,608)
---------- ---------- ----------
Net cash flows (used for)/from financing activities........... (181,156) 70,974 2,092
---------- ---------- ----------
Investment Activities:
Investment in plant:
Electric utility plant.................................... (132,194) (155,550) (140,086)
Nuclear fuel.............................................. (8,444) (702) 553
---------- ---------- ----------
Net cash flows used for investments in plant............ (140,638) (156,252) (139,533)
Investment in NU system Money Pool.......................... (6,600) 109,050 (109,050)
Investment in nuclear decommissioning trusts................ (54,106) (45,314) (50,998)
Other investment activities, net............................ (26,187) (51,196) (2,625)
Capital contributions from Northeast Utilities.............. 20,000 - -
---------- ---------- ----------
Net cash flows used for investments........................... (207,531) (143,712) (302,206)
---------- ---------- ----------
Net (Decrease)/Increase In Cash For The Period................ (25) 55 67
Cash - beginning of period.................................... 459 404 337
---------- ---------- ----------
Cash - end of period.......................................... $ 434 $ 459 $ 404
========== ========== ==========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized........................ $ 110,119 $ 145,962 $ 114,458
========== ========== ==========
Income taxes................................................ $ (46,747) $ (22,338) $ 77,790
========== ========== ==========
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases............. $ 4,102 $ 2,815 $ 2,855
========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Accumulated
Capital Retained Other
Common Surplus, Earnings Comprehensive
Stock Paid In (a) Income Total
- ----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1996.......... $122,229 $637,981 $ 785,476 $ - $1,545,686
Net loss........................ (50,868) (50,868)
Cash dividends on preferred
stock......................... (15,221) (15,221)
Cash dividends.................. (138,608) (138,608)
Capital stock expenses, net..... 1,676 1,676
--------- --------- ---------- -------------- -----------
Balance at December 31, 1996........ 122,229 639,657 580,779 - 1,342,665
Net loss........................ (139,597) (139,597)
Cash dividends on preferred
stock......................... (15,221) (15,221)
Cash dividends.................. (5,989) (5,989)
Capital stock expenses, net..... 1,676 1,676
--------- --------- ---------- -------------- -----------
Balance at December 31, 1997........ 122,229 641,333 419,972 - 1,183,534
Net loss........................ (195,725) (195,725)
Cash dividends.................. (14,139) (14,139)
Capital stock expenses, net..... 2,764 2,764
Capital contribution from
Northeast Utilities........... 20,000 20,000
Gain on repurchase of preferred
stock......................... 59 59
Other comprehensive income...... 378 378
--------- --------- ---------- -------------- -----------
Balance at December 31, 1998........ $122,229 $664,156 $ 210,108 $ 378 $ 996,871
========= ========= ========== ============== ===========
</TABLE>
(a) The company has dividend restrictions imposed by its long-term debt
agreements. At December 31, 1998, these restrictions totaled approximately
$540 million.
See accompanying notes to consolidated financial statements.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. About The Connecticut Light and Power Company
The Connecticut Light and Power Company (the company or CL&P) and
subsidiaries, Western Massachusetts Electric Company (WMECO), Holyoke
Water Power Company (HWP), Public Service Company of New Hampshire
(PSNH) and North Atlantic Energy Corporation (NAEC) are the operating
subsidiaries comprising the Northeast Utilities system (the NU system)
and are wholly owned by Northeast Utilities (NU).
The NU system furnishes franchised retail electric service in
Connecticut, New Hampshire and western Massachusetts through CL&P,
PSNH and WMECO. NAEC sells all of its entitlement to the capacity
and output of the Seabrook nuclear power plant (Seabrook 1 or
Seabrook) to PSNH under two life-of-unit, full cost recovery
contracts. HWP also is engaged in the production and distribution of
electric power. The NU system also furnishes firm and other
wholesale electric services to various municipalities and other
utilities, and participates in limited retail access programs,
providing off-system retail electric service. The NU system serves
in excess of 30 percent of New England's electric needs and is one of
the 24 largest electric utility systems in the country as measured by
revenues.
NU is registered with the Securities and Exchange Commission (SEC) as
a holding company under the Public Utility Holding Company Act of
1935 (1935 Act). NU and its subsidiaries, including CL&P, are
subject to the provisions of the 1935 Act. Arrangements among the NU
system companies, outside agencies and other utilities covering
interconnections, interchange of electric power and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. CL&P is subject to further
regulation for rates, accounting and other matters by the FERC and/or
applicable state regulatory commissions.
Other wholly owned subsidiaries of NU provide support services for
the NU system companies and, in some cases, for other New England
utilities. Northeast Utilities Service Company (NUSCO) provides
centralized accounting, administrative, information resources,
engineering, financial, legal, operational, planning, purchasing and
other services to the NU system companies. Northeast Nuclear Energy
Company (NNECO) acts as agent for the NU system companies and other
New England utilities in operating the Millstone nuclear generating
facilities. North Atlantic Energy Service Corporation (NAESCO) has
operational responsibilities for Seabrook. In addition, CL&P and
WMECO each have established a special purpose subsidiary whose
business consists of the purchase and resale of receivables.
During the first quarter of 1999, NU established three new
subsidiaries: NU Enterprises, Inc., Northeast Generation Company and
Northeast Generation Services Company. Directly or through multiple
subsidiaries, these entities will engage in a variety of energy-
related activities, including the acquisition and management of non-
nuclear generating plants.
B. Presentation
The consolidated financial statements of CL&P include the accounts of
all wholly owned subsidiaries. Significant intercompany transactions
have been eliminated in consolidation.
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 disclosure of contingent 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.
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
All transactions among affiliated companies are on a recovery of cost
basis which may include amounts representing a return on equity and
are subject to approval by various federal and state regulatory
agencies.
C. New Accounting Standards
The Financial Accounting Standards Board (FASB) issued two new
accounting standards during 1998: Statement of Financial Accounting
Standards (SFAS) 132, "Employers' Disclosures About Pensions and
Other Postretirement Benefits," and SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities."
SFAS 132 revises employers' disclosures about pension and other
postretirement benefit plans, but it does not change the measurement
or recognition of those plans. See Note 9, "Pension Benefits
and Postretirement Benefits Other Than Pensions," for further
information on CL&P's pension and postretirement benefits
disclosures.
SFAS 133 establishes accounting and reporting standards for
derivative instruments and hedging activities. This statement
becomes effective for CL&P on January 1, 2000, and will require
derivative instruments used by CL&P to be recognized on the balance
sheets as assets or liabilities at fair value. CL&P uses derivative
instruments for hedging purposes. The accounting for these hedging
instruments will depend on which hedging classification each
derivative instrument falls under, as defined by SFAS 133, offset
by any changes in the market value of the hedged item. Based on the
derivative instruments which currently are being utilized by CL&P to
hedge some of its fuel price risks, there will be an impact on
earnings upon adoption of SFAS 133 which management cannot estimate
at this time. For further information see Note 12, "Fuel-Price Risk-
Management."
During June 1997, the FASB issued SFAS 131, "Disclosures about
Segments of an Enterprise and Related Information." SFAS 131
determines the standards for reporting and disclosing qualitative and
quantitative information about a company's operating segments. More
specifically, it requires financial information to be disclosed for
segments whose operating results are received by the chief operating
officer for decisions on resource allocation. It also requires
related disclosures about products and services, geographic areas and
major customers. CL&P currently evaluates management performance
using a cost-based budget and the information required by SFAS 131 is
not available.
As a result of the changes the NU system and the industry are
undergoing, the company will implement business segment reporting in
1999. This reporting will provide management with revenue and
expense information at the business segment level. Management has
identified significant segments to include transmission,
distribution, generation-related and energy marketing.
D. Investments and Jointly Owned Electric Utility Plant
Regional Nuclear Generating Companies: CL&P owns common stock of
four regional nuclear generating companies (Yankee companies) which
are accounted for on the equity basis due to CL&P's ability to
exercise significant influence over their operating and financial
policies. CL&P's equity investments and ownership interests in the
Yankee companies at December 31, 1998 are:
(Thousands of Dollars, Except for Percentages)
Connecticut Yankee Atomic
Power Company (CYAPC)............. $36,254 34.5%
Yankee Atomic Electric
Company (YAEC).................... 4,882 24.5
Maine Yankee Atomic Power
Company (MYAPC)................... 10,400 12.0
Vermont Yankee Nuclear
Power Corporation (VYNPC)......... 5,463 9.5
Total Equity Investment............. $56,999
Each Yankee company owns a single nuclear generating unit. YAEC's,
CYAPC's and MYAPC's nuclear power plants were shut down permanently
on February 26, 1992, December 4, 1996, and August 6, 1997,
respectively. For additional information on the Yankee companies,
see Note 3, "Nuclear Decommissioning and Plant Closure Costs."
Millstone: CL&P has an 81 percent joint ownership in both
Millstone 1, a 660-megawatt (MW) nuclear generating unit and
Millstone 2, a 870-MW nuclear generating unit. CL&P has a 52.93
percent joint-ownership interest in Millstone 3, a 1,154-MW nuclear
generating unit. During the third quarter of 1998, management
decided to retire Millstone 1 and prepare for final decommissioning.
For further information on the Millstone 1 closure, see Note 3,
"Nuclear Decommissioning and Plant Closure Costs," and Management's
Discussion and Analysis of Financial Condition and Results of
Operations (MD&A). For further information on Millstone 2 and 3, see
Note 3, "Nuclear Decommissioning and Plant Closure Costs," Note 11C,
"Commitments and Contingencies - Nuclear Performance," and the MD&A.
Seabrook 1: CL&P has a 4.06 percent joint ownership interest in
Seabrook 1, a 1,148-MW nuclear generating unit.
Plant-in-service and the accumulated provision for depreciation for
CL&P's share of the three Millstone units and Seabrook are as
follows:
At December 31,
(Millions of Dollars) 1998 1997
Plant-in-service
Millstone 1.................................. $ - $ 387.7
Millstone 2.................................. 759.3 694.7
Millstone 3.................................. 1,909.4 1,906.9
Seabrook 1................................... 174.3 174.3
Accumulated provision for depreciation
Millstone 1.................................. $ - $ 172.0
Millstone 2.................................. 309.2 249.1
Millstone 3.................................. 609.3 552.7
Seabrook 1................................... 39.3 33.9
CL&P's share of Millstone and Seabrook 1 expenses are included in
operating expenses on the accompanying Consolidated Statements of
Income.
E. Depreciation
The provision for depreciation is calculated using the straight-line
method based on estimated remaining lives of depreciable utility
plant-in-service, adjusted for salvage value and removal costs, as
approved by the appropriate regulatory agency.
Except for major facilities, depreciation rates are applied to the
average plant-in-service during the period. Major facilities are
depreciated from the time they are placed in service. When plant is
retired from service, the original cost of plant, including costs of
removal, less salvage, is charged to the accumulated provision for
depreciation. The costs of closure and removal of non-nuclear
facilities are accrued over the life of the plant as a component of
depreciation. The depreciation rates for the several classes of
electric plant-in-service are equivalent to a composite rate of 3.2
percent in 1998 and 3.8 percent in 1997 and 4.0 percent in 1996. See
Note 3, "Nuclear Decommissioning and Plant Closure Costs," for
information on nuclear decommissioning.
At December 31, 1998 and 1997, the accumulated provision for
depreciation included approximately $47.9 million and $45.8 million,
respectively, accrued for the cost of removal, net of salvage value
for non-nuclear generation property.
F. Revenues
Other than revenues under fixed-rate agreements negotiated with
certain wholesale, commercial and industrial customers and limited
retail access programs, utility revenues are based on authorized
rates applied to each customer's use of electricity. In general,
rates can be changed only through a formal proceeding before the
appropriate regulatory commission. Regulatory commissions also have
authority over the terms and conditions of nontraditional rate making
arrangements. At the end of each accounting period, CL&P accrues an
estimate for the amount of energy delivered but unbilled.
G. Regulatory Accounting and Assets
The accounting policies of CL&P and the accompanying consolidated
financial statements conform to generally accepted accounting
principles applicable to rate-regulated enterprises and reflect the
effects of the ratemaking process in accordance with SFAS 71,
"Accounting for the Effects of Certain Types of Regulation." Assuming
a cost-of-service based regulatory structure, regulators may permit
incurred costs, normally treated as expenses, to be deferred and
recovered through future revenues. Through their actions, regulators
may also reduce or eliminate the value of an asset, or create a
liability. If CL&P was no longer subject to the provisions of SFAS
71, CL&P would be required to write off all of its related regulatory
assets and liabilities unless there is a formal transition plan which
provides for the recovery, through established rates, for the
collection of these costs through a portion of the business which
would remain regulated on a cost-of-service basis. At the time of
transition, CL&P also would be required to determine any impairment
of the carrying costs of deregulated plant and inventory assets.
A restructuring program is being implemented within CL&P's
jurisdiction, however, management continues to believe the
application of SFAS 71 remains appropriate at this time. Once CL&P's
restructuring plan has been formally approved by the appropriate
regulatory agency and management can determine the impacts of
restructuring, CL&P's generation business will no longer be rate
regulated on a cost-of-service basis. The majority of CL&P's
regulatory assets are related to its respective generation business.
Management expects that CL&P's transmission and distribution business
will continue to be rate-regulated on a cost-of-service basis and
restructuring plans will allow for the recovery of regulatory assets
through this portion of the business.
For further information on CL&P's regulatory environment and the
potential impacts of restructuring, see Note 11A, "Commitments and
Contingencies - Restructuring," and the MD&A.
Based on a current evaluation of the various factors and conditions
that are expected to impact future cost recovery, management
continues to believe it is probable that CL&P will recover its
investments in long-lived assets, including regulatory assets.
The components of CL&P's regulatory assets are as follows:
At December 31, 1998 1997
(Thousands of Dollars)
Income taxes, net (Note 1H)................ $ 538,521 $ 709,896
Recoverable energy costs,
net (Note 1I)............................ 102,124 104,796
Deferred demand-side management
costs.................................... 10,014 52,100
Cogeneration costs......................... 5,779 33,505
Unrecovered contractual
obligations (Note 1J).................... 266,992 338,406
Millstone 1 (Note 1K)...................... 442,669 -
Other...................................... 49,739 54,115
$1,415,838 $1,292,818
H. Income Taxes
The tax effect of temporary differences (differences between the
periods in which transactions affect income in the financial
statements and the periods in which they affect the determination of
taxable income) is accounted for in accordance with the ratemaking
treatment of the applicable regulatory commissions. See Note 8,
"Income Tax Expense" for the components of income tax expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, which give
rise to the accumulated deferred tax obligation is as follows:
At December 31, 1998 1997
(Thousands of Dollars)
Accelerated depreciation and other
plant-related differences................ $1,002,725 $1,056,690
Regulatory assets - income tax
gross up................................. 279,823 304,276
Net operating loss carryforwards........... (7,777) (7,670)
Other...................................... (80,049) (4,679)
$1,194,722 $1,348,617
At December 31, 1998, CL&P had a state of Connecticut net operating
loss carryforward of approximately $149 million which can be used
against CL&P and its affiliates' combined Connecticut taxable income
and which if unused, expires in the year 2002.
I. Recoverable Energy Costs
Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed
for its proportionate share of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States
Department of Energy (D&D assessment). The Energy Act requires that
regulators treat D&D assessments as a reasonable and necessary
current cost of fuel, to be fully recovered in rates like any other
fuel cost. CL&P is currently recovering these costs through rates.
As of December 31, 1998, CL&P's total D&D deferrals were approximately
$44.9 million.
CL&P has in place an energy adjustment clause under which fuel prices
above or below base-rate levels are charged or credited to customers.
At December 31, 1998, recoverable energy costs included $78.1 million
of costs previously deferred.
J. Unrecovered Contractual Obligations
Under the terms of contracts with MYAPC, CYAPC and YAEC, the
shareholder-sponsor companies, including CL&P, PSNH and WMECO, are
responsible for their proportionate share of the remaining costs of
the units, including decommissioning. As management expects that the
NU system companies will be allowed to recover these costs from their
customers, the NU system companies have recorded regulatory assets,
with corresponding obligations, on their respective balance sheets.
For further information, see Note 3, "Nuclear Decommissioning and
Plant Closure Costs."
K. Millstone 1
The Millstone 1 regulatory asset includes the recoverable portion of
the undepreciated plant and related balances of approximately $129.5
million, and the regulatory asset associated with the decommissioning
and closure obligation of $313.5 million. See Note 3, "Nuclear
Decommissioning and Plant Closure Costs," for further information.
L. Market Risk-Management Policies
CL&P utilizes swap instruments to hedge well-defined risks associated
with changes in fuel prices. To qualify for hedge treatment, the
underlying hedged item must expose CL&P to risks associated with
market fluctuations and the market-risk management instrument used
must be designated as a hedge and must reduce the company's exposure
to market fluctuations throughout the period.
Amounts receivable or payable under fuel-price management instruments
are recognized in operating expenses when realized. For further
information, see Note 12, "Fuel-Price Risk- Management."
2. LEASES
CL&P finances its nuclear fuel for Millstone 2 and its respective share
of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust
(NBFT) capital lease agreement. This lease agreement has an expiration
date of June 1, 2040. On June 5, 1998, the NBFT issued $180 million
Series G intermediate term notes (ITNs) through a private placement
offering. The five-year notes mature June 5, 2003 and will bear
interest at a rate of 8.59 percent per annum, payable semiannually.
At December 31, 1998, CL&P's capital lease obligation to the NBFT was
approximately $144.8 million.
The permanent shutdown of Millstone 1 in July 1998 afforded the NBFT ITN
holders the right to seek repurchase of a pro rata share of their notes
based upon the stipulated loss value of Millstone 1 fuel compared to the
stipulated loss value of all fuel then under the NBFT, approximately
$80 million. The shutdown also obligates CL&P to pay such amount to
the NBFT under the NBFT lease whether or not any ITN holders request
repurchase. CL&P is seeking consents from the ITN holders to amend this
lease provision so that they will not be obligated to make this payment,
but instead will issue an additional $80 million of collateral first
mortgage bonds in mid-1999.
CL&P makes quarterly lease payments for the cost of nuclear fuel
consumed in the reactors based on a units-of-production method at rates
which reflect estimated kilowatt-hours of energy provided plus financing
costs associated with the fuel in the reactors. Upon permanent
discharge from the reactors, ownership of the nuclear fuel transfers to
CL&P. CL&P also has entered into lease agreements, some of which are
capital leases, for the use of data processing and office equipment,
vehicles, gas turbines, nuclear control room simulators and office
space. The provisions of these lease agreements generally provide for
renewal options.
The following rental payments have been charged to expense:
Year Capital Leases Operating Leases
1998................ $20,494,000 $17,914,000
1997................ 10,457,000 19,749,000
1996................ 17,993,000 22,032,000
Interest included in capital lease rental payments was $14,083,000 in
1998, $9,948,000 in 1997 and $10,144,000 in 1996.
Future minimum rental payments, excluding executory costs such as
property taxes, state use taxes, insurance and maintenance, under long-
term noncancelable leases as of December 31, 1998, are:
Year Capital Leases Operating Leases
(Thousands of Dollars)
1999................ $ 2,900 $22,700
2000................ 2,900 21,200
2001................ 2,900 15,600
2002................ 3,000 6,700
2003................ 3,000 4,200
After 2003.......... 46,200 11,500
Future minimum lease
payments.......... 60,900 $80,900
Less amount
representing
interest.......... 42,859
Present value of
future minimum
lease payments.... 18,041
Present value of
future nuclear
fuel lease
payments.......... 144,843
Present value of
future minimum
lease payments.... $162,884
3. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
Millstone 2 and 3 and Seabrook 1: CL&P's operating nuclear power
plants have service lives that are expected to end during the years
2015 through 2026. Upon retirement, these units must be decommissioned.
Current decommissioning studies concluded that complete and immediate
dismantlement at retirement continues to be the most viable and economic
method of decommissioning the units. Decommissioning studies are
reviewed and updated periodically to reflect changes in decommissioning
requirements, costs, technology and inflation.
The estimated cost of decommissioning CL&P's ownership share of
Millstone 2, in year-end 1998 dollars, is $322.0 million. CL&P's
ownership share of the estimated cost of decommissioning Millstone 3
and Seabrook 1 in year-end 1998 dollars, is $296.2 million and $19.9
million, respectively. Millstone 2 and 3 and Seabrook 1 decommissioning
costs will be increased annually by their respective escalation rates.
Nuclear decommissioning costs are accrued over the expected service
lives of the units and are included in depreciation expense on the
Consolidated Statements of Income. Nuclear decommissioning costs for
these units amounted to $19.1 million in 1998 and $20.0 million each
year in 1997 and 1996. Nuclear decommissioning, as a cost of removal,
is included in the accumulated provision for depreciation on the
Consolidated Balance Sheets. At December 31, 1998 and 1997, the
decommissioning balance in the accumulated reserve for depreciation
amounted to $165.6 million and $146.5 million, respectively.
CL&P has established external decommissioning trusts for its portion of
the costs of decommissioning Millstone 2 and 3. Payments for CL&P's
portion of the cost of decommissioning Seabrook 1 are paid to an
independent decommissioning financing fund managed by the state of New
Hampshire. Funding of the estimated decommissioning costs assumes
levelized collections for the Millstone units and escalated collections
for Seabrook 1 and after-tax earnings on the Millstone and Seabrook
decommissioning funds of approximately 5.5 percent and 6.5 percent,
respectively.
As of December 31, 1998, CL&P collected a total of $162.2 million
through rates toward the future decommissioning costs of its share of
Millstone 2 and 3, of which $142.8 million has been transferred to
external decommissioning trusts. As of December 31, 1998, CL&P paid
approximately $3.0 million into Seabrook 1's external decommissioning
financing fund. Earnings on the decommissioning trusts and financing
fund increase the decommissioning trust balance and the accumulated
reserve for depreciation. Unrealized gains and losses associated with
the decommissioning trusts and financing fund also impact the balance of
the trusts and the accumulated reserve for depreciation. The fair value
of the units in the external decommissioning trusts was $242.2 million
at December 31, 1998.
Changes in requirements or technology, the timing of funding or
dismantling or adoption of a decommissioning method other than immediate
dismantlement would change decommissioning cost estimates and the
amounts required to be recovered. CL&P attempts to recover sufficient
amounts through its allowed rates to cover its expected decommissioning
costs. Only the portion of currently estimated total decommissioning
costs that have been accepted by regulatory agencies is reflected in
CL&P's rates. Based on present estimates and assuming its nuclear units
operate to the end of their respective license periods, CL&P expects
that the decommissioning trusts and financing fund will be substantially
funded when the units are retired from service.
Millstone 1: CL&P's share of the total estimated decommissioning costs
for Millstone 1, which have been updated to reflect the early shutdown
of the unit, are approximately $560.5 million as of December 31, 1998.
The company has recorded the decommissioning and closure obligation as
a liability. Nuclear decommissioning costs for Millstone 1 were $17.3
million in 1998, $17.7 million in 1997 and $17.8 million in 1996.
In February 1999, the DPUC issued a decision on CL&P's rate case filing.
The decision allowed for recovery over a three-year period, without a
return, of $126.0 million of CL&P's remaining investment in Millstone 1.
As a result, CL&P recorded an after-tax loss of approximately $80
million, related to the write down of its investment in Millstone 1.
The decision allowed for the recovery of CL&P's decommissioning and
closure obligations. Accordingly, CL&P recorded a regulatory asset for
its portion of the decommissioning and closure obligation. For further
information on the DPUC decision, see Note 1B, "Commitments and
Contingencies - Rate Matters" and the MD&A.
During 1998, CL&P recorded a loss of approximately $27.9 million related
to the termination of approximately a 4.3 percent entitlement contract
of CL&P's share of Millstone 1, formerly held by the Connecticut
Municipal Electric Energy Cooperative.
CL&P uses external trusts to fund the estimated decommissioning costs of
Millstone 1. As of December 31, 1998, CL&P had collected a total of
$151.7 million through rates toward the future decommissioning costs of
its share of Millstone 1, of which $129.8 million has been transferred
to external decommissioning trusts. At December 31, 1998, the fair
market value of the balance in the external trusts was approximately
$210.5 million.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with
a service life that is expected to end in 2012. CL&P's ownership share
of estimated costs, in year-end 1998 dollars, of decommissioning this
unit is $50.4 million.
At December 31, 1998, the remaining estimated obligation, including
decommissioning, for the Yankee companies' nuclear generating facilities
which have been shut down were:
Total CL&P's
(Thousands of Dollars) Obligation Share
Maine Yankee..................... $715,065 $ 85,808
Connecticut Yankee............... $498,557 $172,002
Yankee Atomic.................... $ 81,699 $ 20,016
For further information on the Yankee companies, see Note 11B,
"Commitments and Contingencies - Rate Matters."
For information on proposed changes to the accounting for
decommissioning, see the MD&A.
4. SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by CL&P
is subject to periodic approval by either the SEC under the 1935 Act or
by the DPUC. SEC authorization allowed CL&P, as of January 1, 1999, to
incur total short-term borrowings up to a maximum of $375 million. In
addition, the charter of CL&P contains preferred stock provisions
restricting the amount of unsecured debt the company may incur. As of
December 31, 1998, CL&P's charter permits CL&P to incur an additional
$466 million of unsecured debt.
Credit Agreements: NU, CL&P and WMECO are parties to a $313.75 million
revolving credit agreement (Credit Agreement). Under the Credit
Agreement amended on September 11, 1998, CL&P and WMECO are able to
borrow, subject to the availability of first mortgage bond collateral,
up to $313.75 million and $150 million, respectively. At December 31,
1998, CL&P and WMECO have issued first mortgage bonds to enable
borrowings under this facility up to a maximum of $225 million and $80
million, respectively. NU, which cannot issue first mortgage bonds,
would be able to borrow up to $50 million if NU consolidated, CL&P and
WMECO each meet certain interest coverage tests for two consecutive
quarters. This requirement for NU has not been met. In addition, CL&P
and WMECO each must meet certain minimum quarterly financial ratios to
access the Credit Agreement. CL&P is currently in the process of
obtaining a waiver of the equity financial ratio requirement for the
quarter ended December 31, 1998. WMECO satisfied these ratios for the
quarter ending December 31, 1998. In connection with obtaining the
waiver for the equity test, NU's participation in the Credit Agreement
will be terminated. The overall limit for all of the borrowing system
companies under the entire Credit Agreement is $313.75 million. The
companies are obligated to pay a facility fee of .50 percent per annum
of each bank's total commitment under the Credit Agreement, which will
expire in November 1999. At December 31, 1998 and 1997, there were $30
million and $50 million, respectively, in borrowings under this Credit
Agreement. Of these amounts, CL&P had $10 million borrowed in 1998 and
$35 million borrowed in 1997.
Under the credit facility discussed above, CL&P may borrow funds on a
short-term revolving basis under its agreement, using either fixed-rate
loans or standby loans. Fixed rates are set using competitive bidding.
Standby loans are based upon several alternative variable rates. The
weighted average annual interest rate on CL&P's notes payable to banks
outstanding on December 31, 1998 and 1997, was 6.53 percent and 6.95
percent, respectively.
Money Pool: Certain subsidiaries of NU, including CL&P, are members of
the Northeast Utilities System Money Pool (Pool). The Pool provides a
more efficient use of the cash resources of the NU system, and reduces
outside short-term borrowings. NUSCO administers the Pool as agent for
the member companies. Short-term borrowing needs of the member
companies are first met with available funds of other member companies,
including funds borrowed by NU parent. NU parent may lend to the Pool
but may not borrow. Funds may be withdrawn from or repaid to the Pool
at any time without prior notice. Investing and borrowing subsidiaries
receive or pay interest based on the average daily Federal Funds rate.
Borrowings based on loans from NU parent, however, bear interest at NU
parent's cost and must be repaid based upon the terms of NU parent's
original borrowing. At December 31, 1998 and 1997, CL&P had no
borrowings and $61.3 million, respectively, of borrowings outstanding
from the Pool. The interest rate on borrowings from the Pool on
December 31, 1998 and 1997 was 5.8 percent, respectively. Maturities of
short-term debt obligations were for periods of three months or less.
For further information on short-term debt, including the ability to
access these agreements, see the MD&A.
5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
December 31, Shares
1998 Outstanding
Redemption December 31, December 31,
Description Price 1998 1998 1997 1996
(Thousands of Dollars)
$1.90 Series of 1947 $52.50 163,912 $ 8,196 $ 8,196 $ 8,196
$2.00 Series of 1947 54.00 336,088 16,804 16,804 16,804
$2.04 Series of 1949 52.00 100,000 5,000 5,000 5,000
$2.06 Series E of 1954 51.00 200,000 10,000 10,000 10,000
$2.09 Series F of 1955 51.00 100,000 5,000 5,000 5,000
$2.20 Series of 1949 52.50 200,000 10,000 10,000 10,000
$3.24 Series G of 1968 51.84 300,000 15,000 15,000 15,000
3.90% Series of 1949 50.50 160,000 8,000 8,000 8,000
4.50% Series of 1956 50.75 104,000 5,200 5,200 5,200
4.50% Series of 1963 50.50 160,000 8,000 8,000 8,000
4.96% Series of 1958 50.50 100,000 5,000 5,000 5,000
5.28% Series of 1967 51.43 200,000 10,000 10,000 10,000
6.56% Series of 1968 51.44 200,000 10,000 10,000 10,000
Total $116,200 $116,200 $116,200
All or any part of each outstanding series of such preferred stock may
be redeemed by CL&P at any time at established redemption prices plus
accrued dividends to the date of redemption.
6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
December 31, Shares
1998 Outstanding
Redemption December 31, December 31,
Description Price* 1998 1998 1997 1996
(Thousands of Dollars)
7.23% Series of 1992 $52.17 1,056,434 $ 52,822 $ 75,000 $ 75,000
5.30% Series of 1993 51.00 1,329,340 66,467 80,000 80,000
119,289 155,000 155,000
Less preferred stock
to be redeemed
within one year...... 395,000 19,750 3,750 -
Total.................. $ 99,539 $151,250 $155,000
*Each of these series is subject to certain refunding limitations
for the first five years after they were issued. Redemption prices
reduce in future years.
The following table details redemption and sinking fund activity for
preferred stock subject to mandatory redemption:
Minimum
Annual
Sinking-Fund Shares Reacquired
Series Requirement 1998 1997 1996
(Thousand of Dollars)
7.23% Series of 1992 (1) $ 3,750 443,566 - -
5.30% Series of 1993 (2) 16,000 270,660 - -
(1) Sinking fund requirements commence September 1, 1998.
(2) Sinking fund requirements commence October 1, 1999.
The minimum sinking-fund provisions of the series subject to mandatory
redemption, for the years 1999 through 2003, aggregate approximately
$19.8 million each year for 1999 through 2002 and $6.2 million for
2003. In case of default on sinking-fund payments, no payments may
be made on any junior stock by way of dividends or otherwise (other
than in shares of junior stock) so long as the default continues.
If CL&P is in arrears in the payment of dividends on any outstanding
shares of preferred stock, CL&P would be prohibited from redeeming
or purchasing less than all of the preferred stock outstanding. All
or part of each of the series named above may be redeemed by CL&P at
any time at established redemption prices plus accrued dividends to
the date of redemption, subject to certain refunding limitations.
7. LONG-TERM DEBT
Details of long-term debt outstanding are:
December 31,
1998 1997
(Thousands of Dollars)
First mortgage bonds:
6 1/2% Series T due 1998.......... $ - $ 20,000
7 1/4% Series VV due 1999.......... 74,000 99,000
5 1/2% Series A due 1999.......... 140,000 140,000
5 3/4% Series XX due 2000.......... 200,000 200,000
7 7/8% Series A due 2001.......... 160,000 160,000
7 3/4% Series C due 2002.......... 200,000 200,000
6 1/8% Series B due 2004.......... 140,000 140,000
7 3/8% Series TT due 2019.......... 20,000 20,000
7 1/2% Series YY due 2023.......... 100,000 100,000
8 1/2% Series C due 2024.......... 115,000 115,000
7 7/8% Series D due 2024.......... 140,000 140,000
7 3/8% Series ZZ due 2025.......... 125,000 125,000
Total 1,414,000 1,459,000
Pollution Control Notes:
Variable rate, due 2016-2022......... 46,400 46,400
Variable tax exempt, due 2028-2031... 377,500 377,500
Fees and interest due for spent
fuel disposal costs (Note 11E)....... 175,022 166,458
Other.................................. 81 86
Less amounts due within one year....... 214,005 20,011
Unamortized premium and discount, net.. (5,045) (6,117)
Long-term debt, net.................. $1,793,953 $2,023,316
Long-term debt and cash sinking-fund requirements on debt outstanding
at December 31, 1998, for the years 1999 through 2002 are approximately
$214.0 million, $200.0 million, $160.0 million, $200.0 million,
respectively, and no requirements for 2003.
All or any part of each outstanding series of first mortgage bonds may
be redeemed by CL&P at any time at established redemption prices plus
accrued interest to the date of redemption, except certain series which
are subject to certain refunding limitations during their respective
initial five-year redemption periods.
Essentially all of CL&P's utility plant is subject to the lien of its
first mortgage bond indenture. As of December 31, 1998 and 1997, CL&P
has secured $369.3 million and $315.5 million, respectively, of
pollution control notes with second mortgage liens on Millstone 1,
junior to the lien of its first mortgage bond indenture. The average
effective interest rate on the variable-rate pollution control notes
ranged from 3.6 percent to 3.7 percent for 1998 and from 3.6 percent to
3.7 percent for 1997.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds with
a bond insurance secured by first mortgage bonds and a liquid facility.
8. INCOME TAX EXPENSE
The components of the federal and state income tax provisions
were(credited)/ charged as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Current income taxes:
Federal....................... $ (9,217) $(53,339) $ 30,650
State......................... (3,863) (3,270) 9,789
Total current............... $(13,080) $(56,609) $ 40,439
Deferred income taxes, net:
Federal....................... (34,880) 8,436 (22,866)
State......................... (17,553) (11,470) (9,409)
Total deferred.............. (52,433) (3,034) (32,275)
Investment tax credits, net..... (13,256) (7,366) (7,367)
Total income tax
(credit)/expense............ $(78,769) $(67,009) $ 797
The components of total income tax expense are classified as
follows:
Income taxes charged to
operating expenses............ $(11,642) $(59,436) $ 957
Other income taxes.............. (67,127) (7,573) (160)
Total income tax
(credit)/expense............ $(78,769) $(67,009) $ 797
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Depreciation, leased nuclear fuel,
settlement credits and
disposal costs................ $ (5,572) $ 11,991 $ 3,981
Energy adjustment clauses....... (24,932) (14,039) (1,654)
Demand-side management.......... (12,474) (12,408) (17,099)
Nuclear plant deferrals......... 674 14,007 (18,861)
Bond redemptions................ 152 (1,339) (1,789)
Contractual settlements......... 1,252 1,754 2,513
Pension accruals................ 8,872 6,524 2,944
State net operating loss
carryforwards................. 1,150 (7,670) -
Millstone revenue out of
rate base..................... (18,080) - -
Other........................... (3,475) (1,854) (2,310)
Deferred income taxes, net...... $(52,433) $ (3,034) $(32,275)
A reconciliation between income tax expense and the expected tax expense
at the applicable statutory rate is as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income... $(96,073) $(72,312) $(18,257)
Tax effect of differences:
State income taxes, net of
federal benefit............. (7,358) (8,966) 248
Depreciation.................. 25,368 18,944 20,470
Amortization of
regulatory assets........... 22,725 3,901 8,601
Investment tax credit
amortization and write off.. (13,256) (7,366) (7,367)
Adjustment for prior years'
taxes....................... (10,991) (10) -
Nondeductible penalties....... 2,551 (82) 717
Other, net.................... (1,735) (1,118) (3,615)
Total income tax
(credits)/expense......... $(78,769) $(67,009) $ 797
9. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system subsidiaries participate in a uniform noncontributory
defined benefit retirement plan covering all regular NU system
employees. Benefits are based on years of service and the employees'
highest eligible compensation during 60 consecutive months of
employment. CL&P's direct portion of the NU system's pension
cost/(credit), part of which was credited to utility plant, approximated
$32.6 million in 1998, ($22.5) million in 1997 and ($8.8) million in
1996.
Currently, CL&P annually funds an amount at least equal to that which
will satisfy the requirements of the Employee Retirement Income Security
Act and the Internal Revenue Code. Pension costs are determined using
market-related values of pension assets.
The NU system's subsidiaries also provide certain health care benefits,
primarily medical and dental, and life insurance benefits through a
benefit plan to retired employees. These benefits are available for
employees retiring from the company who have met specified service
requirements. For current employees and certain retirees, the total
benefit is limited to two times the 1993 per-retiree health care cost.
These costs are charged to expense over the future estimated work life
of the employee. CL&P is funding postretirement costs through external
trusts. CL&P is funding, on an annual basis, amounts that have been
rate-recovered and which also are tax deductible under the Internal
Revenue Code.
Pension and trust assets are invested primarily in domestic and
international equity securities and bonds.
The following table represents the plans' beginning benefit obligation
balance reconciled to the ending benefit obligation balance, beginning
fair value of plan assets balance reconciled to the ending fair value of
plan assets balance and the respective funds' funded status reconciled
to the Consolidated Balance Sheets:
The components of net cost are:
At December 31,
Postretirement
Pension Benefits Benefits
1998 1997 1998 1997
(Thousands of Dollars)
Change in benefit
obligation
Benefit obligation at
beginning of year...........$(531,564) $(514,989) $(126,576) $(137,377)
Service cost................. (9,782) (8,836) (2,006) (1,692)
Interest Cost................ (37,452) (37,938) (9,221) (9,152)
Transfers.................... (6,324) 2,625 - -
Actuarial (loss)/gain........ (12,451) (9,666) (7,703) 8,475
Benefits paid................ 34,900 36,291 11,705 13,170
Curtailments and Settlements. - 949 - -
Benefit obligation at
end of year................$(562,673) $(531,564) $(133,801) $(126,576)
Change in plan assets
Fair value of plan assets at
beginning of year..........$ 846,366 $ 736,448 $ 46,055 $ 38,783
Actual return on plan assets 117,889 148,834 6,143 7,639
Employer contribution........ - - 13,299 12,803
Benefits paid................ (34,900) (36,291) (11,705) (13,170)
Transfers.................... 6,324 (2,625) - -
Fair value of plan assets
at end of year.............$ 935,679 $ 846,366 $ 53,792 $ 46,055
Funded status at
December 31................ 373,006 314,802 (80,009) $ (80,521)
Unrecognized transition
amount..................... (5,525) (6,445) 102,818 110,162
Unrecognized prior service
cost....................... 3,231 3,524 - -
Unrecognized net gain........ (295,763) (269,560) (22,809) (29,641)
Prepaid benefit cost.........$ 74,949 $ 42,321 $ - $ -
The following actuarial assumptions were used in calculating the plans'
year-end funded status:
At December 31,
Postretirement
Pension Benefits Benefits
1998 1997 1998 1997
Discount rate.............. 7.00% 7.25% 7.00% 7.25%
Compensation/
progression rate......... 4.25% 4.25% 4.25% 4.25%
Health care cost
trend rate (a)........... N/A N/A 5.22% 5.76%
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 4.40 percent by 2001.
The components of net periodic benefit cost are:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
1998 1997 1996 1998 1997 1996
(Thousands of Dollars)
Service cost.............. $ 9,782 $ 8,836 $ 9,058 $ 2,006 $ 1,692 $ 2,270
Interest cost............. 37,452 37,938 37,227 9,221 9,152 10,211
Expected return
on plan assets.......... (68,364) (59,608) (52,258) (3,555) (3,132) (981)
Amortization of
unrecognized
transition
obligation/(asset)...... (921) (921) (921) 7,344 7,344 7,344
Amortization of prior
service costs........... 292 292 292 - - -
Amortization of
actuarial (gain)/loss... (10,873) (8,085) (5,062) - - -
Other amortization,
net..................... - - - (1,717) (2,253) (967)
Curtailments and
settlements............. - (949) 2,838 - - -
Net periodic benefit
cost/(credit)........... $32,632 $(22,497) $(8,826) $13,299 $12,803 $17,877
For calculating pension and postretirement benefit costs, the following
assumptions were used:
For the Years Ended December 31,
Postretirement
Pension Benefits Benefits
1998 1997 1996 1998 1997 1996
Discount rate............. 7.25% 7.75% 7.50% 7.25% 7.75% 7.50%
Expected long-term
rate of return.......... 9.50% 9.25% 8.75% N/A N/A N/A
Compensation/
progression rate........ 4.25% 4.75% 4.75% 4.25% 4.75% 4.75%
Long-term rate
of return-
Health assets,
net of tax............ N/A N/A N/A 7.75% 7.50% 5.25%
Life assets............. N/A N/A N/A 9.50% 9.25% 8.75%
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. The effect of changing the
assumed health care cost trend rate by one percentage point in each year
would have the following effects:
One Percentage One Percentage
(Thousands of Dollars) Point Increase Point Decrease
Effect on total service
and interest cost
components............... $ 553 $ (560)
Effect on post-
retirement benefit
obligation............... 7,358 (7,275)
The trust holding the health plan assets is subject to federal income
taxes at a 39.6 percent tax rate.
10. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES
CL&P has entered into an agreement to sell up to $200 million of
undivided ownership interests in eligible customer receivables and
accrued utility revenues (receivables).
CL&P has established a special purpose, wholly owned subsidiary whose
business consists of the purchase and resale of receivables, CL&P
Receivables Corporation (CRC). For receivables sold, CL&P has retained
collection responsibilities as agent for the purchaser under the
company's agreement. As collections reduce previously sold receivables,
new receivables may be sold. At December 31, 1998, approximately $105
million of receivables had been sold to third-party purchasers by CL&P.
All receivables sold to CRC are not available to pay CL&P's creditors.
The receivables are sold to a third-party purchaser with limited
recourse. The sales agreements provide for a formula-based loss reserve
in which additional receivables may be assigned to the third-party
purchaser for costs such as bad debt. The third-party purchaser absorbs
the excess amount in the event that actual loss experience exceeds the
loss reserve. At December 31, 1998, approximately $11.6 million was the
formula-based amount of credit exposure and has been reserved as
collateral by CRC. Historical losses for bad debt for CL&P has been
substantially less.
Concentrations of credit risk to the purchaser under CL&P's agreement
with respect to the receivables are limited due to CL&P's diverse
customer base within its service territory.
11. COMMITMENTS AND CONTINGENCIES
A. Restructuring
During April 1998, the utility restructuring bill was signed into
law by the governor of the state of Connecticut. The legislation
provides for electric utilities, including CL&P, to recover
stranded costs. The legislation also allows for securitization of
generation-related regulatory assets and the costs associated with
renegotiated above-market purchased-power contracts and requires
divestiture of generation-related assets through public auction.
As a result of the restructuring legislation, CL&P will sell non-
nuclear generating assets and purchased-power contracts with
nonutility generators through public auction. CL&P also will
transfer its ownership interests in Millstone 2 and 3 and Seabrook
to a corporate affiliate or division, subject to prior federal
regulatory approvals, which would assume CL&P's responsibilities
related to the plants for the period prior to offering them for the
sale. In February 1999, the DPUC announced the offering for sale
of CL&P's fossil fueled and hydroelectric generating facilities.
Interested parties will be required to submit nonbinding bids by
April 8, 1999. A smaller field of qualified bidders will be
selected to participate in the second round of the auction and will
be invited to submit binding bids. A winning bidder will be chosen
by mid-1999 and the sale will be completed by the end of 1999. At
December 31, 1998, the book value of assets to be auctioned during
1999 was approximately $170 million.
After restructuring is complete, CL&P will be an electric
transmission and distribution company which will continue to
provide transmission and distribution services on a cost-of-service
basis.
Management continues to believe that it is probable that CL&P will
fully recover its prudently incurred costs, including regulatory
assets and stranded investments.
B. Rate Matters
On February 25, 1998, the DPUC issued its decision in CL&P's
Interim Rate case. During the period from March 1, 1998 through
September 28, 1998, rates were charged under an interim rate which
required a $30.5 million annual credit to customer bills to reflect
the removal of Millstone 1 from rates.
During April 1998, the DPUC issued a decision finding Millstone 2
unlikely to restart in 1998 and ordered its removal from rate base
effective May 1, 1998. The DPUC allowed the revenue requirement
reductions related to this decision to be potentially applied
against regulatory asset balances. As a result, there was no
change in rates or CL&P's cash flow from rates. CL&P has accounted
for these reductions as a reserve against revenues until such time
when the regulatory asset balances are reduced. At December 31,
1998, the amount of revenue reductions related to this decision
totaled approximately $36.4 million. The unit will remain out of
rate base until the plant is restarted.
On June 1, 1998, CL&P filed its rate application for a
comprehensive rate proceeding. On February 5, 1999, the DPUC
issued its final decision in CL&P's rate case. The DPUC concluded
that CL&P's annual revenue requirements should be reduced by
approximately $232 million, or 9.68 percent, through a combination
of a 4 percent reduction to CL&P's rates and accelerated
amortization of approximately $136 million of its deferred tax
regulatory asset. The decision is retroactive to September 28,
1998. The retroactive portion of the decision did not require a
base-rate decrease. It resulted in accelerated amortization of the
deferred tax regulatory asset in the amount of $27.6 million. The
decision also resulted in an after-tax write-off of approximately
$80 million related to CL&P's investment in Millstone 1. For
further information, see Note 3, "Nuclear Decommissioning and
Plant Closure Costs," and the MD&A.
FERC: During November 1997, MYAPC filed an amendment to its power
contracts clarifying the obligations of its purchasing utilities
following the decision to cease power production. During January
1998, the FERC accepted the amendments and proposed rates, subject
to a refund. On January 18, 1999, MYAPC filed with the FERC
Administrative Law Judge (ALJ) an Offer of Settlement which if
accepted by the FERC, will resolve all the issues in the FERC
decommissioning rate case proceeding. The settlement provides,
among other things, the following: (1) MYAPC will collect $33.6
million annually to pay for decommissioning and spent fuel; (2) its
return on equity will be set at 6.5 percent; (3) MYAPC is permitted
full recovery of all unamortized investment in MY, including fuel,
and (4) an incentive budget for decommissioning is set at $436.3
million.
During late December 1996, CYAPC filed an amendment to its power
contracts clarifying the obligations of its purchasing utilities
following the decision to cease power production. On February 27,
1997, the FERC accepted CYAPC's contract amendment. The new rates
became effective March 1, 1997, subject to a refund.
On August 31, 1998, the FERC ALJ released an initial decision
regarding the December 1996 filing. The decision contained
provisions which would allow for the recovery, through rates, of
the balance of the NU system companies' net unamortized investment
in CYAPC, which was approximately $51.7 million as of December 31,
1998. The decision also called for the disallowance of the recovery
of a portion of the return on the CY investment. The ALJ's
decision also stated that decommissioning collections should
continue to be based on the previously approved estimate of $309.1
million (in 1992 dollars), with an inflation adjustment of 3.8
percent per year, until a new, more reliable estimate has been
prepared and tested.
During October 1998, CYAPC, CL&P, PSNH and WMECO filed briefs on
exceptions to the ALJ decision. If the initial ALJ decision is
upheld, CYAPC could be required to write off a portion of the
regulatory asset associated with the plant closing.
If upheld, CYAPC's management has estimated the effect of the ALJ
decision on CYAPC's earnings would be approximately $37.5 million,
of which CL&P's share would be approximately $6.4 million. NU
management cannot predict the ultimate outcome of the hearing at
this time, however, management believes that the associated
regulatory assets are probable of recovery.
C. Nuclear Performance
Millstone: The three Millstone units are managed by NNECO. All
three units were placed on the NRC watch list on January 29, 1996.
The units cannot be restarted without appropriate NRC approvals.
Millstone 3 has received these approvals and resumed operation in
July 1998. Restart efforts continue for Millstone 2 and it is
expected to be ready to restart in the spring of 1999. The
estimated replacement power costs are approximately $7 million per
month while Millstone 2 remains out of service. In July 1998,
CL&P and WMECO decided to retire Millstone 1 and prepare for final
decommissioning.
Litigation: Certain of the non-NU joint owners of Millstone 3
have filed demands for arbitration with CL&P and WMECO as well
as lawsuits in Massachusetts Superior Court against NU and its
current and former trustees related to the company's operation of
Millstone 3. The arbitrations and lawsuits seek to recover
compensatory damages in excess of $200 million, together with
punitive damages, treble damages and attorney's fees. Management
cannot estimate the potential outcome of these suits but believes
there is no legal basis for the claims and intends to defend
against them vigorously.
D. Environmental Matters
The NU system is subject to regulation by federal, state and local
authorities with respect to air and water quality, the handling and
disposal of toxic substances and hazardous and solid wastes, and
the handling and use of chemical products. The NU system has an
active environmental auditing and training program and believes
that it is in substantial compliance with current environmental
laws and regulations. However, the NU system is subject to certain
pending enforcement actions and governmental investigations in the
environmental area. Management cannot predict the outcome of these
enforcement actions and investigations.
Environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations
and other facilities. Changing environmental requirements could
also require extensive and costly modifications to CL&P's existing
generating units and transmission and distribution systems, and
could raise operating costs significantly. As a result, CL&P may
incur significant additional environmental costs, greater than
amounts included in cost of removal and other reserves, in
connection with the generation and transmission of electricity and
the storage, transportation and disposal of byproducts and wastes.
CL&P also may encounter significantly increased costs to remedy
the environmental effects of prior waste handling activities. The
cumulative long-term cost impact of increasingly stringent
environmental requirements cannot be estimated accurately.
CL&P has recorded a liability based upon currently available
information for the estimated environmental remediation costs
that it expects to incur. In most cases, additional future
environmental cleanup costs are not reasonably estimable due to
a number of factors, including the unknown magnitude of possible
contamination, the appropriate remediation methods, the possible
effects of future legislation or regulation and the possible
effects of technological changes. At December 31, 1998, the
liability recorded by CL&P for its estimated environmental
remediation costs, not considering any possible recoveries from
third parties, amounted to approximately $8.0 million, within a
range of $8.0 million to $19.3 million.
CL&P has received proceeds from several insurance carriers for
the settlement with certain insurance companies of all past,
present and future environmental matters. As a result of these
settlements, CL&P will retain the risk loss, in part, for some
environmental remediation costs.
CL&P cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought
against it. However, considering known facts, existing laws and
regulatory practices, management does not believe the matters
disclosed above will have a material effect on the NU system's
financial position or future results of operations.
E. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, CL&P must pay the
United States Department of Energy (DOE) for the disposal of
spent nuclear fuel and high-level radioactive waste. The DOE is
responsible for the selection and development of repositories for,
and the disposal of, spent nuclear fuel and high-level radioactive
waste. Fees for nuclear fuel burned on or after April 7, 1983, are
billed currently to customers and paid to the DOE on a quarterly
basis. For nuclear fuel used to generate electricity prior to
April 7, 1983 (prior period fuel), payment must be made prior to
the first delivery of spent fuel to the DOE. Until such payment is
made, the outstanding balance will continue to accrue interest at
the three-month Treasury Bill Yield Rate. At December 31, 1998,
fees due to the DOE for the disposal of prior period fuel were
approximately $175.0 million, including interest costs of $108.5
million.
The DOE was originally scheduled to begin accepting delivery of
spent fuel in 1998. However, delays in identifying a permanent
storage site have continually postponed plans for the DOE's long-
term storage and disposal site. Extended delays or a default by
the DOE could lead to consideration of costly alternatives. The
company has primary responsibility for the interim storage of
its spent nuclear fuel. Adequate storage capacity exists to
accommodate all spent nuclear fuel at Millstone 1. With the
addition of new storage racks, storage facilities for Millstone 3
are expected to be adequate for the projected life of the unit.
With the implementation of currently planned modifications, the
storage facilities for Millstone 2 are expected to be adequate to
accommodate a full-core discharge from the reactor until 2005.
Fuel consolidation, which has been licensed for Millstone 2, could
provide adequate storage capability for its projected life.
Seabrook is expected to have spent fuel storage capacity until at
least 2010. Meeting spent fuel storage requirements beyond these
periods could require new and separate storage facilities, the
costs for which have not been determined.
In November 1997, the U.S. Court of Appeals for the D.C. Circuit
ruled that the lack of an interim storage facility does not excuse
the DOE from meeting its contractual obligation to begin accepting
spent nuclear fuel no later than January 31, 1998. The 1997
ruling by the appeals court said, however, that the 1982 federal
law could not require the DOE to accept waste when it did not have
a suitable storage facility. The court directed the plaintiffs to
pursue relief under the terms of their contracts with the DOE.
Based on this ruling, since the DOE did not take the spent nuclear
fuel as scheduled, it may have to pay contract damages.
In May 1998, the same court denied petitions from 60 states and
state agencies, collectively, and 41 utilities, including the
company, asking the court to compel the DOE to submit a program,
beginning immediately, for disposing of spent nuclear fuel. The
petitions were filed after the DOE defaulted on its January 31,
1998 obligation to begin accepting the fuel. The court directed
the company and other plaintiffs to pursue relief under the terms
of their contracts with the DOE.
In a petition filed in August 1998, the court's May 1998 decision
was appealed to the U.S. Supreme Court. In November 1998, the
Supreme Court declined to review the lower court ruling that said
utilities should go to court and seek monetary damages from the
DOE. The ultimate outcome of this legal proceeding is uncertain at
this time.
F. Nuclear Insurance Contingencies
Under certain circumstances, in the event of a nuclear incident at
one of the nuclear facilities in the country covered by the federal
government's third-party liability indemnification program, an
owner of a nuclear unit could be assessed in proportion to its
ownership interest in each of its nuclear units up to $83.9
million. Payments of this assessment would be limited to $10.0
million in any one year per nuclear incident based upon the owner's
pro rata ownership interest in each of its nuclear units. In
addition, the owner would be subject to an additional 5 percent or
$4.2 million, in proportion to its ownership interests in each of
its nuclear units, if the sum of all claims and costs from any
one nuclear incident exceeds the maximum amount of financial
protection. Based upon its ownership interests in Millstone 1, 2
and 3 and in Seabrook 1, CL&P's maximum liability, including any
additional assessments, would be $192.9 million per incident, of
which payments would be limited to $21.9 million per year. In
addition, through power purchase contracts with VYNPC and CYAPC,
CL&P would be responsible for up to an additional $8.4 million per
incident, of which payments would be limited to $1.0 million per
year.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from
insured occurrences. CL&P is subject to retroactive assessments if
losses exceed the accumulated funds available to the insurer. The
maximum potential assessment against CL&P with respect to losses
arising during the current policy year is approximately $9.5
million under the primary property insurance program.
Insurance has been purchased to cover certain extra costs incurred
in obtaining replacement power during prolonged accidental outages
and the excess cost of repair, replacement or decontamination or
premature decommissioning of utility property resulting from
insured occurrences. CL&P is subject to retroactive assessments if
losses exceed the accumulated funds available to the insurer. The
maximum potential assessments against CL&P with respect to losses
arising during current policy years are approximately $4.6 million
under the replacement power policies and $10.0 million under the
excess property damage, decontamination and decommissioning
policies. The cost of a nuclear incident could exceed available
insurance proceeds.
Insurance has been purchased aggregating $200 million on an
industry basis for coverage of worker claims.
G. Construction Program
The construction program is subject to periodic review and revision
by management. CL&P currently forecasts construction expenditures
of approximately $1.5 billion for the years 1999-2003, including
$231 million for 1999. In addition, CL&P estimates that nuclear
fuel requirements, including nuclear fuel financed through the
NBFT, will be approximately $158.5 million for the years 1999-2003,
including $25.2 million for 1999. See Note 2, "Leases," for
additional information about the financing of nuclear fuel.
H. Long-Term Contractual Arrangements
Yankee Companies: CL&P, WMECO and PSNH rely on VY for
approximately 1.4 percent of their capacity under long-term
contracts. Under the terms of their agreements, the NU system
companies pay their ownership (or entitlement) shares of costs
which include depreciation, operation and maintenance expenses,
taxes, the estimated cost of decommissioning and a return on
invested capital. These costs are recorded as purchased-power
expense and are recovered through the companies' rates. CL&P's
total cost of purchases under contracts with VYNPC amounted to
$15.9 million in 1998, $14.1 million in 1997 and $14.8 million
in 1996.
Nonutility Generators: CL&P has entered into various arrangements
for the purchase of capacity and energy from nonutility generators
(NUGs). These arrangements have terms from 10 to 30 years,
currently expiring in the years 1999 through 2029, and require
CL&P to purchase energy at specified prices or formula rates. For
the 12-month period ending December 31, 1998, approximately 13 percent
of NU system electricity requirements were met by NUGs. CL&P's
total cost of purchases under these arrangements amounted to $290.7
million in 1998, $283.2 million in 1997 and $279.5 million in 1996.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH,
WMECO and HWP have entered into agreements to support transmission
and terminal facilities to import electricity from the Hydro-Quebec
system in Canada. CL&P is obligated to pay, over a 30-year period
ending in 2020, its proportionate share of the annual O&M and
capital costs of these facilities.
Estimated Annual Costs: The estimated annual costs of CL&P's
significant long-term contractual arrangements are as follows:
1999 2000 2001 2002 2003
(Millions of Dollars)
VYNPC $ 17.0 $ 15.8 $ 17.2 $ 17.5 $ 16.3
NUGs 290.3 298.7 292.3 296.1 301.6
Hydro-Quebec 18.3 17.6 17.1 16.7 16.2
12. FUEL-PRICE RISK-MANAGEMENT
CL&P uses swap instruments with financial institutions to hedge against
some of the fuel price risk created by long-term negotiated energy
contracts. These agreements minimize exposure associated with rising
fuel prices by managing a portion of CL&P's cost of producing power for
these negotiated energy contracts. As of December 31, 1998, CL&P had
outstanding agreements with a total notional value of approximately
$422.2 million and a negative mark-to-market position of approximately
$44.9 million.
The terms of the agreements require CL&P to post cash collateral with
its counterparties in the event of negative mark-to-market positions and
lowered credit ratings. The amount of the collateral is to be returned
to CL&P when the mark-to-market position becomes positive, when CL&P
meets specified credit ratings or when an agreement ends and all open
positions are properly settled. At December 31, 1998, cash collateral
in the amount of $45.7 million was posted under these terms. This
amount has been recorded in Other Investments on the accompanying
Consolidated Balance Sheets.
These agreements have been made with various financial institutions,
each of which is rated "A3" or better by Moody's rating group. CL&P
will be exposed to credit risk on its respective market risk management
instruments if the counterparties fail to perform their obligations.
However, management anticipates that the counterparties will be able to
fully satisfy their obligations under the agreements.
13. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
CL&P Capital LP (CL&P LP, a subsidiary of CL&P) had previously issued
$100 million of cumulative 9.3 percent Monthly Income Preferred
Securities (MIPS), Series A. CL&P has the sole ownership interest
in CL&P LP, as a general partner, and is the guarantor of the MIPS
securities. Subsequent to the MIPS issuance, CL&P LP loaned the
proceeds of the MIPS issuance, along with CL&P's $3.1 million capital
contribution, back to CL&P in the form of an unsecured debenture.
CL&P consolidates CL&P LP for financial reporting purposes. Upon
consolidation, the unsecured debenture is eliminated and the MIPS
securities are accounted for as minority interests.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair
value of each of the following financial instruments:
Supplemental Executive Retirement Plan investments: SFAS 115,
"Accounting for Certain Investments in Debt and Equity Securities,"
requires investments in debt and equity securities to be presented at
fair value. As a result of this requirement, the investments having
a cost basis of $5.4 million held for benefit of the Supplemental
Executive Retirement Plan were recorded on the Consolidated Balance
Sheets at their fair market value at December 31, 1998 of $8.7 million.
Nuclear decommissioning trusts: The investments held in the NU system
companies' nuclear decommissioning trusts were adjusted to market by
approximately $110.4 million as of December 31, 1998 and $69.6 million
as of December 31, 1997, with corresponding offsets to the accumulated
provision for depreciation. The amounts adjusted in 1998 and in 1997
represent cumulative net unrealized gains. The cumulative gross
unrealized holding losses were immaterial for both 1998 and 1997.
Preferred stock and long-term debt: The fair value of the NU system's
fixed-rate securities is based upon the quoted market price for those
issues or similar issues. Adjustable rate securities are assumed to have
a fair value equal to their carrying value. The carrying amounts of
CL&P's financial instruments and the estimated fair values are as
follows:
Carrying Fair
At December 31, 1998 Amount Value
(Thousands of Dollars)
Preferred stock not subject
to mandatory redemption.......... $ 116,200 $ 77,217
Preferred stock subject to
mandatory redemption............. 119,289 108,108
Long-term debt -
First mortgage bonds............. 1,414,000 1,421,926
Other long-term debt............. 599,003 601,158
MIPS............................... 100,000 102,000
Carrying Fair
At December 31, 1997 Amount Value
(Thousands of Dollars)
Preferred stock not subject
to mandatory redemption.......... $ 116,200 $ 62,889
Preferred stock subject to
mandatory redemption............. 155,000 135,600
Long-term debt -
First mortgage bonds............. 1,459,000 1,435,772
Other long-term debt............. 590,443 590,443
MIPS............................... 100,000 100,760
The fair values shown above have been reported to meet disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
15. OTHER COMPREHENSIVE INCOME
During 1998, CL&P adopted SFAS 130, "Reporting Comprehensive Income,"
which established standards for reporting and displaying comprehensive
income and its components in a financial statement that is displayed
with the same prominence as other financial statements. During 1997 and
1996, CL&P had no material other comprehensive income items.
The accumulated balance for each other comprehensive income item is as
follows:
Current
December 31, Period December 31,
1997 Change 1998
(Thousands of Dollars)
Unrealized gain on
securities.................. $ - $ 638 $ 638
Minimum pension
liability adjustment........ - (260) (260)
Accumulated other
comprehensive income........ $ - $ 378 $ 378
The changes in the components of other comprehensive income are reported
on the Consolidated Statements of Comprehensive Income net of the
following income tax effects.
1998 1997 1996
(Thousands of Dollars)
Unrealized gain on
securities.................. $(446) $ - $ -
Minimum pension
liability adjustment........ 182 - -
Other comprehensive
income...................... $(264) $ - $ -
To the Board of Directors
of The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The
Connecticut Light and Power Company (a Connecticut corporation and a
wholly owned subsidiary of Northeast Utilities) and subsidiaries as of
December 31, 1998 and 1997, and the related consolidated statements of
income, comprehensive income, common stockholder's equity and cash flows
for each of the three years in the period ended December 31, 1998. 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 in accordance with generally accepted
auditing standards. Those standards 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. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of The
Connecticut Light and Power Company and subsidiaries as of December 31,
1998 and 1997, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 23, 1999
The Connecticut Light and Power Company and Subsidiaries
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This section contains management's assessment of Connecticut Light and
Power's (CL&P or the company) financial condition and the principal factors
having an impact on the results of operations. The company is a wholly-owned
subsidiary of Northeast Utilities (NU). This discussion should be read in
conjunction with the company's consolidated financial statements and
footnotes.
FINANCIAL CONDITION
CL&P's financial outlook improved in 1998 despite reductions in retail rates.
The improved outlook is a result of the successful restart of the Millstone 3
nuclear power plant, significant progress toward the restart of Millstone 2
and significant reductions in operating expenses.
CL&P had a net loss of approximately $196 million in 1998, compared to a net
loss of approximately $140 million in 1997. The greater loss in 1998 was the
result of significant write-offs of the company's investment in the retired
Millstone 1 nuclear power plant and the accelerated amortization of
regulatory assets as ordered by Connecticut regulators in a February 1999
retail rate decision.
Operation and maintenance (O&M) costs at Millstone Station declined to $315
million in 1998 from $440 million in 1997. These decreases were driven
primarily by the decision to retire Millstone 1 and the return to service of
Millstone 3. In addition, total fuel and purchased power costs decreased to
$887 million in 1998 as compared to $977 million in 1997, primarily due to
the restart of Millstone 3.
Total revenues fell 3 percent to $2.39 billion in 1998 from $2.47 billion in
1997. The fall in revenues occurred despite a 2.2 percent increase in retail
kilowatt-hour sales for the year. The lower revenues resulted primarily from
the removal of the Millstone units from the company's retail rate base.
Also offsetting the lower O&M were significant increases in certain noncash
expenses. Primarily as a result of Connecticut regulatory decisions,
amortization of regulatory assets totaled $121 million in 1998, up from $62
million in 1997.
CL&P's ability to improve its financial performance in 1999 will depend
primarily on its success in bringing Millstone 2 back on line, and further
reducing its operating costs to help offset continued downward pressure on
retail revenues. CL&P will continue to be negatively impacted by the $232
million reduction in revenue requirements ordered by Connecticut state
regulators in February 1999.
Restructuring
Although CL&P continues to operate under cost-of-service based regulation,
future rates and the recovery of stranded costs are issues that will be
addressed as restructuring legislation is implemented. Stranded costs are
expenditures or commitments that have been made to meet public service
obligations with the expectation that they would be recovered from customers.
However, under certain circumstances these costs might not be recoverable
from customers in a fully competitive electric utility industry (i.e., the
costs may result in above-market energy prices).
CL&P has exposure to stranded costs for its investments in high-cost nuclear
generating plants, state-mandated purchased-power obligations and significant
regulatory assets. As of December 31, 1998, CL&P's net investment in nuclear
generating plants was approximately $1.9 billion and its regulatory assets
were approximately $1.4 billion. CL&P's financial strength will be
negatively affected if it is unable to recover past investments and
commitments.
In April 1998, Connecticut enacted comprehensive electric utility
restructuring legislation. The act provides for rates to be capped at
December 31, 1996, levels until December 31, 1999. Retail choice will be
phased in over six months beginning January 1, 2000, and will extend to all
retail customers by July 2000. Customers not choosing an alternate supplier
can continue to receive service until January 2004 at a rate that is at least
10 percent less than 1996 rates. The law allows for recovery of all
prudently incurred stranded costs and mandates the functional separation of
competitive and regulated businesses. To qualify for stranded cost recovery,
CL&P must auction off its fossil and hydroelectric generating facilities
prior to January 2000, and its nuclear generating assets prior to January
2004. CL&P also received regulatory approval to auction any of its purchased-
power contracts which cannot be renegotiated by March 1999.
The Connecticut legislation allows the use of securitization after January 1,
2000, to further reduce the costs of the transition to a competitive
marketplace. The use of securitization is limited, however, to non-nuclear
generation-related regulatory assets and costs associated with the
renegotiation of purchased-power contracts. CL&P may not securitize nuclear
stranded costs. The Connecticut Department of Public Utility Control (DPUC)
will initiate an investigation into CL&P's stranded costs in the spring of
1999 with a final decision expected before the end of the year.
As a result of the corporate unbundling and divestiture proposals, CL&P
would redefine itself as a distribution company under the restructuring
legislation, and would provide generation services only to the extent
necessary to provide standard offer, backup and default services as required
by customers who have not chosen an alternate energy supplier.
Rate Matters
In February 1999, the DPUC issued a final order in CL&P's retail rate
proceeding reducing CL&P's revenue requirements by $232 million retroactive
to September 28, 1998. To implement that reduction, the DPUC ordered CL&P to
reduce its retail base rates by approximately $96 million annually and to
increase its amortization of regulatory assets by $136 million annually. The
rate order allowed CL&P to earn a return on equity of 10.3 percent. The DPUC
also said it would allow CL&P to recover only $126 million of its investment
in Millstone 1 undepreciated plant and related assets. As a result of this
decision, CL&P reflected in 1998 a one-time pre-tax charge of $116.5 million
and began amortizing its remaining Millstone 1 investment over three years.
In a February 1998 decision, the DPUC removed Millstone 2 from CL&P's rate
base effective May 1, 1998, and Millstone 3 effective July 1, 1998. On July
18, 1998, Millstone 3 returned to rate base. Millstone 1 previously had been
removed from CL&P's rate base effective March 1, 1998, with customers
receiving a temporary credit of approximately 1.4 percent, or $30 million
annually, on their bills.
The removal of Millstone 2 reduced CL&P's noncash revenues by approximately
$3 million a month. This reduction was increased in the 1999 rate order to
nearly $6.6 million per month to reflect lower fuel costs. Actual fuel costs
are subject to true-up in the Energy Adjustment Clause.
Millstone Nuclear Units
CL&P owns 81.0 percent of Millstone 2 and approximately 52.9 percent of
Millstone 3. CL&P's poor financial performance from 1996 through 1998 was
primarily due to the lengthy outages at Millstone. Costs peaked in 1997 when
replacement power costs and operation and maintenance costs totaled nearly
$730 million. In 1998, Millstone-related costs fell significantly as
Millstone 3 returned to service and Millstone 1 began to prepare for
decommissioning.
After a 27-month outage, Millstone 3 received Nuclear Regulatory Commission
(NRC) permission to restart in June 1998 and reached full power in July. The
unit achieved a capacity factor of approximately 70 percent in 1998 following
its return to service. CL&P's share of the operation, maintenance and
replacement power costs associated with Millstone 3 totaled approximately
$131 million in 1998, down from $241 million in 1997. The unit remains on
the NRC's watch list with a Category 2 designation, which means that it
will continue to be subject to heightened NRC oversight. A refueling and
maintenance outage is scheduled to begin in May 1999.
Millstone 2 remains on the NRC watch list with a Category 3 designation,
meaning that NRC commissioners must formally vote to allow restart.
Key steps before restart include final verification that the unit is in
conformance with its design and licensing basis; that management processes
support safe and conservative operations; and that the employees are
effective at identifying and correcting deficiencies at the unit. Millstone
2 is on schedule for a spring 1999 restart following final NRC review and
approval. Millstone 2's return is expected to restore $6.6 million a month
in noncash revenues to CL&P, reduce fuel and purchased-power expense by
approximately $7 million a month, and significantly reduce the unit's
operation and maintenance expenses, which totaled $178 million in 1998.
In a July 1998 filing with the DPUC, management concluded that Millstone 2
had over $400 million of economic value over the 17 years remaining on its
license life. In its February rate decision, the DPUC concurred that the
unit was economic for customers and ordered it to be restored to CL&P rate
base once it operates at 75 percent or more power for 100 consecutive hours.
Liquidity
CL&P successfully refinanced more than $600 million in expiring debt
obligations and bank commitments in 1998 despite a significant reported
loss. CL&P converted a total of $362 million variable-rate tax exempt debt
to fixed-rate tax exempt debt carrying interest rates of 5.85 to 5.95 percent.
Niantic Bay Fuel Trust (NBFT), which finances CL&P's and WMECO's nuclear fuel
at Millstone, refinanced maturing notes and bank lines through the issuance
of $180 million of five-year 8.59 percent notes. The success in refinancing
CL&P's obligations was due primarily to the progress shown in 1998 by
returning Millstone 3 to service and improved cash flows.
Net cash flows from operations totaled approximately $389 million in 1998, up
sharply from $73 million in 1997. Approximately $208 million of net cash
flow was used for investment activities, including construction expenditures
and investments in nuclear decommissioning trusts, compared with $144 million
in 1997. Another $14 million was used to pay preferred dividends, compared
with $21 million in common and preferred dividends in 1997. The balance of
cash used for financing activities, approximately $167 million, was used to
pay off long-term, short-term debt and preferred stock, a significant shift
from 1997 when net debt and preferred stock levels increased by $92 million.
The return to service of Millstone 3 and resulting reduction in costs
stabilized the NU system's credit ratings in mid-1998 after repeated
downgrades in 1996 and 1997. Moody's Investors Service, which had downgraded
CL&P, WMECO, and NU debt in April 1998, upgraded those same ratings in July
1998 and established a "positive" outlook. Also in July, Standard & Poor's
(S&P) removed the NU system from "CreditWatch--negative" for the first time
in more than two years. In September 1998, S&P upgraded CL&P, WMECO and PSNH
first mortgage bonds.
The rating agency actions also were due in part to the NU system's success in
1998 in maintaining access to its various credit lines. Key covenants on a
$313.75 million revolving credit line primarily serving CL&P and WMECO were
adjusted in the fall. The CL&P rate decision resulted in the need for a
waiver of the revolver's equity test in the fourth quarter, which was
negotiated with banks in March 1999.
The $313.75 million revolving credit line will expire on November 21, 1999.
As of February 23, 1999, CL&P had $165 million outstanding under that line.
CL&P met a $140 million bond maturity on February 1, 1999. Management expects
those borrowings to increase further in the first half of 1999 as CL&P pays
off a $74 million bond issue that matures July 1, 1999.
CL&P has also arranged financing agreements through the sale of its accounts
receivables. CL&P can finance up to $200 million through these facilities.
As of December 31, 1998, CL&P had financed $105 million through its accounts
receivable line.
For additional information on the sales of accounts receivable, see "Notes
to Consolidated Financial Statements," Note 10.
CL&P is party to an operating lease with General Electric Capital Corporation
related to the use of four turbine generators having an installed cost of
approximately $70 million and a stipulated loss value of $59 million. CL&P
must meet certain financial covenants that are substantially similar to the
revolving credit line. CL&P has received a waiver of these tests for the
fourth quarter of 1998 as a result of the CL&P rate decision.
The permanent shutdown of Millstone 1 in July 1998 could require CL&P and
WMECO to immediately repay the NBFT approximately $80 million of capital
lease obligations. CL&P is seeking consents from the note holders to amend
the lease so that they will not be obligated to make this payment. As
consideration for the note holders' consents, the companies intend to issue
an additional $80 million of first mortgage bonds in mid-1999.
Nuclear Decommissioning
The staff of the SEC has questioned certain current accounting practices of
the electric utility industry, regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating units in the
financial statements. In response to these questions, the Financial
Accounting Standards Board (FASB) had agreed to review the accounting for
closure and removal costs, including decommissioning. If current electric
utility industry accounting practices for nuclear power plant decommissioning
are changed, the annual provision for decommissioning could increase relative
to 1998, and the estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation), with recognition of an
increase in the cost of the related nuclear power plant. As management
believes decommissioning costs will continue to be recovered through rates,
changes to the accounting will not affect net income.
Millstone 1
CL&P has an ownership interest of 81 percent in Millstone 1. Based on a
continued unit operation study filed with the DPUC in July 1998, CL&P and
WMECO decided to retire Millstone 1 and begin decommissioning activities.
Subsequently, Millstone 1 was removed from the NRC's watch list.
CL&P's share of the total estimated decommissioning costs for Millstone 1,
which have been updated to reflect the early shutdown of the unit, is
approximately $560.5 million in December 1998 dollars. CL&P uses external
trusts to fund the decommissioning costs. In 1998, CL&P recorded a charge of
approximately $143.2 million for the write-off of its investment in Millstone
1 as a result of the February 1999 rate decision and an earlier settlement
with the Connecticut Municipal Electric Energy Cooperative (CMEEC). At
December 31, 1998, CL&P had unrecovered plant and related assets for
Millstone 1 of $129.5 million and an unrecovered decommissioning obligation
of $313.5 million. These amounts have been recorded as a regulatory asset,
while decommissioning and closure obligations have been recorded as a
liability. CL&P has been allowed to recover its remaining investment in
Millstone 1 over three years beginning October 1998. The rate decision also
stated that CL&P would be allowed to recover its decommissioning costs and
could defer pre-decommissioning costs commencing July 1, 1999 for future
recovery.
Yankee Companies
CL&P has a 34.5 percent ownership interest in the Connecticut Yankee Atomic
Power Company (CYAPC), a 24.5 percent ownership interest in Yankee Atomic
Electric Company (YAEC), a 12 percent ownership interest in Maine Yankee
Atomic Power Company (MYAPC) and a 9.5 percent ownership interest in Vermont
Yankee Nuclear Power Corporation (VYNPC). The nuclear plants owned by YAEC,
CYAPC and MYAPC were shut down permanently on February 26, 1992, December 4,
1996, and August 6, 1997, respectively.
At December 31, 1998, CL&P's share of its estimated remaining contract
obligations, including decommissioning, amounted to approximately $277.8
million; $20.0 million for YAEC, $172.0 million for CYAPC and $85.8 million
for MYAPC. Under the terms of the contracts with the Yankee companies, CL&P
is responsible for its proportionate share of the costs of the units
including decommissioning. Management expects to recover these costs from
customers. Accordingly, CL&P has recognized these costs as a regulatory
asset, with a corresponding obligation on its balance sheet.
CL&P has exposure for its investment in CYAPC as a result of an initial
decision at the Federal Energy Regulatory Commission (FERC). Additionally,
in January 1999, MYAPC filed an offer of settlement which, if accepted by the
FERC, will resolve all the issues in the FERC decommissioning rate case
proceeding. CL&P management cannot predict the ultimate outcome of the FERC
proceedings at this time, but believes that the associated regulatory assets
are probable of recovery. For further information on these proceedings see
"Notes to Consolidated Financial Statements," Note 11B.
CL&P's ownership share of the estimated costs of decommissioning the nuclear
plant owned by VYNPC is approximately $50.4 million in year-end 1998 dollars.
Millstone 2, 3 and Seabrook 1
CL&P's estimated cost to decommission its shares of Millstone 2, Millstone 3
and Seabrook 1 is approximately $638 million in year-end 1998 dollars. These
costs are being recognized over the lives of the respective units with a
portion currently being recovered through rates. As of December 31, 1998,
the market value of the contributions already made to the decommissioning
trusts, including their investment returns, was approximately $242 million.
See the "Notes to Consolidated Financial Statements," Note 3, for further
information on nuclear decommissioning.
Year 2000 Issues
The NU system has established an action plan by which identified processes
must be completed by certain dates in order to ensure its operating systems,
including nuclear systems, and reporting systems are able to properly
recognize the year 2000. This action plan has three phases: the inventory
phase, the detailed assessment phase and the remediation phase. The inventory
phase, which has been completed, identified operating and reporting systems
which may need to be fixed. The detailed assessment phase, which has been
completed, determined exactly what needed to be done in order to ensure that
the systems identified during the inventory phase are able to recognize
properly and process the year 2000. The final phase is the remediation phase.
By the end of this phase, mission critical systems (systems that are
related to safety, keeping the lights on, regulatory requirements, and other
systems that could have a significant financial impact) will be year 2000
ready; that is, these systems will perform their business functions properly
in the year 2000. This phase includes making modifications, testing and
validating changes and verifying that the year 2000 issues have been
resolved.
Although the identification and detailed assessment phases are complete,
newly identified items, such as new software purchases, are added to the
inventory as they are identified and are subject to detailed assessment and,
if needed, remediation. The NU system purchasing policies require newly
purchased software and devices to be year 2000 compliant. None of these
newly identified items are expected to materially impact completion of the
remediation phase.
The NU system has identified and inventoried 2,497 computer systems
(software) and over 24,000 devices (hardware) broken down into 3,450
device types containing date-sensitive computer chips. As of December 31,
1998, 73 percent of the software systems and 81 percent of the hardware
were year 2000 ready.
The remaining items are in various stages of modification or testing.
Management anticipates the remediation phase for mission critical systems
to be completed by mid-1999.
In addition, the NU system has been contacting its key suppliers and
business partners to determine their ability to manage the year 2000
problem successfully. The NU system is adjusting its inventories, working
with suppliers to provide backup inventories, and changing suppliers as
needed to provide for an adequate supply of materials needed to conduct
business into the year 2000.
The NU system also has worked actively with the Independent System Operator
(ISO) New England, the operator of the New England power grid and with the
North American Electric Reliability Council to provide for the year 2000
readiness of the New England power grid.
The NU system has utilized both internal and external resources to identify,
assess, test and reprogram or replace the computer systems for year 2000
readiness. The current projected total cost of the Year 2000 Program to the
NU system is $30 million. The total estimated remaining cost is $18 million,
which is being funded through operating cash flows. The majority of these
costs will be expensed as incurred in 1999. Since 1996, the NU system has
incurred and expensed approximately $12 million related to year 2000
readiness efforts. Total expenditures related to the year 2000 are not
expected to have a material effect on the operations or financial condition
of the NU system.
The costs of the project and the date on which the NU system plans to
complete the year 2000 modifications are based on management's best
estimates, which were derived utilizing numerous assumptions of future
events, including the continued availability of certain resources, third-
party modification plans and other factors. However, there can be no
guarantee that these estimates will be achieved, and actual results could
differ materially from those plans. If the NU system's remediation plans or
those of third parties are not successful, there could be a significant
disruption of the NU system's operations. The most likely worst case
scenario is a limited number of localized interruptions to electric service
which can be restored within a few hours. As a precautionary measure, the
NU system is formulating contingency plans that will evaluate alternatives
that could be implemented if our remediation efforts are not successful.
The contingency plans are being developed by enhancing existing emergency
operating procedures to include year 2000 issues. In addition, the NU system
plans to have staff available to respond to any year 2000 situations that
might arise. The contingency plan is expected to be available by July 30,
1999.
The NU system is committed to assuring that adequate resources are available
in order to implement any changes necessary for its nuclear and other
operations to be compatible with the new millennium.
Risk-Management Instruments
The following discussion about CL&P's risk-management activities includes
forward looking statements that involve risks and uncertainties. Actual
results could differ materially from those projected in the forward looking
statements.
This analysis presents the hypothetical loss in earnings related to the fuel
price and interest rate market risks at December 31, 1998. CL&P uses swaps
to manage the market risk exposures associated with changes in fuel prices
and variable interest rates. CL&P uses these instruments to reduce risk by
essentially creating offsetting market exposures. Based on the derivative
instruments which are currently being utilized by CL&P to hedge some of
their fuel price and interest rate risks, there will be an impact on
earnings upon adoption of Statement of Financial Accounting Standards
No. 133, Accounting for Derivative Instruments and Hedging Activities,
which management cannot estimate at this time. For more information on
CL&P's use of risk-management instruments, see the "Notes to Consolidated
Financial Statements," Notes 1L and 12.
Fuel-Price Risk-Management Instruments
In the generation of electricity, the most significant segment of the
variable cost component is the cost of fuel. Typically, most of CL&P's
fuel purchases are protected by a regulatory fuel price adjustment clause.
However, for a specific, well-defined volume of fuel that is excluded from
the fuel price adjustment clause, CL&P employs fuel-price risk-management
instruments to protect itself against the risk of rising fuel prices, thereby
limiting fuel costs and protecting its profit margins. These risks are
primarily created by the sale of long-term, fixed-price electricity
contracts to wholesale customers.
At December 31, 1998, CL&P had outstanding fuel-price management instrument
agreements with a total notional value of approximately $422 million and
a negative mark-to-market position of approximately $45 million. A
hypothetical 10 percent decrease in average 1998 fuel prices during 1999
may result in a $10 million decrease in the fair value of the fuel-price
risk-management instruments. Because these instruments are used to hedge
the fuel price risk created by the sale of long-term, fixed-price electricity
contracts, it is expected that the hypothetical decrease in fuel prices
during 1999 would result in a corresponding increase in the fair value of
these contracts.
This analysis is based on the assumption that the amount of fuel-price risk-
management instruments and the amount of long-term fixed-price electricity
sales contracts to wholesale customers will not fluctuate during 1999. This
analysis is subject to change as these assumptions change.
Environmental Matters
CL&P is potentially liable for environmental cleanup costs at a number of
sites inside and outside its service territory. To date, the future estimated
environmental remediation liability has not been material with respect to the
earnings or financial position of CL&P. CL&P had recorded an environmental
reserve of approximately $8.0 and $6.4 million, at December 31, 1998 and
1997, respectively. See the "Notes to Consolidated Financial Statements,"
Note 11D, for further information on environmental matters.
RESULTS OF OPERATIONS
Income Statement Variances
(Millions of Dollars)
1998 over/(under) 1997 1997 over/(under) 1996
Amount Percent Amount Percent
Operating revenues $(79) (3)% $ 68 3%
Fuel, purchased and net
interchange power (90) (9) 146 18
Other operation (22) (3) (1) -
Maintenance (84) (24) 56 19
Depreciation (22) (9) (8) (3)
Amortization of regulatory
assets, net 59 96 4 7
Federal and state income
taxes (12) (18) (68) (a)
Millstone 1 unrecoverable
costs (143) (100) - -
Other income, net (4) (a) (16) (89)
Net loss (56) (40) (89) (a)
(a) Percentage greater than 100.
Operating Revenues
The removal of the Millstone units from CL&P's rate base reduced revenues by
$68 million in 1998. Wholesale revenues decreased by $33 million primarily
as a result of the terminated contract with CMEEC. These decreases were
partially offset by higher retail sales volumes. Retail kilowatt-hour sales
were 2.2 percent higher and contributed $36 million to nonfuel revenues in
1998 primarily as a result of economic growth.
Total operating revenues increased in 1997, primarily due to higher fuel
recoveries and higher conservation recoveries. Fuel recoveries increased $33
million, primarily due to higher fuel revenues as a result of a lower fuel
rate in 1996. Conservation recoveries increased by $17 million, primarily due
to a 1996 reserve for overrecoveries of demand-side management costs.
Fuel, Purchased and Net Interchange Power
The change in fuel, purchased and net interchange power expense in 1998 is
primarily due to lower replacement power costs due to the return to service
of Millstone 3.
Fuel, purchased and net interchange power expense increased in 1997,
primarily due to replacement power costs associated with the Millstone
outages.
Other Operation and Maintenance
Other operation and maintenance expenses decreased in 1998, primarily due
to lower costs at the Millstone nuclear units ($125 million), lower costs
at the Yankee nuclear units ($21 million), lower administrative and general
expenses ($12 million), the recognition of environmental insurance proceeds
($9 million), lower distribution costs ($8 million), a decrease in sales and
marketing expenses ($8 million), and lower costs from ISO New England for
interchange services ($7 million). These decreases were partially offset
by higher capacity charges ($51 million) and the recognition of nuclear
refueling outage costs primarily as a result of the 1996 Rate Settlement
($34 million).
Other operation and maintenance expenses increased in 1997, primarily due to
higher costs associated with the Millstone restart effort ($173 million) and
higher charges from MYAPC ($9 million), partially offset by lower recognition
of nuclear refueling outage costs primarily as a result of the 1996 Rate
Settlement ($72 million), lower capacity charges from CYAPC as a result of a
property tax refund ($27 million), lower administrative and general expenses
($23 million) primarily due to lower pensions and benefit costs, and lower
storm expenses.
Depreciation
Depreciation decreased in 1998, primarily due to the retirement of Millstone 1.
Depreciation decreased in 1997, primarily due to lower depreciation rates
partially offset by higher plant balances.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased in 1998, primarily due to
accelerated amortizations in accordance with retail regulatory decisions and
the beginning of the amortization of the Millstone 1 remaining investment.
Amortization of regulatory assets, net increased in 1997, primarily due to
the completion of cogeneration deferrals in 1996 and increased amortization
in 1997, partially offset by the completion of CL&P's Seabrook amortization
in 1996.
Federal and State Income Taxes
Federal and state income taxes decreased in 1998 primarily due to lower book
taxable income and the increase in income tax credits due to the Millstone 1
write off.
Federal and state income taxes decreased in 1997 primarily due to lower book
taxable income.
Millstone 1 Unrecoverable Costs
Millstone 1 unrecoverable costs represents the write-off of the Millstone 1
entitlement formerly held by CMEEC and the write-off of unrecoverable costs
as a result of the February 1999 rate decision.
Other Income, Net
The change in other income, net in 1998 was not significant. Other income,
net decreased in 1997, primarily due to costs associated with the sale of
accounts receivable facility and lower miscellaneous income.
The Connecticut Light and Power Company and Subsidiaries
SELECTED FINANCIAL DATA(a)
1998 1997 1996 1995 1994
(Thousands of Dollars)
Operating Revenues....$2,386,864 $2,465,587 $2,397,460 $2,387,069 $2,328,052
Operating Income/
(Loss).............. 28,254 (12,399) 29,773 324,026 286,948
Net (Loss)/Income..... (195,725) (144,377) (80,237) 205,216 198,288
Cash Dividends on
Common Stock........ - 5,989 138,608 164,154 159,388
Total Assets.......... 6,050,198 6,081,223 6,244,036 6,045,631 6,217,457
Long-Term Debt (c).... - 2,043,327 2,038,521 1,822,018 1,823,690
Preferred Stock Not
Subject to Mandatory
Redemption.......... 116,200 116,200 116,200 116,200 166,200
Preferred Stock
Subject to Mandatory
Redemption(c)....... 119,289 155,000 155,000 155,000 230,000
Obligations Under
Capital Leases(c)... 162,884 158,118 155,708 172,264 175,969
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
Quarter Ended(a)
1998 March 31 June 30 September 30 December 31
(Thousands of Dollars)
Operating Revenues $608,961 $561,224 $628,148 $ 588,531
Operating Income/(Loss) $ 6,261 $ 11,066 $ 29,945 $ (19,018)
Net Loss $(30,979) $(26,361) $(20,405) $(117,980)
1997
Operating Revenues $624,908 $574,841 $627,712 $638,126
Operating Income/(Loss) $ 23,148 $(33,587) $(15,552) $ 13,592
Net Loss $ (6,431) $(64,089) $(50,077) $(23,780)
(a) Reclassifications of prior data have been made to conform with the current
presentation.
(b) Includes the cumulative effect of change in accounting for municipal
property tax expense, which increased earnings for common shares by
$47.7 million.
(c) Includes portion due within one year.
The Connecticut Light and Power Company and Subsidiaries
STATISTICS (Unaudited)
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions) Customer (kWh) (Average) (December 31)
1998 $6,345,215 27,356 8,476 1,113,370 2,336
1997 6,639,786 26,766 8,526 1,103,309 2,163
1996 6,512,659 26,043 8,639 1,099,340 2,194
1995 6,389,190 26,366 8,506(a) 1,094,527 2,270
1994 6,327,967 26,975 8,775 1,086,400 2,587
(a) Effective January 1, 1996, the amounts shown reflect billed and
unbilled sales. 1995 has been restated to reflect this change.
1998 Annual Report
Western Massachusetts Electric Company and Subsidiary
Index
Contents Page
Consolidated Balance Sheets..................................... 2-3
Consolidated Statements of Income............................... 4
Consolidated Statements of Comprehensive Income................. 4
Consolidated Statements of Cash Flows........................... 5
Consolidated Statements of Common Stockholder's Equity.......... 6
Notes to Consolidated Financial Statements...................... 7
Report of Independent Public Accountants........................ 36
Management's Discussion and Analysis of Financial
Condition and Results of Operations........................... 37
Selected Financial Data......................................... 45
Statements of Quarterly Financial Data (Unaudited).............. 45
Statistics (Unaudited).......................................... 46
Preferred Stockholder and Bondholder Information................ Back Cover
PART I. FINANCIAL INFORMATION
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
AT DECEMBER 31, 1998 1997
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at original cost:
Electric................................................ $ 1,221,257 $ 1,284,288
Less: Accumulated provision for depreciation......... 517,401 559,119
------------- ------------
703,856 725,169
Construction work in progress........................... 14,858 19,038
Nuclear fuel, net....................................... 19,931 30,907
------------- ------------
Total net utility plant............................. 738,645 775,114
------------- ------------
Other Property and Investments:
Nuclear decommissioning trusts, at market............... 125,598 102,708
Investments in regional nuclear generating
companies, at equity................................... 15,440 15,741
Other, at cost.......................................... 7,322 4,900
------------- ------------
148,360 123,349
------------- ------------
Current Assets:
Cash.................................................... 106 105
Investments in securitizable assets..................... 21,865 25,280
Receivables, less accumulated provision for
uncollectible accounts of $50,000 in 1998 and 1997.... 862 2,739
Accounts receivable from affiliated companies........... 4,188 3,933
Taxes receivable........................................ 14,255 10,768
Fuel, materials and supplies, at average cost........... 5,053 5,860
Recoverable energy costs, net--current portion.......... 1,924 -
Prepayments and other................................... 23,996 14,945
------------- ------------
72,249 63,630
------------- ------------
Deferred Charges:
Regulatory assets (Note 1G)............................. 322,435 211,377
Unamortized debt expense................................ 2,298 2,695
Other................................................... 3,695 2,963
------------- ------------
328,428 217,035
------------- ------------
Total Assets........................................ $ 1,287,682 $ 1,179,128
============= ============
</TABLE>
See accompanying notes to consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
AT DECEMBER 31, 1998 1997
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock--$25 par value.
Authorized and outstanding 1,072,471 shares............ $ 26,812 $ 26,812
Capital surplus, paid in................................ 151,431 151,171
Retained earnings....................................... 46,003 58,608
Accumulated other comprehensive income.................. 150 -
------------- ------------
Total common stockholder's equity.............. 224,396 236,591
Preferred stock not subject to mandatory redemption..... 20,000 20,000
Preferred stock subject to mandatory redemption......... 18,000 19,500
Long-term debt.......................................... 349,314 386,849
------------- ------------
Total capitalization........................... 611,710 662,940
------------- ------------
Obligations Under Capital Leases.......................... 12,129 217
------------- ------------
Current Liabilities:
Notes payable to banks.................................. 20,000 15,000
Notes payable to affiliated companies................... 30,900 14,350
Long-term debt and preferred stock--current
portion................................................ 41,500 11,300
Obligations under capital leases--current
portion................................................ 21,964 32,670
Accounts payable........................................ 17,952 30,571
Accounts payable to affiliated companies................ 12,866 21,209
Accrued taxes........................................... 1,264 522
Accrued interest........................................ 8,030 3,318
Other................................................... 6,831 2,446
------------- ------------
161,307 131,386
------------- ------------
Deferred Credits:
Accumulated deferred income taxes....................... 248,985 246,453
Accumulated deferred investment tax credits............. 21,895 23,364
Decommissioning obligation--Millstone 1 (Note 2)........ 131,500 -
Deferred contractual obligations........................ 74,534 93,628
Other................................................... 25,622 21,140
------------- ------------
502,536 384,585
------------- ------------
Commitments and Contingencies (Note 11)
Total Capitalization and Liabilities........... $ 1,287,682 $ 1,179,128
============= ============
</TABLE>
See accompanying notes to consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1998 1997 1996
- --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues............................. $ 393,322 $426,447 $421,337
---------- --------- ---------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power. 113,148 140,976 115,691
Other..................................... 134,916 153,399 136,897
Maintenance.................................. 56,622 81,466 56,201
Depreciation................................. 40,901 39,753 39,710
Amortization of regulatory assets............ 6,016 6,428 9,170
Federal and state income taxes............... 2,109 (15,142) 10,628
Taxes other than income taxes................ 19,756 19,316 19,850
---------- --------- ---------
Total operating expenses............... 373,468 426,196 388,147
---------- --------- ---------
Operating Income............................... 19,854 251 33,190
---------- --------- ---------
Other Income:
Equity in earnings of regional nuclear
generating companies....................... 1,699 1,524 1,800
Other, net................................... (1,905) (1,106) 1,153
Income taxes................................. 2,198 1,026 1,068
---------- --------- ---------
Other income, net...................... 1,992 1,444 4,021
---------- --------- ---------
Income before interest charges......... 21,846 1,695 37,211
---------- --------- ---------
Interest Charges:
Interest on long-term debt................... 28,027 26,046 24,094
Other interest............................... 3,398 3,109 2,028
---------- --------- ---------
Interest charges, net.................. 31,425 29,155 26,122
---------- --------- ---------
Net (Loss)/Income.............................. $ (9,579) $(27,460) $ 11,089
========== ========= =========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net (Loss)/Income.............................. $ (9,579) $(27,460) $ 11,089
---------- --------- ---------
Other comprehensive income, net of tax:
Unrealized gains on securities................. 183 - -
Minimum pension liability adjustments.......... (33) - -
---------- --------- ---------
Other comprehensive income, net of tax...... 150 - -
---------- --------- ---------
Comprehensive (Loss)/Income.................... $ (9,429) $(27,460) $ 11,089
========== ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities:
Net (Loss)/Income........................................... $ (9,579) $ (27,460) $ 11,089
Adjustments to reconcile to net cash
from operating activities:
Depreciation.............................................. 40,901 39,753 39,710
Deferred income taxes and investment tax credits, net..... 7,405 (1,256) 1,194
Amortization of regulatory assets - income taxes.......... 2,657 5,452 2,917
Amortization of other regulatory assets................... 3,359 976 6,253
Other sources of cash..................................... 14,395 22,011 7,749
Other uses of cash........................................ (11,809) (21,215) (10,270)
Changes in working capital:
Receivables and accrued utility revenues.................. 1,622 29,415 (1,853)
Fuel, materials and supplies.............................. 807 (543) (203)
Accounts payable.......................................... (20,962) 4,826 20,875
Sale of receivables and accrued utility revenues, net..... - 20,000 -
Investment in securitizable assets........................ 3,415 (25,280) -
Accrued taxes............................................. 742 (2,137) (805)
Other working capital (excludes cash)..................... (3,441) (16,882) (8,144)
----------- ----------- -----------
Net cash flows from operating activities...................... 29,512 27,660 68,512
----------- ----------- -----------
Financing Activities:
Issuance of long-term debt.................................. - 60,000 -
Net increase/(decrease) in short-term debt.................. 21,550 (18,050) 23,350
Reacquisitions and retirements of long-term debt............ (9,800) (14,700) -
Reacquisitions and retirements of preferred stock........... (1,500) - (36,500)
Cash dividends on preferred stock........................... (3,026) (3,140) (5,305)
Cash dividends on common stock.............................. - (15,004) (16,494)
----------- ----------- -----------
Net cash flows from/(used for) financing activities........... 7,224 9,106 (34,949)
----------- ----------- -----------
Investment Activities:
Investment in plant:
Electric utility plant.................................... (19,895) (26,249) (23,468)
Nuclear fuel.............................................. (1,801) (8) 541
----------- ----------- -----------
Net cash flows used for investments in plant............ (21,696) (26,257) (22,927)
Investment in nuclear decommissioning trusts................ (12,918) (9,645) (9,794)
Other investment activities, net............................ (2,121) (826) (977)
----------- ----------- -----------
Net cash flows used for investments........................... (36,735) (36,728) (33,698)
----------- ----------- -----------
Net Increase/(Decrease) In Cash For The Period................ 1 38 (135)
Cash - beginning of period.................................... 105 67 202
----------- ----------- -----------
Cash - end of period.......................................... $ 106 $ 105 $ 67
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized........................ $ 22,902 $ 28,711 $ 21,725
=========== =========== ===========
Income taxes................................................ $ (2,624) $ (1,121) $ 7,816
=========== =========== ===========
Increase in obligations:
Niantic Bay Fuel Trust...................................... $ 962 $ 660 $ 669
=========== =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------
Accumulated
Capital Retained Other
Common Surplus, Earnings Comprehensive
Stock Paid In (a) Income Total
- --------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1996............... $26,812 $150,182 $115,296 $ - $292,290
Net income for 1996.................. 11,089 11,089
Cash dividends on preferred
stock.............................. (5,305) (5,305)
Cash dividends on common stock....... (16,494) (16,494)
Loss on the retirement of preferred
stock.............................. (374) (374)
Capital stock expenses, net.......... 729 729
-------- --------- --------- ------------- ---------
Balance at December 31, 1996............. 26,812 150,911 104,212 - 281,935
Net income for 1997.................. (27,460) (27,460)
Cash dividends on preferred
stock.............................. (3,140) (3,140)
Cash dividends on common stock....... (15,004) (15,004)
Capital stock expenses, net.......... 260 260
-------- --------- --------- ------------- ---------
Balance at December 31, 1997............. 26,812 151,171 58,608 - 236,591
Net loss for 1998.................... (9,579) (9,579)
Cash dividends on preferred
stock.............................. (3,026) (3,026)
Capital stock expenses, net.......... 260 260
Other comprehensive income........... 150 150
-------- --------- --------- ------------- ---------
Balance at December 31, 1998............. $26,812 $151,431 $ 46,003 $ 150 $224,396
======== ========= ========= ============= =========
</TABLE>
(a) The company has dividend restrictions imposed by its long-term debt
agreements. At December 31, 1998, these restrictions totaled approximately
$33.8 million.
See accompanying notes to consolidated financial statements.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. About Western Massachusetts Electric Company
Western Massachusetts Electric Company and Subsidiary (WMECO or the
company), The Connecticut Light and Power Company (CL&P), Holyoke
Water Power Company (HWP), Public Service Company of New Hampshire
(PSNH) and North Atlantic Energy Corporation (NAEC) are the operating
subsidiaries comprising the Northeast Utilities system (the NU system)
and are wholly owned by Northeast Utilities (NU).
The NU system furnishes franchised retail electric service in
Connecticut, New Hampshire and western Massachusetts through CL&P,
PSNH and WMECO. NAEC sells all of its entitlement to the capacity
and output of the Seabrook nuclear power plant (Seabrook) to PSNH
under two life-of-unit, full cost recovery contracts. HWP is engaged
in the production and distribution of electric power. The NU system
also furnishes firm and other wholesale electric services to various
municipalities and other utilities, and participates in limited retail
access programs, providing off-system retail electric service. The NU
system serves in excess of 30 percent of New England's electric needs
and is one of the 24 largest electric utility systems in the country as
measured by revenues.
NU is registered with the Securities and Exchange Commission (SEC) as
a holding company under the Public Utility Holding Company Act of 1935
(1935 Act). NU and its subsidiaries, including WMECO, are subject to
the provisions of the 1935 Act. Arrangements among the NU system
companies, outside agencies and other utilities covering inter-
connections, interchange of electric power and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. WMECO is subject to further
regulation for rates, accounting, and other matters by the FERC
and/or the applicable state regulatory commissions.
Several wholly owned subsidiaries of NU provide support services for
the NU system companies and, in some cases, for other New England
utilities. Northeast Utilities Service Company (NUSCO) provides
centralized accounting, administrative, information resources,
engineering, financial, legal, operational, planning, purchasing and
other services to the NU system companies. Northeast Nuclear Energy
Company (NNECO) acts as agent for the NU system companies and other
New England utilities in operating the Millstone nuclear generating
facilities. In addition, CL&P and WMECO each have established a
special purpose subsidiary whose business consists of the purchase
and resale of receivables.
During the first quarter of 1999, NU established three new
subsidiaries: NU Enterprises, Inc., Northeast Generation Company and
Northeast Generation Services Company. Directly or through multiple
subsidiaries, these entities will engage in a variety of energy-
related activities, including the acquisition and management of non-
nuclear generating plants.
B. Presentation
The consolidated financial statements of WMECO include the accounts
of its wholly owned subsidiary. Significant intercompany
transactions have been eliminated in consolidation.
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 disclosure of contingent 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.
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
All transactions among affiliated companies are on a recovery of cost
basis which may include amounts representing a return on equity and
are subject to approval by various federal and state regulatory
agencies.
C. New Accounting Standards
The Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) 132, "Employers' Disclosures
About Pensions and Other Postretirement Benefits," in 1998. SFAS 132
revises employers' disclosures about pension and other postretirement
benefit plans but it does not change the measurement or recognition
of those plans. See Note 9, "Pension Benefits and Postretirement
Benefits Other Than Pensions," for further information on WMECO's
pension and postretirement benefits disclosures.
During June 1997, the FASB issued SFAS 131, "Disclosures about
Segments of an Enterprise and Related Information." SFAS 131
determines the standards for reporting and disclosing qualitative and
quantitative information about a company's operating segments. More
specifically, it requires financial information to be disclosed for
segments whose operating results are received by the chief operating
officer for decisions on resource allocation. It also requires
related disclosures about products and services, geographic areas and
major customers. WMECO currently evaluates management performance
using a cost-based budget, and the information required by SFAS 131
is not available.
As a result of the changes WMECO and the industry are undergoing, the
company will implement business segment reporting in 1999. This
reporting will provide management with revenue and expense information
at the business segment level. Management has identified significant
segments to include transmission, distribution, generation-related and
energy marketing.
D. Investments and Jointly Owned Electric Utility Plant
Regional Nuclear Generating Companies: WMECO owns common stock of
four regional nuclear generating companies (Yankee companies) which
are accounted for on the equity basis due to WMECO's ability to
exercise significant influence over their operating and financial
policies. WMECO's equity investments and ownership interests in the
Yankee companies at December 31, 1998 are:
(Thousands of Dollars, except for percentages)
Connecticut Yankee Atomic
Power Company (CYAPC).................. $ 9,974 9.5%
Yankee Atomic Electric
Company (YAEC)......................... 1,395 7.0
Maine Yankee Atomic Power
Company (MYAPC)........................ 2,629 3.0
Vermont Yankee Nuclear
Power Corporation (VYNPC).............. 1,442 2.5
$15,440
Each Yankee company owns a single nuclear generating unit. YAEC's,
CYAPC's and MYAPC's nuclear power plants were shut down permanently
on February 26, 1992, December 4, 1996, and August 6, 1997,
respectively. For additional information on the Yankee companies,
see Note 2, "Nuclear Decommissioning and Plant Closure Costs."
Millstone: WMECO has 19 percent joint-ownership interest in
Millstone 1, a 660-megawatt (MW) nuclear generating unit and
Millstone 2, a 870-MW nuclear generating unit. WMECO has a 12.24
percent joint-ownership interest in Millstone 3, a 1,154-MW nuclear
generating unit. During the third quarter of 1998, management
decided to retire Millstone 1 and prepare for final decommissioning.
For further information on the Millstone 1 closure, see Note 2,
"Nuclear Decommissioning and Plant Closure Costs," and Management's
Discussion and Analysis (MD&A). For further information on Millstone
2 and 3, see Note 2, "Nuclear Decommissioning and Plant Closure
Costs," Note 11C, "Commitments and Contingencies - Nuclear
Performance," and the MD&A.
Plant-in-service and the accumulated provision for depreciation for
WMECO's share of the three Millstone units are as follows:
At December 31,
(Millions of Dollars) 1998 1997
Plant-in-service
Millstone 1...................................... $ - $ 91.0
Millstone 2...................................... 177.5 162.4
Millstone 3...................................... 379.2 378.7
Accumulated provision for depreciation
Millstone 1...................................... $ - $ 40.1
Millstone 2...................................... 70.4 57.6
Millstone 3...................................... 121.1 110.1
WMECO's share of Millstone expenses are included in operating
expenses on the accompanying Consolidated Statements of Income.
E. Depreciation
The provision for depreciation is calculated using the straight-line
method based on estimated remaining lives of depreciable utility
plant-in-service, adjusted for salvage value and removal costs, as
approved by the appropriate regulatory agency. Except for major
facilities, depreciation rates are applied to the average
plant-in-service during the period. Major facilities are depreciated
from the time they are placed in service. When plant is retired from
service, the original cost of plant, including costs of removal, less
salvage, is charged to the accumulated provision for depreciation.
The costs of closure and removal of non-nuclear facilities are
accrued over the life of the plant as a component of depreciation.
The depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 2.9 percent
in 998 and 3.2 percent in 1997 and 1996. See Note 2, "Nuclear
Decommissioning and Plant Closure Costs," for information on nuclear
plant decommissioning.
At December 31, 1998 and 1997, the accumulated provision for
depreciation included approximately $3.2 million accrued for the cost
of removal, net of salvage, for non-nuclear generation property.
WMECO is currently in the process of selling its non-nuclear
generation. See 11A, "Commitment and Contingencies - Restructuring"
for further information.
F. Revenues
Other than revenues under fixed-rate agreements negotiated with
certain wholesale, commercial and industrial customers and limited
retail access programs, utility revenues are based on authorized
rates applied to each customer's use of electricity. In general,
rates can be changed only through a formal proceeding before the
appropriate regulatory commission. Regulatory commissions also have
authority over the terms and conditions of nontraditional rate making
arrangements. At the end of each accounting period, WMECO accrues an
estimate for the amount of energy delivered but unbilled.
G. Regulatory Accounting and Assets
The accounting policies of WMECO and the accompanying consolidated
financial statements conform to generally accepted accounting
principles applicable to rate-regulated enterprises and reflect the
effects of the ratemaking process in accordance with SFAS 71,
"Accounting for the Effects of Certain Types of Regulation." Assuming
a cost-of-service based regulatory structure, regulators may permit
incurred costs, normally treated as expenses, to be deferred and
recovered through future revenues. Through their actions, regulators
also may reduce or eliminate the value of an asset, or create a
liability. If WMECO was no longer subject to the provisions of SFAS
71, the company would be required to write-off all of its related
regulatory assets and liabilities unless there is a formal transition
plan which provides for the recovery, through established rates, for
the collection of these costs through a portion of the business which
would remain regulated on a cost of service basis. At the time of
transition, WMECO would also be required to determine any impairment
to the carrying costs of deregulated plant and inventory assets.
Electric utility industry restructuring in Massachusetts was
effective March 1, 1998, however, management continues to believe the
application of SFAS 71 remains appropriate at this time. Once
WMECO's restructuring plan has been formally approved by the
Massachusetts Department of Telecommunications and Energy (DTE) and
management can determine the impacts of restructuring, WMECO's
generation business will no longer be rate regulated on a cost-of-
service basis. The majority of WMECO's regulatory assets are
generation-related. Management expects that WMECO's transmission and
distribution business will continue to be rate-regulated on a cost-
of-service basis and the restructuring plan will allow for the
recovery of regulatory assets through this portion of the business.
For further information on WMECO's regulatory environment and the
potential impacts of restructuring, see Note 11A, "Commitments and
Contingencies-Restructuring," and the MD&A.
Based on a current evaluation of the various factors and conditions
that are expected to impact future cost recovery, management
continues to believe it is probable that WMECO will recover its
investments in long-lived assets, including regulatory assets. The
components of WMECO's regulatory assets are as follows:
At December 31, 1998 1997
(Thousands of Dollars)
Income taxes, net (Note 1H)............ $57,079 $ 63,716
Unrecovered contractual obligations
(Note 1J)............................ 74,534 93,628
Recoverable energy costs (Note 1I)..... 18,980 26,270
Millstone 1 (Note 1K).................. 133,653 -
Standard service offer deferral
(Note 1L)............................ 13,271 -
Other.................................. 24,918 27,763
$322,435 $211,377
H. Income Taxes
The tax effect of temporary differences (differences between the
periods in which transactions affect income in the financial
statements and the periods in which they affect the determination of
taxable income) is accounted for in accordance with the ratemaking
treatment of the applicable regulatory commissions. See Note 7,
"Income Tax Expense" for the components of income tax expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, that give
rise to the accumulated deferred tax obligation is as follows:
At December 31, 1998 1997
(Thousands of Dollars)
Accelerated depreciation and
other plant-related differences........ $228,059 $223,038
Regulatory assets - income tax gross up 29,286 30,175
Other.................................. (8,360) (6,760)
$248,985 $246,453
I. Recoverable Energy Costs
Under the Energy Policy Act of 1992 (Energy Act), WMECO is assessed
for its proportionate share of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States
Department of Energy (D&D assessment). The Energy Act requires that
regulators treat D&D assessments as a reasonable and necessary
current cost of fuel, to be fully recovered in rates like any other
fuel cost. WMECO is currently recovering these costs through rates.
As of December 31, 1998, WMECO's total D&D deferrals were approximately
$10.5 million.
Prior to March 1, 1998, WMECO had in place a comprehensive fuel
adjustment clause which allowed for the collection or refund of fuel
price differences between the cost of fuel and the amounts collected.
Management expects the deferred fuel balance will be collected as
part of the restructuring proceeding.
J. Unrecovered Contractual Obligations
Under the terms of contracts with MYAPC, CYAPC and YAEC, the
shareholder-sponsor companies, including WMECO, are responsible for
their proportionate share of the remaining costs of the units,
including decommissioning. As management expects that WMECO will be
allowed to recover these costs from its customers, WMECO has recorded
regulatory assets, with corresponding obligations, on its balance
sheets. For further information, see Note 2, "Nuclear
Decommissioning and Plant Closure Costs."
K. Millstone 1
The Millstone 1 regulatory asset includes the recoverable portion of
the undepreciated plant and related balances of approximately $60.8
million, and the regulatory asset associated with the decommissioning
and closure obligation of $72.8 million. See Note 2, "Nuclear
Decommissioning and Plant Closure Costs," for further information.
L. Standard Service Offer Deferral
For the period March 1, 1998 through December 31, 1998, WMECO has
recorded a standard service offer deferral regulatory asset
representing a portion of the costs of providing energy in excess of
the standard offer rate as allowed by the restructuring legislation.
Management expects WMECO will be allowed to recover these costs
under the restructuring plan.
2. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
Millstone 2 and 3: WMECO's operating nuclear power plants have service
lives that are expected to end during the years 2015 through 2025. Upon
retirement, these units must be decommissioned. Current decommissioning
studies conclude that complete and immediate dismantlement at retirement
continues to be the most viable and economic method of decommissioning
the units. Decommissioning studies are reviewed and updated periodically
to reflect changes in decommissioning requirements, costs, technology and
inflation.
The estimated cost of decommissioning WMECO's ownership share of
Millstone 2 and 3, in year-end 1998 dollars, is $75.5 million and $68.5
million, respectively. Millstone 2 and 3 decommissioning costs will be
increased annually by their respective escalation rates. Nuclear
decommissioning costs are accrued over the expected service lives of the
units and are included in depreciation expense on the Consolidated
Statements of Income. Nuclear decommissioning costs for these units
amounted to $3.7 million in 1998, 1997 and 1996, respectively. Nuclear
decommissioning, as a cost of removal, is included in the accumulated
provision for depreciation on the Consolidated Balance Sheets. At
December 31, 1998 and 1997, the decommissioning balance in the
accumulated provision for depreciation amounted to $35.5 million and
$31.9 million, respectively.
WMECO has established external decommissioning trusts for its portion of
the costs of decommissioning Millstone 2 and 3. Funding of the estimated
decommissioning costs for these units assumes levelized collections and
after-tax earnings on the decommissioning funds of approximately 5.5
percent.
As of December 31, 1998, WMECO has collected a total of $35.5 million
through rates toward the future decommissioning costs of its share of
Millstone 2 and 3, all of which has been transferred to the external
decommissioning trusts. Earnings on the decommissioning trusts increase
the decommissioning trust balance and the accumulated reserve for
depreciation. Unrealized gains and losses associated with the
decommissioning trusts also impact the balance of the trust and the
accumulated reserve for depreciation. The fair value of the amounts in
the external decommissioning trusts was $66.9 million at December 31, 1998.
Changes in requirements or technology, the timing of funding or
dismantling, or adoption of a decommissioning method other than immediate
dismantlement would change decommissioning cost estimates and the amounts
required to be recovered. WMECO attempts to recover sufficient amounts
through its allowed rates to cover its expected decommissioning costs.
Only the portion of currently estimated total decommissioning costs that
has been accepted by regulatory agencies is reflected in the rates of
WMECO. Based on present estimates and assuming its nuclear units operate
to the end of their respective license periods, WMECO expects that the
decommissioning trusts will be substantially funded when the units are
retired from service.
Millstone 1: WMECO's share of the total estimated decommissioning costs
for Millstone 1, which have been updated to reflect the early shutdown of
the unit, are approximately $131.5 million as of December 31, 1998. The
company has recorded the decommissioning and closure obligation as a
liability. Nuclear decommissioning costs for Millstone 1 were $2.5 million
in 1998, 1997 and 1996, respectively.
WMECO will seek recovery of unrecovered Millstone 1 balances of
approximately $60.8 million and decommissioning related costs of
approximately $63.3 million as part of its restructuring regulatory
proceedings. Based upon the restructuring law in Massachusetts,
management believes it is probable that WMECO will be allowed the
recovery of these costs and has recorded a regulatory asset.
WMECO uses external trusts to fund its estimated Millstone 1
decommissioning costs. As of December 31, 1998, WMECO had collected a
total of $30.3 million through rates toward the future decommissioning
costs of its share of Millstone 1, all of which has been transferred to
external decommissioning trusts. At December 31, 1998, the fair market
value of the balance in the external trusts was approximately $58.7 million.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with
a service life that is expected to end in 2012. WMECO's ownership share
of estimated costs, in year-end 1998 dollars, of decommissioning this
unit is $13.2 million.
At December 31, 1998, the remaining estimated obligation, including
decommissioning, for the Yankee company nuclear generating facilities
which have been shut down were:
Total WMECO's
(Thousands of Dollars) Obligation Share
Maine Yankee............................. $715,065 $21,452
Connecticut Yankee....................... $498,557 $47,363
Yankee Atomic............................ $ 81,699 $ 5,719
For further information on the Yankee companies, see Note 11B,
"Commitments and Contingencies - Rate Matters."
For information on proposed changes to the accounting for
decommissioning, see the MD&A.
3. SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by WMECO
is subject to periodic approval by either the SEC under the 1935 Act or
by the DTE. SEC authorization allowed WMECO, as of January 1, 1999, to
incur short-term borrowings up to a maximum of $150 million. In addition,
the charter of WMECO contains a preferred stock provision restricting the
amount of unsecured debt that the company may incur. As of December 31,
1998, this charter permits WMECO to incur an additional $96 million of
unsecured debt.
Credit Agreements: NU, CL&P and WMECO are parties to a $313.75 million
revolving credit agreement (Credit Agreement). Under the Credit Agreement
amended on September 11, 1998, CL&P and WMECO are able to borrow, subject
to the availability of first mortgage bond collateral, up to $313.75
million and $150 million, respectively. At December 31, 1998, CL&P and
WMECO have issued first mortgage bonds to enable borrowings under this
facility up to a maximum of $225 million and $80 million, respectively.
NU, which cannot issue first mortgage bonds, would be able to borrow up
to $50 million if NU consolidated, CL&P and WMECO each meet certain
interest coverage tests for two consecutive quarters. This requirement
for NU has not been met. In addition, CL&P and WMECO each must meet
certain minimum quarterly financial ratios to access the Credit
Agreement. CL&P is currently in the process of obtaining a waiver of
the equity financial ratio requirement for the quarter ended December 31,
1998. WMECO satisfied these requirements for the quarter ending December
31, 1998. In connection with obtaining the waiver for the equity test,
NU's participation in the Credit Agreement will be terminated. The
overall limit for all of the NU system companies under the entire Credit
Agreement is $313.75 million. The NU system companies are obligated to
pay a facility fee of .50 percent per annum of each bank's total
commitment under the Credit Agreement which will expire in November 1999.
At December 31, 1998 and 1997, there were $30 million and $50 million,
respectively, in borrowings under this Credit Agreement. Of these
borrowings, $20 million was borrowed by WMECO in 1998 and $15 million was
borrowed by WMECO in 1997.
Under the credit facility discussed above, WMECO may borrow funds on a
short-term revolving basis under its agreement, using either fixed-rate
loans or standby loans. Fixed rates are set using competitive bidding.
Standby loans are based upon several alternative variable rates. The
weighted average annual interest rate on WMECO's notes payable to banks
outstanding on December 31, 1998 and 1997 was 6.53 percent and 6.95
percent, respectively.
Money Pool: Certain subsidiaries of NU, including WMECO, are members of
the Northeast Utilities System Money Pool (Pool). The Pool provides a
more efficient use of the cash resources of the NU system, and reduces
outside short-term borrowings. NUSCO administers the Pool as agent for
the member companies. Short-term borrowing needs of the member companies
are first met with available funds of other member companies, including
funds borrowed by NU parent. NU parent may lend to the Pool but may not
borrow. Funds may be withdrawn from or repaid to the Pool at any time
without prior notice. Investing and borrowing subsidiaries receive or
pay interest based on the average daily Federal Funds rate. Borrowings
based on loans from NU parent, however, bear interest at NU parent's cost
and must be repaid based upon the terms of NU parent's original
borrowing. At December 31, 1998 and 1997, WMECO had $30.9 million and
$14.4 million, respectively, of borrowings outstanding from the Pool. The
interest rate on borrowings from the Pool at December 31, 1998 and 1997,
was 5.8 percent each year.
Maturities of short-term debt obligations were for periods of three
months or less.
For further information on WMECO's short-term debt, see the MD&A.
4. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemptions are:
December 31, Shares
1998 Outstanding
Redemption December 31, December 31,
Description Price 1998 1998 1997 1996
(Thousands of Dollars)
7.72% Series B
of 1971....... $103.51 200,000 $20,000 $20,000 $20,000
All or any part of the outstanding preferred stock may be redeemed by the
company at any time at established redemption prices plus accrued dividends
to the date of redemption.
5. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
December 31, Shares
1998 Outstanding
Redemption December 31, December 31,
Description Price* 1998 1998 1997 1996
(Thousands of Dollars)
7.60% Series
of 1987....... $25.51 780,000 $19,500 $21,000 $21,000
Less preferred stock to be
redeemed within one
year, net of reacquired
stock......... 60,000 1,500 1,500 -
Total........... $18,000 $19,500 $21,000
*Redemption price reduces in future years.
The minimum sinking-fund provisions of the 1987 Series subject to
mandatory redemption at December 31, 1998, for the years 1999 through
2003 is $1.5 million per year. In case of default on sinking-fund
payments, no payments may be made on any junior stock by way of dividends
or otherwise (other than in shares of junior stock) so long as the
default continues. If the company is in arrears in the payment of
dividends on any outstanding shares of preferred stock, the company would
be prohibited from redemption or purchase of less than all of the
preferred stock outstanding. All or part of the 7.60% Series of 1987 may
be redeemed by the company at any time at an established redemption price
plus accrued dividends to the date of redemption subject to certain
refunding limitations.
6. LONG-TERM DEBT
Details of long-term debt outstanding are:
December 31,
1998 1997
(Thousands of Dollars)
First mortgage bonds:
6 3/4% Series G, due 1998.................. $ - $ 9,800
6 1/4% Series X, due 1999.................. 40,000 40,000
6 7/8% Series W, due 2000.................. 60,000 60,000
7 3/8% Series B, due 2001.................. 60,000 60,000
7 3/4% Series V, due 2002.................. 85,000 85,000
7 3/4% Series Y, due 2024.................. 50,000 50,000
Total 295,000 304,800
Pollution control notes:
Tax Exempt 1993 A Series, 5.85% due 2028... 53,800 53,800
Fees and interest due for spent
fuel disposal costs (Note 11E)............. 41,355 39,045
Less: Amounts due within one year.......... 40,000 9,800
Unamortized premium and discount, net....... (841) (996)
Long-term debt, net......................... $349,314 $386,849
On October 1, 1998, the variable interest rate on WMECO's $53.8 million
principal amount PCRB, 1993 A Series, due September 1, 2028, was fixed at
a rate of 5.85 percent per annum.
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1998 for the years 1999 through 2002 are
approximately $40 million, $60 million, $60 million, and $85 million,
respectively. There are no long-term debt maturities or cash sinking-
fund requirements for 2003. In addition, there are annual one-percent
sinking- and improvement-fund requirements, currently amounting to $1.5
million for 1999 and 2000, $900 thousand for 2001 and 2002 and no
requirement for 2003. Such sinking- and improvement-fund requirements
may be satisfied by the deposit of cash or bonds by certification of
property additions.
All or any part of each outstanding series of first mortgage bonds may be
redeemed by WMECO at any time at established redemption prices plus
accrued interest to the date of redemption, except certain series which
are subject to certain refunding limitations during their respective
initial five-year redemption periods.
Essentially all of WMECO's utility plant is subject to the lien of its
first mortgage bond indenture. As of December 31, 1998 and 1997, WMECO
has secured $53.8 million of pollution control notes with second mortgage
liens on Millstone 1, junior to the liens of its first mortgage bond
indenture. The average effective interest rate on the variable-rate
pollution control notes was 3.2 percent for 1998 and 3.5 percent for 1997.
7. INCOME TAX EXPENSE
The components of the federal and state income tax provisions were
charged as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Current income taxes:
Federal............................ $(7,412) $(14,277) $7,007
State.............................. (82) (635) 1,358
Total current.................... (7,494) (14,912) 8,365
Deferred income taxes, net:
Federal............................ 6,535 3 2,054
State.............................. 2,339 210 609
Total deferred................... 8,874 213 2,663
Investment tax credits, net.......... (1,469) (1,469) (1,468)
Total income tax (credit)/
expense............................ $ (89) $(16,168) $9,560
The components of total income tax expense are classified as follows:
Income taxes charged to
operating expenses................. $ 2,109 $(15,142) $10,628
Other income taxes................... (2,198) (1,026) (1,068)
Total income tax (credit)/
expense............................ $ (89) $(16,168) $ 9,560
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Depreciation, leased nuclear
fuel, settlement credits,
and disposal costs................. $ 5,808 $ 1,407 $ 32
Energy adjustment clause............. 3,389 3,115 4,102
Demand side management............... (1,192) 321 1,557
Nuclear plant deferrals.............. (897) (3,431) (2,258)
Pension.............................. 950 999 (57)
Bond redemptions..................... (500) (535) (502)
Other................................ 1,316 (1,663) (211)
Deferred income taxes, net........... $ 8,874 $ 213 $ 2,663
A reconciliation between income tax expense and the expected tax expense at
the applicable statutory rate is as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income for..... $(3,384) $(15,270) $7,076
Tax effect of differences:
Depreciation........................ 1,765 630 1,499
Amortization of regulatory assets... 938 1,916 1,029
Investment tax credit amortization.. (1,469) (1,469) (1,468)
Nondeductible penalties............. 599 (19) 89
State income taxes, net of
federal benefit................... 1,052 (225) 1,279
Adjustment for prior years' taxes... 692 (967) -
Dividends received reduction........ (666) (408) (378)
Other, net.......................... 384 (356) 434
Total income tax (credit)/expense..... $ (89) $(16,168) $9,560
8. LEASES
WMECO finances its share of the nuclear fuel for Millstone 2 and Millstone 3
under the Niantic Bay Fuel Trust (NBFT) capital lease agreement. This lease
agreement has an expiration date of June 1, 2040. On June 5, 1998, the NBFT
issued $180 million Series G intermediate term notes (ITNs) through a
private placement offering. The five-year notes mature on June 5, 2003
and will bear interest at a rate of 8.59 percent per annum, payable
semiannually. At December 31, 1998, WMECO's capital lease obligation to
the NBFT was approximately $33.9 million.
The permanent shutdown of Millstone 1 in July 1998 afforded the NBFT ITN
holders the right to seek repurchase of a pro rata share of their notes
based upon the stipulated loss value of Millstone 1 fuel compared to the
stipulated loss value of all fuel then under the NBFT. This amount was
approximately $80 million. The shutdown also obligates WMECO to pay such
amount to the NBFT under the NBFT lease whether or not any ITN holders
request repurchase. WMECO is seeking consents from the ITN holders to
amend this lease provision so that they will not be obligated to make
this payment, but instead will issue an additional $80 million of
collateral first mortgage bonds in mid-1999.
WMECO makes quarterly lease payments for the cost of nuclear fuel consumed
in the reactors based on a units-of-production method at rates which reflect
estimated kilowatt-hours of energy provided plus financing costs associated
with the fuel in the reactors. Upon permanent discharge from the reactors,
ownership of the nuclear fuel transfers to WMECO. WMECO's current portion
of the NBFT lease obligation at December 31, 1998 was approximately $21.9
million, including approximately $15.2 million reclassified to current as
a result of the shutdown of Millstone 1. Future minimum lease payments
under the nuclear fuel capital lease for the remaining portion of the
obligation cannot be reasonably estimated on an annual basis due to
variations in the usage of nuclear fuel.
WMECO also has entered into nonfuel lease agreements, some of which may
be capital leases, for the use of data processing and office equipment,
vehicles, nuclear control room simulators and office space. The
provisions of these lease agreements generally provide for renewal
options. Future minimum lease payments for nonfuel capital leases as of
December 31, 1998, were approximately $36 thousand each year for 1999
through 2003. Future minimum rental payments, excluding executory costs
such as property taxes, state use taxes, insurance and maintenance under
long-term noncancelable operating leases, as of December 31, 1998, are:
Year (Thousands of Dollars)
1999......................... $ 3,902
2000......................... 3,594
2001......................... 3,217
2002......................... 2,785
2003......................... 2,233
After 2003................... 15,460
$31,191
The following rental payments have been charged to expense:
Year Capital Leases Operating Leases
1998......................... $4,137,000 $5,790,000
1997......................... 1,820,000 5,968,000
1996......................... 3,598,000 6,410,000
Interest included in capital lease rental payments was $2,796,000 in
1998, $1,820,000 in 1997, and $1,858,000 in 1996.
9. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system subsidiaries participate in a uniform non-contributory
defined benefit retirement plan covering all regular NU system employees.
Benefits are based on years of service and the employees' highest
eligible compensation during 60 consecutive months of employment.
WMECO's direct portion of the NU system's pension credit, part of which
was credited to utility plant, approximated $7.4 million in 1998, $5.7
million in 1997, and $2.0 million in 1996.
Currently, WMECO funds annually an amount at least equal to that which
will satisfy the requirements of the Employee Retirement Income Security
Act and the Internal Revenue Code. Pension costs are determined using
market-related values of pension assets.
The NU system subsidiaries also provide certain health care benefits,
primarily medical and dental, and life insurance benefits through a
benefit plan to retired employees. These benefits are available for
employees retiring from the company who have met specified service
requirements. For current employees and certain retirees, the total
benefit is limited to two times the 1993 per-retiree health care cost.
These costs are charged to expense over the future estimated work life of
the employee. WMECO is funding postretirement costs through external
trusts. WMECO is funding, on an annual basis, amounts that have been
rate-recovered and which are also tax deductible under the Internal
Revenue Code.
Pension and trust assets are invested primarily in domestic and
international equity securities and bonds.
The following table represents the plans' beginning benefit obligation
balance reconciled to the ending benefit obligation balance, beginning
fair value of plan assets balance reconciled to the ending fair value of
plan assets balance and the respective funds' funded status reconciled to
the Consolidated Balance Sheets:
The components of net cost are:
At December 31,
Postretirement
Pension Benefits Benefits
1998 1997 1998 1997
(Thousands of Dollars)
Change in benefit
obligation
Benefit obligation at
beginning of year............ $(109,536) $(107,816) $(27,826) $(30,091)
Service cost.................. (2,192) (1,876) (460) (355)
Interest Cost................. (7,914) (7,858) (2,074) (2,011)
Transfers..................... (3,044) 820 - -
Actuarial (loss)/gain......... (3,751) (1,224) (2,415) 2,028
Benefits paid................. 7,700 7,889 2,661 2,603
Curtailments and settlements.. - 529 - -
Benefit obligation at
end of year................. $(118,737) $(109,536) $(30,114) $(27,826)
Change in plan assets
Fair value of plan assets at
beginning of year........... $181,028 $157,863 $ 12,838 $ 10,215
Actual return on plan assets. 25,229 31,874 1,588 2,058
Employer contribution......... - - 2,870 3,168
Benefits paid................. (7,700) (7,889) (2,661) (2,603)
Transfers..................... 3,044 (820) - -
Fair value of plan assets
at end of year.............. $201,601 $181,028 $ 14,635 $ 12,838
Funded status at
December 31................. $ 82,864 $ 71,492 $(15,479) $(14,988)
Unrecognized transition
amount...................... (1,492) (1,727) 22,977 24,618
Unrecognized prior service
cost........................ 1,070 1,142 - -
Unrecognized net gain......... (66,542) (62,370) (7,498) (9,630)
Prepaid benefit cost.......... $15,900 $ 8,537 $ - $ -
The following actuarial assumptions were used in calculating the plans'
year-end funded status:
At December 31,
Postretirement
Pension Benefits Benefits
1998 1997 1998 1997
Discount rate................. 7.00% 7.25% 7.00% 7.25%
Compensation/
progression rate............ 4.25% 4.25% 4.25% 4.25%
Health care cost
trend rate (a).............. N/A N/A 5.22% 5.76%
(a) The annual growth in per capita cost of covered health care benefits
was assumed to decrease to 4.40 percent by 2001.
The components of net periodic benefit cost are:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
1998 1997 1996 1998 1997 1996
(Thousands of Dollars)
Service cost............$ 2,192 $ 1,876 $ 1,979 $ 460 $ 355 $ 490
Interest cost........... 7,914 7,858 7,786 2,074 2,011 2,236
Expected return on plan
assets................ (14,754) (12,746) (11,216) (935) (736) (330)
Amortization of
unrecognized transition
(asset)/obligation.... (235) (235) (235) 1,641 1,641 1,641
Amortization of prior
service cost.......... 72 72 72 - - -
Amortization of actuarial
gain.................. (2,551) (2,022) (1,337) - - -
Other amortization, net. - - - (370) (484) (200)
Curtailments and
settlements........... - (529) 953 - - -
Net periodic benefit
(credit)/cost.........$ (7,362) $ (5,726) $(1,998) $2,870 $2,787 $3,837
For calculating pension and postretirement benefit costs, the following
assumptions were used:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
1998 1997 1996 1998 1997 1996
Discount rate.......... 7.25% 7.75% 7.50% 7.25% 7.75% 7.50%
Expected long-term
rate of return....... 9.50% 9.25% 8.75% N/A N/A N/A
Compensation/
progression rate..... 4.25% 4.75% 4.75% 4.25% 4.75% 4.75%
Long-term rate
of return-
Health assets
net of tax........... N/A N/A N/A 7.75% 7.50% 5.25%
Life assets............ N/A N/A N/A 9.50% 9.25% 8.75%
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. The effect of changing the
assumed health care cost trend rate by one percentage point in each year
would have the following effects:
One Percentage One Percentage
(Thousands of Dollars) Point Increase Point Decrease
Effect on total service
and interest cost
components.................. $ 130 $ (131)
Effect on post-
retirement benefit
obligation.................. 1,740 (1,698)
The trust holding the health plan assets is subject to federal income
taxes at a 39.6 percent tax rate.
10. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES
WMECO has entered into an agreement to sell up to $40 million of
undivided ownership interests in eligible customer receivables and
accrued utility revenues (receivables).
WMECO has established a special purpose, wholly owned subsidiary, WMECO
Receivables Corporation (WRC), whose business consists of the purchase
and resale of receivables. For receivables sold, WMECO has retained
collection responsibilities as agent for the purchaser under its
agreement. As collections reduce previously sold receivables, new
receivables may be sold. At December 31, 1998, approximately $20 million
of receivables had been sold to a third-party purchaser by WMECO. All
receivables sold to WRC are not available to pay WMECO's creditors.
The receivables are sold to a third-party purchaser with limited
recourse. The sales agreement provides for a formula-based loss reserve
in which additional receivables may be assigned to the third-party
purchaser for costs such as bad debt. The third-party purchaser absorbs
the excess amount in the event that actual loss experience exceeds the
loss reserve. At December 31, 1998 approximately $2.9 million was the
formula-based amount of credit exposure and has been reserved as
collateral by WRC. Historical losses for bad debt for WMECO have been
substantially less.
As a result of prior period downgrades on WMECO's first mortgage bonds,
the current bond rating is at a level where the sponsor of WMECO's
accounts receivable program could take various actions at its
discretion, which would have the practical effect of limiting WMECO's
ability to utilize the facility. To date, the sponsor has not notified
WMECO that it will elect to exercise those rights and the program is
functioning in its normal mode.
Concentrations of credit risk to the purchaser under WMECO's agreement
with respect to the receivables are limited due to WMECO's diverse
customer base within its service territory.
11. COMMITMENTS AND CONTINGENCIES
A. Restructuring
Electric utility industry restructuring in Massachusetts became
effective March 1, 1998. As required by the legislation enacted in
November 1997, WMECO will continue to operate and maintain its
transmission and local distribution network and deliver electricity
to all customers. The restructuring legislation specifically
provides for the cost recovery of generation-related assets. The
legislation gives the DTE the authority to determine the amount of
stranded costs that will be eligible for recovery by utilities.
Costs which will qualify as stranded costs and be eligible for
recovery include, but are not limited to, certain above-market
costs associated with generating facilities, costs associated with
long-term commitments to purchase power at above-market prices from
small-power producers and nonutility generators (NUGs), and
regulatory assets and associated liabilities related to the
generation portion of WMECO's business.
Effective March 1, 1998, WMECO's restructuring plan has been filed
with the DTE and includes a 10 percent rate reduction, divestiture
of generation assets, securitization of approximately $500 million
of stranded costs and customer choice of supplier. The DTE has
not approved WMECO's plan yet and rates are being charged under an
interim order. A final decision is expected in mid-1999.
On January 22, 1999, WMECO signed an agreement to sell 290-MW of
fossil and hydroelectric generation assets to Consolidated Edison
Energy, Inc. of New York for $47 million. The sale price is
approximately 3.8 times greater than the assets' 1997 book value of
$12.5 million. WMECO did not offer its 19 percent share of the
Northfield Mountain pumped storage generating facility and
associated hydroelectric facilities. WMECO's book value in
Northfield Mountain was $13.0 million at December 31, 1998. This
asset will be auctioned in conjunction with CL&P's fossil/hydro
auction to take place before 2000. The net proceeds in excess of
book value received from the actual divestiture of these units will
be used to mitigate stranded costs.
Based upon the legislation and regulatory proceedings to date,
management continues to believe that the company will recover its
prudently incurred costs, including regulatory assets and
generation-related investments. However, a change in one or more of
these factors could affect the recovery of stranded costs and may
result in a loss to the company.
B. Rate Matters
During November 1997, MYAPC filed an amendment to its power
contracts clarifying the obligations of its purchasing utilities
following the decision to cease power production. During January
1998, the FERC accepted the amendments and proposed rates, subject
to a refund. On January 18, 1999, MYAPC filed with the FERC
Administrative Law Judge (ALJ) an Offer of Settlement which if
accepted by the FERC, will resolve all the issues in the FERC
decommissioning rate case proceeding. The settlement provides,
among other things, the following: (1) MYAPC will collect $33.6
million annually to pay for decommissioning and spent fuel; (2) its
return on equity will be set at 6.5 percent; (3) MYAPC is permitted
full recovery of all unamortized investment in MY, including fuel,
and (4) an incentive budget for decommissioning is set at $436.3
million.
During late December 1996, CYAPC filed an amendment to its power
contracts clarifying the obligations of its purchasing utilities
following the decision to cease power production. On February 27,
1997, the FERC accepted CYAPC's contract amendment. The new rates
became effective March 1, 1997, subject to a refund.
On August 31, 1998, the FERC ALJ released an initial decision
regarding the December 1996 filing. The decision contained
provisions which would allow for the recovery, through rates, of
the balance of WMECO's net unamortized investment in CYAPC, which
was approximately $10 million as of December 31, 1998. The decision
also called for the disallowance of the recovery of a portion of
the return on the CY investment. The ALJ's decision also stated
that decommissioning collections should continue to be based on the
previously approved estimate of $309.1 million (in 1992 dollars),
with an inflation adjustment of 3.8 percent per year, until a new,
more reliable estimate has been prepared and tested.
During October 1998, CYAPC, CL&P, PSNH and WMECO filed briefs on
exceptions to the ALJ decision. If the initial ALJ decision is
upheld, CYAPC could be required to write-off a portion of the
regulatory asset associated with the plant closing.
If upheld, CYAPC's management has estimated the effect of the ALJ
decision on CYAPC's earnings would be approximately $37.5 million
of which WMECO's share would be approximately $3.6 million.
WMECO's management cannot predict the ultimate outcome of the
hearing at this time, however, management believes that the
associated regulatory assets are probable of recovery.
C. Nuclear Performance
Millstone: The three Millstone units are managed by NNECO. All
three units were placed on the NRC watch list on January 29, 1996.
The units cannot be restarted without appropriate NRC approvals.
Millstone 3 has received these approvals and resumed operation in
July 1998. Restart efforts continue for Millstone 2 and it is
expected to be ready to restart in the spring of 1999. WMECO's
estimated replacement power costs are approximately $1 million per
month while Millstone 2 remains out of service. In July 1998,
CL&P and WMECO decided to retire Millstone 1 and prepare for final
decommissioning.
Litigation: Certain of the non-NU joint owners of Millstone 3 have
filed demands for arbitration with CL&P and WMECO as well as
lawsuits in Massachusetts Superior Court against NU and its current
and former trustees related to the company's operation of Millstone 3.
The arbitrations and lawsuits seek to recover compensatory damages
in excess of $200 million, together with punitive damages, treble
damages and attorneys' fees. Management cannot estimate the potential
outcome of these suits but believes there is no legal basis for the
claims and intends to defend against them vigorously.
D. Environmental Matters
The NU system is subject to regulation by federal, state and local
authorities with respect to air and water quality, the handling and
disposal of toxic substances and hazardous and solid wastes, and
the handling and use of chemical products. The NU system has an
active environmental auditing and training program and believes
that it is in substantial compliance with current environmental
laws and regulations. However, the NU system is subject to certain
enforcement actions and governmental investigations in the
environmental area. Management cannot predict the outcome of these
enforcement acts and investigations.
Environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations
and other facilities. Changing environmental requirements could
also require extensive and costly modifications to WMECO's existing
generating units, and transmission and distribution systems, and
could raise operating costs significantly. As a result, WMECO may
incur significant additional environmental costs, greater than
amounts included in cost of removal and other reserves, in
connection with the generation and transmission of electricity and
the storage, transportation and disposal of by-products and wastes.
WMECO also may encounter significantly increased costs to remedy
the environmental effects of prior waste handling activities. The
cumulative long-term cost impact of increasingly stringent
environmental requirements cannot be estimated accurately.
WMECO has recorded a liability based upon currently available
information for the estimated environmental remediation costs that
it expects to incur. In most cases, additional future
environmental cleanup costs are not reasonably estimable due to a
number of factors, including the unknown magnitude of possible
contamination, the appropriate remediation methods, the possible
effects of future legislation or regulation and the possible
effects of technological changes. At December 31, 1998, the
liability recorded by WMECO for its estimated environmental
remediation costs, not considering any possible recoveries from
third parties, amounted to approximately $1.9 million, within a
range of $1.9 million to $3.1 million.
WMECO has received proceeds from several insurance carriers for
the settlement with certain insurance companies of all past,
present and future environmental matters. As a result of these
settlements, WMECO will retain the risk loss, in part, for some
environmental remediation costs.
WMECO cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought
against it. However, considering known facts, existing laws and
regulatory practices, management does not believe the matters
disclosed above will have a material effect on WMECO's financial
position or future results of operations.
E. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, WMECO must pay the
United States Department of Energy (DOE) for the disposal of spent
nuclear fuel and high-level radioactive waste. The DOE is
responsible for the selection and development of repositories for,
and the disposal of, spent nuclear fuel and high-level radioactive
waste. Fees for nuclear fuel burned on or after April 7, 1983, are
billed currently to customers and paid to the DOE on a quarterly
basis. For nuclear fuel used to generate electricity prior to
April 7, 1983 (prior period fuel), payment must be made prior to
the first delivery of spent fuel to the DOE. Until such payment is
made, the outstanding balance will continue to accrue interest at
the three-month Treasury Bill Yield Rate. At December 31, 1998,
fees due to the DOE for the disposal of prior period fuel were
approximately $41.1 million, including interest costs of $25.5
million.
The DOE originally was scheduled to begin accepting delivery of
spent fuel in 1998. However, delays in identifying a permanent
storage site have continually postponed plans for the DOE's long-
term storage and disposal site. Extended delays or a default by
the DOE could lead to consideration of costly alternatives. The
company has primary responsibility for the interim storage of its
spent nuclear fuel. Adequate storage capacity exists to accommodate
all spent nuclear fuel at Millstone 1. With the addition of new
storage racks, storage facilities for Millstone 3 are expected to
be adequate for the projected life of the unit. With the
implementation of currently planned modifications, the storage
facilities for Millstone 2 are expected to be adequate to
accommodate a full-core discharge from the reactor until 2005.
Fuel consolidation, which has been licensed for Millstone 2, could
provide adequate storage capability for its projected life.
Meeting spent fuel storage requirements beyond these periods could
require new and separate storage facilities, the costs for which
have not been determined.
In November 1997, the U.S. Court of Appeals for the D.C. Circuit
ruled that the lack of an interim storage facility does not excuse
the DOE from meeting its contractual obligation to begin accepting
spent nuclear fuel no later than January 31, 1998. The 1997 ruling
by the appeals court said, however, that the 1982 federal law could
not require the DOE to accept waste when it did not have a suitable
storage facility. The court directed the plaintiffs to pursue
relief under the terms of their contracts with the DOE. Based on
this ruling, since the DOE did not take the spent nuclear fuel as
scheduled, it may have to pay contract damages.
In May 1998, the same court denied petitions from 60 states and
state agencies, collectively, and 41 utilities, including the
company, asking the court to compel the DOE to submit a program,
beginning immediately, for disposing of spent nuclear fuel. The
petitions were filed after the DOE defaulted on its January 31,
1998 obligation to begin accepting the fuel. The court directed
the company and other plaintiffs to pursue relief under the terms
of their contracts with the DOE.
In a petition filed in August 1998, the court's May 1998 decision
was appealed to the U.S. Supreme Court. In November 1998, the
Supreme Court declined to review the lower court ruling that said
utilities should go to court and seek monetary damages from the
DOE. The ultimate outcome of this legal proceeding is uncertain at
this time.
F. Nuclear Insurance Contingencies
Under certain circumstances, in the event of a nuclear incident
at one of the nuclear facilities in the country covered by the
federal government's third-party liability indemnification
program, WMECO could be assessed in proportion to its ownership
interest in each of its nuclear units up to $83.9 million.
WMECO's payments of this assessment would be limited to, in
proportion to its ownership interest in each of its nuclear
units, $10.0 million in any one year per nuclear incident. In
addition, if the sum of all claims and costs from any one nuclear
incident exceeds the maximum amount of financial protection,
WMECO would be subject to an additional 5 percent, or $4.2
million, in proportion to its ownership interests in each of its
nuclear units. Based upon its ownership interests in Millstone
1, 2 and 3, WMECO's maximum liability, including any additional
assessments, would be $44.3 million per incident, of which
payments would be limited to $5.0 million per year. In addition,
through power purchase contracts with VYNPC, WMECO would be
responsible for up to an additional $2.2 million per incident, of
which payments would be limited to $0.3 million per year.
The NRC approved CYAPC's and MYAPC's requests for withdrawal from
participation in the secondary financial protection program,
effective November 19, 1998, and January 17, 1999, respectively,
due to their permanently shutdown and defueled status. Therefore,
neither CYAPC, MYAPC, nor their sponsor companies have any future
obligations for potential assessments.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from
insured occurrences. WMECO is subject to retroactive assessments
if losses exceed the accumulated funds available to the insurer.
The maximum potential assessment against WMECO with respect to
losses arising during the current policy year is approximately $2.2
million under the primary property insurance program.
Insurance has been purchased to cover certain extra costs incurred
in obtaining replacement power during prolonged accidental outages
and the excess cost of repair, replacement, or decontamination or
premature decommissioning of utility property resulting from
insured occurrences. WMECO is subject to retroactive assessments if
losses exceed the accumulated funds available to the insurer. The
maximum potential assessments against WMECO with respect to losses
arising during current policy years are approximately $1.0 million
under the replacement power policies and $2.3 million under the
excess property damage, decontamination and decommissioning
policies. The cost of a nuclear incident could exceed available
insurance proceeds.
Insurance has been purchased aggregating $200 million on an
industry basis for coverage of worker claims.
G. Construction Program
The construction program is subject to periodic review and revision
by management. WMECO currently forecasts construction expenditures
of approximately $167.8 million for the years 1999-2003, including
$33.5 million for 1999. In addition, WMECO estimates that nuclear
fuel requirements, including nuclear fuel financed through the
NBFT, will be approximately $35.5 million for the years 1999-2003,
including $5.8 million for 1999. See Note 8, "Leases" for additional
information about the financing of nuclear fuel.
H. Long-Term Contractual Arrangements
Yankee Companies: The NU system companies rely on VY for approximately
1.4 percent of their capacity under long-term contracts. Under the
terms of their agreements, the NU system companies pay their ownership
(or entitlement) shares of costs, which include depreciation, operation
and maintenance expenses, taxes, the estimated cost of decommissioning
and a return on invested capital. These costs are recorded as purchased-
power expense and are recovered through the companies' rates. WMECO's
total cost of purchases under contracts with VYNPC amounted to $4.4
million in 1998, $3.9 million in 1997 and $4.1 million in 1996. WMECO
may also be asked to provide direct or indirect financial support from
one or more of the Yankee companies, including VYNPC.
NUGs: WMECO has entered into arrangements for the purchase of
capacity and energy from two NUGs. These arrangements have terms
from 15 to 25 years, currently expiring in the years 2008 through
2013, and require WMECO to purchase energy at specified prices or
formula rates. For the 12-month period ending December 31, 1998,
approximately 13 percent of NU system electricity requirements were
met by NUGs. WMECO's total cost of purchases under these arrangements
amounted to $29.9 million in 1998, $31.2 million in 1997 and $29.5
million in 1996.
Hydro-Quebec: Along with other New England utilities, WMECO, CL&P,
PSNH and HWP have entered into agreements to support transmission
and terminal facilities to import electricity from the Hydro-Quebec
system in Canada. WMECO is obligated to pay, over a 30-year period
ending in 2020, its proportionate share of the annual O&M and capital
costs of these facilities.
Estimated Annual Costs: The estimated annual costs of WMECO's
significant long-term contractual arrangements are as follows:
1999 2000 2001 2002 2003
(Millions of Dollars)
VYNPC......................... $ 4.7 $ 4.3 $ 4.7 $ 4.8 $ 4.5
NUGs.......................... 31.1 32.2 33.1 33.9 34.9
Hydro-Quebec.................. 3.7 3.6 3.5 3.4 3.3
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each of the following financial instruments:
Supplemental Executive Retirement Plan investments: SFAS 115,
"Accounting for Certain Investments in Debt and Equity Securities,"
requires investments in debt and equity securities to be presented at
fair value. As a result of this requirement, the investments having a
cost basis of $52,000 held for the benefit of the Supplemental Executive
Retirement Plan were recorded on the Consolidated Balance Sheets at their
fair market value at December 31, 1998 of $352,000.
Nuclear decommissioning trusts: The investments held in WMECO's nuclear
decommissioning trusts were adjusted to market by approximately $27.8
million as of December 31, 1998 and $17.9 million as of December 31,
1997, with corresponding offsets to the accumulated provision for
depreciation. The amounts adjusted in 1998 and 1997 represent cumulative
net unrealized gains. The cumulative gross unrealized holding losses were
immaterial for both 1998 and 1997.
Preferred stock and long-term debt: The fair value of WMECO's fixed-
rate securities is based upon the quoted market price for those issues
or similar issues. Adjustable rate securities are assumed to have a
fair value equal to their carrying value. The carrying amount of WMECO's
financial instruments and the estimated fair values are as follows:
Carrying Fair
At December 31, 1998 Amount Value
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption................... $ 20,000 $ 19,800
Preferred stock subject to
mandatory redemption................... 19,500 19,796
Long-term debt - first mortgage bonds.... 295,000 297,162
Other long-term debt..................... 95,155 95,419
Carrying Fair
At December 31, 1997 Amount Value
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption................... $ 20,000 $ 16,252
Preferred stock subject to
mandatory redemption................... 21,000 20,580
Long-term debt - first mortgage bonds.... 304,800 302,627
Other long-term debt..................... 92,845 92,845
13. OTHER COMPREHENSIVE INCOME
During 1998, WMECO adopted SFAS 130, "Reporting Comprehensive Income,"
which established standards for reporting and displaying comprehensive
income and its components in a financial statement that is displayed
with the same prominence as other financial statements. During 1997 and
1996, WMECO had no material other comprehensive income items.
The accumulated balance for each other comprehensive income item is as
follows:
Current
December 31, Period December 31,
1997 Change 1998
(Thousands of Dollars)
Unrealized gains on
securities.................... $ - $183 $183
Minimum pension
liability adjustment.......... - (33) (33)
Accumulated other
comprehensive income.......... $ - $150 $150
The changes in the components of other comprehensive income are reported
on the Consolidated Statements of Comprehensive Income net of the following
income tax effects:
1998 1997 1996
(Thousands of Dollars)
Unrealized gains
on securities................. $(117) $ - $ -
Minimum pension
liability adjustment.......... 21 - -
Other comprehensive
income........................ $ (96) $ - $ -
To the Board of Directors
of Western Massachusetts Electric Company:
We have audited the accompanying consolidated balance sheets of Western
Massachusetts Electric Company (a Massachusetts corporation and a wholly
owned subsidiary of Northeast Utilities) and subsidiary as of December 31,
1998 and 1997, and the related consolidated statements of income,
comprehensive income, common stockholder's equity and cash flows for each
of the three years in the period ended December 31, 1998. 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 in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Western Massachusetts
Electric Company and subsidiary as of December 31, 1998 and 1997, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1998, in conformity with generally accepted
accounting principles.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 23, 1999
Western Massachusetts Electric Company and Subsidiary
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This section contains management's assessment of Western Massachusetts
Electric Company's (WMECO or the company) financial condition and the
principal factors having an impact on the results of operations. The company
is a wholly-owned subsidiary of Northeast Utilities (NU). This discussion
should be read in conjunction with the company's consolidated financial
statements and footnotes.
FINANCIAL CONDITION
Overview
WMECO's financial results improved in 1998 despite a reduction in retail
rates. The improved results are a result of the successful restart of the
Millstone 3 nuclear power plant, significant progress toward the restart of
Millstone 2 and significant reductions in operating expenses.
WMECO had a net loss of approximately $10 million in 1998, compared to a net
loss of approximately $28 million in 1997. Improved results in 1998 were
primarily due to a $43 million reduction in nonfuel operation and maintenance
costs and a $28 million reduction in fuel and purchased power expense,
partially offset by a reduction in operating revenues.
Total revenues fell 8 percent to $393 million in 1998 from $426 million in
1997. The fall in revenues occurred despite a 1.3 percent increase in retail
kilowatt-hour sales for the year. The revenue reduction primarily resulted
from a 10 percent retail rate decrease required by Massachusetts
restructuring legislation.
WMECO's ability to improve its financial performance in 1999 will depend
primarily on its success in bringing Millstone 2 back on line, and further
reducing its operating costs to help offset continued downward pressure on
retail revenues. WMECO's financial performance will be affected by the
carryover of 1998 rate reductions, plus another 5 percent rate reduction,
adjusted for inflation, that is scheduled to take effect September 1, 1999.
WMECO is in the process of auctioning approximately 560 megawatts (MW) of
fossil and hydroelectric generating capacity. Management also hopes in 1999
to begin the process of securitizing stranded costs, a means of monetizing
the company's regulatory assets and certain other stranded costs. WMECO
intends to use most of the proceeds from asset sales and securitization to
repay outstanding debt and preferred securities.
Restructuring
In November 1997, Massachusetts enacted comprehensive electric utility
industry restructuring legislation. As required by that legislation, WMECO
instituted a 10 percent rate reduction in 1998 and continues to work with
the Massachusetts Department of Telecommunications and Energy (DTE) on
implementing WMECO's restructuring plan. In September 1999, WMECO must
institute another 5 percent rate reduction, adjusted for inflation.
In January 1999, WMECO announced the sale of approximately 290 MW of
fossil/hydro generating capacity to Consolidated Edison Energy, Inc. for $47
million. The sale price is approximately 3.8 times greater than the assets'
1997 book value of $12.5 million. WMECO hopes to close on that transaction
in midsummer and expects to use the majority of the proceeds to repay
outstanding debt. The sale of these assets and future asset sales will be
used to reduce WMECO's stranded costs. WMECO will auction another 270 MW of
pumped storage and conventional hydroelectric plant later in 1999. WMECO has
notified the DTE that it will also seek to auction its ownership in the
Millstone units. WMECO expects to seek approval to securitize up to $500
million in stranded costs.
Following the sale of its generating assets, WMECO will continue to operate
and maintain the transmission and local distribution network and deliver
electricity to its customers.
Millstone Nuclear Units
WMECO has a 19 percent ownership interest in Millstone 2 and a 12.24 percent
ownership interest in Millstone 3. In 1998, Millstone-related costs fell
significantly as Millstone 3 returned to service and Millstone 1 began to
prepare for decommissioning.
After a 27-month outage, Millstone 3 received Nuclear Regulatory Commission
(NRC) permission to restart in June 1998 and reached full power in July. The
unit achieved a capacity factor of approximately 70 percent in 1998 following
its return to service. WMECO's share of the operation, maintenance and
replacement power costs associated with Millstone 3 totaled approximately $28
million in 1998, down from $52 million in 1997. The unit remains on the
NRC's watch list with a Category 2 designation, which means that it will
continue to be subject to heightened NRC oversight. A refueling and
maintenance outage is scheduled to begin in May 1999.
Millstone 2 remains on the NRC watch list with a Category 3 designation,
meaning that NRC commissioners must formally vote to allow restart. Key
steps before restart include final verification that the unit is in
conformance with its design and licensing basis; that management processes
support safe and conservative operations; and that the employees are
effective at identifying and correcting deficiencies at the unit. Millstone
2 is on schedule for a spring 1999 restart following final NRC review and
approval. Millstone 2's return to service will reduce WMECO's fuel and
purchased-power expense by approximately $1 million a month and significantly
reduce O&M which totaled $42 million in 1998.
Liquidity
WMECO converted a total of $53.8 million variable-rate tax exempt debt to
fixed-rate tax exempt debt carrying an interest rate of 5.85 percent.
Niantic Bay Fuel Trust (NBFT), which finances CL&P's and WMECO's nuclear fuel
at Millstone, refinanced maturing notes and bank lines through the issuance
of $180 million of five-year 8.59 percent notes.
Net cash flows from operations totaled approximately $30 million in 1998, up
from $28 million in 1997. Approximately $37 million of net cash flow was
used for investment activities, including construction expenditures and
investments in nuclear decommissioning trusts, essentially unchanged from
1997. Approximately $7 million of net cash flows was from financing
activities, compared with $9 million in 1997. Short-term debt increased by
$22 million while long-term debt and preferred stock levels were reduced by
$11 million in 1998. In 1997, debt levels increased a net of $27 million.
Approximately $3 million was used to pay preferred dividends in 1998,
compared with $18 million in preferred and common dividends in 1997.
The return to service of Millstone 3 and resulting reduction in costs
stabilized the NU system's credit ratings in mid-1998 after repeated
downgrades in 1996 and 1997. Moody's Investors Service, which had downgraded
CL&P, WMECO, and NU debt in April 1998, upgraded those same ratings in July
1998 and established a "positive" outlook. Also in July, Standard & Poor's
(S&P) removed the NU system from "CreditWatch--negative" for the first time in
more than two years. In September 1998, S&P upgraded CL&P, WMECO and PSNH
first mortgage bonds.
Key covenants on a $313.75 million revolving credit line primarily serving
CL&P and WMECO were adjusted in the fall. The $313.75 million revolving
credit line will expire on November 21, 1999. As of February 23, 1999,
WMECO had $60 million outstanding under that line. WMECO paid off a $40
million bond issue that matured on March 1, 1999.
WMECO has arranged financing agreements through the sale of its accounts
receivables. WMECO can finance up to $40 million through this facility. As of
December 31, 1998, WMECO had financed $20 million through its accounts
receivable line.
The permanent shutdown of Millstone 1 in July 1998 could require CL&P and
WMECO to immediately repay the NBFT approximately $80 million of capital
lease obligations. The companies are seeking consents from the note holders
to amend the lease so that they will not be obligated to make this payment.
As consideration for the note holders' consent, the companies intend to issue
an additional $80 million of first mortgage bonds in mid-1999.
Nuclear Decommissioning
Millstone 1
WMECO has a 19 percent ownership interest in Millstone 1. Based on a
continued unit operation study filed with the Connecticut Department of
Public Utility Control (DPUC) in July 1998, management decided to retire
Millstone 1 and begin decommissioning activities. Subsequently, Millstone 1
was removed from the NRC's watch list.
WMECO's share of the total estimated decommissioning costs for Millstone 1,
which have been updated to reflect the early shutdown of the unit, are
approximately $131.5 million in December 1998 dollars. WMECO uses external
trusts to fund the decommissioning costs. At December 31, 1998, WMECO had
unrecovered plant and related assets for Millstone 1 of $60.8 million and
unrecovered decommissioning obligation of $72.8 million. These amounts have
been recorded as a regulatory asset, while decommissioning and closure
obligations have been recorded as a liability. Management expects the DTE to
decide on the recovery of WMECO's share of Millstone 1 investment and
decommissioning liability as part of the ongoing restructuring docket.
Yankee Companies
WMECO has a 9.5 percent ownership interest in the Connecticut Yankee Atomic
Power Company (CYAPC), a 7.0 percent ownership interest in Yankee Atomic
Electric Company (YAEC), a 3.0 percent ownership interest in Maine Yankee
Atomic Power Company (MYAPC) and a 2.5 percent ownership interest in Vermont
Yankee Nuclear Power Corporation (VYNPC). The nuclear plants owned by YAEC,
CYAPC and MYAPC were shut down permanently on February 26, 1992, December 4,
1996, and August 6, 1997, respectively.
At December 31, 1998, WMECO's share of its estimated remaining contract
obligations, including decommissioning, amounted to approximately $74.6
million: $47.4 million for CYAPC, $21.5 million for MYAPC and $5.7 million
for YAEC. Under the terms of the contracts with the Yankee companies, WMECO
is responsible for its proportionate share of the costs of the units
including decommissioning. Management expects to recover these costs from
customers. Accordingly, WMECO has recognized these costs as regulatory
assets, with corresponding obligations on its balance sheet.
WMECO has exposure for its investment in CYAPC as a result of an initial
decision at the Federal Energy Regulatory Commission (FERC). Additionally,
in January 1999, MYAPC filed an offer of settlement which, if accepted by the
FERC, will resolve all the issues in the FERC decommissioning rate case
proceeding. Management cannot predict the ultimate outcome of the FERC
proceedings at this time, but believes that the associated regulatory assets
are probable of recovery. For further information on Yankee companies see
"Notes to Consolidated Financial Statements," Note 11B.
WMECO's share of estimated costs of decommissioning the nuclear plant owned
by VYNPC is approximately $13.2 million in year-end 1998 dollars.
Millstone 2 and 3
WMECO's estimated cost to decommission its shares of Millstone 2 and
Millstone 3 is approximately $144.0 million in year-end 1998 dollars. These
costs are being recognized over the lives of the respective units with a
portion currently being recovered through rates. As of December 31, 1998,
the market value of the contributions already made to the decommissioning
trusts, including their investment returns, was approximately $66.9 million.
See the "Notes to Consolidated Financial Statements," Note 2, for further
information on nuclear decommissioning.
Year 2000 Issues
The NU system has established an action plan by which identified processes
must be completed by certain dates in order to ensure its operating systems,
including nuclear systems, and reporting systems are able to properly
recognize the year 2000. This action plan has three phases: the inventory
phase, the detailed assessment phase and the remediation phase. The inventory
phase, which has been completed, identified operating and reporting systems
which may need to be fixed. The detailed assessment phase, which has been
completed, determined exactly what needed to be done in order to ensure that
the systems identified during the inventory phase are able to recognize
properly and process the year 2000. The final phase is the remediation phase.
By the end of this phase, mission critical systems (systems that are
related to safety, keeping the lights on, regulatory requirements, and other
systems that could have a significant financial impact) will be year 2000
ready; that is, these systems will perform their business functions properly
in the year 2000. This phase includes making modifications, testing and
validating changes and verifying that the year 2000 issues have been resolved.
Although the identification and detailed assessment phases are complete,
newly identified items, such as new software purchases, are added to the
inventory as they are identified and are subject to detailed assessment and,
if needed, remediation. NU system purchasing policies require newly
purchased software and devices to be year 2000 compliant. None of these newly
identified items are expected to materially impact completion of the
remediation phase.
The NU system has identified and inventoried 2,497 computer systems
(software) and over 24,000 devices (hardware) broken down into 3,450 device
types containing date-sensitive computer chips. As of December 31, 1998, 73
percent of the software systems and 81 percent of the hardware were year
2000 ready.
The remaining items are in various stages of modification or testing.
Management anticipates the remediation phase for mission critical systems to
be completed by mid-1999.
In addition, the NU system has been contacting its key suppliers and business
partners to determine their ability to manage the year 2000 problem
successfully. The NU system is adjusting its inventories, working with
suppliers to provide backup inventories, and changing suppliers as needed to
provide for an adequate supply of materials needed to conduct business into
the year 2000.
The NU system also has worked actively with the Independent System Operator
(ISO) New England, the operator of the New England power grid, and with the
North American Electric Reliability Council to provide for the year 2000
readiness of the New England power grid.
The NU system has utilized both internal and external resources to identify,
assess, test and reprogram or replace the computer systems for year 2000
readiness. The current projected total cost of the Year 2000 Program to the
NU system is $30 million. The total estimated remaining cost is $18 million,
which is being funded through operating cash flows. The majority of these
costs will be expensed as incurred in 1999. Since 1996, the NU system has
incurred and expensed approximately $12 million related to Year 2000
readiness efforts. Total expenditures related to the year 2000 are not
expected to have a material effect on the operations or financial condition
of the NU system.
The costs of the project and the date on which the NU system plans to
complete the year 2000 modifications are based on management's best
estimates, which were derived utilizing numerous assumptions of future
events, including the continued availability of certain resources, third-
party modification plans and other factors. However, there can be no
guarantee that these estimates will be achieved, and actual results could
differ materially from those plans. If the NU system's remediation plans or
those of third parties are not successful, there could be a significant
disruption of the NU system's operations. The most likely worst case
scenario is a limited number of localized interruptions to electric service
which can be restored within a few hours. As a precautionary measure, the NU
system is formulating contingency plans that will evaluate alternatives that
could be implemented if our remediation efforts are not successful. The
contingency plans are being developed by enhancing existing emergency
operating procedures to include year 2000 issues. In addition, the NU system
plans to have staff available to respond to any year 2000 situations that
might arise. The contingency plan is expected to be available by July 30,
1999.
The NU system is committed to assuring that adequate resources are available
in order to implement any changes necessary for its nuclear and other
operations to be compatible with the new millennium.
Environmental Matters
WMECO is potentially liable for environmental cleanup costs at a number of
sites inside and outside its service territory. To date, the future estimated
environmental remediation liability has not been material with respect to the
earnings or financial position of WMECO. At December 31, 1998, WMECO had
recorded an environmental reserve of approximately $1.9 million. See the
"Notes to Consolidated Financial Statements," Note 11D, for further
information on environmental matters.
RESULTS OF OPERATIONS
Income Statement Variances
Millions of Dollars
1998 over/(under) 1997 1997 over/(under) 1996
Amount Percent Amount Percent
Operating revenues $ (33) (8)% $ 5 1 %
Fuel, purchased and net
interchange power (28) (20) 25 22
Other operation (18) (12) 17 12
Maintenance (25) (30) 25 45
Amortization of regulatory
assets, net - - (3) (30)
Federal and state
income taxes 16 (99) (26) (a)
Net income 18 (65) (39) (a)
(a) Percentage greater than 100.
Operating Revenues
Total operating revenues decreased in 1998, primarily due to a 10 percent
retail rate decrease in 1998, partially offset by higher retail sales. Retail
kilowatt-hour sales were 1.3 percent higher than 1997.
Total operating revenues increased in 1997, primarily due to higher
transmission and capacity revenues, partially offset by lower retail sales.
Retail kilowatt-hour sales were 1.0 percent lower in 1997 as a result of mild
winter weather.
Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased in 1998,
primarily due to lower replacement power costs as a result of the return to
service of Millstone 3.
Fuel, purchased and net interchange power expense increased in 1997,
primarily due to replacement power costs associated with the Millstone
outages.
Other Operation and Maintenance
Other operation and maintenance expense decreased in 1998, primarily due to
lower costs at the Millstone units ($30 million), lower capacity charges from
CYAPC and MYAPC ($10 million) and the recognition of environmental insurance
proceeds ($2 million).
Other operation and maintenance expense increased in 1997, primarily due to
higher costs associated with the Millstone restart effort ($40 million),
higher capacity charges from MYAPC ($2 million) and higher costs to ensure
adequate capacity ($6 million), partially offset by lower capacity charges
from CYAPC as a result of a property tax refund ($4 million) and lower
administrative and general expenses primarily due to lower pensions and
benefit costs ($5 million).
Amortization of Regulatory Assets, Net
The change in amortization of regulatory assets, net in 1998 was not
significant.
Amortization of regulatory assets, net decreased in 1997, primarily due to
the completion of the amortization of Millstone 3 investment in 1996.
Federal and State Income Taxes
Federal and state income taxes increased in 1998, primarily due to higher
book taxable income.
Federal and state income taxes decreased in 1997, primarily due to lower book
taxable income.
Western Massachusetts Electric Company And Subsidiary
SELECTED FINANCIAL DATA (a)
1998 1997 1996 1995 1994
(Thousands of Dollars)
Operating Revenues....$ 393,322 $ 426,447 $ 421,337 $ 420,434 $ 421,477
Operating Income/
(Loss).............. 19,854 251 33,190 63,064 70,940
Net (Loss)/Income..... (9,579) (27,460) 11,089 39,133 49,457
Cash Dividends on
Common Stock........ - 15,004 16,494 30,223 29,514
Total Assets.......... 1,287,682 1,179,128 1,191,915 1,142,346 1,183,618
Long-Term Debt (b).... 389,314 396,649 349,442 347,470 379,969
Preferred Stock Not
Subject to Mandatory
Redemption.......... 20,000 20,000 20,000 53,500 68,500
Preferred Stock Subject
to Mandatory
Redemption(b)....... 19,500 21,000 21,000 24,000 24,675
Obligations Under
Capital Leases(b)... 34,093 32,887 32,234 36,011 36,797
(a) Reclassifications of prior data have been made to conform with the
current presentation.
(b) Includes portion due within one year.
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
Quarter Ended (a)
1998 March 31 June 30 Sept. 30 Dec. 31
Operating Revenues......... $107,189 $ 90,649 $93,839 $101,645
Operating Income........... $ 7,838 $ 6,614 $ 4,301 $ 1,101
Net Income/(Loss).......... $ 1,367 $ (738) $(3,546) $ (6,662)
1997
Operating Revenues......... $106,054 $104,130 $111,166 $105,097
Operating Income/(Loss).... $ 675 $ (4,794) $ 1,875 $ 2,495
Net Loss................... $ (5,033) $(11,492) $ (5,303) $ (5,632)
Western Massachusetts Electric Company and Subsidiary
STATISTICS (Unaudited)
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands kWh Sales Residential Customers Employees
of Dollars) (Millions) Customer (kWh) (Average) (December 31)
1998 $1,256,046 4,091 6,979 196,339 533
1997 1,334,233 4,300 7,121 195,324 507
1996 1,303,361 4,626 7,335 194,705 497
1995 1,285,269 4,846 7,105* 193,964 527
1994 1,271,513 4,978 7,433 193,187 617
*Effective January 1, 1996, the amounts shown reflect billed
and unbilled sales. 1995 has been restated to reflect this change.
1998 Annual Report
Public Service Company of New Hampshire
Index
Contents Page
Balance Sheets 2
Statements of Income 4
Statements of Comprehensive Income 4
Statements of Cash Flows 5
Statements of Common Stockholder's Equity 6
Notes to Financial Statements 7
Report of Independent Public Accountants 39
Management's Discussion and Analysis of Financial
Condition and Results of Operations 41
Selected Financial Data 50
Statistics (Unaudited) 52
Statements of Quarterly Financial Data (Unaudited) 52
Preferred Stockholder and Bondholder Information Back Cover
PART I. FINANCIAL INFORMATION
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
BALANCE SHEETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
AT DECEMBER 31, 1998 1997
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at cost:
Electric................................................ $ 1,927,341 $ 1,898,319
Less: Accumulated provision for depreciation......... 631,584 590,056
------------- -------------
1,295,757 1,308,263
Unamortized acquisition costs........................... 352,855 402,285
Construction work in progress........................... 20,735 10,716
Nuclear fuel, net....................................... 1,323 1,308
------------- -------------
Total net utility plant............................. 1,670,670 1,722,572
------------- -------------
Other Property and Investments:
Nuclear decommissioning trusts, at market............... 5,580 4,332
Investments in regional nuclear generating
companies and subsidiary company, at equity............ 19,836 19,169
Other, at cost.......................................... 4,319 3,773
------------- -------------
29,735 27,274
------------- -------------
Current Assets:
Cash and cash equivalents............................... 60,885 94,459
Receivables, less accumulated provision for
uncollectible accounts of $2,041,000 in 1998
and of $1,702,000 in 1997............................. 89,044 89,338
Accounts receivable from affiliated companies........... 12,018 38,520
Accrued utility revenues................................ 42,145 36,885
Fuel, materials and supplies, at average cost........... 36,642 40,161
Recoverable energy costs--current portion............... 65,257 31,886
Prepayments and other................................... 22,744 11,271
------------- -------------
328,735 342,520
------------- -------------
Deferred Charges:
Regulatory assets....................................... 610,222 695,418
Deferred receivable from affiliated company............. 22,728 32,472
Unamortized debt expense................................ 13,995 11,749
Other................................................... 5,510 5,154
------------- -------------
652,455 744,793
------------- -------------
Total Assets........................................ $ 2,681,595 $ 2,837,159
============= =============
</TABLE>
See accompanying notes to financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
BALANCE SHEETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
AT DECEMBER 31, 1998 1997
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock--$1 par value.
Authorized and outstanding 1,000 shares................ $ 1 $ 1
Capital surplus, paid in................................ 424,250 423,713
Retained earnings....................................... 252,912 170,501
Accumulated other comprehensive income.................. 1,004 -
------------- -------------
Total common stockholder's equity.............. 678,167 594,215
Preferred stock subject to mandatory redemption......... 50,000 75,000
Long-term debt.......................................... 516,485 516,485
------------- -------------
Total capitalization........................... 1,244,652 1,185,700
------------- -------------
Obligations Under Seabrook Power Contracts
and Other Capital Leases................................. 703,411 799,450
------------- -------------
Current Liabilities:
Long-term debt and preferred stock--current portion..... 25,000 195,000
Obligations under Seabrook Power Contracts and other
capital leases--current portion........................ 138,812 122,363
Accounts payable........................................ 26,227 21,231
Accounts payable to affiliated companies................ 28,410 32,677
Accrued taxes........................................... 82,743 69,445
Accrued interest........................................ 5,894 7,197
Accrued pension benefits................................ 46,004 46,061
Other................................................... 8,540 9,417
------------- -------------
361,630 503,391
------------- -------------
Deferred Credits:
Accumulated deferred income taxes....................... 225,091 204,406
Accumulated deferred investment tax credits............. 3,460 3,972
Deferred contractual obligations........................ 66,400 83,042
Deferred revenue from affiliated company................ 22,728 32,472
Other................................................... 54,223 24,726
------------- -------------
371,902 348,618
------------- -------------
Commitments and Contingencies (Note 6)
------------- -------------
Total Capitalization and Liabilities........... $ 2,681,595 $ 2,837,159
============= =============
</TABLE>
See accompanying notes to financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1998 1997 1996
- ------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues................................. $ 1,087,247 $ 1,108,459 $ 1,110,169
------------ ------------ ------------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power..... 322,071 326,745 356,679
Other......................................... 402,012 368,363 326,337
Maintenance...................................... 51,734 38,320 45,728
Depreciation..................................... 45,342 44,377 42,983
Amortization of regulatory assets, net........... 26,758 56,557 56,884
Federal and state income taxes................... 65,079 86,450 80,677
Taxes other than income taxes.................... 43,052 43,623 45,123
------------ ------------ ------------
Total operating expenses................... 956,048 964,435 954,411
------------ ------------ ------------
Operating Income................................... 131,199 144,024 155,758
------------ ------------ ------------
Other Income:
Equity in earnings of regional nuclear
generating companies and subsidary company..... 2,649 1,373 2,075
Other, net....................................... 9,222 698 8,075
Income taxes..................................... (7,473) (2,391) (7,723)
------------ ------------ ------------
Other income, net.......................... 4,398 (320) 2,427
------------ ------------ ------------
Income before interest charges............. 135,597 143,704 158,185
------------ ------------ ------------
Interest Charges:
Interest on long-term debt....................... 43,317 51,259 57,557
Other interest................................... 594 273 3,163
------------ ------------ ------------
Interest charges, net...................... 43,911 51,532 60,720
------------ ------------ ------------
Net Income......................................... $ 91,686 $ 92,172 $ 97,465
============ ============ ============
STATEMENTS OF COMPREHENSIVE INCOME
Net Income......................................... $ 91,686 $ 92,172 $ 97,465
------------ ------------ ------------
Other comprehensive income, net of tax:
Unrealized gains on securities..................... 1,198 - -
Minimum pension liability adjustments.............. (194) - -
------------ ------------ ------------
Other comprehensive income, net of tax........... 1,004 - -
------------ ------------ ------------
Comprehensive Income............................... $ 92,690 $ 92,172 $ 97,465
============ ============ ============
</TABLE>
See accompanying notes to financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities:
Net Income.................................................. $ 91,686 $ 92,172 $ 97,465
Adjustments to reconcile to net cash
from operating activities:
Depreciation.............................................. 45,342 44,377 42,983
Deferred income taxes and investment tax credits, net..... 78,366 21,645 94,983
Recoverable energy costs, net of amortization............. 2,065 (12,336) 31,663
Amortization of acquisition costs......................... 49,431 89,417 89,744
Amortization of regulatory liability...................... (32,860) (32,860) (32,860)
Amortization of other regulatory assets................... 10,187 - -
Deferred Seabrook capital costs .......................... (31,587) (8,376) -
Other sources of cash..................................... 32,255 51,054 65,922
Other uses of cash........................................ (53,615) (67,590) (51,188)
Changes in working capital:
Receivables and accrued utility revenues.................. 21,536 9,407 (36,907)
Fuel, materials and supplies.............................. 3,519 4,691 (3,135)
Accounts payable.......................................... 729 (14,897) (7,714)
Accrued taxes............................................. 13,298 69,364 (717)
Other working capital (excludes cash)..................... (13,710) (13,365) (13,559)
----------- ----------- -----------
Net cash flows from operating activities...................... 216,642 232,703 276,680
----------- ----------- -----------
Financing Activities:
Reacquisitions and retirements of long-term debt............ (170,000) - (172,500)
Reacquisitions and retirements of preferred stock........... (25,000) (25,000) -
Cash dividends on preferred stock........................... (9,275) (11,925) (13,250)
Cash dividends on common stock.............................. - (85,000) (52,000)
----------- ----------- -----------
Net cash flows used for financing activities.................. (204,275) (121,925) (237,750)
----------- ----------- -----------
Investment Activities:
Investment in plant:
Electric utility plant.................................... (43,780) (33,570) (37,480)
Nuclear fuel.............................................. (307) 5 129
----------- ----------- -----------
Net cash flows used for investments in plant............ (44,087) (33,565) (37,351)
Investment in NU system Money Pool.......................... - 18,250 850
Investment in nuclear decommissioning trusts................ (641) (490) (521)
Other investment activities, net............................ (1,213) (1,529) (1,010)
----------- ----------- -----------
Net cash flows used for investments........................... (45,941) (17,334) (38,032)
----------- ----------- -----------
Net (decrease)/increase in cash for the period................ (33,574) 93,444 898
Cash and cash equivalents- beginning of period................ 94,459 1,015 117
----------- ----------- -----------
Cash and cash equivalents- end of period...................... $ 60,885 $ 94,459 $ 1,015
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized........................ $ 42,677 $ 51,775 $ 58,835
=========== =========== ===========
Income taxes................................................ $ 18,948 $ 10,612 $ (457)
=========== =========== ===========
(Decrease)/increase in obligations:
Seabrook Power Contracts and other capital leases........... $ (78,939) $ 6,197 $ 93
=========== =========== ===========
</TABLE>
See accompanying notes to financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------
Accumulated
Capital Other
Common Surplus, Retained Comprehensive
Stock Paid In Earnings Income Total
- --------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1996............... $ 1 $422,385 $143,039 $ - $565,425
Net income........................... 97,465 97,465
Cash dividends on preferred stock.... (13,250) (13,250)
Cash dividends on common stock....... (52,000) (52,000)
Capital stock expenses, net.......... 673 673
-------- --------- --------- ------------- ---------
Balance at December 31, 1996............. 1 423,058 175,254 - 598,313
Net income........................... 92,172 92,172
Cash dividends on preferred stock.... (11,925) (11,925)
Cash dividends on common stock....... (85,000) (85,000)
Capital stock expenses, net.......... 655 655
-------- --------- --------- ------------- ---------
Balance at December 31, 1997............. 1 423,713 170,501 - 594,215
Net income........................... 91,686 91,686
Cash dividends on preferred stock.... (9,275) (9,275)
Capital stock expenses, net.......... 537 537
Other comprehensive income........... 1,004 1,004
-------- --------- --------- ------------- ---------
Balance at December 31, 1998............. $ 1 $424,250 $252,912 $ 1,004 $678,167
======== ========= ========= ============= =========
</TABLE>
See accompanying notes to financial statements.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. About Public Service Company of New Hampshire
Public Service Company of New Hampshire (PSNH or the company), The
Connecticut Light and Power Company (CL&P), Western Massachusetts
Electric Company (WMECO),North Atlantic Energy Corporation (NAEC)
and Holyoke Water Power Company (HWP) are the operating subsidiaries
comprising the Northeast Utilities system (the NU system) and are
wholly owned by Northeast Utilities (NU).
The NU system furnishes franchised retail electric service in
Connecticut, New Hampshire, and western Massachusetts through CL&P,
PSNH and WMECO. NAEC sells all of its entitlement to the capacity
and output of the Seabrook nuclear power plant (Seabrook, a 1,148
megawatt (MW) nuclear power generating unit) to PSNH under two life-
of-unit, full cost recovery contracts (the Seabrook Power Contracts).
HWP is also engaged in the production and distribution of electric
power. The NU system also furnishes firm and other wholesale electric
services to various municipalities and other utilities, and participates
in limited retail access programs, providing off-system retail electric
service. The NU system serves in excess of 30 percent of New England's
electric needs and is one of the 24 largest electric utility systems in
the country as measured by revenues.
NU is registered with the Securities and Exchange Commission (SEC)
as a holding company under the Public Utility Holding Company Act
of 1935 (1935 Act). NU and its subsidiaries, including PSNH, are
subject to the provisions of the 1935 Act. Arrangements among the
NU system companies, outside agencies and other utilities covering
interconnections, interchange of electric power and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. PSNH is subject to further
regulation for rates, accounting and other matters by the FERC
and/or the applicable state regulatory commissions.
Other wholly owned subsidiaries of NU provide support services for
the NU system companies and, in some cases, for other New England
utilities. Northeast Utilities Service Company (NUSCO) provides
centralized accounting, administrative, information resources,
engineering, financial, legal, operational, planning, purchasing and
other services to the NU system companies. North Atlantic Energy
Service Corporation (NAESCO) acts as agent for CL&P and NAEC, and
has operational responsibilities for Seabrook. Northeast Nuclear
Energy Company (NNECO) acts as agent for the NU system companies and
other New England utilities in operating the Millstone nuclear
generating facilities.
During the first quarter of 1999, NU established three new
subsidiaries: NU Enterprises, Inc., Northeast Generation Company,
and Northeast Generation Services Company. Directly or through
multiple subsidiaries, these entities will engage in a variety of
energy-related activities, including the acquisition and management
of non-nuclear generating plants.
B. Presentation
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 disclosure of contingent 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.
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
All transactions among affiliated companies are on a recovery of
cost basis which may include amounts representing a return on equity
and are subject to approval by various federal and state regulatory
agencies.
C. New Accounting Standards
The Financial Accounting Standards Board (FASB) issued a new
accounting standard during 1998: Statement of Financial Accounting
Standards (SFAS) 132, "Employers' Disclosures About Pensions and
Other Postretirement Benefits."
SFAS 132 revises employers' disclosures about pension and other
postretirement benefit plans, but it does not change the measurement
or recognition of those plans. See Note 6, "Pension Benefits and
Postretirement Benefits Other Than Pensions," for further information
on PSNH's pension and postretirement benefits disclosures.
During June 1997, the FASB issued SFAS 131, "Disclosures about
Segments of an Enterprise and Related Information." SFAS 131
determines the standards for reporting and disclosing qualitative
and quantitative information about a company's operating segments.
More specifically, it requires financial information to be disclosed
for segments whose operating results are received by the chief
operating officer for decisions on resource allocation. It also
requires related disclosures about products and services, geographic
areas and major customers. PSNH currently evaluates management
performance using a cost-based budget, and the information required
by SFAS 131 is not available.
As a result of the changes which PSNH and the industry are undergoing
the company will implement business segment reporting in 1999. This
reporting will provide management with revenue and expense information
at the business segment level. Management has identified significant
segments to include transmission, distribution, generation-related
and energy marketing.
D. Investments and Jointly Owned Electric Utility Plant
Regional Nuclear Generating Companies: PSNH owns common stock of
four regional nuclear generating companies (Yankee companies) which
are accounted for on the equity basis due to PSNH's ability to
exercise significant influence over their operating and financial
policies. PSNH's ownership interests in the Yankee companies at
December 31, 1998 are:
Connecticut Yankee Atomic Power Company (CYAPC) 5.0%
Yankee Atomic Electric Company (YAEC) 7.0
Maine Yankee Atomic Power Company (MYAPC) 5.0
Vermont Yankee Nuclear Power Corporation (VYNPC) 4.0
PSNH's equity investments in the Yankee companies at December 31,
1998 are:
(Thousands of Dollars)
CYAPC....................... $ 5,457
YAEC........................ 1,356
MYAPC....................... 4,312
VYNPC....................... 2,227
$13,352
Each Yankee company owns a single nuclear generating unit. YAEC's,
CYAPC's and MYAPC's nuclear power plants were shut down permanently
on February 26, 1992, December 4, 1996 and August 6, 1997,
respectively. For further information on the Yankee companies, see
Note 4, "Nuclear Decommissioning and Plant Closure Costs."
Millstone 3: PSNH has a 2.85 percent joint ownership interest in
Millstone 3, a 1,154 MW nuclear generating unit. As of December 31,
1998 and 1997, plant-in-service included approximately $118.8
million and $118.7 million, respectively, and the accumulated
provision for depreciation included approximately $35.5 million and
$32.3 million, respectively, for PSNH's share of Millstone 3. PSNH's
share of Millstone 3 expenses is included in the corresponding
operating expenses on the accompanying Statements of Income.
For further information on the Millstone 3 unit, see Note 10C,
"Commitments and Contingencies - Nuclear Performance."
Wyman Unit 4: PSNH has a 3.14 percent ownership interest in Wyman
Unit 4 (Wyman), a 632 MW oil-fired generating unit. At December 31,
1998 and 1997, plant-in-service included approximately $6.1 million
and $6.0 million, respectively and the accumulated provision for
depreciation included approximately $4.0 million and $3.9 million,
respectively, for PSNH's share of Wyman. PSNH's share of Wyman
expenses is included in the corresponding operating expenses on the
accompanying Statements of Income.
E. Depreciation
The provision for depreciation is calculated using the straight-line
method based on estimated remaining lives of depreciable utility
plant-in-service, adjusted for salvage value and removal costs, as
approved by the appropriate regulatory agency. Except for major
facilities, depreciation rates are applied to the average plant-in-
service during the period. Major facilities are depreciated from the
time they are placed in service. When plant is retired from service,
the original cost of plant, including costs of removal, less salvage,
is charged to the accumulated provision for depreciation. The costs
of closure and removal of non-nuclear facilities are accrued over the
life of the plant as a component of depreciation. The depreciation
rates for the several classes of electric plant-in-service are
equivalent to a composite rate of 3.6 percent in 1998 and 3.7 percent
in 1997 and 1996. See Note 4, "Nuclear Decommissioning and Plant
Closure Costs," for information on nuclear plant decommissioning.
At December 31, 1998 and 1997, the accumulated provision for
depreciation included approximately $37.3 million and $34.2 million,
respectively, accrued for the cost of removal, net of salvage for
non-nuclear generation property.
F. Revenues
Other than revenues under fixed-rate agreements negotiated with
certain wholesale, commercial and industrial customers and limited
retail access programs, utility revenues are based on authorized
rates applied to each customer's use of electricity. In general,
rates can be changed only through a formal proceeding before the
appropriate regulatory commission. Regulatory commissions also have
authority over the terms and conditions of nontraditional rate
making arrangements. At the end of each accounting period, PSNH
accrues an estimate for the amount of energy delivered but unbilled.
For information on PSNH rate proceedings and the impact on PSNH, see
Management's Discussion and Analysis of Financial Condition and
Results of Operations (MD&A), and Note 10B, "Commitments and
Contingencies - Rate Matters."
G. Acquisition Costs
The PSNH acquisition costs represent the aggregate value placed by
the 1989 rate agreement with the state of New Hampshire (Rate
Agreement) on PSNH's assets in excess of the net book value of
PSNH's non-Seabrook assets, plus the $700 million value assigned to
Seabrook by the Rate Agreement, as part of the bankruptcy resolution
on June 5, 1992 (Acquisition Date). The Rate Agreement provides for
the recovery through rates, with a return, of the PSNH acquisition
costs. The unrecovered balance at December 31, 1998, was approximately
$352.9 million and is being recovered ratably over a 20-year period
through May 1, 2011 in accordance with the Rate Agreement. Through
December 31, 1998, PSNH has collected approximately $640.0 million of
acquisition costs.
H. Regulatory Accounting and Assets
The accounting policies of PSNH and the accompanying financial
statements conform to generally accepted accounting principles
applicable to rate-regulated enterprises and reflect the effects of
the ratemaking process in accordance with SFAS 71, "Accounting for
the Effects of Certain Types of Regulation." Assuming a cost-of-
service based regulatory structure, regulators may permit incurred
costs, normally treated as expenses, to be deferred and recovered
through future revenues. Through their actions, regulators may also
reduce or eliminate the value of an asset, or create a liability. If
any portion of PSNH's operations were no longer subject to the
provisions of SFAS 71, PSNH would be required to write off all of its
related regulatory assets and liabilities unless there is a formal
transition plan which provides for the recovery, through established
rates, for the collection of these costs through a portion of the
business which would remain regulated on a cost-of-service basis. At
the time of transition, PSNH would be required to determine any
impairment to the carrying costs of deregulated plant and inventory
assets.
Management anticipates that a restructuring program will be
implemented in New Hampshire, and such a program is currently the
focus of negotiations and proceedings within the federal and state
legal systems. However, management continues to believe the
application of SFAS 71 remains appropriate at this time. Once PSNH's
restructuring plan has been formally approved by the appropriate
regulatory agency and management can determine the impacts of
restructuring, PSNH's generation businesses no longer will be rate
regulated on a cost-of-service basis. The majority of PSNH's
regulatory assets are related to its generation business. Management
expects that the transmission and distribution business within New
Hampshire will continue to be rate-regulated on a cost-of-service
basis and restructuring plans will allow for the recovery of
regulatory assets through this portion of the business.
For further information on PSNH's regulatory environment and the
potential impacts of restructuring, see Note 10A, "Commitments and
Contingencies - Restructuring" and the MD&A.
Based on a current evaluation of the various factors and conditions
that are expected to impact future cost recovery, management
continues to believe it is probable that PSNH will recover its
investments in long-lived assets, including regulatory assets.
The components of PSNH's regulatory assets are as follows:
At December 31, 1998 1997
(Thousands of Dollars)
Recoverable energy costs, net
(Note 1J)......................... $156,250 $191,686
Income taxes, net (Note 1I)......... 139,739 128,244
Unrecovered contractual
obligations (Note 1K)............. 66,400 83,042
Deferred costs - nuclear
plants (Note 1L).................. 244,599 290,232
Other............................... 3,234 2,214
$610,222 $695,418
I. Income Taxes
The tax effect of temporary differences (differences between the
periods in which transactions affect income in the financial
statements and the periods in which they affect the determination of
taxable income) is accounted for in accordance with the ratemaking
treatment of the applicable regulatory commissions. See Note 9,
"Income Tax Expense" for the components of income tax expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, that give
rise to the accumulated deferred tax obligation is as follows:
At December 31, 1998 1997
(Thousands of Dollars)
Accelerated depreciation and
other plant-related differences.... $100,786 $103,985
Net operating loss (NOL)
carryforwards...................... (25,610) (94,822)
Regulatory assets - income tax
gross up........................... 52,425 49,101
Other................................ 97,490 146,142
$225,091 $204,406
At December 31, 1998, PSNH had a federal NOL carryforward of
approximately $94 million that can be used against PSNH's federal
taxable income and which if unused, expires between the years 2005
and 2006. PSNH also had Investment Tax Credit (ITC) carryforwards of
$37 million which if unused, expire between the years 1999 and 2004.
The reorganization of PSNH under Chapter 11 of the United States
Bankruptcy Code limits the annual amount of ITC carryforward that
may be used. Approximately $6 million of the ITC carryforward is
subject to this limitation.
J. Recoverable Energy Costs
Under the Energy Policy Act of 1992 (Energy Act), PSNH is assessed
for its proportionate share of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States
Department of Energy (D&D assessment). The Energy Act requires
that regulators treat D&D assessments as a reasonable and necessary
current cost of fuel, to be fully recovered in rates like any other
fuel cost. PSNH is currently recovering these costs through rates.
As of December 31, 1998, PSNH's total D&D deferrals were approximately
$237,000.
The Rate Agreement includes a comprehensive fuel and purchased power
adjustment clause (FPPAC) permitting PSNH to pass through to retail
customers, for a 10-year period that began in May 1991, the retail
portion of differences between the fuel and purchased power costs
assumed in the Rate Agreement and PSNH's actual costs, which include
the costs related to the Seabrook Power Contracts and the Clean Air
Act Amendment. The cost components of the FPPAC are subject to a
prudence review by the New Hampshire Public Utilities Commission
(NHPUC). At December 31, 1998, recoverable energy costs include
$156.3 million of noncurrent recoverable energy costs deferred under
the FPPAC.
Under the Rate Agreement, charges made by NAEC through the Seabrook
Power Contracts, including the deferred Seabrook capital expenses,
are to be deferred by PSNH and subsequently billed and collected by
PSNH through the FPPAC. PSNH began to defer the amount of these
costs on December 1, 1997 and continued to do so for the period
December 1, 1997 through May 31, 1998. Beginning on June 1, 1998,
these costs began to be recovered over a 36-month period. At
December 31, 1998, PSNH has deferred approximately $40.0 million
of these costs, which balance is recorded in PSNH's deferred costs,
nuclear plants.
See Note 10A, "Commitments and Contingencies - Restructuring" for the
possible impacts on PSNH of the NHPUC's decision related to industry
restructuring.
K. Unrecovered Contractual Obligations
Under the terms of contracts with MYAPC, CYAPC, and YAEC, the
shareholder-sponsor companies, including CL&P, PSNH and WMECO, are
responsible for their proportionate share of the remaining costs of
the units, including decommissioning. As management expects that the
NU system companies will be allowed to recover these costs from their
customers, the NU system companies have recorded regulatory assets,
with corresponding obligations on their respective balance sheets.
For further information, see Note 4, "Nuclear Decommissioning and
Plant Closure Costs."
L. Deferred Costs - Nuclear Plants
Under the Rate Agreement, the plant costs of Seabrook were phased
into rates over a seven-year period beginning May 15, 1991. These
deferred costs are being billed to PSNH by NAEC through the Seabrook
Power Contracts beginning December 1, 1997, and will be fully
recovered from PSNH's customers by May 2001.
M. Cash and Cash Equivalents
Cash and cash equivalents includes cash on hand and short-term cash
investments which are highly liquid in nature and have original
maturities of three months or less.
2. SEABROOK POWER CONTRACTS
PSNH and NAEC have entered into two power contracts that obligate PSNH
to purchase NAEC's 35.98 percent ownership of the capacity and output of
Seabrook for the term of Seabrook's Nuclear Regulatory Commission (NRC)
operating license. Under these power contracts, PSNH is obligated to
pay NAEC's cost of service during this period, regardless of whether
Seabrook 1 is operating. NAEC's cost of service includes all of its
Seabrook-related costs, including operation and maintenance (O&M)
expenses, fuel expense, income and property tax expense, depreciation
expense, certain overhead and other costs and a return on its allowed
investment.
PSNH has included its right to buy power from NAEC on its Balance Sheets
as part of utility plant and regulatory assets with a corresponding
obligation. At December 31, 1998, this right was valued at
approximately $838.1 million.
The contracts established the value of the initial investment in Seabrook
(initial investment) at $700 million. As prescribed by the Rate Agreement,
as of May 1, 1996, NAEC phased into rates 100 percent of its investment
in Seabrook 1. This plan is in compliance with SFAS 92,"Regulated
Enterprises-Accounting for Phase-in Plans." From the Acquisition Date
through November 1997, NAEC recorded $203.9 million of deferred return on
its investment in Seabrook 1. At November 30, 1997, NAEC's utility plant
included $84.1 million of deferred return that was transferred as part of
the Seabrook plant assets to NAEC on the Acquisition Date. Beginning on
December 1, 1997, the deferred return, including the portion transferred
to NAEC, is currently being billed through the Seabrook Power Contracts
to PSNH and will be fully recovered from customers by May 2001. NAEC
depreciated its initial investment over the term of Seabrook 1's
operating license (39 years), and any subsequent plant additions are
depreciated on a straight-line basis over the remaining term of the
power contracts at the time the subsequent additions are placed in
service.
If Seabrook 1 is shut down prior to the expiration of the NRC operating
license, PSNH will be unconditionally required to pay NAEC termination
costs for 39 years, less the period during which Seabrook 1 has operated.
These termination costs will reimburse NAEC for its share of Seabrook 1
shut-down and decommissioning costs, and will pay NAEC a return of and
on any undepreciated balance of its initial investment over the remaining
term of the power contracts, and the return of and on any capital
additions to the plant made after the Acquisition Date over a period of
five years after shut down (net of any tax benefits to NAEC attributable
to the cancellation).
Contract payments charged to operating expenses are approximately:
Year Contract Payments
(Thousands of Dollars)
1998............................ $272,000
1997............................ 188,000
1996............................ 159,000
Interest included in the contract payment was $54 million in 1998, $57
million in 1997, and $55 million in 1996.
Future minimum payments, excluding executory costs, such as property
taxes, state use taxes, insurance and maintenance, under the terms of
the contracts, as of December 31, 1998, are approximately:
Year Seabrook Power Contracts
(Thousands of Dollars)
1999........................... $ 195,000
2000........................... 193,000
2001........................... 117,000
2002........................... 78,100
2003........................... 76,000
After 2003..................... 1,095,000
Future minimum payments........ 1,754,000
Less amount representing
interest..................... 916,000
Present value of Seabrook Power
Contracts payments........... $ 838,100
See Note 10A, "Commitments and Contingencies - Restructuring" for the
possible impacts the NHPUC's restructuring decision may have on the
Seabrook Power Contracts.
3. LEASES
PSNH has entered into lease agreements, some of which are capital leases,
for the use of data processing and office equipment, vehicles and office
space. The provisions of these lease agreements generally provide for
renewal options. The following rental payments have been charged to
expense:
Year Capital Leases Operating Leases
1998................. $1,584,000 $5,392,000
1997................. 1,579,000 5,657,000
1996................. 1,105,000 4,884,000
Interest included in capital lease rental payments was $193,000 in 1998,
$272,000 in 1997 and $292,000 in 1996.
Future minimum rental payments, excluding executory costs, such as
property taxes, state use taxes, insurance and maintenance, under long-
term noncancellable leases, as of December 31, 1998, are:
Year Capital Leases Operating Leases
(Thousands of Dollars)
1999.................... $1,400 $ 5,800
2000.................... 1,200 5,100
2001.................... 1,200 4,600
2002.................... 400 2,500
2003.................... 400 1,300
After 2003.............. 1,500 3,000
Future minimum lease
payments............... 6,100 $22,300
Less amount representing
interest............... 2,000
Present value of future
minimum lease payments. $4,100
4. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
Millstone 3 and Seabrook 1: Millstone 3 and Seabrook 1 have service
lives that are expected to end during the years 2025 and 2026,
respectively. Upon retirement, these units must be decommissioned.
Current decommissioning studies conclude that complete and immediate
dismantlement at retirement continues to be the most viable and economic
method of decommissioning Millstone 3 and Seabrook 1. Decommissioning
studies are reviewed and updated periodically to reflect changes in
decommissioning requirements, costs, technology and inflation.
The estimated cost of decommissioning PSNH's 2.85 percent ownership share
of Millstone 3 and NAEC's 35.98 percent share of Seabrook 1, in year-end
1998 dollars is $15.9 million and $175.9 million, respectively. Millstone 3
and Seabrook 1 decommissioning costs will be increased annually by their
respective escalation rates. PSNH's Millstone 3 decommissioning costs
are accrued over the expected service life of the unit and are included in
depreciation expense on its Statements of Income. Nuclear decommissioning
costs related to PSNH's share of Millstone 3 amounted to $0.4 million in
1998, 1997 and 1996. Nuclear decommissioning, as a cost of removal, is
included in the accumulated provision for depreciation on PSNH's Balance
Sheets. At December 31, 1998 and 1997, the balance in the accumulated
reserve for depreciation amounted to $3.0 million and $2.6 million,
respectively.
PSNH makes payments to an independent decommissioning trust for its
portion of the costs of decommissioning Millstone 3. NAEC's portion of
the cost of decommissioning Seabrook 1 is paid to an independent
decommissioning financing fund managed by the state of New Hampshire.
Funding of the estimated decommissioning costs assumes levelized
collections for Millstone 3 and escalated collections for Seabrook 1,
and after-tax earnings on the Millstone and Seabrook decommissioning
funds of approximately 5.5 percent and 6.5 percent, respectively. Under
the terms of the Rate Agreement, PSNH is obligated to pay NAEC's share
of Seabrook's decommissioning costs, even if the unit is shut down prior
to the expiration of its operating license. Accordingly, NAEC bills PSNH
directly for its share of the costs of decommissioning Seabrook 1. PSNH
records its Seabrook decommissioning costs as a component of purchased
power expense on its Statements of Income. Under the Rate Agreement,
PSNH's Seabrook decommissioning costs are recovered through base rates.
As of December 31, 1998, PSNH collected through rates approximately
$3.0 million toward the future decommissioning costs of its share of
Millstone 3, which has been transferred to the external decommissioning
trust. As of December 31, 1998, NAEC has paid approximately $25.6
million (including payments made prior to the Acquisition Date by PSNH),
into Seabrook 1's decommissioning financing fund. Earnings on the
decommissioning trust and financing fund increase the decommissioning
trust balance and the accumulated reserve for depreciation. Unrealized
gains and losses associated with the decommissioning trust and financing
fund also impact the balance of the trust, and the accumulated reserve
for depreciation. The fair value of the amounts in the external
decommissioning trust and financing fund was $5.6 million and $35.2
million, respectively, as of December 31, 1998.
Changes in requirements or technology, the timing of funding or
dismantling, or adoption of a decommissioning method other than immediate
dismantlement would change decommissioning cost estimates and the amounts
required to be recovered. PSNH attempts to recover sufficient amounts
through its allowed rates to cover its expected decommissioning costs.
Only the portion of currently estimated total decommissioning costs that
has been accepted by regulatory agencies is reflected in rates of PSNH.
Based on present estimates and assuming its nuclear units operate to
the end of their respective licensing periods, PSNH expects that the
decommissioning trust and financing fund will be substantially funded
when the units are retired from service.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with
a service life that is expected to end in 2012. PSNH's ownership share of
estimated costs, in year-end 1998 dollars, of decommissioning the unit
owned and operated by VYNPC is approximately $21.2 million.
At December 31, 1998, the remaining estimated obligation, including
decommissioning, for the Yankee company nuclear generating facilities
which have been shut down were:
Total PSNH's
(Thousands of Dollars) Obligation Share
Maine Yankee.................... $715,065 $ 35,753
Connecticut Yankee.............. 498,557 24,928
Yankee Atomic................... 81,699 5,719
For further information on the Yankee companies, see Note 10B,
"Commitments and Contingencies - Rate Matters."
For information on proposed changes to the accounting for decommissioning,
see the MD&A.
5. SHORT-TERM DEBT
The amount of short-term borrowings that may be incurred by PSNH is
subject to periodic approval by either the SEC under the 1935 Act or
by the NHPUC. Effective April 1998, PSNH was authorized under a waiver
from the NHPUC, to incur short-term borrowings up to a maximum of $75
million.
PSNH has access to a $75 million revolving credit agreement entered
into in April 1998 with a group of 16 banks. The borrowing level under
this agreement was reduced from the previous $125 million level. The
agreement will expire in April 1999. Under the terms of this agreement,
PSNH is obligated to pay a facility fee of .50 percent per annum on the
commitment. PSNH's borrowings under the $75 million agreement are
secured, per dollar of borrowing, by $75 million of first mortgage bonds
and substantially all of PSNH's accounts receivable. There were no
borrowings under this facility at December 31, 1998.
On March 20, 1998, in connection with the $75 million PSNH credit
agreement, the NHPUC issued an order requiring PSNH to obtain NHPUC
approval before paying any dividends on its common stock and before
investing any PSNH funds in the NU system Money Pool during the expected
364-day term of the facilities. PSNH has not sought such authorization.
Under the credit agreement discussed above, PSNH may borrow funds on a
short-term revolving basis under its agreement, using either fixed-rate
loans or standby loans. Fixed rates are set using competitive bidding.
Standby loans are based upon several alternative variable rates.
Money Pool: Certain subsidiaries of NU, including PSNH, are members of
the Northeast Utilities System Money Pool (Pool). The Pool provides a
more efficient use of the cash resources of the NU system, and reduces
outside short-term borrowings. NUSCO administers the Pool as agent
for the member companies. Short-term borrowing needs of the member
companies are first met with available funds of other member companies,
including funds borrowed by NU parent. NU parent may lend to the Pool
but may not borrow. Funds may be withdrawn from or repaid to the Pool
at any time without prior notice. Investing and borrowing subsidiaries
receive or pay interest based on the average daily Federal Funds rate.
However, borrowings based on loans from NU parent bear interest at NU
parent's cost and must be repaid based upon the terms of NU parent's
original borrowing. At December 31, 1998 and 1997, PSNH had no
outstanding borrowings from the Pool. Due to the conditions placed
on PSNH by lenders and the NHPUC during April 1998 refinancings, PSNH
is presently restricted from lending money to the NU System Money Pool.
Maturities of PSNH's short-term debt obligations are for periods of
three months or less.
6. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system's subsidiaries participate in a uniform noncontributory
defined benefit retirement plan covering all regular NU system
employees. Benefits are based on years of service and employees'
highest eligible compensation during 60 consecutive months of employment.
PSNH's direct portion of the NU system's pension (credit)/cost, part
of which was charged to utility plant, approximated $(0.06) million
in 1998, $1.3 million in 1997 and $6.2 million in 1996.
Currently, PSNH annually funds an amount at least equal to that which
will satisfy the requirements of the Employee Retirement Income Security
Act and the Internal Revenue Code. Pension costs are determined using
market-related values of pension assets.
PSNH also provides certain health care benefits, primarily medical and
dental, and life insurance benefits through a benefit plan to retired
employees. These benefits are available for employees retiring from PSNH
who have met specified service requirements. For current employees and
certain retirees, the total benefit is limited to two times the 1993 per-
retiree health care cost. These costs are charged to expense over the
future estimated work life of the employee. PSNH is funding postretirement
costs through external trusts. PSNH is funding, on an annual basis,
amounts that have been rate-recovered and which also are tax deductible
under the Internal Revenue Code.
Pension and trust assets are invested primarily in domestic and
international equity securities and bonds.
The following table represents the plans' beginning benefit obligation
balance reconciled to the ending benefit obligation balance, beginning
fair value of plan assets balance reconciled to the ending fair value of
plan assets balance and the respective funds' funded status reconciled to
the Balance Sheets:
The components of net cost are:
At December 31,
Postretirement
Pension Benefits Benefits
1998 1997 1998 1997
(Thousands of Dollars)
Change in benefit
obligation
Benefit obligation at
beginning of year........... $(187,968) $(179,192) $(46,609) $(47,963)
Service cost.................. (4,275) (4,021) (858) (802)
Interest Cost................. (13,192) (13,398) (3,439) (3,352)
Transfers..................... (729) 1,049 - -
Actuarial (loss)/gain......... (5,128) (4,434) (2,807) 1,782
Benefits paid................. 10,249 10,995 3,644 3,726
Special termination benefits.. - 1,033 - -
Benefit obligation at
end of year................. $(201,043) $(187,968) $(50,069) $(46,609)
Change in plan assets
Fair value of plan assets at
beginning of year........... $ 195,612 $ 173,035 $ 22,908 $ 17,882
Actual return on plan assets. 27,088 34,621 3,211 3,697
Employer contribution......... - - 4,847 5,055
Benefits paid................. (10,249) (10,995) (3,644) (3,726)
Transfers..................... 729 (1,049) - -
Fair value of plan assets
at end of year.............. $ 213,180 $ 195,612 $ 27,322 $ 22,908
Funded status at
December 31................. $ 12,137 $ 7,644 $(22,747) $(23,701)
Unrecognized transition
amount...................... 3,670 4,003 41,167 44,108
Unrecognized prior service
cost........................ 7,058 7,597 - -
Unrecognized net gain......... (68,869) (65,305) (18,420) (20,407)
Accrued benefit cost.......... $ (46,004) $(46,061) $ - $ -
The following actuarial assumptions were used in calculating the plan's year-
end funded status:
At December 31,
Pension Postretirement
Benefits Benefits
1998 1997 1998 1997
Discount rate.................... 7.00% 7.25% 7.00% 7.25%
Compensation/progression rate.... 4.25% 4.25% 4.25% 4.25%
Health care cost trend rate (a).. N/A N/A 5.22% 5.76%
(a) The annual growth in per capita cost of covered health care benefits was
assumed to decrease to 4.40 percent by 2001.
The components of net periodic benefit cost are:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
1998 1997 1996 1998 1997 1996
(Thousands of Dollars)
Service cost.......... $ 4,275 $ 4,021 $ 4,245 $ 858 $ 802 $ 914
Interest cost......... 13,192 13,398 12,808 3,439 3,352 3,559
Expected return on
plan assets......... (15,626) (13,873) (12,344) (1,767) (1,385) (821)
Amortization of
unrecognized transition
obligation.......... 334 334 334 2,941 2,941 2,941
Amortization of prior
service cost........ 539 539 539 - - -
Amortization of
actuarial
gain................ (2,771) (2,115) (1,315) - - -
Other amortization,
net................. - - - (624) (827) (352)
Curtailment........... - (1,033) 1,917 - - -
Net periodic
(credit)/cost....... $ (57) $ 1,271 $ 6,184 $ 4,847 $ 4,883 $ 6,241
For calculating pension and postretirement benefit costs, the following
assumptions were used:
For the Years Ended December 31,
Postretirement
Pension Benefits Benefits
1998 1997 1996 1998 1997 1996
Discount rate........ 7.25% 7.75% 7.50% 7.25% 7.75% 7.50%
Expected long-term
rate of return...... 9.50% 9.25% 8.75% N/A N/A N/A
Compensation/
progression rate.... 4.25% 4.75% 4.75% 4.25% 4.75% 4.75%
Long-term rate
of return-
Health assets
net of tax......... N/A N/A N/A 7.75% 7.50% 5.25%
Life assets......... N/A N/A N/A 9.50% 9.25% 8.75%
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. The effect of changing the
assumed health care cost trend rate by one percentage point in each year
would have the following effects:
One Percentage One Percentage
(Thousands of Dollars) Point Increase Point Decrease
Effect on total service
and interest cost
components of net periodic
retirement health care
benefit costs................. $ 236 $ (224)
Effect on accumulated post-
retirement benefit
obligation.................... 3,178 (2,952)
The trust holding the health plan assets is subject to federal income
taxes at a 39.6 percent tax rate.
7. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
Shares
Outstanding December 31,
Description December 31, 1998 1998 1997 1996
(Thousands of Dollars)
10.60%
Series A of 1991...... 3,000,000 $ 75,000 $100,000 $125,000
Less preferred stock
to be redeemed
within one year..... 1,000,000 25,000 25,000 25,000
Total................. $ 50,000 $ 75,000 $100,000
In case of default on dividends or sinking-fund payments, no payments
may be made on any junior stock by way of dividends or otherwise (other
than in shares of junior stock) so long as the default continues. If
PSNH is in arrears in the payment of dividends on any outstanding shares
of preferred stock, PSNH would be prohibited from redemption or purchase
of less than all of the preferred stock outstanding. The Series A
Preferred Stock is not subject to optional redemption by PSNH. It is
subject to an annual sinking fund requirement of $25 million, which
began on June 30, 1997, sufficient to retire annually 1,000,000 shares
at $25 per share.
8. LONG-TERM DEBT
Details of long-term debt outstanding are:
At December 31,
1998 1997
---- ----
(Thousands of Dollars)
First Mortgage Bonds:
9.17% Series B, due 1998 $ - $170,000
Pollution Control Revenue Bonds:
7.65% Tax-Exempt Series A, due 2021........ 66,000 66,000
7.50% Tax-Exempt Series B, due 2021........ 108,985 108,985
7.65% Tax-Exempt Series C, due 2021........ 112,500 112,500
Adjustable Rate, Taxable, Series D,due 2021.. 39,500 39,500
Adjustable Rate, Taxable, Series E, due 2021. 69,700 69,700
6% Tax-Exempt, Series D, due 2021............ 75,000 75,000
6% Tax-Exempt, Series E due 2021 (a)......... 44,800 44,800
Less: Amounts due within one year........... - 170,000
Long-term debt, net................. $516,485 $516,485
(a) On April 23, 1998, PSNH amended and extended letters of credit and
reimbursement agreements that provide credit support for $39.5 million
principal amount of taxable Pollution Control Refunding Revenue Bonds
(PCRB), 1991 Series D, due May 1, 2021, and $69.7 million principal
amount of taxable PCRB, 1991 Series E, due 2021.
The Series D and E taxable PCRB's are special limited obligations
of the Business Finance Authority of the State of New Hampshire (BFA)
and are payable solely by PSNH under the applicable loan and trust
agreements. PSNH's obligations to make payments under the loan and
trust agreements, letters of credit and reimbursement agreements are
secured by approximately $110 million of first mortgage bonds and
substantially all of PSNH's accounts receivable.
On May 1, 1998, the $75 million principal amount of tax-exempt PCRB,
1992 Series D, due May 1, 2021, and $44.8 million principal amount
of tax-exempt PCRB, 1993 Series E, due May 1, 2021, which were
previously issued by the BFA on PSNH's behalf as variable rate
bonds, were converted to fixed rate bonds bearing interest at 6
percent per annum. These bonds are special limited obligations of
the BFA and are payable solely by PSNH under the applicable loan and
trust agreement.
There are neither cash sinking-fund requirements nor debt maturities
existing for the years 1999 through 2003. There are annual renewal and
replacement fund requirements equal to 2.25 percent of the average of
net depreciable utility property owned by PSNH at the reorganization
date, plus cumulative gross property additions thereafter. PSNH expects
to meet these future fund requirements by certifying property additions.
Any deficiency would need to be satisfied by the deposit of cash or bonds.
PSNH's $75 million Revolving Credit Facility has a lien, on all PSNH
property located in New Hampshire which will expire in April 1999. At
December 31, 1998, there were no borrowings under the Revolving Credit
Facility.
Concurrent with the issuance of PSNH's Series A and B First Mortgage
Bonds, PSNH entered into financing arrangements with the BFA. Pursuant
to these arrangements, the BFA issued seven series of Pollution Control
Revenue Bonds (PCRBs) and loaned the proceeds to PSNH. The average
effective interest rates on the variable-rate pollution control notes
ranged from 3.1 percent to 5.6 percent in 1998 and from 3.8 percent to
5.6 percent in 1997. PSNH's obligation to repay each series of PCRBs is
secured by a series of first mortgage bonds that were issued under its
indenture. Each such series of first mortgage bonds contains terms and
provisions with respect to maturity, principal payment, interest rate,
and redemption that correspond to those of the applicable series of
PCRBs. For financial reporting purposes, these bonds would not be
considered outstanding unless PSNH fails to meet its obligations under
the PCRBs.
The PCRBs, except for taxable Series D and E and tax-exempt Series D
and E, are redeemable on or after May 1, 2001 and May 1, 2008,
respectively, at the option of the company with accrued interest and
at specified premiums. Under current interest rate elections by PSNH,
the Series D and E PCRBs are redeemable at par plus accrued interest at
the end of each interest-rate period. Future interest-rate elections by
PSNH could significantly defer or eliminate the availability of optional
redemptions by PSNH and could affect costs as well.
9. INCOME TAX EXPENSE
The components of the federal and state income tax provisions charged
to operations are:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Current income taxes:
Federal.............................. $(6,573) $67,148 $(4,978)
State................................ 759 48 (1,605)
Total current...................... (5,814) 67,196 (6,583)
Deferred income taxes, net:
Federal.............................. 78,022 20,983 95,225
State................................ 855 1,202 306
Total deferred..................... 78,877 22,185 95,531
Investment tax credits, net............ (511) (540) (548)
Total income tax expense............... $72,552 $88,841 $88,400
The components of total income tax expense are classified as follows:
Income taxes charged to operating
expenses............................. $65,079 $86,450 $80,677
Other income taxes..................... 7,473 2,391 7,723
Total income tax expense............... $72,552 $88,841 $88,400
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Depreciation........................... $(4,317) $(1,937) $(1,055)
Deferred tax asset associated
with NOL.............................. 69,212 - 96,756
Energy adjustment clauses.............. (765) 16,839 (10,716)
Proceeds from the sale of NOX Credits.. (7,813) - -
Nuclear plant deferrals................ 11,836 - -
Amortization of regulatory
settlement........................... 11,501 11,501 11,501
Other.................................. (777) (4,218) (955)
Deferred income taxes, net............. $78,877 $22,185 $95,531
A reconciliation between income tax expense and the expected tax expense
at the applicable statutory rate is as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income.......... $57,484 $63,355 $64,931
Tax effect of differences:
Depreciation......................... (38) 1,890 1,841
Amortization of acquisition costs.... 17,301 31,298 31,410
Seabrook intercompany gains
and losses......................... 630 (3,898) (7,504)
Adjustment for prior years' taxes.... (1,974) (2,034) (2,182)
Investment tax credit amortization... (511) (540) (548)
State income taxes, net of
federal benefit.................... 306 1,085 (845)
Other, net........................... (646) (2,315) 1,297
Total income tax expense............... $72,552 $88,841 $88,400
10.COMMITMENTS AND CONTINGENCIES
A. Restructuring
New Hampshire: In 1996, New Hampshire enacted legislation requiring
a competitive electric industry beginning in 1998. In February 1997,
the NHPUC issued its restructuring order, which would have forced
PSNH and NAEC to write off all of their regulatory assets, and
possibly to seek protection under Chapter 11 of the bankruptcy laws.
The amount of potential write-off which would have been triggered by
the order is currently estimated to be in excess of approximately
$400 million, after taxes.
Following the issuance of these orders, PSNH immediately sought
declaratory and injunctive relief on various grounds in federal
district court and has received a preliminary injunction that freezes
implementation of the NHPUC's restructuring orders. Restructuring
in New Hampshire has resulted in numerous subsequent proceedings
within the federal and state legal systems.
As the court proceedings are ongoing, PSNH continues to be involved
in settlement discussions with representatives from the state of New
Hampshire. PSNH hopes to reach a settlement, which would include,
among other things, recovery of regulatory assets and stranded costs,
rate reductions, an auction of PSNH's generating units and
securitization of PSNH's stranded costs. If a settlement is not
reached, a trial is expected to begin mid to late 1999.
As a result of the February 1997 NHPUC decision and the potential
consequences discussed above, the reports of our auditors on the
individual financial statements of PSNH and NAEC contain explanatory
paragraphs. Those explanatory paragraphs indicate that a substantial
doubt exists currently about the ability of PSNH and NAEC to continue
as going concerns.
Management believes that PSNH is entitled to full recovery of its
prudently incurred costs, including regulatory assets and other
stranded costs. It bases this belief both on the general nature of
public utility industry cost-of-service based regulation and the
specific circumstances of the resolution of PSNH's previous
bankruptcy proceedings and its acquisition by NU, including the
recoveries provided by the Rate Agreement and related agreements.
B. Rate Matters
PSNH's Rate Agreement between NU, PSNH and the state of New Hampshire
provided for seven base-rate increases of 5.5 percent per year
beginning in 1990 and for the FPPAC. The final base-rate increase
went into effect on June 1, 1996. The Rate Agreement contemplates
that PSNH's rates are subject to traditional rate regulation after
the fixed-rate period, which expired on May 31, 1997. The FPPAC,
however, would continue through May 31, 2001, and other Rate
Agreement requirements would continue in accordance with the terms
of the agreement.
A PSNH base-rate case was filed in May 1997, but was delayed in
connection with the restructuring proceedings discussed above. In
November 1997, the NHPUC ordered a temporary base rate reduction for
PSNH of 6.87 percent effective December 1, 1997. The NHPUC also set
an interim return on equity of 11 percent. In December 1998, the
base-rate case was reopened and an updated rate case was filed.
A final decision, which will be reconciled to July 1, 1997, is
currently scheduled to be issued by June 1, 1999.
Concurrently with the 6.87 percent rate reduction beginning in
December 1997, the NHPUC allowed an FPPAC increase of approximately
6 percent. This rate increase was effective for the period from
December 1, 1997, through May 31, 1998. On May 29, 1998, the NHPUC
approved slightly more than a one percent increase in PSNH's FPPAC
rate for the period June through November 1998. On December 1, 1998,
the NHPUC allowed the current FPPAC rate to remain in place through
May 31, 1999. As a result of this decision, unrecovered energy
costs are projected to increase by approximately $17.4 million from
January 1, 1999 through May 31, 1999, to an estimated balance of
approximately $79.7 million. PSNH's ongoing restructuring settlement
negotiations with the state of New Hampshire could resolve both the
base-rate case and the FPPAC proceedings discussed above.
FERC: During November 1997, MYAPC filed an amendment to its power
contracts clarifying the obligations of its purchasing utilities
following the decision to cease power production. During January
1998, the FERC accepted the amendments and proposed rates, subject
to a refund. On January 18, 1999, MYAPC filed with the FERC
Administrative Law Judge (ALJ) an Offer of Settlement which,
if accepted by the FERC, will resolve all the issues in the FERC
decommissioning rate case proceeding. The settlement provides,
among other things, the following: (1) MYAPC will collect
$33.6 million annually to pay for decommissioning and spent fuel;
(2) its return on equity will be set at 6.5 percent; (3) MYAPC
is permitted full recovery of all unamortized investment in MY,
including fuel, and (4) an incentive budget for decommissioning
is set at $436.3 million.
During late December 1996, CYAPC filed an amendment to its power
contracts clarifying the obligations of its purchasing utilities
following the decision to cease power production. On February 27,
1997, the FERC accepted CYAPC's contract amendment. The new rates
became effective March 1, 1997, subject to a refund.
On August 31, 1998, the FERC ALJ released an initial decision
regarding the December 1996 filing. The decision contained
provisions which would allow for the recovery, through rates,
of the balance of PSNH's net unamortized investment in CYAPC,
which was approximately $5.5 million as of December 31, 1998.
The decision also called for the disallowance of the recovery
of a portion of the return on the CY investment. The ALJ's
decision also stated that decommissioning collections should
continue to be based on the previously approved estimate of
$309.1 million (in 1992 dollars), with an inflation adjustment
of 3.8 percent per year, until a new, more reliable estimate has
been prepared and tested.
During October 1998, CYAPC, CL&P, PSNH and WMECO filed briefs on
exceptions to the ALJ decision. If the initial ALJ decision is
upheld, CYAPC could be required to write off a portion of the
regulatory asset associated with the plant closing.
If upheld, CYAPC's management has estimated the effect of the ALJ
decision on CYAPC's earnings would be approximately $37.5 million,
of which PSNH's share would be approximately $1.9 million. NU
management cannot predict the ultimate outcome of the hearing at
this time, however, management believes that the associated regulatory
assets are probable of recovery.
C. Nuclear Performance
Millstone: The three Millstone units are managed by NNECO. All
three units were placed on the NRC watch list on January 29, 1996.
The units cannot be restarted without appropriate NRC approvals.
Millstone 3 has received these approvals and resumed operation in
July 1998.
Litigation: Certain of the non-NU joint owners of Millstone 3 have
filed demands for arbitration with CL&P and WMECO as well as lawsuits
in Massachusetts Superior Court against NU and its current and former
trustees related to the company's operation of Millstone 3. The
arbitrations and lawsuits seek to recover compensatory damages in
excess of $200 million, together with punitive damages, treble
damages and attorney's fees. Management cannot estimate the potential
outcome of these suits but believes there is no legal basis for the
claims and intends to defend against them vigorously.
D. Environmental Matters
PSNH is subject to regulation by federal, state and local authorities
with respect to air and water quality, the handling and disposal of
toxic substances and hazardous and solid wastes, and the handling and
use of chemical products. The NU system has an active environmental
auditing and training program and believes that it is in substantial
compliance with current environmental laws and regulations. However,
the NU system is subject to certain pending enforcement actions and
governmental investigations in the environmental area. Management
cannot predict the outcome of these enforcement actions and
investigations.
Environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations
and other facilities. Changing environmental requirements could also
require extensive and costly modifications to PSNH's existing
generating units, and transmission and distribution systems, and
could raise operating costs significantly. As a result, PSNH may
incur significant additional environmental costs, greater than
amounts included in cost of removal and other reserves, in
connection with the generation and transmission of electricity and
the storage, transportation and disposal of by-products and wastes.
PSNH may also encounter significantly increased costs to remedy the
environmental effects of prior waste handling activities. The
cumulative long-term cost impact of increasingly stringent
environmental requirements cannot be estimated accurately.
PSNH has recorded a liability based upon currently available
information for what it believes are its estimated environmental
remediation costs that it expects to incur for waste disposal sites.
In most cases, additional future environmental cleanup costs are not
reasonably estimable due to a number of factors, including the
unknown magnitude of possible contamination, the appropriate
remediation methods, the possible effects of future legislation or
regulation and the possible effects of technological changes. At
December 31, 1998, the liability recorded by PSNH for its estimated
environmental remediation costs, not considering any possible
recoveries from third parties, amounted to approximately $7.9
million within a range of $7.9 million to $9.0 million.
PSNH has received proceeds from several insurance carriers for the
settlement with certain insurance companies of all past, present and
future environmental matters. As a result of these settlements,
PSNH will retain the risk loss, in part, for some environmental
remediation costs.
PSNH cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought
against it. However, considering known facts, existing laws, and
regulatory practices, management does not believe the matters
disclosed above will have a material effect on PSNH's financial
position or future results of operations.
E. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, PSNH must pay the United
States Department of Energy (DOE) for the disposal of spent nuclear
fuel and high-level radioactive waste. The DOE is responsible for
the selection and development of repositories for, and the disposal
of, spent nuclear fuel and high-level radioactive waste. Fees are
billed currently to customers and paid to the DOE on a quarterly
basis.
The DOE was originally scheduled to begin accepting delivery of spent
fuel in 1998. However, delays in identifying a permanent storage site
have continually postponed plans for the DOE's long-term storage and
disposal site. Extended delays or a default by the DOE could lead
to consideration of costly alternatives. The company has primary
responsibility for the interim storage of its spent nuclear fuel.
Current capability to store spent fuel at Seabrook are estimated to
be adequate until at least the year 2010. Meeting spent fuel storage
requirements beyond this period could require new and separate
storage facilities, the costs for which have not been determined.
In November 1997, the U.S. Court of Appeals for the D.C. Circuit
ruled that the lack of an interim storage facility does not excuse
the DOE from meeting its contractual obligation to begin accepting
spent nuclear fuel no later than January 31, 1998. The 1997 ruling
by the appeals court said, however, that the 1982 federal law could
not require the DOE to accept waste when it did not have a suitable
storage facility. The court directed the plaintiffs to pursue relief
under the terms of their contracts with the DOE. Based on this
ruling, since the DOE did not take the spent nuclear fuel as
scheduled, it may have to pay contract damages.
In May 1998, the same court denied petitions from 60 states and state
agencies, collectively, and 41 utilities, including the company, asking
the court to compel the DOE to submit a program, beginning immediately,
for disposing of spent nuclear fuel. The petitions were filed after
the DOE defaulted on its January 31, 1998 obligation to begin
accepting the fuel. The court directed the company and other
plaintiffs to pursue relief under the terms of their contracts with
the DOE.
In a petition filed in August 1998, the court's May 1998 decision was
appealed to the U.S. Supreme Court. In November 1998, the Supreme
Court declined to review the lower court ruling that said utilities
should go to court and seek monetary damages from the DOE. The ultimate
outcome of this legal proceeding is uncertain at this time.
F. Nuclear Insurance Contingencies
Under certain circumstances, in the event of a nuclear incident at
one of the nuclear facilities in the country covered by the federal
government's third-party liability indemnification program, an owner
of a nuclear unit could be assessed in proportion to its ownership
interest in each of its nuclear units up to $83.9 million. Payments
of this assessment would be limited to $10.0 million in any one year
per nuclear incident based upon the owner's pro rata ownership
interest in each of its nuclear units. In addition, the owner
would be subject to an additional 5 percent or $4.2 million, in
proportion to its ownership interests in each of its nuclear units,
if the sum of all claims and costs from any one nuclear incident
exceeds the maximum amount of financial protection. Under the terms
of the Seabrook Power Contracts with NAEC, PSNH could be obligated
to pay for any assessment charged to NAEC as a "cost of service."
Based on its ownership interest in Millstone 3 and NAEC's ownership
interest in Seabrook 1, PSNH's maximum liability, including any
additional assessments, would be $28.8 million per incident of
which payments would be limited to $3.8 million per year. In
addition, through power purchase contracts with VYNPC, PSNH would
be responsible for up to an additional $3.5 million per incident,
of which payments would be limited to a maximum of $0.4 million
per year.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from
insured occurrences. PSNH is subject to retroactive assessments if
losses exceed the accumulated funds available to the insurer. The
maximum potential assessment against PSNH with respect to losses
arising during the current policy year is approximately $0.4 million
under the primary property insurance program.
Insurance has been purchased to cover certain extra costs incurred
in obtaining replacement power during prolonged accidental outages
and the excess cost of repair, replacement, or decontamination or
premature decommissioning of utility property resulting from insured
occurrences. PSNH is subject to retroactive assessments if losses
exceed the accumulated funds available to the insurer. The maximum
potential assessments against PSNH (including costs resulting from
PSNH's contracts with NAEC), with respect to losses arising during
current policy years are approximately $1.3 million under the
replacement power policies and $4.1 million under the excess
property damage, decontamination and decommissioning policies.
Although PSNH has purchased the limits of coverage currently
available from the conventional nuclear insurance pools, the cost
of a nuclear incident could exceed available insurance proceeds.
The NRC approved CYAPC's and MYAPC's requests for withdrawal from
participation in the secondary financial protection program on
November 19, 1998 and January 17, 1999, respectively, due to their
permanently shutdown and defueled status. Therefore, neither
CYAPC nor their sponsor companies have any future obligations
for potential assessment.
Insurance has been purchased aggregating $200 million on an industry
basis for coverage of worker claims.
G. Construction Program
The construction program is subject to periodic review and revision
by management. PSNH currently forecasts construction expenditures
of approximately $331.4 million for the years 1999-2003, including
approximately $68.0 million for 1999. In addition, PSNH estimates
that nuclear fuel requirements, for its share of Millstone 3, will
be $4.5 million for the years 1999-2003, including $1.4 million for
1999.
H. Long-Term Contractual Arrangements
Yankee Companies: PSNH, CL&P and WMECO rely on VY for approximately
1.4 percent of their capacity under long-term contracts. Under the
terms of their agreements, the NU system companies pay their ownership
(or entitlement) shares of costs, which include depreciation, O&M
expenses, taxes, the estimated cost of decommissioning and a return
on invested capital. These costs are recorded as purchased-power
expense and are recovered through the companies' rates. PSNH's
total cost of purchases under contracts with VYNPC, amounted to
$7.0 million in 1998, $6.2 million in 1997 and $6.5 million in 1996.
PSNH may also be asked to provide direct or indirect financial
support for one or more of the Yankee companies, including VYNPC.
Nonutility Generators (NUGs): PSNH has requirements under various
arrangements for the purchase of capacity and energy from NUGs.
These arrangements have terms from 20 to 30 years, currently
expiring in the years 1998 through 2023, and require PSNH to
purchase energy at specified prices or formula rates. For the 12-
month period ending December 31, 1998, approximately 13 percent of
the NU system electricity requirements were met by NUGs. PSNH's
total cost of purchases under these arrangements amounted to $139.1
million in 1998, $133.1 million in 1997 and $132.6 million in 1996.
New Hampshire Electric Cooperative: PSNH entered into a buy-back
agreement to purchase the capacity and energy of the New Hampshire
Electric Cooperative, Inc.'s (NHEC) share of Seabrook 1 and to pay
all of NHEC's Seabrook 1 costs for a ten-year period, which began on
July 1, 1990. The total cost of purchases under this agreement was
$29.7 million in 1998, $23.4 million in 1997 and $14.6 million in
1996. The total cost of these purchases has been collected through
the FPPAC in accordance with the Rate Agreement.
Although under the agreement NHEC agreed to continue as a firm-
requirements customer of PSNH for 15 years, it has recently
received a FERC ruling allowing it to purchase power from qualifying
facilities. The ruling allows that the price for such purchases
may be determined through negotiation between NHEC and the qualifying
facility. The financial impact of this decision in the future will
vary depending upon the level of purchases made by NHEC from the
qualifying purchasers.
NHEC also is seeking to be able to purchase energy under the
agreement from competitive sources once competition has begun in
its service territory. A final FERC decision is expected by March
1999. The financial impact of this decision in the future will
depend upon the implementation of restructuring in NHEC's service
territory.
Hydro-Quebec: Along with other New England utilities, PSNH, CL&P,
WMECO, and HWP have entered into agreements to support transmission
and terminal facilities to import electricity from the Hydro-Quebec
system in Canada. PSNH is obligated to pay, over a 30-year period
ending in 2020, its proportionate share of the annual O&M and
capital costs of these facilities.
Estimated Annual Costs: The estimated annual costs of PSNH's
significant long-term contractual arrangements are as follows:
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
(Millions of Dollars)
VYNPC......... $ 7.5 $ 6.9 $ 7.5 $ 7.7 $ 7.1
NUGs.......... 142.9 147.1 151.3 155.5 160.3
NHEC.......... 30.0 14.6 - - -
Hydro-Quebec.. 10.0 9.6 9.3 9.1 8.9
I. Deferred Receivable from Affiliated Company
At the time PSNH emerged from bankruptcy on May 16, 1991, in
accordance with the phase-in under the Rate Agreement, it began
accruing a deferred return on a portion of its Seabrook investment.
From May 16, 1991 to the Acquisition Date, PSNH accrued a deferred
return of $50.9 million. On the Acquisition Date, PSNH sold the
$50.9 million deferred return to NAEC as part of the Seabrook-
related assets.
At the time PSNH transferred the deferred return to NAEC, it
realized, for income tax purposes, a gain that is deferred under
the consolidated income tax rules. Beginning December 1, 1997,
this gain is being restored for income tax purposes, as the deferred
return of $50.9 million, and the associated income taxes of $32.9
million, are being collected by NAEC through the Seabrook Power
Contracts. As NAEC recovers the $32.9 million in years eight
through ten of the Rate Agreement, it will be obligated to make
these corresponding payments to PSNH.
On the Acquisition Date, PSNH recorded the $32.9 million of income
taxes associated with the deferred return as a deferred receivable
from NAEC, with a corresponding entry to deferred revenue, on its
Balance Sheet. In 1993, due to changes in tax rates, this amount
was adjusted to $33.2 million.
For further information related to the phase-in of the Seabrook
power plant, see Note 2, "Seabrook Power Contracts."
See Note 10A, "Commitments and Contingencies - Restructuring" for
the possible impacts of the NHPUC's decision related to industry
restructuring on this intercompany transaction between PSNH and
NAEC.
11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair
value of each of the following financial instruments:
Cash and cash equivalents: The carrying amounts approximate fair value
due to short-term nature of cash and cash equivalents.
Supplemental Executive Retirement Plan investments: SFAS 115,
"Accounting for Certain Investments in Debt and Equity Securities,"
requires investments in debt and equity securities to be presented
at fair value. As a result of this requirement, the investments
having a cost basis of $321,000 held for benefit of the Supplemental
Executive Retirement Plan were recorded on the balance sheet at their
fair market value at December 31, 1998, of $2.2 million.
Preferred stock and long-term debt: The fair value of PSNH's fixed-rate
securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair
value equal to their carrying value. The carrying amounts of PSNH's
financial instruments and the estimated fair values are as follows:
Carrying Fair
At December 31, 1998 Amount Value
(Thousands of Dollars)
Preferred stock subject to
mandatory redemption............... $ 75,000 $ 78,000
Other long-term debt................. $516,485 $535,401
Carrying Fair
At December 31, 1997 Amount Value
(Thousands of Dollars)
Preferred stock subject to
mandatory redemption............... $100,000 $ 99,000
Long-term debt - First mortgage bonds 170,000 170,424
Other long-term debt................. 516,485 537,599
The fair values shown above have been reported to meet the disclosure
requirements and do not purport to represent the amounts at which
those obligations would be settled.
12. OTHER COMPREHENSIVE INCOME
During 1998, the NU system adopted SFAS 130, "Reporting Comprehensive
Income," which established standards for reporting and displaying
comprehensive income and its components in a financial statement that is
displayed with the same prominence as other financial statements. During
1997 and 1996, PSNH had no material other comprehensive income items.
The accumulated balance for each other comprehensive income item is as
follows:
Current
December 31 Period December 31,
1997 Change 1998
(Thousands of Dollars)
Unrealized gain on
securities.............. $ - $1,198 $1,198
Minimum pension
liability adjustment.... - (194) (194)
Accumulated other
comprehensive income.... $ - $1,004 $1,004
The changes in the components of other comprehensive income are reported
on the Statements of Comprehensive Income net of the following income tax
effects:
1998 1997 1996
(Thousands of Dollars)
Unrealized gain on
securities............. $(660) $ - $ -
Minimum pension
liability adjustment... 107 - -
Other comprehensive
income................. $ 553 $ - $ -
To the Board of Directors
of Public Service Company of New Hampshire:
We have audited the accompanying balance sheets of Public Service
Company of New Hampshire (a New Hampshire corporation and a wholly
owned subsidiary of Northeast Utilities) as of December 31, 1998 and
1997, and the related statements of income, comprehensive income, common
stockholder's equity, and cash flows for each of the three years in the
period ended December 31, 1998. 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 in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Public
Service Company of New Hampshire as of December 31, 1998 and 1997,
and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles.
The accompanying financial statements have been prepared assuming that
the company will continue as a going concern. As discussed in Note 10A,
on February 28, 1997, the State of New Hampshire Public Utilities
Commission (the NHPUC) issued an order outlining its final plan to
restructure the electric utility industry. The final plan announced
a departure from cost-based rate making, which, if implemented, would
require the company to discontinue the application of Financial
Accounting Standard No. 71, "Accounting for the Effects of Certain
Types of Regulation," (FAS 71). The implementation of the final plan,
including the effect of the discontinuation of FAS 71, would result in
after tax write-off of over $400 million. Such a write-off would cause
the company to be in technical default under financial covenants imposed
by lenders, which, would, if not waived or renegotiated, give rise to
the rights of lenders to accelerate the repayment of approximately $516
million of the company's indebtedness and approximately $475 million of
an affiliated company's indebtedness.
These conditions raise substantial doubt about the company's ability to
continue as a going concern. The financial statements referred to above
do not include any adjustments that might result from the outcome of
this uncertainty.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 23, 1999
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
Management's Discussion and Analysis of Financial
Condition and Results of Operations
This section contains management's assessment of Public Service Company of
New Hampshire's (PSNH or the company) financial condition and the principal
factors having an impact on the results of operations. The company is a
wholly-owned subsidiary of Northeast Utilities (NU). This discussion should
be read in conjunction with the company's financial statements and footnotes.
FINANCIAL CONDITION
Earnings Overview
PSNH had net income of approximately $92 million for 1998, essentially
unchanged from the same period in 1997.
Lower operating revenues as a result of rate decreases were offset by lower
operating expenses and lower interest costs. Operating revenues fell 2
percent despite a 2.3 percent increase in retail kilowatt-hour sales.
The resolution of New Hampshire restructuring and the final decision in
PSNH's rate case, that is currently scheduled to be issued in 1999, will
impact PSNH's ability to improve its results in 1999.
Restructuring
Although PSNH continues to operate under cost-of-service based regulation,
future rates and the recovery of stranded costs are issues that will be
addressed as restructuring legislation is implemented. Stranded costs are
expenditures or commitments that have been made to meet public service
obligations with the expectation that they would be recovered from customers.
However, under certain circumstances these costs might not be recoverable
from customers in a fully competitive electric utility industry (i.e., the
costs may result in above-market energy prices).
PSNH has exposure to stranded costs for its investments in high-cost nuclear
generating plants, state-mandated purchased-power obligations and significant
regulatory assets. As of December 31, 1998, PSNH's net investment in nuclear
generating plants, was approximately $83 million, and its regulatory assets
were approximately $610 million. PSNH's financial strength will be negatively
affected if it is unable to recover their past investments and commitments.
Restructuring efforts in New Hampshire have resulted in numerous proceedings
within the federal and state court systems. The New Hampshire Public
Utilities Commission's (NHPUC) 1997 restructuring orders have been prevented
from being implemented as a result of various court actions pending the
outcome of a full trial in the U.S. District Court. The 1997 orders would
have forced PSNH to write-off substantially all of its regulatory assets.
A trial is expected to begin in mid to late 1999.
In January 1999, the NHPUC issued an order stating that it intends to reopen
restructuring hearings. PSNH has requested the federal court to enforce its
preliminary injunction barring the NHPUC from proceeding with restructuring
efforts pending the court's decision on the merits after trial. The NHPUC
has agreed to delay this new proceeding until the federal court has had an
opportunity to rule on PSNH's enforcement motion.
The litigation has caused New Hampshire to fall behind several other
Northeast states in implementing industry restructuring. PSNH hopes to
reach a settlement that would include, among other things, substantial rate
reductions, customer choice, an auction of PSNH's generating units and
securitization of PSNH's stranded costs. PSNH believes that a negotiated
resolution of outstanding restructuring and rate issues would be in the best
interests of the state, the company and customers.
Rate Matters
In May 1998, the NHPUC approved slightly more than a 1 percent net increase
in PSNH's fuel and purchased-power adjustment clause (FPPAC) rate for the
period June through November 1998. As part of this proceeding, PSNH agreed
to offset in base rates the scheduled reduction in acquisition premium
amortization with the scheduled amortization of the Seabrook deferred return.
On December 1, 1998, the NHPUC approved a Stipulation and Settlement executed
by PSNH, the NHPUC staff, and the Governor's Office of Energy and Community
Services. They recommended that PSNH's currently effective FPPAC rate be
continued for another six-month period - December 1, 1998, through May 31,
1999. The FPPAC rate currently in effect will produce an estimated $80
million underrecovery as of May 31, 1999. All other FPPAC costs are being
recovered on a current basis.
A PSNH rate case has been pending at the NHPUC since May 1997 but was delayed
in connection with various restructuring proceedings. In November 1997, the
NHPUC ordered a temporary rate reduction of 6.87 percent effective December
1, 1997. A final rate case decision currently is scheduled to be issued by
June 1, 1999, the same date when PSNH's FPPAC rate is scheduled to be set for
the second half of 1999. The final decision will be reconciled to July 1,
1997. PSNH's ongoing settlement negotiations with the State of New Hampshire
could resolve both the rate case and FPPAC issues discussed above.
Millstone 3
PSNH has a 2.85 percent joint ownership interest in Millstone 3. After a
27-month outage, Millstone 3 received Nuclear Regulatory Commission (NRC)
permission to restart in June 1998 and reached full power in July. The unit
achieved a capacity factor of approximately 70 percent in 1998 following
its return to service. PSNH's share of the operation, maintenance and
replacement power costs associated with Millstone 3 totaled approximately
$5 million in 1998, down from $11 million in 1997. The unit remains on the
NRC's watch list with a Category 2 designation, which means that it will
continue to be subject to heightened NRC oversight. A refueling and
maintenance outage is scheduled to begin in May 1999.
Seabrook
PSNH is obligated to purchase North Atlantic Energy Corporation's (NAEC)
35.98 percent share of the capacity and output generated by Seabrook
1(Seabrook) under the Seabrook Power Contract for a period equal to the
length of the NRC full-power operating license for Seabrook (through 2026)
whether or not Seabrook is operating and without regard to the cost of
alternative sources of power. North Atlantic Energy Service Corporation is
the managing agent and operates Seabrook.
Seabrook operated at a capacity factor of 82.8 percent in 1998, compared to
78.3 percent for the same period in 1997. The unit operated well, except for
two unplanned outages, one in late 1997 through early 1998 and the other in
mid-1998, to repair the control building's air-conditioning system. Seabrook
is scheduled to begin a refueling outage in March 1999.
Liquidity And Capital Resources
Cash provided from operations totaled approximately $217 million in 1998
compared to $233 million in 1997, primarily due to the billing from NAEC of
the Seabrook phase-in costs beginning in December 1997 which were not being
recovered from customers for the first six months of 1998. Approximately
$195 million of net cash flows were used to repay long-term debt and
preferred stock in 1998, compared to only $25 million in 1997. Another $9
million was used to pay cash dividends on preferred stock in 1998 compared
to $97 million in 1997 for common and preferred dividends. Approximately
$46 million of net cash flows was used for investment in plant and other
investment activities compared to a net of $17 million in 1997.
During 1998 PSNH converted a total of $119.8 million variable-rate tax
exempt debt to fixed-rate tax exempt debt carrying an interest rate of 6.0
percent. PSNH met a $170 million bond maturity in May 1998 with cash on hand
and operating cash flows and successfully extended $190 million in credit
($75 million in bank credit lines and $115 million in letters of credit).
In September 1998, S&P upgraded PSNH's first mortgage bonds. The rating
agency actions were due in part to the NU system's success in 1998 in
maintaining access to its various credit lines. PSNH renegotiated a one-year
extension of the $75 million revolving credit agreement in April 1998.
PSNH's revolving credit agreement expires on April 22, 1999, and the company
currently does not intend to renew it. PSNH will fund its needs through
operating cash flows or other short-term credit arrangements which may be
negotiated later in the year. PSNH has had no borrowings under that line
since October 1998. PSNH expects to renew the bank letters of credit that
support nearly $110 million of taxable variable-rate pollution control bonds.
Those letters of credit also expire April 22, 1999.
Nuclear Decommissioning
The staff of the SEC has questioned certain current accounting practices of
the electric utility industry, regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating units in the
financial statements. In response to these questions, the Financial
Accounting Standards Board (FASB) had agreed to review the accounting for
closure and removal costs, including decommissioning. If current electric
utility industry accounting practices for nuclear power plant decommissioning
are changed, the annual provision for decommissioning could increase relative
to 1998, and the estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation), with recognition of an
increase in the cost of the related nuclear power plant. As management
believes decommissioning costs will continue to be recovered through rates,
changes to the accounting will not affect net income.
Yankee Companies
PSNH has a 5 percent ownership interest in the Connecticut Yankee Atomic
Power Company (CYAPC), a 7 percent ownership interest in Yankee Atomic
Electric Company (YAEC), a 5 percent ownership interest in Maine Yankee
Atomic Power Company (MYAPC)and a 4 percent ownership interest in Vermont
Yankee Nuclear Power Corporation (VYNPC). The nuclear plants owned by YAEC,
CYAPC and MYAPC were shut down permanently on February 26, 1992, December 4,
1996, and August 6, 1997, respectively.
At December 31, 1998, PSNH's share of its estimated remaining contract
obligations, including decommissioning, amounted to approximately $66.5
million: $5.7 million for YAEC, $24.9 million for CYAPC and $35.8 million for
MYAPC. Under the terms of the contracts with the Yankee companies, PSNH is
responsible for its proportionate share of the costs of the units including
decommissioning. Management expects to recover these costs from customers.
Accordingly, PSNH has recognized these costs as a regulatory asset, with a
corresponding obligation on its balance sheet.
PSNH has exposure for its investment in CYAPC as a result of an initial
decision at the Federal Energy Regulatory Commission (FERC). Additionally,
in January 1999, MYAPC filed an offer of settlement which, if accepted by
FERC, will resolve all the issues in the FERC decommissioning rate case
proceeding. NU management cannot predict the ultimate outcome of the FERC
proceedings at this time, but believes that the associated regulatory assets
are probable of recovery. For further information on these proceedings see
the "Notes to Consolidated Financial Statements," Note 10B.
PSNH's ownership share of estimated costs, in year-end 1998 dollars, of
decommissioning the nuclear plant owned by VYNPC is approximately $21.2
million.
Millstone 3 and Seabrook 1
PSNH's estimated cost to decommission its share of Millstone 3 is
approximately $15.9 million in year-end 1998 dollars. These costs are
being recognized over the life of the unit with a portion currently being
recovered through rates. As of December 31, 1998, the market value of the
contributions already made to the decommissioning trust, including its
investment return, was approximately $5.6 million.
PSNH is obligated to pay NAEC's share of Seabrook's decommissioning costs
even if the unit is shut down prior to the expiration of its license. NAEC's
estimated cost to decommission its share of Seabrook is approximately $175.9
million in year-end 1998 dollars. These costs are being recognized over the
life of the unit with a portion currently being recovered through PSNH's
rates. As of December 31, 1998, the market value of the contributions already
made to Seabrook's decommissioning financing fund, including its investment
returns, was approximately $35.2 million.
See the "Notes to Consolidated Financial Statements," Note 4, for further
information on nuclear decommissioning.
Year 2000 Issue
The NU system has established an action plan by which identified processes
must be completed by certain dates in order to ensure its operating systems,
including nuclear systems and reporting systems, are able to properly
recognize the year 2000. This action plan has three phases: the inventory
phase, the detailed assessment phase and the remediation phase. The inventory
phase, which has been completed, identified operating and reporting systems
which may need to be fixed. The detailed assessment phase, which has been
completed, determined exactly what needed to be done in order to ensure that
the systems identified during the inventory phase are able to recognize
properly and process the year 2000. The final phase is the remediation
phase. By the end of this phase, mission critical systems (systems that are
related to safety, keeping the lights on, regulatory requirements, and other
systems that could have a significant financial impact) will be year 2000
ready; that is, these systems will perform their business functions properly
in the year 2000. This phase includes making modifications, testing and
validating changes and verifying that the year 2000 issues have been
resolved.
Although the identification and detailed assessment phases are complete,
newly identified items, such as new software purchases, are added to the
inventory as they are identified and are subject to detailed assessment
and, if needed, remediation. NU system purchasing policies require newly
purchased software and devices to be year 2000 compliant. None of these
newly identified items are expected to materially impact completion of the
remediation phase.
The NU system has identified and inventoried 2,497 computer systems
(software) and over 24,000 devices (hardware) broken down into 3,450 device
types containing date-sensitive computer chips. As of December 31, 1998,
73 percent of the software systems and 81 percent of the hardware were
year 2000 ready.
The remaining items are in various stages of modification or testing.
Management anticipates the remediation phase for mission critical systems
to be completed by mid-1999.
In addition, the NU system has been contacting its key suppliers and
business partners to determine their ability to manage the year 2000
problem successfully. The NU system is adjusting its inventories, working
with suppliers to provide backup inventories, and changing suppliers as
needed to provide for an adequate supply of materials needed to conduct
business into the year 2000.
The NU system also has worked actively with the Independent System Operator
(ISO) New England, the operator of the New England power grid, and with the
North American Electric Reliability Council to provide for the year 2000
readiness of the New England power grid.
The NU system has utilized both internal and external resources to identify,
assess, test and reprogram or replace the computer systems for year 2000
readiness. The current projected total cost of the Year 2000 Program to the
NU system is $30 million. The total estimated remaining cost is $18 million,
which is being funded through operating cash flows. The majority of these
costs will be expensed as incurred in 1999. Since 1996, the NU system has
incurred and expensed approximately $12 million related to year 2000
readiness efforts. Total expenditures related to the year 2000 are not
expected to have a material effect on the operations or financial condition
of the NU system.
The costs of the project and the date on which the NU system plans to
complete the year 2000 modifications are based on management's best
estimates, which were derived utilizing numerous assumptions of future
events, including the continued availability of certain resources, third-
party modification plans and other factors. However, there can be no
guarantee that these estimates will be achieved, and actual results could
differ materially from those plans. If the NU system's remediation plans or
those of third parties are not successful, there could be a significant
disruption of the NU system's operations. The most likely worst case
scenario is a limited number of localized interruptions to electric service
which can be restored within a few hours. As a precautionary measure, the NU
system is formulating contingency plans that will evaluate alternatives that
could be implemented if our remediation efforts are not successful. The
contingency plans are being developed by enhancing existing emergency
operating procedures to include year 2000 issues. In addition, the NU system
plans to have staff available to respond to any year 2000 situations that
might arise. The contingency plan is expected to be available by July 30,
1999.
The NU system is committed to assuring that adequate resources are available
in order to implement any changes necessary for its nuclear and other
operations to be compatible with the new millennium.
Environmental Matters
PSNH is potentially liable for environmental cleanup costs at a number of
sites inside and outside its service territory. To date, the future estimated
environmental remediation liability has not been material with respect to
the earnings or financial position of PSNH. At December 31, 1998, PSNH had
recorded an environmental reserve of approximately $7.9 million. See the
"Notes to Consolidated Financial Statements," Note 10D, for further
information on environmental matters.
RESULTS OF OPERATIONS
Income Statement Variances
Millions of Dollars
1998 over/(under) 1997 1997 over/(under) 1996
---------------------- ----------------------
Amount Percent Amount Percent
Operating revenues $(21) (2)% $ (2) (-)%
Fuel, purchased and net
interchange power (5) (1) (30) (8)
Other operation 34 9 42 13
Maintenance 13 35 (7) (16)
Amortization of
regulatory assets, net (30) (53) - -
Federal and state income
taxes (16) (18) - -
Other, net 9 12 (7) (92)
Interest on long-term debt (8) (15) (6) (11)
Other interest expense - - (3) (91)
(a) Percent greater than 100.
Operating Revenues
Retail nonfuel revenues decreased $97 million due to the 1997 retail rate
decrease and the June 1998 base rate offset described under "Rate Matters."
This decrease was partially offset by higher fuel recoveries and higher
retail sales. Fuel recoveries increased $66 million due to the higher FPPAC
rate and the base rate offset. Retail kilowatt-hour sales were 2.3 percent
higher for 1998 and contributed approximately $9 million to nonfuel revenues.
Total operating revenues decreased in 1997 primarily due to lower fuel
recoveries, partially offset by higher retail revenues. Fuel recoveries
decreased approximately $12 million, primarily due to the customer refund
ordered by the NHPUC. Retail revenues increased approximately $9 million,
primarily due to the June 1996 rate increase, partially offset by the
December 1997 rate decrease and higher price discounts to retain customers.
Retail sales were essentially unchanged.
Fuel Expense
The change in fuel, purchased and net interchange power expense was not
significant in 1998.
Fuel, purchased and net interchange power expense decreased in 1997,
primarily due to the timing in the recognition of fuel expenses under the
FPPAC, partially offset by higher purchased power costs.
Other Operation and Maintenance Expense
Other operation maintenance increased in 1998 primarily due to higher costs
associated with the Seabrook Power Contract as a result of the amortization
of Seabrook phase-in costs that began in June 1998 ($57 million) and higher
costs related to the January ice storm, net of insurance proceeds, ($8
million); partially offset by the recognition of environmental insurance
proceeds ($12 million) and lower costs at Millstone 3 and the Maine Yankee
nuclear unit ($10 million).
Other operation and maintenance expense increased in 1997 primarily due to
higher capacity charges under the Seabrook Power Contract as a result of
the scheduled May 1997 refueling and maintenance outage and the unplanned
December 1997 outage ($23 million), higher capacity purchases from the New
Hampshire Electric Cooperative ($11 million), higher capacity charges from
MYAPC ($4 million) and higher costs for PSNH's share of Millstone 3
($2 million), partially offset by lower fossil costs ($4 million) and lower
administration and sales costs ($3 million).
Amortization of Regulatory Assets
Amortization of regulatory assets decreased in 1998, primarily due to the
completion of the amortization of a portion of the company's acquisition
premium ($40 million), partially offset by the additional amortization of
Seabrook phase-in costs($10 million).
The change in amortization of regulatory assets in 1997 was not significant.
Federal and State Income taxes
Federal and state income taxes decreased in 1998 compared to 1997 primarily
due to lower taxable income.
The change in federal and state income taxes was not significant in 1997.
Other, net income
Other, net income increased in 1998, primarily due to the amortization of the
taxes associated with the Seabrook-phase-in costs which began in December
1997.
Other, net income decreased in 1997, primarily due to the deferral in 1996 of
interest expense ($5 million) associated with the FPPAC refund.
Interest on Long-Term Debt
Interest on long-term debt decreased due to the maturity of bonds ($170
million) in May 1998.
Interest on long-term debt decreased in 1997, primarily due to the repayment
of the $172.5 million Series A first-mortgage bond in May 1996.
Other Interest Expense
The change in other interest in 1998 was not significant.
Other interest expense decreased in 1997, primarily due to 1996 interest
expense ($5 million) associated with the FPPAC refund.
Public Service Company of New Hampshire
SELECTED FINANCIAL DATA (a)
Jan. 1, 1998 Jan. 1, 1997 Jan. 1, 1996
to to to
For the Periods Dec. 31, 1998 Dec. 31, 1997 Dec. 31, 1996
------------- ------------- --------------
(Thousands of Dollars)
Operating Revenues........... $1,087,247 $1,108,459 $1,110,169
Operating Income............. 131,199 144,024 155,758
Net Income................... 91,686 92,172 97,465
Cash Dividends on
Common Stock............... - 85,000 52,000
At Dec. 31, 1998 Dec. 31, 1997 Dec. 31, 1996
------------- ------------- -------------
Total Assets................. $2,681,595 $2,837,159 $2,851,212
Long-Term Debt (b)........... 516,485 686,485 686,485
Preferred Stock
Subject to Mandatory
Redemption(b).............. 75,000 100,000 125,000
Obligations Under
Seabrook Power
Contracts and Other
Capital Leases(b).......... 838,100 921,813 914,617
(a) Reclassifications of prior data have been made to conform with
the current presentation.
(b) Includes portions due within one year.
Public Service Company of New Hampshire
SELECTED FINANCIAL DATA
Jan. 1, 1995 Jan. 1, 1994
to to
Dec. 31, 1995 Dec. 31, 1994
------------- -------------
(Thousands of Dollars)
$979,971 $922,039
155,628 152,086
83,255 77,444
52,000 -
Dec. 31,1995 Dec. 31, 1994
------------ -------------
$2,920,487 $2,845,967
858,985 999,985
125,000 125,000
915,288 887,967
Public Service Company of New Hampshire
- -----------------------------------------------------------------------------
STATISTICS (Unaudited)
- -----------------------------------------------------------------------------
Average
Gross Electric Annual
Utility Plant Use Per
December 31, kWh Residential Electric
(Thousands of Sales Customer Customers Employees
Dollars)(a) (Millions) (kWh) (Average) (December 31)
1998 $2,302,254 12,579 6,347 421,602 1,265
1997 2,312,628 13,340 6,528 407,642 1,254
1996 2,382,009 13,601 6,567 407,082 1,279
1995 2,469,474 11,001 6,524(c) 406,077 1,325
1994 2,521,960 11,008 6,768 400,775 1,374
- -----------------------------------------------------------------------------
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
- -----------------------------------------------------------------------------
Quarter Ended (b)
-----------------
1999 March 31 June 30 Sept.30 Dec. 31
- ------------------------------------------------------------------------------
Operating Revenues... $261,745 $250,784 $286,614 $288,104
Operating Income..... $ 18,769 $ 42,406 $ 37,434 $ 32,590
Net Income........... $ 6,791 $ 31,601 $ 29,892 $ 23,402
1997 March 31 June 30 Sept.30 Dec. 31
- -------------------------------------------------------------------------------
Operating Revenues... $278,321 $257,098 $285,390 $287,650
Operating Income..... $ 44,776 $ 34,190 $ 32,166 $ 32,892
Net Income........... $ 32,295 $ 21,289 $ 18,900 $ 19,688
(a) Includes reclassification of the unamortized acquisition costs to
gross utility plant.
(b) Reclassifications of prior data have been made to conform with
the current presentation.
(c) Effective January 1, 1996, the amounts shown reflect billed and
unbilled sales. 1995 has been restated to reflect this change.
1998 Annual Report
North Atlantic Energy Corporation
Index
Contents Page
Balance Sheets........................................ 2
Statements of Income.................................. 4
Statements of Cash Flows.............................. 5
Statements of Common Stockholder's Equity............. 6
Notes to Financial Statements......................... 7
Report of Independent Public Accountants.............. 22
Management's Discussion and Analysis of Financial
Condition and Results of Operations................. 24
Selected Financial Data............................... 30
Statistics (Unaudited)................................ 30
Statements of Quarterly Financial Data (Unaudited).... 30
Bondholder Information................................ Back Cover
PART I. FINANCIAL INFORMATION
NORTH ATLANTIC ENERGY CORPORATION
BALANCE SHEETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
At December 31, 1998 1997
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
- ------
Utility Plant, at original cost:
Electric................................................ $ 753,379 $ 779,111
Less: Accumulated provision for depreciation......... 165,114 143,778
------------- -------------
588,265 635,333
Construction work in progress........................... 7,090 4,616
Nuclear fuel, net....................................... 23,644 27,413
------------- -------------
Total net utility plant............................. 618,999 667,362
------------- -------------
Other Property and Investments:
Nuclear decommissioning trust, at market................ 35,210 26,547
------------- -------------
35,210 26,547
------------- -------------
Current Assets:
Cash.................................................... 71 13
Special deposits........................................ 11,198 -
Notes receivable from affiliated companies.............. 30,350 -
Receivables from affiliated companies................... 23,804 25,695
Taxes receivable........................................ 7,887 4,613
Materials and supplies, at average cost................. 12,812 13,003
Prepayments and other................................... 2,198 4,220
------------- -------------
88,320 47,544
------------- -------------
Deferred Charges:
Regulatory assets....................................... 199,882 269,484
Unamortized debt expense................................ 2,742 3,702
------------- -------------
202,624 273,186
------------- -------------
Total Assets........................................ $ 945,153 $ 1,014,639
============= =============
</TABLE>
See accompanying notes to financial statements.
NORTH ATLANTIC ENERGY CORPORATION
BALANCE SHEETS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
At December 31, 1998 1997
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock--$1 par value. Authorized
and outstanding 1,000 shares.......................... $ 1 $ 1
Capital surplus, paid in................................ 160,999 160,999
Retained earnings....................................... 43,196 58,702
------------- -------------
Total common stockholder's equity.............. 204,196 219,702
Long-term debt.......................................... 405,000 475,000
------------- -------------
Total capitalization........................... 609,196 694,702
------------- -------------
Current Liabilities:
Notes payable to affiliated companies................... - 9,950
Long-term debt--current portion......................... 70,000 20,000
Accounts payable........................................ 5,924 7,912
Accounts payable to affiliated companies................ 867 6,040
Accrued interest........................................ 2,987 3,025
Accrued taxes........................................... 710 -
Other................................................... 285 1,055
------------- -------------
80,773 47,982
------------- -------------
Deferred Credits:
Accumulated deferred income taxes....................... 209,634 216,701
Deferred obligation to affiliated company............... 22,728 32,472
Other................................................... 22,822 22,782
------------- -------------
255,184 271,955
------------- -------------
Commitments and Contingencies (Note 7)
------------- -------------
Total Capitalization and Liabilities........... $ 945,153 $ 1,014,639
============= =============
</TABLE>
See accompanying notes to financial statements.
NORTH ATLANTIC ENERGY CORPORATION
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- ------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues................................. $ 276,685 $ 192,381 $ 162,152
---------- ---------- ----------
Operating Expenses:
Operation --
Fuel.......................................... 13,305 13,405 15,013
Other......................................... 36,763 39,091 35,268
Maintenance...................................... 14,120 24,146 9,154
Depreciation..................................... 25,381 25,170 24,056
Amortization of regulatory assets, net........... 85,464 6,270 (912)
Federal and state income taxes................... 36,194 14,845 12,341
Taxes other than income taxes.................... 11,401 12,393 12,343
---------- ---------- ----------
Total operating expenses................... 222,628 135,320 107,263
---------- ---------- ----------
Operating Income................................... 54,057 57,061 54,889
---------- ---------- ----------
Other Income:
Deferred Seabrook return--other funds............ 6,731 7,205 7,700
Other, net....................................... (8,435) (747) 1,200
Income taxes..................................... 14,378 4,394 5,052
---------- ---------- ----------
Other income, net.......................... 12,674 10,852 13,952
---------- ---------- ----------
Income before interest charges............. 66,731 67,913 68,841
---------- ---------- ----------
Interest Charges:
Interest on long-term debt....................... 50,082 50,722 52,414
Other interest................................... (676) 649 (697)
Deferred Seabrook return--borrowed funds......... (12,169) (13,411) (14,948)
---------- ---------- ----------
Interest charges, net...................... 37,237 37,960 36,769
---------- ---------- ----------
Net Income......................................... $ 29,494 $ 29,953 $ 32,072
========== ========== ==========
</TABLE>
See accompanying notes to financial statements.
NORTH ATLANTIC ENERGY CORPORATION
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities:
Net Income.................................................. $ 29,494 $ 29,953 $ 32,072
Adjustments to reconcile to net cash
from operating activities:
Depreciation.............................................. 25,381 25,170 24,056
Amortization of nuclear fuel.............................. 10,453 10,705 11,668
Deferred income taxes and investment tax credits, net..... 6,010 22,649 15,749
Deferred return - Seabrook................................ (18,900) (20,616) (22,648)
Amortization of nuclear plants return..................... 86,376 7,182 -
Amortization of other regulatory assets................... (912) (912) (912)
Amortization of deferred obligation to affiliated company. (9,744) (812) -
Sale of Seabrook 2 steam generator........................ - - 20,931
Other sources of cash..................................... 24,643 12,776 10,087
Other uses of cash........................................ (6,429) (9,406) (2,582)
Changes in working capital:
Receivables............................................... 1,891 (9,273) 2,270
Materials and supplies.................................... 191 90 (824)
Accounts payable.......................................... (7,161) (11,835) 19,509
Accrued taxes............................................. 710 (3,486) 2,140
Other working capital (excludes cash)..................... (13,258) 3,429 (7,675)
----------- ----------- -----------
Net cash flows from operating activities...................... 128,745 55,614 103,841
----------- ----------- -----------
Financing Activities:
Net (decrease)/increase in short-term debt.................. (9,950) 7,450 (5,500)
Reacquisitions and retirements of long-term debt............ (20,000) (20,000) (45,000)
Cash dividends on common stock.............................. (45,000) (25,000) (38,000)
----------- ----------- -----------
Net cash flows used for financing activities.................. (74,950) (37,550) (88,500)
----------- ----------- -----------
Investment Activities:
Investment in plant:
Electric utility plant.................................... (9,028) (6,606) (5,921)
Nuclear fuel.............................................. (6,474) (6,147) (15,752)
----------- ----------- -----------
Net cash flows used for investments in plant............ (15,502) (12,753) (21,673)
Investment in NU system Money Pool.......................... (30,350) - 2,500
Investment in nuclear decommissioning trusts................ (7,885) (5,597) (4,404)
Other investment activities, net............................ - - 222
----------- ----------- -----------
Net cash flows used for investments........................... (53,737) (18,350) (23,355)
----------- ----------- -----------
Net increase/(decrease) in cash for the period................ 58 (286) (8,014)
Cash - beginning of period.................................... 13 299 8,313
----------- ----------- -----------
Cash - end of period.......................................... $ 71 $ 13 $ 299
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized........................ $ 42,498 $ 45,297 $ 46,322
=========== =========== ===========
Income taxes................................................ $ 22,136 $ - $ (13,160)
=========== =========== ===========
</TABLE>
See accompanying notes to financial statements.
NORTH ATLANTIC ENERGY CORPORATION
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings
Stock Paid In (a) Total
- -----------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1996 ............. $ 1 $ 160,999 $ 59,677 $ 220,677
Net income.......................... 32,072 32,072
Cash dividends...................... (38,000) (38,000)
---------- ---------- --------- ----------
Balance at December 31, 1996............ 1 160,999 53,749 214,749
Net income.......................... 29,953 29,953
Cash dividends...................... (25,000) (25,000)
---------- ---------- --------- ----------
Balance at December 31, 1997............ 1 160,999 58,702 219,702
Net income.......................... 29,494 29,494
Cash dividends...................... (45,000) (45,000)
---------- ---------- --------- ----------
Balance at December 31, 1998............ $ 1 $ 160,999 $ 43,196 $ 204,196
========== ========== ========= ==========
</TABLE>
(a) All retained earnings are available for distribution, plus an allowance of
$10 million. However, there is a 25% common equity ratio test that must be
met in order to comply with the 1995 Term Credit Agreement maturing November
2000. Therefore, the company can pay out all of its retained earnings plus a
portion of the allowance. Currently there is $45.8 million available for
dividends.
See accompanying notes to financial statements.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. About North Atlantic Energy Corporation
North Atlantic Energy Corporation (NAEC or the company), The
Connecticut Light and Power Company (CL&P), Public Service Company
of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO),
and Holyoke Water Power Company (HWP), are the operating subsidiaries
comprising the Northeast Utilities system (the NU system) and are
wholly owned by Northeast Utilities (NU).
The NU system furnishes franchised retail electric service in
Connecticut, New Hampshire, and western Massachusetts through CL&P,
PSNH and WMECO. NAEC sells all of its entitlement to the capacity
and output of the Seabrook nuclear power plant, (Seabrook or Seabrook
1, a 1,148 megawatt nuclear generating unit) to PSNH under two life-
of-unit full cost recovery contracts (the Seabrook Power Contracts).
HWP is also engaged in the production and distribution of electric
power. The NU system also furnishes firm and other wholesale
electric services to various municipalities and other utilities,
and participates in limited retail access programs, providing off-
system retail electric service. The NU system serves in excess of 30
percent of New England's electric needs and is one of the 24 largest
electric utility systems in the country as measured by revenues.
NU is registered with the Securities and Exchange Commission (SEC)
as a holding company under the Public Utility Holding Company Act
of 1935 (1935 Act). NU and its subsidiaries, including NAEC, are
subject to the provisions of the 1935 Act. Arrangements among the
NU system companies, outside agencies and other utilities covering
interconnections, interchange of electric power and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. NAEC is subject to further
regulation for rates, accounting and other matters by the FERC
and/or applicable state regulatory commissions.
Other wholly owned subsidiaries of NU provide support services for
the NU system companies and, in some cases, for other New England
utilities. Northeast Utilities Service Company (NUSCO) provides
centralized accounting, administrative, information resources,
engineering, financial, legal, operational, planning, purchasing and
other services to the NU system companies. North Atlantic Energy
Service Corporation (NAESCO) acts as agent for NAEC and CL&P and has
operational responsibility for Seabrook. Northeast Nuclear Energy
Company (NNECO) acts as agent for the NU system companies and other
New England utilities in operating the Millstone nuclear generating
facilities.
During the first quarter of 1999, NU established three new
subsidiaries: NU Enterprises, Inc., Northeast Generation Company,
and Northeast Generation Services Company. Directly or through
multiple subsidiaries, these entities will engage in a variety of
energy-related activities, including the acquisition and management
of non-nuclear generating plants.
B. Presentation
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 disclosure of contingent 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.
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
All transactions among affiliated companies are on a recovery of cost
basis which may include amounts representing a return on equity and
are subject to approval by various federal and state regulatory
agencies.
C. New Accounting Standards
The Financial Accounting Standards Board (FASB) issued a new
accounting standard during 1998: Statement of Financial Accounting
Standards (SFAS) 133, "Accounting for Derivative Instruments and
Hedging Activities."
SFAS 133 establishes accounting and reporting standards for
derivative instruments and hedging activities. This statement
becomes effective for NAEC on January 1, 2000 and will require
derivative instruments used by NAEC to be recognized on the balance
sheets as assets or liabilities at fair value. NAEC uses derivative
instruments for hedging purposes. The accounting for these hedging
instruments will depend on which hedging classification each
derivative instrument falls under, as defined by SFAS 133, offset
by any changes in the market value of the hedged item.
Based on the derivative instruments which are currently being
utilized by NAEC to hedge some of its interest-rate risks, there will
be an impact on earnings upon adoption of SFAS 133 which management
cannot estimate at this time. For further information regarding
derivative instruments, see Note 8, "Market Risk-Management."
D. Jointly Owned Electric Utility Plant
NAEC has a 35.98 percent joint-ownership interest in Seabrook which
includes the 0.4 percent ownership interest in Seabrook 1 which
NAEC acquired from Vermont Electric Generation and Transmission
Cooperative in February 1994. NAEC sells all of its entitlement
to the capacity and output of the Seabrook nuclear generating unit
to PSNH under the Seabrook Power Contracts.
As of December 31, 1998 and 1997, plant-in-service included
approximately $721.2 million and $723.2 million, respectively,
and the accumulated provision for depreciation included approximately
$130.7 million and $116.1 million, respectively, for NAEC's share of
Seabrook 1. NAEC's share of Seabrook 1 expenses is included in the
corresponding operating expenses on the accompanying Statements of
Income.
E. Depreciation
The provision for depreciation is calculated using the straight-line
method based on estimated remaining lives of depreciable utility
plant-in-service, adjusted for salvage value and removal costs, as
approved by the appropriate regulatory agency. Except for major
facilities, depreciation rates are applied to the average plant-in
service during the period. Major facilities are depreciated from the
time they are placed in service. When plant is retired from service,
the original cost of plant, including costs of removal, less salvage,
is charged to the accumulated provision for depreciation. The costs
of closure and removal of non-nuclear facilities are accrued over the
life of the plant as a component of depreciation. The depreciation
rates for the several classes of electric plant-in-service are
equivalent to a composite rate of 3.5 percent in 1998 and 1997, and
3.4 percent in 1996. See Note 2, "Nuclear Decommissioning" for
additional information on nuclear plant decommissioning.
F. Seabrook Power Contracts
PSNH and NAEC have entered into the Seabrook Power Contracts which
obligate PSNH to purchase NAEC's 35.98 percent ownership of the
capacity and output of Seabrook 1 for the term of Seabrook 1's
Nuclear Regulatory Commission (NRC) operating license. Under these
contracts, PSNH is obligated to pay NAEC's cost of service during
this period, regardless if Seabrook 1 is operating. NAEC's cost of
service includes all of its Seabrook-related costs, including
operation and maintenance (O&M) expenses, fuel expense, income and
property tax expense, depreciation expense, certain overhead and
other costs and a return on its allowed investment.
The Seabrook Power Contracts established the value of the initial
investment in Seabrook (initial investment) at $700-million. As
prescribed by the 1989 rate agreement between NU, PSNH, the State of
New Hampshire (Rate Agreement), as of May 1, 1996, NAEC phased into
rates 100 percent of the recoverable portion of its investment in
Seabrook 1. From June 5, 1992 (the date NU acquired PSNH and NAEC
acquired Seabrook 1 from PSNH - the Acquisition Date) through
November 1997, NAEC recorded $203.9 million of deferred return on its
investment in Seabrook 1. At November 30, 1997, NAEC's utility plant
included $84.1 million of deferred return that was transferred as
part of the Seabrook plant assets to NAEC on the Acquisition Date.
Beginning on December 1, 1997, the deferred return, including the
portion transferred to NAEC began to be billed through the Seabrook
Power Contracts to PSNH, and will be fully recovered from customers
by May 2001. NAEC is depreciating its initial investment over the
term of Seabrook 1's operating license (39 years), and any subsequent
plant additions are depreciated on a straight-line basis over the
remaining term of the Seabrook Power Contracts at the time the
subsequent additions are placed in service.
If Seabrook 1 is shut down prior to the expiration of the NRC
operating license, PSNH will be unconditionally required to pay NAEC
termination costs for 39 years, less the period during which Seabrook
1 has operated. These termination costs will reimburse NAEC for its
share of Seabrook 1 shut-down and decommissioning costs, and will
pay NAEC a return of and on any undepreciated balance of its initial
investment over the remaining term of the Seabrook Power Contracts,
and the return of and on any capital additions to the plant made
after the Acquisition Date over a period of five years after shut
down (net of any tax benefits to NAEC attributable to the
cancellation).
G. Regulatory Accounting and Assets
The accounting policies of the company and the accompanying financial
statements conform to generally accepted accounting principles
applicable to rate-regulated enterprises and reflect the effects of
the ratemaking process in accordance with SFAS 71, "Accounting for
the Effects of Certain Types of Regulation." Assuming a cost-of-
service based regulatory structure, regulators may permit incurred
costs, normally treated as expenses, to be deferred and recovered
through future revenues. Through their actions, regulators also may
reduce or eliminate the value of an asset, or create a liability. If
any portion of the company's operations were no longer subject to the
provisions of SFAS 71, the company would be required to write off all
of its related regulatory assets and liabilities unless there is a
formal transition plan which provides for the recovery, through
established rates, for the collection of these costs through a
portion of the business which would remain regulated on a cost-of-
service basis. At the time of transition, NAEC would be required to
determine any impairment to the carrying costs of deregulated plant
and inventory assets.
The issue of restructuring the electric utility industry in New
Hampshire is currently the focus of negotiations and proceedings
within the federal and state legal systems. The outcome of these
court proceedings will impact NAEC due to NAEC's contractual
relationship with PSNH through the Seabrook Power Contracts.
Management continues to believe that NAEC's use of regulatory
accounting emains appropriate while this issue remains in
litigation.
For further information on NAEC's regulatory environment and the
potential impacts of restructuring, see Note 7A, "Commitments and
Contingencies - Restructuring," and Management's Discussion and
Analysis of Financial Condition and Results of Operations (MD&A).
Based on a current evaluation of the various factors and conditions
that are expected to impact future cost recovery, management
continues to believe it is probable that the operating companies,
including NAEC, will recover their investments in long-lived assets,
including regulatory assets. The components of NAEC's regulatory
assets are as follows:
At December 31, 1998 1997
(Thousands of Dollars)
Deferred costs-Seabrook 1
(Note 1J)........................... $147,169 $199,753
Income taxes, net (Note 1H)........... 39,472 48,736
Recoverable energy costs (Note 1I).... 1,878 2,057
Unamortized loss on reacquired
debt................................ 11,363 18,938
$199,882 $269,484
H. Income Taxes
The tax effect of temporary differences (differences between the
periods in which transactions affect income in the financial
statements and the periods in which they affect the determination of
taxable income) is accounted for in accordance with the ratemaking
treatment of the applicable regulatory commissions. See Note 5,
"Income Tax Expense" for the components of income tax expense.
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, which give
rise to the accumulated deferred tax obligation is as follows:
At December 31, 1998 1997
(Thousands of Dollars)
Accelerated depreciation and
other plant-related differences..... $182,170 $159,251
Regulatory assets - income tax
gross up............................ 13,640 17,094
Other................................. 13,824 40,356
$209,634 $216,701
I. Recoverable Energy Costs
Under the Energy Policy Act of 1992 (Energy Act), NAEC is assessed
for its proportionate share of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States
Department of Energy (D&D assessment). The Energy Act requires that
regulators treat D&D assessments as a reasonable and necessary
current cost of fuel, to be fully recovered in rates, like any other
fuel cost. NAEC is currently recovering these costs through the
Seabrook Power Contracts. As of December 31, 1998, NAEC's total D&D
deferral was approximately $1.9 million.
J. Deferred Cost - Seabrook 1
Under the Rate Agreement, the plant costs of Seabrook were phased
into rates over a seven-year period beginning May 15, 1991. Total
costs deferred under the phase-in plan were approximately $288
million. This plan is in compliance with SFAS 92, "Regulated
Enterprises - Accounting for Phase-In Plans." These deferred costs
are being billed to PSNH by NAEC through the Seabrook Power Contracts
beginning December 1, 1997, and will be fully recovered from PSNH by
NAEC through the Seabrook Power Contracts beginning December 1, 1997,
and will be fully recovered from PSNH's customers by May 2001. See
Note 1F, "Summary of Significant Accounting Policies - Seabrook
Power Contracts," for terms of Seabrook 1's phase-in. See Note 7A,
"Commitments and Contingencies - Restructuring" for the possible
impacts of the NHPUC's decision related to industry restructuring.
K. Market Risk-Management Policies
NAEC utilizes market risk-management instruments to hedge well-
defined risks associated with variable interest rates. To qualify
for hedge treatment, the underlying hedged item must expose the
company to risks associated with market fluctuations and the market
risk-management instrument used must be designated as a hedge and
must reduce the company's exposure to market fluctuations throughout
the period.
Amounts receivable or payable under interest-rate management
instruments are accrued and offset against interest expense. For
further information, see Note 8, "Market Risk-Management."
2. NUCLEAR DECOMMISSIONING
The Seabrook 1 nuclear power plant has a service life that is expected to
end in the year 2026. Upon retirement, this unit must be decommissioned.
A current decommissioning study concluded that complete and immediate
dismantlement at retirement continues to be the most viable and economic
method of decommissioning Seabrook 1. Decommissioning studies are
reviewed and updated periodically to reflect changes in decommissioning
requirements, costs, technology and inflation.
NAEC's 35.98 percent ownership of the estimated costs of decommissioning
Seabrook 1, in year-end 1998 dollars, is $175.9 million. Seabrook 1
decommissioning costs will be increased annually by an escalation rate.
Nuclear decommissioning costs are accrued over the expected service life
of the unit and are included in depreciation expense on the Statements of
Income. Nuclear decommissioning costs amounted to $4.7 million in 1998,
$4.5 million in 1997 and $3.5 million in 1996. Nuclear decommissioning,
as a cost of removal, is included in the accumulated provision for
depreciation on the Balance Sheets. At December 31, 1998 and 1997, the
balance in the accumulated reserve for depreciation amounted to $25.6
million and $21.1 million, respectively.
Under the terms of the Rate Agreement, PSNH is obligated to pay NAEC's
share of Seabrook 1's decommissioning costs, even if the unit is shut
down prior to the expiration of its operating license. NAEC's portion
of the cost of decommissioning Seabrook 1 is paid to an independent
decommissioning financing fund managed by the state of New Hampshire.
Funding of the estimated decommissioning costs assumes escalated
collections for Seabrook 1 and after-tax earnings on the Seabrook
decommissioning fund of 6.5 percent.
As of December 31, 1998, NAEC (including payments made prior to the
Acquisition Date by PSNH) had paid approximately $25.6 million into
Seabrook 1's decommissioning financing fund. Earnings on the
decommissioning financing fund increase the decommissioning trust
balance and the accumulated reserve for depreciation. Unrealize
gains and losses associated with the decommissioning financing fund
also impact the balance of the trust and the accumulated reserve
for depreciation. The fair value of the amounts in the external
decommissioning trusts was $35.2 million as of December 31, 1998.
Changes in requirements or technology, the timing of funding or
dismantling, or adoption of a decommissioning method other than immediate
dismantlement would change decommissioning cost estimates and the amounts
required to be recovered. PSNH attempts to recover sufficient amounts
through its allowed rates to cover NAEC's expected decommissioning costs.
Only the portion of currently estimated total decommissioning cost that
has been accepted by regulatory agencies is reflected in PSNH's rates.
Based on present estimates and assuming Seabrook 1 operates to the end of
its licensing period, NAEC expects that the decommissioning financing
fund will be substantially funded when Seabrook 1 is retired from
service.
3. SHORT-TERM DEBT
The amount of short-term borrowings that may be incurred by NAEC is
subject to periodic approval by either the SEC under the 1935 Act or by
its state regulator. Under the SEC restrictions, NAEC was authorized, as
of January 1, 1999, to incur short-term borrowings up to a maximum of $60
million.
Money Pool: Certain subsidiaries of NU, including NAEC, are members of
the Northeast Utilities System Money Pool (Pool). The Pool provides a
more efficient use of the cash resources of the system, and reduces
outside short-term borrowings. NUSCO administers the Pool as agent for
the member companies. Short-term borrowing needs of the member companies
are first met with available funds of other member companies, including
funds borrowed by NU parent. NU parent may lend to the Pool but may not
borrow. Funds may be withdrawn from or repaid to the Pool at any time
without prior notice. Investing and borrowing subsidiaries receive or
pay interest based on the average daily Federal Funds rate. However,
borrowings based on loans from NU parent bear interest at NU parent's
cost and must be repaid based upon the terms of NU parent's original
borrowing. At December 31, 1998 and 1997, NAEC had no borrowings and
$9.95 million, respectively, of borrowings outstanding from the Pool.
The interest rate on borrowings from the Pool at December 31, 1998 and
1997 was 5.8 percent, respectively.
Maturities of NAEC's short-term debt obligations were for periods of
three months or less.
4. LONG-TERM DEBT
Details of long-term debt outstanding are:
December 31,
1998 1997
(Thousands of Dollars)
First Mortgage Bonds:
9.05% Series A, due 2002............. $275,000 $295,000
Notes:
Variable - Rate Facility, due 2000... 200,000 200,000
Less: Amounts due within one year..... 70,000 20,000
Long-term debt, net............. $405,000 $475,000
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1998 is $70 million for 1999, $270 million
for 2000, $70 million for 2001, $65 million for 2002 and no requirements
for the year 2003.
Market risk-management instruments with financial institutions
effectively fix the interest rate on NAEC's $200 million variable-rate
bank note at 7.823 percent. For more information on the interest-rate
management instruments, see Note 8, "Market Risk- Management."
The Series A Bonds are not redeemable prior to maturity except out of
proceeds of sales of property subject to the lien of the Series A First
Mortgage Bond Indenture (Indenture), at general redemption prices
established by the Indenture, and out of condemnation or insurance
proceeds and through the operation of the sinking fund. Essentially all
of NAEC's utility plant is subject to the lien of its Indenture.
5. INCOME TAX EXPENSE
The components of the federal and state income tax provisions were
charged as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Current income taxes:
Federal................................ $15,206 $(11,889) $(8,570)
State.................................. 600 (309) 110
Total current........................ 15,806 (12,198) (8,460)
Deferred income taxes, net:
Federal................................ 4,032 21,528 14,884
State.................................. 1,978 1,121 865
Total deferred....................... 6,010 22,649 15,749
Total income tax expense............. $21,816 $10,451 $ 7,289
The components of total income tax expense are classified as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Income taxes charged to
operating expenses..................... $36,194 $14,845 $12,341
Other income taxes....................... (14,378) (4,394) (5,052)
Total income tax expense............... $21,816 $10,451 $ 7,289
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Depreciation............................. $ 21,828 $20,823 $12,730
Bond redemptions......................... (2,824) (2,351) (2,359)
Seabrook 1 deferred return............... (14,233) 3,338 5,438
Other.................................... 1,239 839 (60)
Deferred income taxes, net............. $ 6,010 $22,649 $15,749
A reconciliation between income tax expense and the expected tax expense
at the applicable statutory rate is as follows:
For the Years Ended December 31, 1998 1997 1996
(Thousands of Dollars)
Expected federal income tax
at 35 percent of
pretax income.......................... $17,959 $14,141 $13,776
Tax effect of differences:
Amortization of regulatory
assets............................... 7,077 (319) -
Depreciation........................... 949 (1,049) (1,343)
Deferred Seabrook 1 return............. (2,356) (2,522) (2,695)
State income taxes,
net of federal benefit............... 1,657 718 634
Allocation of Parent
Company's loss....................... (3,874) (615) (578)
Sale of Seabrook 2 steam
generator.............................. - - (2,516)
Other, net............................... 404 97 11
Total income tax expense................. $21,816 $10,451 $ 7,289
6. DEFERRED OBLIGATION TO AFFILIATED COMPANY
At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance
with the phase-in under the Rate Agreement, it began accruing a deferred
return on the unphased-in portion of its Seabrook 1 investment. From
May 16, 1991 to the Acquisition Date, PSNH accrued a deferred return
of $50.9 million. On the Acquisition Date, PSNH transferred the
$50.9 million deferred return to NAEC as part of the Seabrook-related
assets.
At the time PSNH transferred the deferred return to NAEC, it realized,
for income tax purposes, a gain that is deferred under the consolidated
income tax rules. Beginning December 1, 1997, this gain is being
restored for income tax purposes as the deferred return of $50.9 million,
and the associated income taxes of $33.2 million, are collected by NAEC
through the Seabrook Power Contracts. As NAEC recovers the $33.2 million
in years eight through ten of the Rate Agreement, it will be obligated to
make corresponding payments to PSNH.
See Note 1F, "Seabrook Power Contracts" for further information on the
phase-in of the Seabrook power plant and see Note 7A, "Commitments and
Contingencies - Restructuring" for the possible impacts on NAEC from the
NHPUC's decision related to industry restructuring.
7. COMMITMENTS AND CONTINGENCIES
A. Restructuring
New Hampshire: In 1996, New Hampshire enacted legislation requiring a
competitive electric industry beginning in 1998. In February 1997,
the NHPUC issued its restructuring order, which would have forced
PSNH and NAEC to write off all of their regulatory assets, and
possibly to seek protection under Chapter 11 of the bankruptcy laws.
The amount of potential write-off which would have been triggered by
the order is currently estimated to be in excess of $400 million,
after taxes.
Following the issuance of these orders, PSNH immediately sought
declaratory and injunctive relief on various grounds in federal
district court and has received a preliminary injunction that freezes
implementation of the NHPUC's restructuring orders. Restructuring
in New Hampshire has resulted in numerous subsequent proceedings
within the federal and state legal systems.
As the court proceedings are ongoing, PSNH continues to be involved
in settlement discussions with representatives from the state of New
Hampshire. PSNH hopes to reach a settlement, which would include,
among other things, recovery of regulatory assets and stranded
costs, rate reductions, an auction of PSNH's generating units and
securitization of PSNH's stranded costs. If a settlement is not
reached a trial is expected to begin mid to late 1999.
As a result of the NHPUC decision and the potential consequences
discussed above, the reports of our auditors on the individual
financial statements of PSNH and NAEC contain explanatory paragraphs.
Those explanatory paragraphs indicate that a substantial doubt exists
currently about the ability of PSNH and NAEC to continue as going
concerns.
Management believes that PSNH is entitled to full recovery of its
prudently incurred costs, including regulatory assets and other
stranded costs (such as its obligations to NAEC under the Seabrook
Power Contracts). It bases this belief both on the general nature of
public utility industry cost-of-service based regulation and the
specific circumstances of the resolution of PSNH's previous
bankruptcy proceedings and its acquisition by NU, including the
recoveries provided by the Rate Agreement and related agreements.
B. Environmental Matters
NAEC is subject to regulation by federal, state and local authorities
with respect to air and water quality, the handling and disposal of
toxic substances and hazardous and solid wastes, and the handling and
use of chemical products. NAESCO, on behalf of NAEC and the other
Seabrook joint owners, has an active environmental auditing and
training program and believes that it is in substantial compliance
with current environmental laws and regulations. However, the NU
system is subject to certain pending enforcement actions and
governmental investigations in the environmental area. Management
cannot predict the outcome of these enforcement actions and
investigations.
Environmental requirements could hinder future construction. Changing
environmental requirements could also require extensive and costly
modifications to NAEC's existing investment in Seabrook 1 and could
raise operating costs significantly. As a result, NAEC may incur
significant additional environmental costs, greater than amounts
included in cost of removal and other reserves, in connection with
the generation of electricity and the storage, transportation, and
disposal of by-products and wastes. NAEC may also encounter
significantly increased costs to remedy the environmental effects
of prior waste handling activities. The cumulative long-term cost
impact of increasingly stringent environmental requirements cannot
be estimated accurately.
NAEC cannot estimate the potential liability for future claims,
including environmental remediation costs, that may be brought
against it. However, considering known facts, existing laws and
regulatory practices, management does not believe the matters
disclosed above will have a material effect on NAEC's financial
position or future results of operations.
C. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, NAEC must pay the United
States Department of Energy (DOE) for the disposal of spent nuclear
fuel and high-level radioactive waste. The DOE is responsible for the
selection and development of repositories for, and the disposal of,
spent nuclear fuel and high-level radioactive waste. Fees for
nuclear fuel burned on or after April 7, 1983, are billed currently
to customers and paid to the DOE on a quarterly basis.
The DOE was originally scheduled to begin accepting delivery of spent
fuel in 1998. However, delays in identifying a permanent storage
site have continually postponed plans for the DOE's long-term storage
and disposal site. Extended delays or a default by the DOE could
lead to consideration of costly alternatives. The company has
primary responsibility for the interim storage of its spent nuclear
fuel. Current capability to store spent fuel at Seabrook 1 is
expected to have spent fuel storage capacity until at least 2010.
Meeting spent fuel storage requirements beyond this period could
require new and separate storage facilities, the costs for which have
not been determined.
In November 1997, the U.S. Court of Appeals for the D.C. Circuit
ruled that the lack of an interim storage facility does not excuse
the DOE from meeting its contractual obligation to begin accepting
spent nuclear fuel no later than January 31, 1998. The 1997 ruling
by the appeals court said, however, that the 1982 federal law could
not require the DOE to accept waste when it did not have a suitable
storage facility. The court directed the plaintiffs to pursue relief
under the terms of their contracts with the DOE. Based on this
ruling, since the DOE did not take the spent nuclear fuel as
scheduled, it may have to pay contract damages.
In May 1998, the same court denied petitions from 60 states and state
agencies, collectively, and 41 utilities, including the company,
asking the court to compel the DOE to submit a program, beginning
immediately, for disposing of spent nuclear fuel. The petitions were
filed after the DOE defaulted on its January 31, 1998 obligation to
begin accepting the fuel. The court directed the company and other
plaintiffs to pursue relief under the terms of their contracts with
the DOE.
In a petition filed in August 1998, the court's May 1998 decision was
appealed to the U.S. Supreme Court. In November 1998, the Supreme
Court declined to review the lower court ruling that said utilities
should go to court and seek monetary damages from the DOE. The
ultimate outcome of this legal proceeding is uncertain at this time.
D. Nuclear Insurance Contingencies
Under certain circumstances, in the event of a nuclear incident at
one of the nuclear facilities in the country covered by the federal
government's third-party liability indemnification program, an owner
of a nuclear unit could be assessed in proportion to its ownership
interest in each of its nuclear units up to $83.9 million. Payments
of this assessment would be limited to, in proportion to its
ownership interest in each of its nuclear units, $10.0 million in
any one year per nuclear incident. In addition, if the sum of all
claims and costs from any one nuclear incident exceeds the maximum
amount of financial protection, the owner would be subject to an
additional five percent or $4.2 million, in proportion to its
ownership interests in each of its nuclear units. Based upon its
ownership interest in Seabrook 1, NAEC's maximum liability, including
any additional assessments, would be $31.3 million per incident, of
which payments would be limited to $3.6 million per year.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from
insured occurrences at Seabrook station. NAEC is subject to
retroactive assessments if losses exceed the accumulated funds
available to the insurer. The maximum potential assessment against
NAEC with respect to losses arising during the current policy year
is approximately $2.0 million.
Insurance has been purchased to cover certain extra costs of repair,
replacement or decontamination or premature decommissioning of
utility property resulting from insured occurrences. NAEC is subject
to retroactive assessments if losses exceed the accumulated funds
available to the insurer. The maximum potential assessment against
NAEC with respect to losses arising during current policy years is
approximately $3.2 million. The cost of a nuclear incident could
exceed available insurance proceeds.
Insurance has been purchased aggregating $200 million on an industry
basis for coverage of worker claims.
Under the terms of the Seabrook Power Contracts, any nuclear
insurance assessments described above would be passed on to PSNH as
a "cost of service."
E. Seabrook 1 Construction Program
The construction program for Seabrook 1 is subject to periodic review
and revision by management. NAEC currently forecasts construction
expenditures for its share of Seabrook 1 to be $27.3 million for the
years 1999-2003, including approximately $8.2 million for 1999. In
addition, NAEC estimates that its share of Seabrook 1 nuclear fuel
requirements will be approximately $53.7 million for the years 1999-
2003, including $1.6 million for 1999.
8. MARKET RISK-MANAGEMENT
NAEC uses swap instruments with financial institutions to hedge against
interest-rate risk associated with its $200 million variable rate bank
note. The interest-rate management instruments employed eliminate the
exposure associated with rising interest rates, and effectively fix the
interest rate for this borrowing arrangement. Under the agreements, NAEC
exchanges quarterly payments based on a differential between a fixed
contractual interest rate and the three-month LIBOR rate at a given time.
As of December 31, 1998, NAEC had outstanding agreements with a total
notional value of $200 million and a negative mark-to-market position of
approximately $2.3 million.
Credit Risk: These agreements have been made with various financial
institutions, each of which is rated "A3" or better by Moody's rating
group. NAEC will be exposed to credit risk on its respective market
risk-management instruments if the counterparties fail to perform their
obligations. However, management anticipates that the counterparties will
be able to fully satisfy their obligations under the agreements.
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair
value of each of the following financial instruments:
Cash and cash equivalents: The carrying amounts approximate fair value
due to the short-term nature of cash and cash equivalents.
Nuclear decommissioning trust: The investments held in NAEC's nuclear
decommissioning fund were adjusted to market by approximately $2.3
million as of December 31, 1998 and by approximately $1.5 million as
of December 31, 1997 with corresponding offsets to the accumulated
provision for depreciation. The amounts adjusted in 1998 and 1997
represent cumulative gross unrealized holding gains. The cumulative
gross unrealized holding losses were immaterial for 1998 and 1997.
Long-term debt: The fair value of NAEC's fixed-rate security is based
upon the quoted market price for that issue or similar issue. The
adjustable rate security is assumed to have a fair value equal to its
carrying value.
The carrying amounts of NAEC's financial instruments and the estimated
fair values are as follows:
Carrying Fair
At December 31, 1998 Amount Value
(Thousands of Dollars)
First mortgage bonds................. $275,000 $284,543
Other long-term debt................. $200,000 $200,000
Carrying Fair
At December 31, 1997 Amount Value
(Thousands of Dollars)
First mortgage bonds................. $295,000 $301,599
Other long-term debt................. $200,000 $200,000
The fair values shown above have been reported to meet the disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
10. NUCLEAR PERFORMANCE
For information on nuclear performance related to the Seabrook nuclear
power plant, see the MD&A.
To the Board of Directors
of North Atlantic Energy Corporation:
We have audited the accompanying balance sheets of North Atlantic Energy
Corporation (a New Hampshire corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 1998 and 1997, and the related
statements of income, common stockholder's equity, and cash flows for each
of the three years in the period ended December 31, 1998. 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 in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of North Atlantic Energy
Corporation as of December 31, 1998 and 1997, and the results of its
operations and its cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted accounting
principles.
The accompanying financial statements have been prepared assuming that the
company will continue as a going concern. As discussed in Note 7A, on
February 28, 1997, the State of New Hampshire Public Utilities Commission
(the NHPUC) issued an order outlining its final plan to restructure the
electric utility industry. The final plan announced a departure from cost-
based ratemaking for Public Service Company of New Hampshire (PSNH). PSNH
is the sole customer of the company. The final plan, if implemented, would
require PSNH to discontinue the application of Financial Accounting Standard
No. 71, "Accounting for the Effects of Certain Types of Regulation," (FAS
71). The effects of such a discontinuation would cause PSNH and the company
to be in technical default under their current financial covenants, which
would, if not waived or renegotiated, give rise to the rights of lenders to
accelerate the repayment of approximately $516 million of PSNH's indebtedness
and approximately $475 million of the company's indebtedness. These conditions
raise substantial doubt about the company's ability to continue as a going
concern. The financial statements referred to above do not include any
adjustments that might result from the outcome of this uncertainty.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 23, 1999
North Atlantic Energy Corporation
Management's Discussion and Analysis of Financial
Condition and Results of Operations
This section contains management's assessment of North Atlantic Energy
Corporation's (NAEC or the company) financial condition and the principal
factors having an impact on the results of operations. The company is a
wholly-owned subsidiary of Northeast Utilities (NU). This discussion should
be read in conjunction with the company's financial statements and notes to
financial statements.
FINANCIAL CONDITION
Earnings Overview
NAEC's net income for 1998 was essentially unchanged. NAEC had net income of
approximately $29 million in 1998 compared to approximately $30 million in
1997.
The company's only assets are Seabrook and other Seabrook-related assets and
its only source of revenues are the power contracts between PSNH and the
company. PSNH's obligations under the Power Contracts are solely its own and
have not been guaranteed by NU. The Power Contracts contain no provisions
entitling PSNH to terminate its obligations. If, however, PSNH were to fail
to perform its obligation under the Power Contracts, the company would be
required to find other purchasers for Seabrook power.
Liquidity and Capital Resources
Net cash flows from operations totaled approximately $129 million in 1998,
up sharply from $56 million in 1997. The increase resulted from the
recovery of the Seabrook deferred nuclear costs beginning in December 1997.
Approximately $54 million of net cash flow was used for investment activities,
including construction expenditures, investments in the NU system money pool
and investments in nuclear decommissioning trusts, compared with $18 million
in 1997. Another $45 million was used to pay common dividends, compared
with $25 million in 1997. The balance of cash used for financing activities,
approximately $30 million, was used to pay off long-term and short-term debt.
In 1997 net debt and preferred stock levels were reduced by only $13 million.
PSNH Restructuring
Restructuring efforts in New Hampshire have resulted in numerous proceedings
within the federal and state court systems. The New Hampshire Public
Utilities Commission's (NHPUC) 1997 restructuring orders have been prevented
from being implemented as a result of various court actions pending the
outcome of a full trial in the U.S. District Court. The 1997 orders would
have forced PSNH and NAEC to write off substantially all of their regulatory
assets. A trial is expected to begin in mid to late 1999.
In January 1999, the NHPUC issued an order stating that it intends to reopen
restructuring hearings. PSNH has requested the federal court to enforce its
preliminary injunction barring the NHPUC from proceeding with restructuring
efforts pending the court's decision on the merits after trial. The NHPUC
has agreed to delay this new proceeding until the federal court has had an
opportunity to rule on PSNH's enforcement motion.
The litigation has caused New Hampshire to fall behind several other
Northeast states in implementing industry restructuring. PSNH hopes to
reach a settlement that would include, among other things, substantial rate
reductions, customer choice, an auction of PSNH's generating units and
securitization of PSNH's stranded costs. PSNH believes that a negotiated
resolution of outstanding restructuring and rate issues would be in the best
interests of the state, PSNH and customers.
Seabrook Performance
Seabrook operated at a capacity factor of 82.8 percent through December 1998,
compared to 78.3 percent for the same period in 1997. The unit operated well,
except for two unplanned outages, one in late 1997 through early 1998 and the
other in mid-1998, to repair control building's air conditioning system.
Seabrook is scheduled to begin a refueling outage in March 1999.
Seabrook Decommissioning
NAEC's estimated cost to decommission its share of Seabrook is approximately
$175.9 million in year-end 1998 dollars. These costs are being recognized
over the life of the unit with a portion currently being recovered through
PSNH's rates. PSNH is obligated to pay NAEC's share of Seabrook's
decommissioning costs even if the unit is shut down prior to the expiration
of its license. As of December 31, 1998, the market value of the
contributions already made to the decommissioning trusts, including their
investment returns, was approximately $35.2 million.
See the "Notes to Consolidated Financial Statements," Note 2, for further
information on nuclear decommissioning.
Year 2000 Issue
The NU system has established an action plan by which identified processes
must be completed by certain dates in order to ensure its operating systems,
including nuclear systems, and reporting systems are able to properly
recognize the year 2000. This action plan has three phases: the inventory
phase, the detailed assessment phase and the remediation phase. The inventory
phase, which has been completed, identified operating and reporting systems
which may need to be fixed. The detailed assessment phase, which has been
completed, determined exactly what needed to be done in order to ensure that
the systems identified during the inventory phase are able to recognize
properly and process the year 2000. The final phase is the remediation phase.
By the end of this phase, mission critical systems (systems that are
related to safety, keeping the lights on, regulatory requirements, and other
systems that could have a significant financial impact) will be year 2000
ready; that is, these systems will perform their business functions properly
in the year 2000. This phase includes making modifications, testing and
validating changes and verifying that the year 2000 issues have been
resolved.
Although the identification and detailed assessment phases are complete,
newly identified items, such as new software purchases, are added to the
inventory as they are identified and are subject to detailed assessment
and, if needed, remediation. NU system purchasing policies require newly
purchased software and devices to be year 2000 compliant. None of these
newly identified items are expected to materially impact completion of
the remediation phase.
The NU system has identified and inventoried 2,497 computer systems
(software) and over 24,000 devices (hardware) broken down into 3,450 device
types containing date-sensitive computer chips. As of December 31, 1998, 77
percent of the software systems and 81 percent of the hardware at Seabrook
were year 2000 ready.
The remaining items are in various stages of modification or testing.
Management anticipates the remediation phase for mission critical systems
to be completed by mid-1999.
In addition, the NU system has been contacting its key suppliers and
business partners to determine their ability to manage the year 2000
problem successfully. The NU system is adjusting its inventories, working
with suppliers to provide backup inventories, and changing suppliers as
needed to provide for an adequate supply of materials needed to conduct
business into the year 2000.
The NU system has utilized both internal and external resources to identify,
assess, test and reprogram or replace the computer systems for year 2000
readiness. The current projected total cost of the Year 2000 Program to the
NU system is $30 million. The total estimated remaining cost is $18 million,
which is being funded through operating cash flows. The majority of these
costs will be expensed as incurred in 1999. Since 1996, the NU system has
incurred and expensed approximately $12 million related to Year 2000
readiness efforts. Total expenditures related to the year 2000 are not
expected to have a material effect on the operations or financial condition
of the NU system.
The costs of the project and the date on which the NU system plans to
complete the year 2000 modifications are based on management's best
estimates, which were derived utilizing numerous assumptions of future
events, including the continued availability of certain resources, third-
party modification plans and other factors. However, there can be no
guarantee that these estimates will be achieved, and actual results could
differ materially from those plans. If the NU system's remediation plans or
those of third parties are not successful, there could be a significant
disruption of the NU system's operations. The most likely worst case
scenario is a limited number of localized interruptions to electric service
which can be restored within a few hours. As a precautionary measure, NU is
formulating contingency plans that will evaluate alternatives that could be
implemented if our remediation efforts are not successful. The contingency
plans are being developed by enhancing existing emergency operating
procedures to include year 2000 issues. In addition, the NU system plans
to have staff available to respond to any year 2000 situations that might
arise. The contingency plan is expected to be available by July 30, 1999.
The NU system is committed to assuring that adequate resources are available
in order to implement any changes necessary for its nuclear and other
operations to be compatible with the new millennium.
Risk-Management Instruments
NAEC uses swaps to manage the market risk exposures associated with changes
in variable interest rates. NAEC uses these instruments to reduce risk by
essentially creating offsetting market exposures. Based on the derivative
instruments which currently are being utilized by NAEC to hedge some of its
interest rate risks, there will be an impact on earnings upon adoption of
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities, which management cannot
estimate at this time. For more information on NU's use of risk-management
instruments, see the "Notes to Consolidated Financial Statements," Notes 1K
and 8.
NEAC holds a variable-rate long-term note, exposing the company to interest
rate risk. In order to hedge some of this risk, interest rate risk-
management instruments have been entered into on NAEC's $200 million
variable-rate note, effectively fixing the interest on this note at 7.823
percent. As of December 31, 1998, NAEC had outstanding agreements with a
total notional value of approximately $200 million and a negative mark-to-
market position of approximately $2.3 million.
Environmental Matters
NAEC is potentially liable for environmental cleanup costs at a number
of sites inside and outside of its service territory. To date, the future
estimated environmental remediation liability has not been material with
respect to the earnings or financial position of the company. See the "Notes
to Consolidated Financial Statements," Note 7B, for further information on
environmental matters.
RESULTS OF OPERATIONS
Income Statement Variances
Increase/(Decrease)
Millions of Dollars
1998 over/(under)1997 1997 over/(under)1996
Amount Percent Amount Percent
Operating revenues $84 44% $30 19%
Other operation and
maintenance expense $(12) (20%) $20 45%
Amortization of Regulatory
Assets, net $ 79 (a) $ 6 (a)
Federal and State Income Taxes $ 11 (a) $ 3 43%
Other, net $ (8) (a) $(2) (a)
(a) Percent greater than 100.
Operating Revenues
Operating revenues represent amounts billed to PSNH under the terms of the
Power Contracts and billings to PSNH for decommissioning expense.
Operating revenues increased in 1998 primarily due to amounts billed to PSNH
for the amortization of the Seabrook deferred return which began in December
1997.
Operating revenues increased in 1997 primarily due to higher operation and
maintenance expenses and the increased return associated with the phase-in of
the final 15 percent of the Seabrook plant investment in May, 1996.
Other Operation and Maintenance Expense
Other operation and maintenance expenses decreased in 1998 primarily due to
lower costs associated with Seabrook outages in 1998.
Other operation and maintenance expenses increased in 1997 primarily due to
higher costs associated with a planned refueling and unplanned Seabrook
outages in 1997.
Amortization of Regulatory Assets, net
Amortization of Regulatory Assets, net increased in 1998 and 1997 primarily
due to the amortization of the Seabrook deferred return which began in
December 1997.
Federal and State Income Taxes
Federal and State income taxes increased in 1998 primarily due to higher
taxable income.
Federal and State income taxes increased in 1997 primarily due to deferred
tax benefits in 1996 associated with proceeds from the sale of the Seabrook
Unit 2 steam generators.
Other, net
Other, net income decreased in 1998 primarily due to the amortization of the
taxes associated with the Seabrook-phase-in costs which began in December
1997.
Other, net income decreased in 1997 primarily due to lower income from
temporary cash investments and the amortization of the Seabrook deferred
charges associated with the taxes on the purchased return.
North Atlantic Energy Corporation
SELECTED FINANCIAL DATA (a) 1998 1997 1996 1995 1994
(Thousands of Dollars)
Operating Revenues......... $276,685 $ 192,381 $ 162,152 $ 157,183 $145,751
Operating Income........... $ 54,057 $ 57,061 $ 54,889 $ 51,394 $ 42,950
Net Income................. $ 29,494 $ 29,953 $ 32,072 $ 24,441 $ 30,535
Cash Dividends on
Common Stock............. $ 45,000 $ 25,000 $ 38,000 $ 24,000 $ 10,000
Total Assets............... $945,153 $1,014,639 $1,017,388 $1,014,649 $963,579
Long-Term Debt (b)......... $475,000 $ 495,000 $ 515,000 $ 560,000 $560,000
STATISTICS (Unaudited) 1998 1997 1996 1995 1994
Gross Electric Utility
Plant at December 31,
(Thousands of Dollars)..... $784,113 $ 811,140 $ 816,446 $ 806,892 $792,880
kWh Sales (Millions) for
the twelve month period
ending December 31,...... 3,018 2,859 3,542 3,016 2,229
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) (Thousands of Dollars)
Quarter Ended (a)
1998 March 31 June 30 Sept. 30 Dec. 31
Operating Revenues......... $68,169 $69,627 $69,087 $69,802
Operating Income........... $13,648 $13,365 $13,159 $13,885
Net Income................. $ 6,909 $ 8,303 $ 7,170 $ 7,112
1997
Operating Revenues......... $41,976 $50,128 $45,943 $54,334
Operating Income........... $14,406 $14,183 $14,124 $14,348
Net Income................. $ 7,240 $ 6,958 $ 8,086 $ 7,669
(a) Reclassifications of prior data have been made to conform with the current
presentation.
(b) Includes portion due within one year.
NORTHEAST UTILITIES SYSTEM Exhibit 21
SUBSIDIARIES OF THE REGISTRANT
Northeast Utilities
The Connecticut Light and Power Company (100%)
- CL&P Capital, L.P. (3%)
- Research Park, Inc. (100%)
- The City and Suburban Electric and Gas Company (100%)
- Electric Power Incorporated (100%)
- The Connecticut Transmission Corporation (100%)
- The Nutmeg Power Company (100%)
- The Connecticut Steam Company (100%)
- CL&P Receivables Corporation (100%)
- Connecticut Yankee Atomic Power Company (34.5%)
- Yankee Atomic Electric Company (24.5%)
- Maine Yankee Atomic Power Company (12%)
- Vermont Yankee Nuclear Power Corporation (9.5%)
Public Service Company of New Hampshire (100%)
- Properties, Inc. (100%)
- New Hampshire Electric Company (100%)
- Connecticut Yankee Atomic Power Company (5%)
- Yankee Atomic Electric Company (7%)
- Maine Yankee Atomic Power Company (5%)
- Vermont Yankee Nuclear Power Corporation (4%)
North Atlantic Energy Corporation (100%)
North Atlantic Energy Service Corporation (100%)
Western Massachusetts Electric Company (100%)
- WMECO Receivables Corporation (100%)
- Connecticut Yankee Atomic Power Company (9.5%)
- Yankee Atomic Electric Company (7%)
- Maine Yankee Atomic Power Company (3%)
- Vermont Yankee Nuclear Power Corporation (2.5%)
Holyoke Water Power Company (100%)
- Holyoke Power and Electric Company (100%)
Charter Oak Energy, Inc. (100%)
- COE Development Corporation (100%)
- COE Argentina II Corp. (100%)
- COE Ave Fenix Corporation (100%)
Northeast Nuclear Energy Company (100%)
Northeast Utilities Service Company (100%)
The Quinnehtuk Company (100%)
The Rocky River Realty Company (100%)
NU Enterprises, Inc. (100%)
- Northeast Generation Company (100%)
- Northeast Generation Services Company (100%)
- Mode 1 Communications, Inc. (100%)
- Select Energy, Inc. (100%)
- HEC Inc. (100%)
- HEC International Corporation (100%)
- HEC Energy Consulting Canada, Inc. (100%)
- Southwest HEC Energy Services L.L.C. (99%)
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